Filed by e3 Filing, Computershare 1-800-973-3274 - Nevada Geothermal Power Inc.

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")

[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE EXCHANGE ACT

For the fiscal year ended June 30, 2011.

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE EXCHANGE ACT

For the transition period from ____________ to ____________

[ ] SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE EXCHANGE ACT

Date 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)

840 – 1140 West Pender Street, Vancouver, British Columbia, Canada, V6E 4G1
(Address of principal executive offices)

Name: Andrew T. Studley; Telephone: 604-688-1553; Email: info@nevadageothermal.com; Facsimile: 604-688-5926; Address: 840 – 1140 West Pender Street, Vancouver, British Columbia, Canada, V6E 4G1
(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 registered
Not 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)

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 June 30, 2011 is 122,410,573

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 ]

TABLE OF CONTENTS

Page No.


	Forward Looking Statements	7

	Presentation of Financial Information and Other Information	8

PART I

ITEM 1	Identity of Directors, Senior Management and Advisers	9

ITEM 2	Offer Statistics and Expected Timetable	9

ITEM 3	Key Information	9
A.	Selected Financial Data	9
B.	Capitalization and Indebtedness	11
C.	Reasons For The Offer and Use of Proceeds	11
D.	Risk Factors	11

ITEM 4	Information on the Company	27
A.	History and Development of the Company	27
B.	Business Overview	28
C.	Organizational Structure	37
D.	Property, Plants and Equipment	38

ITEM 4A	Unresolved Staff Comments	82

ITEM 5	Operating and Financial Review and Prospects	82
A.	Operating Results	82
B.	Liquidity and Capital Resources	92
C.	Research and Development, Patents and Licenses, etc.	96
D.	Trend Information	96
E.	Off-Balance Sheet Arrangements	97
F.	Tabular Disclosure of Contractual Obligations	98

ITEM 6	Directors, Senior Management and Employees	99
A.	Directors and Senior Management	99
B.	Compensation	105
C.	Board Practices	108
D.	Employees	111
E.	Share Ownership	111

ITEM 7	Major Shareholders and Related Party Transactions	113
A.	Major Shareholders	113


B.	Related Party Transactions	114
C.	Interests of Experts and Counsel	115

ITEM 8	Financial Information	115
A.	Consolidated Statements and Other Financial Information	115
B.	Significant Changes	116

ITEM 9	The Offer and Listing	116
A.	Offer and Listing Details	116
B.	Plan of Distribution	117
C.	Markets	117
D.	Selling Shareholders	117
E.	Dilution	117
F.	Expenses of the Issue	118

ITEM 10	Additional Information	118
A.	Share Capital	118
B.	Memorandum and Articles of Association	118
C.	Material Contracts	120
D.	Exchange Controls	123
E.	Taxation	126
F.	Dividends and Paying Agents	137
G.	Statement by Experts	137
H.	Documents on Display	137
I.	Subsidiary Information	137

ITEM 11	Quantitative and Qualitative Disclosures About Market Risk	138

ITEM 12	Description of Securities Other Than Equity Securities	140

PART II

ITEM 13	Defaults, Dividend Arrearages and Delinquencies	140

ITEM 14	Material Modifications to the Rights of Security Holders and Use of Proceeds	140

ITEM 15	Controls and Procedures	140

ITEM 16A	Audit Committee Financial Expert	142

ITEM 16B	Code of Ethics	142

ITEM 16C	Principal Accountant Fees and Services	143

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 ability to operate our power plants in accordance with our power production forecasts;
Our plans to obtain adequate partners to assist in future development;
Our expected commencement and completion dates related to resource production operations; and
Our 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 resource and revenue shortfall compared to loan agreement and other contractual requirements, as well as our 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
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 (“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 and joint venture are referred to in this Annual Report as follows:


Subsidiaries:
Blue Mountain Power Company Inc.	BMPC
Desert Valley Gold Co.	DVG
NGP Chile S.A.	NGP Chile
Nevada Geothermal Power US Holdings Inc.	US Holdings
Nevada Geothermal Power Company	NGPC
Nevada Geothermal Operating Company LLC	NGOP
Nevada Geothermal Power Holding Company LLC	Holdings
NGP Blue Mountain Holdco LLC	BM Holdco
NGP Blue Mountain I LLC	NGP I
NGP Blue Mountain Holdco II LLC	BM Holdco II
NGP Blue Mountain Holdco III LLC	BM Holdco III
NGP Blue Mountain Holdco IV LLC	BM Holdco IV
NGP Blue Mountain II LLC	NGP II
NGP Blue Mountain III LLC	NGP II
NGP Blue Mountain IV LLC	NGP IV
NGP North Valley Inc (formerly NGP (Black Warrior I))	North Valley
NGP (Crump I)	Crump
NGP (Pumpernickel I)	Pumpernickel
Nevada Geothermal Power East Brawley LLC	East Brawley
Nevada Geothermal Power South Brawley LLC	South Brawley
NGP Truckhaven LLC	New Truckhaven

Joint venture:
Crump Geothermal Company LLC	CGC

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, 2011 unless an earlier or later date is indicated.

Financial information is presented in accordance with Canadian generally accepted accounting principles. Differences between Canadian and United States generally accepted accounting principles, as applicable to Nevada Geothermal Power Inc., are discussed in Item 5 of this Annual Report and in Note 30 of 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.

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 following tables summarize our selected consolidated financial data (stated in US dollars) prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). The selected historical financial data for the last five fiscal years has been extracted from more detailed information and financial statements, including our audited consolidated financial statements as of June 30, 2011 and 2010 and for each of the years in the three year period ended June 30, 2011 which appear elsewhere in this Annual Report. Certain historical consolidated financial data as of and for the years ended June 30, 2009, 2008 and 2007, has been extracted from our consolidated financial statements not included in this Annual Report. Unless otherwise indicated, dollar amounts are set forth in US dollars and foreign currency are translated into US dollars as described in the Company’s audited financial statements which appear elsewhere in this Annual Report.

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 thereto included elsewhere in this Annual Report. Note 30 to our Consolidated Financial Statements included in this Annual Report sets forth the material differences between Canadian and United States generally accepted accounting principles (“United States GAAP”).

Financial information prepared in accordance with Canadian GAAP:


	Year ended June 30,
	2011	2010	2009	2008	2007
Revenue	$24,856,817	$11,839,010	$-	$-	$-
Operating profit (loss)	6,917,764	(737,623)	(3,363,418)	(3,556,175)	(2,512,780)
Net loss	(8,606,976)	(17,981,451)	(5,088,760)	(3,425,767)	(2,538,389)
Weighted average number of shares	111,497,866	95,280,808	94,438,849	79,122,910	61,294,757
Net loss per share (basic and diluted)	(0.08)	(0.19)	(0.05)	(0.04)	(0.30)
Cash dividends declared per share	-	-	-	-	-
Total assets	193,052,603	187,273,781	222,810,846	81,418,879	37,374,414
Share capital	62,925,121	54,942,619	53,857,748	53,701,819	36,875,324
Total shareholders’ equity	29,831,848	25,789,636	42,542,780	48,920,501	34,217,929
Number of shares outstanding	122,410,573	95,576,504	94,547,504	94,169,504	76,824,1714

Financial information prepared in accordance with United States GAAP:


	Year ended June 30,
	2011	2010	2009	2008	2007
Revenue	$24,856,817	$11,839,010	$-	$-	$-
Operating profit (loss)	6,989,693	577,527	(5,567,461)	(29,298,620)	(16,421,431)
Net loss	(8,497,141)	(16,723,009)	(7,292,803)	(29,168,212)	(16,447,040)
Weighted average number of shares	111,497,866	95,280,808	94,438,849	79,122,910	61,294,757
Net loss per share (basic and diluted)	(0.08)	(0.18)	(0.08)	(0.37)	(0.27)
Cash dividends declared per share	-	-	-	-	-
Total assets	142,432,357	139,054,680	173,333,303	31,167,953	13,739,557
Share capital	62,925,121	54,942,619	53,857,748	53,701,819	36,875,324
Total shareholders equity	(18,277,418)	(22,429,465)	(6,934,763)	(1,330,425)	10,583,074
Number of shares outstanding	122,410,573	95,576,504	94,547,504	94,169,504	76,824,1714

In computing diluted loss per share, no shares were added to the weighted average number of common shares outstanding on a fully diluted basis as the effect of such issuance is anti-dilutive.

Disclosure of Exchange Rate History

On November 30, 2011, 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 $1.0199.

For the past five fiscal years ended June 30, 2011, and for each month ended during the period between June 1, 2011 and November 30, 2011, 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	Average

Year:
June 30, 2007	1.1322
June 30, 2008	1.0102
June 30, 2009	1.1658
June 30, 2010	1.0559
June 30, 2011	0.9998

Month:	Low/High

June 30, 2011	0.9859/0.9642
July 31, 2011	0.9667/0.9448
August 30, 2011	0.9909/0.9577
September 30, 2011	1.0389/0.9751
October 31, 2011	1.0605/0.9932
November 30, 2011	1.0487/1.0125

B. Capitalization and Indebtedness

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. Reasons for the Offer and Use of Proceeds

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.

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 financial condition, operations and future financial performance. You should carefully consider the following risks and uncertainties in addition to other information contained in this Annual Report in evaluating us and our business before purchasing our common shares.

Risks Relating to our Business

We May Not be Able to Achieve Target Power Production at our Blue Mountain Power Plant and, Therefore, Comply with the 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. However, work to date and a model of the geothermal reservoir prepared by the consultant indicates that additional injection wells, further from the current production wells, are required to mitigate the effect of premature reservoir cooling currently experienced. To date, while several new wells have been drilled in high target locations, the Company has not sufficiently improved injection to reach and sustain the target power production.

In August 2009, the Company’s Blue Mountain subsidiary, NGP I, began supplying power to NV Energy (“NVE”) under a power purchase agreement (“PPA”). During November 2009 NGP I declared Commercial Operation under the PPA, committing to supply the minimum 36.1 MW that was required during 2010. NGP I continued drilling and despite a first calendar quarter electrical wiring issue, during which NGP I declared Force Majeure, successful drilling resulted in an increase in power production to this PPA minimum by the end of March 2010, averaging 37, 34 and 33 MW respectively during the three following calendar quarters and an average of approximately 35 MW for the full 2011 fiscal year. The quarter ended September 30, 2010 average of 34 MW was adversely affected by a July 2010 well pump failure and the 2012 financial year has been affected by a pentane pump failure and associated fire that has affected power generation during the first two quarters.

Under the John Hancock Life Insurance Company (“John Hancock”) loan, the Company agreed to limit power production to the PPA minimum in order to manage reservoir temperature decline. Accordingly, the Company continues to nominate minimum PPA power production, a reduction of 3% per year: 35 MW during 2011 and 33.95 MW for calendar 2012.

Recent modelling of the Blue Mountain reservoir indicates that reinjection of cooled geothermal brine is reducing and will continue to reduce the reservoir temperature more quickly than the initial forecasts due to interference between production and injection wells. Without changes to the current well configuration, plant power production may decrease more than the originally modelled 2.5% per year and more than the PPA allowance of 3% per year. To ensure compliance with the PPA (and John Hancock loan covenants as discussed below) the Company has undertaken an ongoing mitigation program to reduce temperature decline. The mitigation program, which uses funds set aside at the closing of the John Hancock loan, involves distributing injection further from the current production wells using previously drilled wells. The mitigation program, or some future mitigation program, must be successful for the Company to meet the terms of its PPA with NVE (and its John Hancock loan agreement covenants).

In addition, the Company is required to supply a minimum number of portfolio credits (“PCs” which are similar to Renewable Energy Credits (“RECS”)) to NVE during a contract year. Because anticipated calendar year 2011 power production may not meet the Company’s 35 MW nomination under the NVE PPA, the Company may be subject to a PC liability at 2011 calendar year end.

There is no certainty: (i) that the Company will meet the minimum PC commitment for calendar 2011; or (ii) that the Company will always meet the minimum requirements of the PPA, despite the current mitigation program and further distribution of injection. 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 specified market prices and/or incremental production costs) and PC replacement costs. NVE may also elect to terminate the PPA, which could result in a material adverse effect on the Company.

We May Not be Able to Comply with Terms of the John Hancock Loan Agreement

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 factors may result in a covenant breach and/or default of the John Hancock agreement. In the event of 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.

During September 2011, in compliance with the John Hancock loan agreement, the Company and its third party resource and engineering consultants updated the projected Blue Mountain power production forecast and developed a mitigation plan to reduce the rate of reservoir temperature decline, as discussed above, so that the associated power production would decline close to the original forecast of 2.5% per year. The mitigation plan is necessary to maintain compliance with the terms of the PPA and the John Hancock loan covenants for the full term of the agreements. The plan involves re-distributing injection further from current production wells and is currently underway. If the mitigation plan is unsuccessful, by September 2012, a new mitigation plan must be developed and/or the John Hancock loan must be repaid so that the forecast debt service coverage ratio is a minimum of 1.45 for the full loan term. Funding of a new mitigation plan and/or repayment of the John Hancock loan would reduce funds otherwise available to EIG Global Energy Partners (“EIG”).

Unless the Terms of the Loan Agreement with EIG (formerly the Trust Company of the West) Are Revised or Amended, it is Anticipated that We Will Be in Breach of our EIG Loan Agreement.

At June 30, 2010 NGP I owed EIG approximately $164 million, which was paid down to approximately $86 million by September 30, 2010 with the proceeds of the DOE guaranteed John Hancock loan. Given 2011 earnings, permitted interest deferral and the 2009 American Recovery and Reinvestment Act (“ARRA”) grant received in July 2011, the December 31, 2011 loan balance is expected to be approximately $86 million.

Under the John Hancock loan, $8.4 million was set aside in a reserve fund for drilling three additional wells that could be used to inject cool brine further from production wells, facilitating higher power production than the 36.1 MW average nominated in 2010 and reducing the 2.5% per year temperature decline forecast at the time. The additional drilling would complete a program that began following plant start-up and NGP I intended to apply for an ARRA grant related to this program when it was completed. The ARRA $7.9 million grant was received during July 2011, facilitating a further payment to EIG.

While the drilling program increased power output, it did not reach the originally planned 40 plus MW and temperature decline was and is a continuing concern. After drilling two additional wells, rather than three, with the funds set aside at the closing of the John Hancock loan NGP I decided to use the remaining funds to stimulate and connect existing wells to enable a re-distribution of injection fluid. Re-distributing injection (“the mitigation plan”) was and is thought to provide the best chance of increasing power output and decreasing the forecast temperature decline, which now exceeds the projected levels anticipated at the time of the loan closing. The mitigation plan is underway. It is expected to be completed during the first calendar quarter of 2012, followed by testing as quickly as possible. Success is necessary to meet the terms of the John Hancock loan and without success John Hancock has the right to withhold cash that would otherwise be distributed to EIG, to fund either further resource development or pay down the John Hancock loan so that covenants can be met.

Higher power production than the minimum PPA nomination (2012 average supply amount: 33.95 MW, declining 3% per year) requires lender approval and third party engineering reports supporting higher sustainable power production. The PPA with NVE precludes payment of the full contract sales price for power production higher than supply amount plus 5% (2012: 35.65 MW) - meaning a waiver and/or PUC approval of production greater than 35.65 MW is also required to receive the full contract sales price.

Even if the current mitigation plan is successful, NGP I will be unable to meet the terms of the EIG loan (without much higher power production than forecast and/or a reduction of the loan principal). In addition, without a successful mitigation plan, the Company may not meet the terms of its PPA with NVE, nor the John Hancock loan covenants, resulting in even less cash with which to pay EIG. The Company is working with advisors and EIG to develop a plan, possibly including a tax assisted financing and/or investment in additional drilling, to manage the EIG loan. The Company expects to breach the EIG debt service coverage ratio at December 31, 2011 and anticipates difficulty making the minimum interest payment early in 2012. The debt service coverage ratio test was not required under the agreement in previous quarters, but the Company anticipates that the actual ratio as at December 31, 2011 will be below the required 1.4. In the event of a default EIG 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 BM Holdco and NGP I equity.

We May Not Succeed in Our Force Majeure Claim in Respect of the January 2010 Electrical Incident

During the first 2011 fiscal quarter, NVE challenged the Force Majeure claim discussed above (see “We May Not be Able to Achieve Target Power Production at our Blue Mountain Power Plant and, Therefore, Comply with the Terms of the Power Purchase Agreement with NV Energy”), and subsequently deducted $76,698 from a 2011 invoice payment. The Company believes that its Force Majeure claim is valid and that NVE has not substantiated its challenge to the Company’s Force Majeure claim to the Company’s satisfaction. Consequently the claim remains subject to some uncertainty, although the $76,698 has been recognized as an expense in our financial statements for the year ended June 30, 2011.

Our Interest in the Crump Geyser Joint Venture May Be Diluted

The Company and Ormat Nevada Inc. (“Ormat”), a wholly-owned subsidiary of Ormat Technologies Inc. (NYSE-ORA) have entered into a letter agreement and formed Crump Geothermal Company LLC (“CGC”), with each party holding an initial 50% interest in CGC, 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 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 $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. 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, potentially as a result of not meeting ARRA grant requirements, such as the project completion deadline, 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.

We Will Need Additional Capital to Finance Operations Which May Dilute Our Existing Shareholders’ Ownership Interests

The Company will not receive funds, beyond a payment for services provided, from Blue Mountain until the EIG loan is paid down to a target note balance, of approximately $62.3 million at December 31, 2011, and NGP I complies with covenants. In addition, NGP I is subject to certain covenants under the John Hancock loan. Further, 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 and the $2.5 million purchase price, for a number of years. The Company is dependent upon its current cash balance (see “Liquidity and Capital Resources” below) and potential future financings to support corporate operations and property development costs. The Company spends about $1.4 million per quarter on corporate operations.

The Company may not have sufficient working capital to fund its operations for the fiscal year end 2012 and it is unlikely that the Company will receive any funds from its projects. Therefore, it is likely the Company will have to seek additional financing for its operations. Although 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. Further, any additional financing by the Company may subject existing shareholders to substantial dilution. The Company is currently stimulating, connecting and testing additional wells to support higher power production, seeking financing for Blue Mountain, and also continuing a joint venture with Ormat, however there is no certainty that these endeavors will be successful.

Rising Inflation May Reduce or Eliminate Our Potential Profitability

The price escalation provisions in the PPA with NVE may not keep pace with inflation affecting our Blue Mountain power plant’s operations thereby reducing or eliminating NGP I’s potential profitability and increasing the default risk with both John Hancock and EIG.

Project price inflation may affect the return on investment at the Crump project but the Company is partly protected by the low level of its committed investment - $15 million to potentially be borrowed from Ormat.

Our Calculation of Geothermal Resources Are Estimates and May Not Reflect Actual Results

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 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.

Our Development and Operational Activities are Subject to Risks

Our development activities are inherently risky. 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 or operational 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, cash flows 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, cash flows and results of operations.

Our New Truckhaven, Pumpernickel, Edna, East Brawley, North Valley (formerly Black Warrior), South Brawley and Crump Properties Lack Proven Reserves and May Not Be Commercially Feasible

Despite exploration and development work, our New Truckhaven, Pumpernickel, Edna, East Brawley, North Valley, South Brawley and Crump properties do not yet 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 effect on the Company.

Energy price fluctuations May Subject our Operations and Development of Projects to Risks

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 geothermal energy produced from that resource. Factors beyond our control may affect the marketability of any energy produced from 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 renewable production targets, royalties and taxes, as well as allowable production and exporting of energy sources, the effect of which cannot be accurately predicted.

Industry Competition

Significant 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.

Our Projects are Subject to 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 development 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 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.

Our 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, 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 to the environment, and while 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 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.

Our Properties May be Subject to Other Title Claims

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.

Our Business is Dependent on Third Parties

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 Engineering, Procurement and Construction (“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 partner 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 effects on our projects.

In addition, some of our projects require the cooperation of third party leaseholders and/or third parties with related land rights. There can be no assurance of cooperation and this too may prevent our continued operations or cause delays in construction or operations and have other material adverse effects on our projects

Risks Relating to Financial Matters

We Have a History of Losses

Although the Company began operations at Blue Mountain in August 2009 and recognized revenue for the fiscal years ended June 30, 2011, and 2010, the Company has recognized net losses since incorporation and anticipates to continue to experience net losses in the near future. We will not earn sufficient revenue to cover our operating and financing expenses until we increase power production at Blue Mountain, repay more of the EIG loan and/or profitably bring CGC into production. There can be no assurance that our operations will be profitable in the future.

We May Not Have Sufficient Working Capital to Meet Our Cash Requirements for Fiscal 2012 and Will Have to Raise Additional Funds

At June 30, 2011, we had cash and equivalents in the amount of $9,461,451 and working capital of $9,806,358. Approximately $3.0 million was paid to EIG subsequent to year-end, reducing the cash balance.

We may not have sufficient working capital to meet our cash requirements for fiscal 2012, and we are working with our advisors to raise additional funds. In order to conserve cash, we have reduced our expenditures on certain project development and other activities. As a result of this curtailment on the development of certain projects, such curtailment may delay our ability to carry out our business plan. In addition, the raising of additional funds may subject existing shareholders to dilution.

It Is Anticipated That We Will Not Be Able To Meet Our EIG Loan Covenants

The Company must repay the EIG loan and produce at least 40 MW to meet certain loan covenants, particularly the debt service coverage ratio, and remain in compliance with EIG loan terms. Failure to increase power production, which requires both NVE and lender approval and/or failure to obtain additional lower cost funding may result in a default under the terms of the EIG loan agreement (see above - Unless the Terms of the Loan Agreement with EIG (formerly the Trust Company of the West) Are Revised or Amended, it is Anticipated that We Will Be in Breach of our EIG Loan Agreement). In the event of a default, EIG 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 BM Holdco and NGP I equity.

A Further Reduction in Our Power Production Outlook or Other Changes in Circumstances May Result in an Impairment of Our Blue Mountain Assets

If the current mitigation program in unsuccessful, or not as successful as anticipated, this could result in a further reduction in the power production outlook for the Blue Mountain power plant. If power production estimates decrease sufficiently, this may result in an impairment of our Blue Mountain assets, which could be material. Changes in other estimates and assumptions used in our impairment tests, such as discount rates, inflation rates and expected future capital expenditure could also lead to impairment.

We Are Unable To Meet Our 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. As discussed above, we believe that we may not have sufficient capital to meet our cash requirements for fiscal 2012. 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 successful completion of the current mitigation program to meet the terms of the loan with John Hancock, guaranteed by the DOE, and without further drilling, yet to be funded, the project cannot meet the terms of the loan with EIG. As currently projected, we will fail to meet the EIG loan covenants on December 31, 2011 and we may not be able to make the minimum EIG loan payment in early 2012.

The Company is 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 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 US dollar and/or US dollar balances are material. We do not at present, nor do we plan to in the future, 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, 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, Stu Johnson, Kim Niggemann, Max Walenciak and Andrew Studley. Loss of the services of such persons may have a material 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 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 Common 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 funds 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 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 30, 2011 exercisable into 35,582,500 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. This ownership 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 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 Commission 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 was not a PFIC for the taxable year ended June 30, 2010 and will not be treated as a PFIC for the taxable year ended June 30, 2011. 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 treated as a PFIC for the taxable year ending June 30, 2012 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, 2009 or any other 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.

We Do Not Anticipate Issuing 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.

As a foreign private issuer, the Company is subject to different U.S. securities laws and rules than a domestic U.S. issuer, which may limit the information publicly available to U.S. shareholders.

The Company is a foreign private issuer under applicable U.S. federal securities laws and, therefore, is not required to comply with all the periodic disclosure and current reporting requirements of Exchange Act. As a result, the Company does not file the same reports that a U.S. domestic issuer would file with the Commission, although the Company will be required to file with or furnish to the Commission the continuous disclosure documents that the Company is required to file in Canada under Canadian securities laws. In addition, the Company’s officers, directors, and principal shareholders are exempt from the reporting and “short swing” profit rules of Section 16 of the Exchange Act. Therefore, shareholders may not know on as timely a basis when the Company’s officers, directors and principal shareholders purchase or sell common shares, as the reporting periods under the corresponding Canadian insider reporting requirements are longer. In addition, as a foreign private issuer the Company is exempt from the proxy rules under the Exchange Act.

United States Investors May Not Be Able to Obtain Enforcement of Civil Liabilities Against the Company.

The enforcement by investors of civil liabilities under the United States federal or state securities laws may be affected adversely by the fact that the Company is governed by the British Columbia Business Corporations Act, that the some of the Company’s officers and directors are residents of Canada or otherwise reside outside the United States, and that all, or a substantial portion of their assets are located outside the United States. It may not be possible for investors to effect service of process within the United States on certain of the Company’s directors and officers or enforce judgments obtained in the United States courts against the Company, certain of its directors and officers based upon the civil liability provisions of United States federal securities laws or the securities laws of any state of the United States.

There Is Some Doubt as to Whether a Judgment of a United States Court Based Solely Upon the Civil Liability of the United States Federal or State Securities Laws Is Enforceable

Provisions of United States federal or state securities laws may not be enforceable in Canada against the Company, its directors and officers. There is also doubt as to whether an original action could be brought in Canada against the Company or its directors and officers to enforce liabilities based solely upon United States federal or state securities laws.

ITEM 4 Information on the 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."

Corporate head office:

Suite 840 – 1140 West Pender Street, Vancouver, BC, V6E 4G1. Telephone: 604 688 1553

Agents in Nevada:

	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.

Agent in Delaware:

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


2011	We incurred $9,318,959 capital expenditure at the Blue Mountain power plant and $5,208,975 in expenditures that we capitalized as Resource Property Interests in respect of our other properties, including $1,939,022 relating to the acquisition of the Imperial Valley projects (New Truckhaven, East Brawley and South Brawley). There were no material divestitures during the year.
2010	We incurred $32,754,654 capital expenditure at the Blue Mountain power plant and $417,393 in expenditures that we capitalized as Resource Property Interests 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. Acquisition and deferred exploration and development expenditures originally capitalized as Interests in Geothermal Properties at the Blue Mountain Power plant were transferred to Property, plant and Equipment upon completion of the plant during the 2010 financial year. There were no material divestitures during the year.

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, California and Oregon. The Company also evaluates potential electricity generation, if synergistic, from other renewable sources such as wind and solar. 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, electric power.

The Company holds 100% leasehold interests in seven properties: Blue Mountain, Pumpernickel North Valley and Edna, all located in Nevada, and New Truckhaven, East Brawley and South Brawley in California and is also a 50% joint venture partner with Ormat at 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 PPAs and, as long as they are available, fixed price 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: for example the cost of development (drilling) 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, California and Oregon, with Renewable Portfolio Standards (“RPS”) that require 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 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 allow replenishment of 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 (> 400F usually) and binary systems for more moderate temperatures (up to 400F usually). In a "binary system", such as our Blue Mountain plant, geothermal brine is extracted from the underground reservoir and flows under pump pressure 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. The secondary fluid is typically an organic “working” 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. After passing through the closed loop heat exchanger, the geothermal water is injected back into the reservoir, and the organic working fluid is re-used.

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 Blue Mountain geothermal power plant was substantially completed October 9, 2009. Power sales to NVE began during August 2009, when testing began, and drilling and optimization have continued since that time. At start-up the plant operated below the target capacity and well field drilling and optimization were required to increase 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 plans to raise funds for further drilling intended to capitalize on this additional capacity.

Since start-up the Company discovered the Blue Mountain water/brine temperature is declining and injection must be redistributed to keep the temperature decline within reasonable limits. Accordingly, prior to new drilling, the Company has embarked upon a program to connect and stimulate idle wells intended to be used for injection (“the mitigation program”). The Company anticipates completing the mitigation program, using the remaining portion of funds set aside at the John Hancock loan closing, during the second quarter of 2012.

The Company and Ormat have entered into a 50/50 Joint Venture agreement to develop the Crump Geyser property in Oregon in October 2010. Drilling to date has focussed on the extremities of the potential resource to gain an understanding of its potential. Temperatures encountered have been at the lower end of the commercial range (approximately 265 degrees F).

Reference is made to the heading "Property, plants and equipment" under Item 4.D below for further information relating to development of our 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 there have been more prevalent legislative and regulatory incentives such as state renewable portfolio standards, production tax credits and, more recently, ARRA grants.

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.

One factor driving 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. It is in response to an increasing demand for ‘‘green’’ energy that 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 do 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 EPC contracts, particularly Ormat Nevada Inc., who have provided power plant warranties and manufactured certain parts.

Seasonality

Project work in Nevada, Oregon and California, including drilling and other surface surveys can be conducted at any time of year. Winter weather can be cold, but precipitation is low and snow does not accumulate significantly. Topography is moderate. There has been flooding in the past at our Oregon property. If it recurs, it could impede work.

Operations typically produce less electricity during the hotter summer months when cooling water is warmer and the temperature drop across the turbines is lower.

Blue Mountain Power Plant

On August 18, 2006, our wholly-owned subsidiary Nevada Geothermal Power Company, entered into a long-term portfolio energy credit and renewable power purchase agreement (later assigned to our NGP I 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 EIG 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 EIG loan it cannot meet the loan agreement interest coverage covenant. EIG waived the penalty in favour of a 2% fee when the loan was partially repaid during the third calendar quarter of 2010. In November 2011 the loan was further repaid with proceeds of a $7.9 million cash grant received during July 2011. The Company is highly dependent upon paying down the EIG debt and covering the EIG interest payments since EIG is secured by the Company’s equity interest in BM Holdco and NGP I.

At Blue Mountain, with wells drilled to date, modelling predicts the current configuration will cool the resource, reducing power production. As a result, until the current mitigation program and/or additional drilling (to be funded) demonstrates higher sustainable power production the PPA and John Hancock covenants are at risk. And even if the mitigation program is successful John Hancock requires lower power nomination (3% per year) and supply to NVE annually to ensure PPA compliance over the term of their loan.

The PPA with NVE precludes an increase in power nomination, beyond 3% per year, so in addition to successful drilling and lender approval, the Company requires NVE and/or Nevada PUC approval to increase power production substantially. The Company is highly dependent upon increasing power production and/or reducing the EIG loan balance, for example by raising tax assisted funds, to lower its cost of capital. The Company believes it has strong working relationship with EIG and has engaged an advisor to help develop different EIG loan terms. Strong relationships with all of NVE, EIG, John Hancock and DOE continue to be essential.

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 PPA, 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, 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 hydro-electric 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) 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. In 2011, FERC granted petitions by the three major California investor-owned utilities, Southern California Edison Company, San Diego Gas & Electric Company and Pacific Gas & Electric Company, to terminate their mandatory Qualifying Facility 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. Our projects under development in Nevada are not 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. We have not identified the specific utilities to which our projects under development in California are planned to sell power.

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 (“PUHCA”) was 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 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 Administrative 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.

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” of 2.1 cents per kilowatt hour is adjusted annually for inflation over a 10-year production tax credit period beginning on the placed-in-service date.

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 and following additional drilling the Company received an additional $7.9 million during July 2011.

The Company is aware of efforts to extend the PTC and the 30% ITC/Cash grant to 2016, without which geothermal projects are eligible for a 10% ITC. We understand an extension requires the approval of the US Congress.

C. Organizational Structure

As of November 30, 2011, we have the following wholly-owned subsidiaries:

	1.	Blue Mountain Power Company Inc. (formerly Powertec Development Company Ltd.), a company incorporated in the Province of British Columbia, Canada;
	2.	Desert Valley Gold Co., a company incorporated in the State of Nevada;
	3.	NGP Chile S.A., a company incorporated in Chile;
	4.	Nevada Geothermal Power US Holdings Inc., a company incorporated in the State of Nevada.
	5.	Nevada Geothermal Power Company (‘‘NGPC’’), formerly Noramex Corp., a company incorporated in the State of Nevada;
	6.	Nevada Geothermal Operating Company LLC, a limited liability company formed in the State of Delaware;
	7.	Nevada Geothermal Power Holding Company LLC, a limited liability company formed in the State of Delaware;
	8.	NGP Blue Mountain Holdco LLC (“BM Holdco”), a limited liability company formed in the State of Delaware;
	9.	NGP Blue Mountain I LLC (“NGP I”), a limited liability company formed in the State of Delaware;
	10.	NGP Blue Mountain Holdco II LLC, a limited liability company formed in the State of Delaware;
	11.	NGP Blue Mountain Holdco III LLC, a limited liability company formed in the State of Delaware;

	12.	NGP Blue Mountain Holdco IV LLC, a limited liability company formed in the State of Delaware;
	13.	NGP Blue Mountain II LLC, a limited liability company formed in the State of Delaware;
	14.	NGP Blue Mountain III LLC, a limited liability company formed in the State of Delaware;
	15.	NGP Blue Mountain IV LLC, a limited liability company formed in the State of Delaware;
	16.	NGP North Valley Inc, a company incorporated in the State of Nevada;
	17.	NGP (Crump I), a company incorporated in the State of Nevada;
	18.	NGP (Pumpernickel I), a company incorporated in the State of Nevada;
	19.	Nevada Geothermal Power East Brawley LLC, a Delaware limited liability company;
	20.	Nevada Geothermal Power South Brawley LLC, a Delaware limited liability company; and
	21.	NGP Truckhaven LLC, a Delaware limited liability company.

In addition, we hold a 50% interest in Crump Geothermal Company LLC (“CGC”) a limited liability company formed in the State of Delaware.

D. Property, Plants and Equipment

Executive Offices

We rent approximately 6,173 sq. ft. of executive and administrative office space, located at Suite 840-1140 West Pender Street, Vancouver, B.C., Canada V6E 4G1, for the average sum of CAD 15,661 per month. Our lease expires in May 2016.

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 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 $3,853 US per month.

Area of Interest and Interests Held

NGPC, 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 as follows:


NGP Blue Mountain I LLC	Blue Mountain project
NGP (Pumpernickel I)	Pumpernickel project
NGP North Valley Inc	North Valley project
Nevada Geothermal Power Company	Edna Mountain project
NGP Truckhaven LLC	New Truckhaven project
Nevada Geothermal Power East Brawley LLC	East Brawley project
Nevada Geothermal Power South Brawley LLC	South Brawley project

NGP (Crump I) holds a 50% interest in Crump Geothermal Company LLC, which holds the Crump Geyser project.

The Federal Bureau of Land Management ("BLM") is empowered to grant lease rights on federal lands. We have federal geothermal leases in Nevada and California. In Oregon, the Department of State Lands has granted Crump Geothermal Company LLC leases on state lands. Leases on private lands are contracted with the owner of the geothermal resource/minerals. The Nevada Land and Resource Company, LLC ("NLRC") grants leases covering patented lands, while other lessors such as Arie H. De Jong Family Trust, Atkinson et al., Blue Mountain Research & Development LLC, Burlington Northern Santa Fe ("BNSF"), JHG, LLC c/o Will DeLong ("DeLong"), Jordan et al., 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"), Pon et al., Rutherford Family Trust, Salton Sea Energy, SF Pacific, and Smith Brothers Geothermal, LLC have granted leases to us on private lands.

Most leases also grant surface rights, and some leases also grant water rights.

BLUE MOUNTAIN PROJECT

LOCATION

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 18 square miles (11,145 acres). The Company holds a 100% geothermal mineral interest and is entitled to explore, develop, and produce any geothermal resources located on the leased properties. Blue Mountain power is transmitted 33 km (21 miles) on a company-owned power line to 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, Blue Mountain road leads north off Jungo Road, about 5.5 km (3.5 miles) to the site.

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 4,319 acres.

Particulars with respect to the Blue Mountain leases are as follows:


	Owner	Lease No.	Sections	Acreage	Effective Date	Expiry Date

1	BNSF	187556	15, 23	1,280.00	March 1, 1994	February 28, 2014
2	NLRC	189093	1, 11, 25, 27, 35	3,333.48	March 31, 2003	March 30, 2013
3	BLM	N58196	14	663.36	April 1, 1994	March 31, 2044
4	BLM	N77668	10, 12, 22, 24, 26	3,297.94	August 1, 2004	July 31, 2014
5	BLM	N80086	16	650.32	August 1, 2006	July 31, 2016
6	BLM	N80159	28	640.00	August 1, 2006	July 31, 2016
7	Crawford	Private	21	640.00	January 10, 2006	January 9, 2016
8	Blue Mountain Research and Development LLC	Private	13	640.00	March 31, 2003	March 30, 2013
	Total			11,145.10

Blue Mountain water and surface access:
9	JHG,LLC (DeLong)	Private-Surface only	27	640.00	August 27, 2009	August 26, 2029

1. BNSF Lease No. 187556

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 a 1.5% royalty 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 also committed to pay the following royalties to BNSF:

- 3% of the gross proceeds for geothermal energy used for electric or non-electric purposes.

- 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 $5,118, representing $2.00 per acre for each acre that comprised the original lease. The lease was kept in good standing by:

- 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; and
	iii.	On the seventh anniversary and each anniversary that follows: $6.00 per acre plus a 3% increase in the rental payments annually.

- 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.

We were committed to pay the following royalties to NLRC:

- 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 issued 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

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.

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 issued there-under in 2007.

6. BLM Lease No. 80159

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:

- 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:

- 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.

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.

Effective May 6, 2011 RLF Nevada Properties, LLC assigned all its right, title and interest to Blue Mountain Research and Development LLC, this included Geothermal Lease Agreement #189093. Previously, effective October 3, 2006, RLF Nevada Properties, LLC had purchased Section 13 of Lease No. 189093 from the NLRC, which maintained the Company’s lease agreement terms including the effective date of this lease as at March 31, 2003.

-	Pay Blue Mountain Research and Development LLC 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.

If in any year, we do not fulfill the work commitments, we must pay Blue Mountain Research and Development LLC 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 Blue Mountain Research and Development LLC.

We are committed to pay the following royalties to Blue Mountain Research and Development LLC:


	-	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;
	-	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;
	-	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.

Through the original NLRC option (see NLRC lease, above) we had the option to purchase this royalty at any time not later than 6 months following the commencement of commercial production. NGP exercised this option and purchased the royalty in 2009.

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 (BLM) approved this agreement, with the above mentioned effective date, on September 8, 2006. A Participating Area boundary has been defined within the unit, within which royalties are paid. While the unit is effective, work requirements for acreage within units are met by qualifying expenditures or commercial production anywhere 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 Blue Mountain Research and Development LLC, the Bureau of Land Management (“BLM”), Burlington Northern Santa Fe (“BNSF”), Nevada Land and Resource Company (“NLRC”), Crawford and DeLong Ranch. The Company holds a 100% geothermal mineral interest and is entitled to explore, develop, and produce any geothermal resources located on the properties.

On October 10, 2009, the Company declared substantial completion of its power plant at Blue Mountain and began supplying energy to NV Energy (“NVE”) under a 20-year Power Purchase Agreement (“PPA”). Current modeling suggests that plant inlet temperatures will gradually decline over time without changes to the wellfield operation. The predicted temperature decline results from injection wells that are too close to production wells to provide time to re-heat recycled brine. The solution is more distributed injection and injection further from the current production wells.

To date six commercial production wells have been drilled: 14-14, 15-14, 17-14, 23-14, 25-14 and 26A-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). A pump is not currently set in well 15-14, and it remains on standby as an emergency back up production well. A seventh production well (44-14), was stimulated using propellant during the 2011 financial year but is not capable of commercial production or suitable for use as an injector, due to marginal permeability.

Seven deep injection wells have been drilled to date: 58-11, 38-14, 55-15, 57-15ST1, 58-15, 91-15 and 61-22ST2 ranging from 1410 – 2548 m (4627 – 8359 ft). Six of these, namely 58-11, 55-15, 57-15ST1, 58-15, 91-15 and 61-22ST2 are currently in use. Two shallow injectors 58A-15 and 58B-15 intersect 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. Despite this, injection into 58A-15 commenced in early November 2011 at a rate of 600gpm as the benefits from this are expected to outweigh the risks.

During the 2011 financial year, NGP I completed drilling of two injection test wells to the south of the production field (wells 86-22 and 34-23). Unfortunately the wells showed only marginal permeability associated with a weak thermal zone and are not connected to the plant at this time. As a next step, the Company started a program of wellfield optimization, testing and stimulation. Wells 86-22 and 38-14 were stimulated during the final quarter of the 2011 financial year and the permeability modestly improved at well 38-14, making it a candidate for re-allocated injection.

The Company, together with its resource consultants, have incorporated new well data, current test results and field operating history into an updated reservoir model, and have developed a mitigation plan to further re-distribute injection and reduce the rate of temperature decline. Funds set aside at the time of the John Hancock financing are being used for this work.

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.

From 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 replacement 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 settlement regarding this incident was reached during the quarter ended September 2010, and $1.0 million is included in revenue for the 2011 financial year relating to this settlement. The settlement consisted of a cash payment of $1 million, power plant spares and extended warranties. A Force Majeure event was declared for the period from January 16, 2010 to March 5, 2010. In November 2010, during a planned outage, Ormat replaced other potentially damaged equipment.

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. The PPA minimum power nomination for the calendar year ended December 31, 2010 was 36.1 MW (net). The Company nominated 3% less, 35 MW (net), for the calendar year ending December 31, 2011.

During the year ended June 30, 2011, the Blue Mountain power plant produced an average of 34.6 MW (net). This decreased to 30.0 MW (net) during the quarter ended September 30, 2011, since power production is normally lowest during the warmer months of the year (May-September) due to decreased plant efficiencies, and an auxiliary pump failure and resulting localized fire shut down production from one of the plant’s three power units for six weeks during September and October 2011.

Financing for the Blue Mountain project is comprised of approximately $91.7 million senior debt provided by John Hancock to NGP I and a mezzanine loan, with a balance as at September 30, 2011 of approximately $91.3 million, provided by EIG Global Energy Partners (“EIG”) to NGP I’s holding company, BM Holdco. The John Hancock loan is supported by a United States Department of Energy (“DOE”) Financial Institutions Partnership Program (“FIPP”) guarantee. The FIPP program, supported by the 2009 ARRA is designed to facilitate long term financing for renewable energy development projects using commercial technology and applies to up to 80% of the loan amount. The EIG loan is repaid to the extent that there are cash flows available after servicing the John Hancock loan, and accordingly carries an interest rate of 14% compared to 4.14% for the John Hancock loan.

As of the second calendar quarter 2009, the Company was not in compliance with certain terms of its loan agreement with EIG, principally due to project costs exceeding budgeted amounts. During November 2009 the Company agreed to give EIG 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.

Current resource forecasts predict that BM Holdco will not be able to service the EIG loan for the full loan term with the cash that will be available for distribution to BM Holdco after servicing the John Hancock loan. BM Holdco anticipates breaching the EIG debt service coverage ratio (“DSCR”) covenant at December 31, 2011. The reduction in plant revenue caused by the pump failure during September, has reduced the cash available to make EIG’s minimum required interest payment for the next quarter placing the minimum payment at some risk. EIG is not expected to declare a default under the loan but if the loan is placed in default it could result in the loss of the Group’s equity interest in the Blue Mountain project.

NGP I is the beneficiary of grants of approximately $65.7 million awarded by the US Treasury under the 2009 American Recovery and Reinvestment Act (“ARRA”), a program that augmented production tax credits that were difficult to monetize following the financial crisis. Approximately $7.9 million of the US Treasury grant was received during July 2011.

Capital spending on the Blue Mountain project, excluding the effect of government assistance and the Ormat settlement, amounted to $9,318,959 during the 2011 fiscal year.

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.

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 Utility Environmental Protection Act (“UEPA”) permit was first submitted in November 2006, to the Public Utilities Commission of Nevada ("PUCN") and a full application followed, after 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 Nevada Division of Environmental Protection, Bureau of Water Pollution Control for an Underground Injection Control Permit was made in December 2006. The permit was issued March 20, 2008. Subsequent permit modifications and additions of injection wells have been approved in July and October, 2009, June and October 2010, and in February and July, 2011.

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. 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.

7.	On October 21, 2009, 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).

A Unit “Participating Area” (N-82457-01) was approved by the US Bureau of Land Management (“BLM”) 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. In February 2011 NGP applied to BLM to expand the PA to encompass new injection wells and to update the Unit lease and royalty documentation. BLM approval is pending as of December 2011.

PUMPERNICKEL PROJECT

The Group holds private and federal geothermal leases comprising a total holding of 11 square miles (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 and a right of first offer to supply Pumpernickel power plant equipment, and 129 hectares (320 acres) under four private leases.

LOCATION

Our Pumpernickel project is located in north-central Nevada, east of Winnemucca, in Humboldt County. The property is accessible year round traveling from Winnemucca via Interstate Highway I-80, about 20 miles (33 km) east to Golconda, then due south of Golconda about 8 miles (13 km), on Pumpernickel Valley Road, a well-maintained county gravel road 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, 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 Date

1	Newmont	29-462-0003	3, 5, 9, 27, 33	3,150.85	February 13, 2004	February 12, 2014
2	BLM	78124	10, 28, 34	1,898.06	June 1, 2006	May 31, 2016
3	BLM	80070	32	640.00	August 1, 2006	July 31, 2016
4	BLM (Ormat/Ehni)	74855	N ½ 4, 8	933.50	October 1, 2002	September 30, 2012
5	Hot Springs Ranch (Johnson, Hill, Danner, Bear)		S ½ 4	320.00	October 15, 2008	October 15, 2018
	TOTAL			6,942.41

1. Newmont Mining Corporation Lease No. 29-462-0003

To keep this lease in good standing, we must:

-	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:


	-	3.5% of the gross proceeds of the sale of electric power, less taxes and transportation costs;
	-	5% of the gross proceeds of the sale of geothermal substances in arm’s length transactions, less taxes and transmission costs;
	-	2% of the gross proceeds of the sale of any by-products, less taxes and transportation costs;
	-	10% of the net profits produced from the use of geothermal substances at a commercial facility other than an electric power plant.

2. BLM Lease No 78124

In October 2009, the lease terms and royalty provisions were elected to convert under 43 CFR 3200.8(b) (1) (2) 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.

3. BLM Lease No 80070

4. BLM (Ormat/Ehni) N74855

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 Nevada Power Company, Ormat and Ehni Enterprises, Inc., we are required to pay Ehni:


	-	$10,000 within ten business days of entering into a power purchase agreement with respect to this lease; and
	-	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:


	-	$50,000 upon approval of the Public Utilities Commission of Nevada ("PUCN") of a PPA for the Lease or Unit;
	-	a further $50,000 upon issuance of a UEPA Permit to construct the project by the PUCN; and
	-	a further $100,000 when the project begins commercial power production under the PPA.

5. Hot Springs Ranch (Johnson, Hill, Danner, Bear)

This lease was entered between into among NGP and four 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). The four groups of lessors together own the geothermal/mineral rights and Roger and Nancy Johnson own the surface of the 320 acres of land.

To keep these leases in good standing, NGP is required to make annual rental payments in advance of the anniversary, in proportion to the interest of each group of lessors, during the term of the lease:


Year	1/3 Interest	1/6 Interest	100% Interest
1	$ 3,420	$ 1,710	$ 10,260
2	4,020	2,010	12,060
3	4,620	2,310	13,860
4	5,220	2,610	15,660
5	5,820	2,910	17,460
6	12,420	6,210	37,260
7	13,020	6,510	39,060
8	13,620	6,810	40,860
9	14,220	7,110	42,660
10	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 at either one-third or one-sixth of the rate set out below to each group of lessors:


Royalty Rate	Price per kilowatt hour
3.5%	Less than or equal to $0.086
4%	Greater than $0.086 to less than or equal to $0.121
5%	Greater than $0.121

b)	Royalty is paid equal to either one-third or one-sixth of five percent (5%) of the gross proceeds (which excludes 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-third or one-sixth of 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-third or one-sixth of 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 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.

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. Additionally, the site is located in an area of reasonably well-developed infrastructure with no apparent environmental issues.

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 DOE, 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 channelled to the surface via range bounding faults, such as the Pumpernickel fault.

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.

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.

Previous mineral exploration drill holes recorded thermal gradients of up to 283°C/km. 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). 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). Current drilling targets are expected to be in the 170°C (338°F) range.

Drilling corroborates earlier studies indicating geothermal fluids are being channelled 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 Division of Water Resources during October 2010. Phase I and II Transmission Interconnection Studies are complete and the Company is in the queue for necessary transmission rights. In late 2010 construction of a development well pad was completed and conductor casing was installed in the wholly private, south half of section four. Work has been ongoing in preparation for future drilling, including preparing plans of operation. A DOE grant was successfully transferred from North Valley to Pumpernickel Valley, and work under the grant has commenced with planning and preparation for cultural and biological surveys, which will lead to permitting activities and National Environmental Policy Act (“NEPA”) review, including biological and archaeological/cultural surveys. These initial permitting requirements are expected to lead to sub-soil gas sampling by approximately mid 2012.

A total of $269,710 was expended on our Pumpernickel project during the 2011 fiscal year.

PERMITTING

The following is a summary of the primary permits required for the Pumpernickel project:

1.	A Plan of Exploration is under development. After a pre-application meeting with BLM, cultural and biological block surveys will be conducted and a NEPA review initiated and anticipated to be completed on about 10 alternate drillsites in 2012.

2.	Drilling permits are issued by the Nevada Division of Minerals and, if on federal lands, the BLM.

3.	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 Division of Water Resources in October 2010.

4.	For a power plant, development wells and the transmission line, permits and additional NEPA review will be required, as well as transmission line easements and rights of way on federal and private lands.

5.	The power plant and transmission line will also require the same set of permitting actions listed above under Blue Mountain.

NORTH VALLEY

The Company has a total of 10 square miles (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 is via Interstate 80 from Fernley east to Exit 65 at Brady's Hot Springs, then about 23 miles (37 km) on an unpaved road west of the Nightingale Mine area, turning north at the DC transmission line road.

NORTH VALLEY LEASES

North Valley leases, which include surface and, on the NLRC leases, water rights, are as follows:


	Owner	Lease No.	Sections	Location	Acreage	Effective Date	Expiry Date

1	NLRC	189099	T23N, R24E: 1, 3, 5, 7, 11, T2N, R24E: 29, 31, 35	Washoe Co. and Churchill Co.	5,066.69	August 1, 2004	July 31, 2014
2	BLM	79745	8	Churchill Co.	640.00	March 1, 2006	February 29, 2016
3	BLM	78777	30	Churchill Co.	566.40	March 1, 2006	February 29, 2016
	TOTAL				6,273.09

1. NLRC Lease No. 189099

This lease was granted for consideration of $8,853, representing $2.00 per acre for each acre that comprised the original lease. To keep the lease in good standing, we must:

-	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.

- 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 are committed to pay the following royalties to NLRC:

- 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 property

- 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;

- 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.

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

In October 2009 the lease terms and royalty provisions were elected to convert under 43 CFR 3200.8(b) (1) (2) 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.

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, Salt Wells, 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 (10 miles) west, or 19 km (12 miles) 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 in July 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. 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.

A well pad has been graded and minor improvements to a short section of road have been completed. Right of way approval was granted by the BLM in July 2011 and a thermal gradient observation well was completed during August 2011, intersecting intensely altered, layered and faulted volcanic rocks and a subsurface temperature gradient of 285ºC/km. 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.

On October 29, 2009, the Company was awarded approximately $1.6 million from the DOE under the ARRA for the North Valley geothermal project under a program calls for cost sharing grants on exploration and drilling work. This grant was subsequently transferred to the Pumpernickel Valley project.

A total of $107,996 was expended on our North Valley project during the 2011 fiscal year, after the application of DOE funding of $13,713.

PERMITTING

The following is a summary of the primary permits required for the North Valley project:

1.	A drilling permit was obtained from the Nevada Division of Minerals for well 25-31. Future drilling will require the same and also, if on federal lands, from the BLM.

2.	As required by the Churchill County Geothermal Ordinance, a letter notification of the drilling of well 25-31 was made to the Churchill County Planning Department.

3.	For additional exploration/reservoir confirmation drilling, for a power plant, development wells and for the transmission line, additional permitting and NEPA reviews will be required, as well as transmission line easements and rights of way on federal and private lands.

CRUMP GEYSER (Joint venture)

During the 2011 financial year, the Company and Ormat Nevada Inc. (“Ormat”), formed a 50/50 joint venture company, Crump Geothermal Company LLC (“CGC”), for the development of the Crump Geyser project. Leases totalling 11 square miles (7,205 acres) of private land were transferred to the joint venture during October 2010. The private leases are subject to a 3.5% royalty of gross revenues from the sale or use of electricity. Additional state land leases totalling 24 square miles (15,389 acres) were acquired by CGC during the quarter ended September 30, 2011.

LOCATION

The Crump Geyser property is a hot spring system located in Warner Valley, Lake County, north of Adel, Oregon, 53 km (33 miles) east of Lakeview Oregon, and 287 km (178 miles) 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 miles) to the west on Highway 140 at Adel.

CRUMP GEYSER LEASES

Crump Geyser Leases, which are held by CGC, (in which NGP has a 50% interest) are as follows:


	Owner	Acreage	Effective Date	Expiry Date
1	Oregon State Lands	15,388.99	July 5, 2011	July 4, 2021
2	LX Ranch	5,000.00	August 1, 2005	July 31, 2015
3	O’Keeffe Ranch	733.36	August 1, 2005	July 31, 2015
4	Stabb Trust	1,471.84	August 1, 2005	July 31, 2015

1. Oregon State Lands

This lease was acquired by Crump Geothermal Company LLC in 2011. The primary term of this lease shall be 10 years from the effective date. Upon payment of annual commercial production royalties in an amount equal to the annual rental due under the lease, the lessee may renew for subsequent ten year periods upon application.

To keep this lease in good standing we must make the following rental payments each year in advance:

- Years 1-3: $1.00/acre

- Year 4: $3.00/acre

- Year 5 and each year thereafter: $5.00/acre

We are committed to paying the lessor the following royalties:

- 1% on the value of commercially demineralised water.

- 5% on the value of any by-product except water derived from production under this lease.

- 10% royalty based on the gross purchase price for the value of all geothermal steam, hot water, or power generating gases sold.

LX Ranch, O’Keeffe Ranch, and Stabb Trust were assigned by NGP (Crump 1) to CGC 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:

- for two additional extension terms of five 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 years each on the express conditions that Geothermal Resources 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 consecutive months.

To keep all the leases in good standing we must:

- 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.

- 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’Keeffe Ranch and Stabb Trust:

- 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;

- 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;

- 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.

If LX Ranch, O’Keeffe 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:

- $600 per acre, per year for productive crop land;

- $300 per acre, per year for pasture land; and

- $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 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). Northwest Wildlife Consultants also completed a preliminary wildlife survey of the Crump Geyser project area, determining that there are no endangered species that would prohibit development. That determination was confirmed in a 2010 biological survey of well sites by Rabe Consulting.

From November, 2005 until the end of 2007, NGP conducted geophysical field studies and developed plans for drilling, including Schlumberger electrical resistivity 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.

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).

On October 29, 2009, the Company was granted approximately $1.8 million in cost share funding for the Crump Geyser project by the DOE. The grant reimburses approximately 50% of qualifying expenditures, with phase I expenditures reimbursed at 80% and later expenditures at a lower rate. 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. In 2010 and 2011, biological and cultural surveys and a NEPA review by the DOE were completed for well sites in the upland and wetland, with wetland site drilling authorization pending approval of a removal fill permit application from the Army Corps of Engineers and Department of State lands. Quarterly water quality samples have been collected from groundwater wells and from Crump and Pelican Lakes and analyzed by independent laboratories to create baseline data on groundwater quality.

A development test well completed to 5,000 feet in early 2011 has undergone production and injection tests. It encountered temperatures at the lower end of the commercial range (maximum temperature 130ºC, 265ºF), and intersected permeability that may allow it to be used for injection. A Phase I report has been approved by DOE, and approval to move to Phase II cost-shared drilling has been granted. Ormat, the CGC operations manager, completed the first exploration well (well 38-34) to 3000 feet in June 2011. A second well (35-34), partially funded through the DOE program, was completed during October 2011 and is undergoing evaluation and well testing. A third slim well site has been permitted and may be drilled in conjunction with the DOE program. Four well sites are also in the process of receiving approval from the Oregon Department of Geology and Mineral Industries (“DOGAMI”), the Army Corps of Engineers and Oregon Department of State Lands for sites determined to be in a wetland. Additionally, a “push-core” shallow temperature survey of approximately 10 sites down to approximately 100 feet depth has been completed to better define the reservoir extent and support well siting.

In October 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 contributed 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 is funding 100% of the initial development activities of CGC in the amount of US$15 million and pay NGP US$2.5 million in instalments over a three year period, of which $300,000 has been received. 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.

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 thickness of 760 to 1,680 m (most-likely 1,070 m), and average reservoir temperature 140 to 160°C (most-likely 150°C or 302°F).

The Company’s interest in spending on the Crump Geyser project amount to $2,319,821 during the 2011 fiscal year after the application of $309,324 in DOE funding.

PERMITTING

The following is a summary of the primary permits required for the Crump project:

1.	DOGAMI Prospect Well and Geothermal Well permits were issued in 2010 and 2011.

2.	DOGAMI sets construction standards for the sump in the drilling permit, and the Department of Environmental Quality (DEQ) sets groundwater protection and requires a Solid Waste Disposal Permit.

3.	In October 2010, a wetlands delineation for the valley floor was submitted to DOE, Oregon State Lands and the Army Corps of Engineers by the Company. In 2011, after approval of the delineation, CGC submitted a removal/fill permit application for drill sites on the valley floor. Oregon State Lands has issued draft conditions and the application is pending approval by the Army Corps of Engineers.

4.	In 2010, NGP and landowners Stabb and O’Keeffe obtained from the Oregon Water Resources Department (WRD) a Limited Water Use License authorizing use of existing water wells for drilling operations. That permit application included a Water Availability Statement signed by the local Watermaster and a Land Use Compatibility Statement signed by the Lake County Planning Department. The right was transferred to CGC in 2011.

5.	If a commercially developable resource is confirmed, a new set of applications for permits will be submitted to the agencies for the drilling of development production and injection wells, and power plant construction. Plants under about 38.8 MW will require Lake County permitting. Plants over about 38.8 MW must go through a siting process by the Oregon Department of Energy, Energy Facility Siting Council.

EDNA MOUNTAIN

The Company leases, at Edna Mountain, cover an 11 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 Date

1	BLM	N88435	T34N R41E: 4, 6, 8	2,022.16	June 1, 2010	May 31, 2020
2	BLM	N88436	T34N R 41E: 16, 18, 20, 30	2,490.52	June 1, 2010	May 31, 2020
3	BLM	N88437	T35N R41E: 26, 28, 32, 34	2,560.00	June 1, 2010	May 31, 2020
	Total			7,072.68

1. BLM Leases N88435, N88436 & N88437

As a competitive lease, in its primary term the Company is required to make rental payments of $2.00 per acre in the first year. 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 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 implementing an exploration strategy. During the quarter ended September 30, 2011, an exploration program commenced with a two-metre temperature survey to map the shallow thermal anomaly, which will enhance our understanding of the distribution of fluid flow on the property. Data from the survey is currently being processed and interpreted. Further work planned includes detailed geological mapping, geophysical surveying and thermal gradient drilling.

The balance capitalized in respect of the Edna Mountain project was reduced by $10,467 during the 2011 fiscal year.

PERMITTING

The following is a summary of the primary permits required for the Edna project:

1.	Drilling permits are required by the Nevada Division of Minerals and, if on Federal lands, the BLM.

2.	For a power plant, development wells and the transmission line, permits and additional biological and cultural surveys and NEPA reviews will be required, as well as transmission line easements and rights of way on federal and private lands.

NEW TRUCKHAVEN

During the 4^thquarter of the 2011 financial year the Company purchased three properties, including New Truckhaven, in California’s Imperial Valley from Iceland America Energy (“IAE”) for approximately $680,000 cash and 6,074,069 shares.

LOCATION

The Company acquired Federal and private leases covering a 9.3 square mile (5949 net mineral acres) parcel of land in the Imperial Valley, California from IAE during the second calendar quarter of 2011. The property is located on the west side of the Salton Sea in a largely undeveloped area accessible by Highway 86 and intersected by an Imperial Irrigation District transmission line.

NEW TRUCKHAVEN LEASES

Particulars with respect to our New Truckhaven leases are as follows:


	Owner	Lease No.	Sections	Acreage	Effective Date	Expiry Date

1	Atkinson et al.	N/A	T11S R10E: 5 (part) T10S R10E: 32 (part)	0 surface 2.36 minerals	February 8, 2002	February 7, 2012
2	Bureau of Land Management	CACA-3302	T11S R10E: 18	650.96	October 1, 2009	September 30, 2019
3	Bureau of Land Management	CACA-3003	T11S R9E: 2, 12	1281.32	October 1, 2009	September 30, 2019
4	Pon et al.	N/A	T11S R10E: 7, 9 (part), 15 (part), 17	2222.52 surface 1902.52 minerals	March 26, 2011	March 25, 2014 (primary term) March 25, 2021 (secondary term) March 25, 2027 (second extended term)
5	Salton Sea Energy	N/A	T11S R10E: 5 (part)	189.82	February 8, 2002	February 7, 2012
6	SF Pacific Properties	N/A	T11S R9E: 1, 3, 11	0 surface 1922 minerals	April 1, 2006	March 31, 2012

1. Atkinson et al.

This lease was purchased from Iceland America Energy in the 4^thquarter of 2011. This lease includes geothermal rights to the lands and includes all land lying more than fifty (50) feet below the surface. The primary term of the lease shall be for a term of five (5) years from the effective date. The lessee may extend the primary term of the lease from five (5) years to ten (10) years by paying the lessor a bonus of $100.00 per acre prior to expiry of the primary term. The bonus to extend the primary term of the lease to ten (10) years was paid in February 2007. The lease will be in effect so long as substances are produced in commercial quantities from any of the lands. There are no annual fees or rentals due to the lessor.

We are committed to pay the lessor the following royalties:

- 2% of the sale of any by-products

- 3% of the gross proceeds of the sale of electric power produced by binary technology

- 3.5% of the gross proceeds of the sale of electric power produced by flash technology

- 4% of the gross proceeds of the sale of electric power produced by dry steam technology

- 10% of the sale of any substance used or sold to a commercial facility other than an electric power generating facility

2. BLM Lease CACA-43302

This lease was purchased from Iceland America Energy in the 4^thquarter of 2011. 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.

3. BLM Lease CACA-43302

4. Pon et al.

This lease was purchased from Iceland America Energy in the 4^thquarter of 2011. The Primary Term commenced on the Effective Date (March 26, 2011) and shall expire four (4) years after the effective date. If at the time of expiration of the Primary Term the Lessee has completed at least one new geothermal development well on the Property, then the Primary term shall be extended for an additional six (6) years (the First Extended Term). If, due to issues with permitting/approvals from the State of California, the lessee is unable to drill on lessors’ land, the lessee may elect to satisfy the Primary Term drilling obligations by completing a new geothermal development well on an adjacent property. At the time of expiration of the First Extended Term, the First Extended Term shall be extended for an additional six (6) years (the Second Extended Term) upon payment of the additional annual Rentals. If on or before the end of the Second Extended Term resources are continuously being produced in commercial quantities, this agreement shall continue for so long as resources are continuously commercially produced.

To keep the lease in good standing we must pay the following rentals annually in advance:

- Primary term: $21.10 per Net Subsurface Acre, without adjustment for CPI

- First Extended Term: $24.00 per Net Subsurface Acre, years 6-10 adjusted for changes in CPI

- Second Extended Term: $24.00 per Net Subsurface Acre, years 11-16 adjusted for changes in CPI

Upon sale or use of the resources from the lessors’ property in commercial quantities the rental payment obligations will terminate immediately. Royalty payments shall not be less than the amount of the annual rental payments that were in effect as of the date that resource commenced to be produced in commercial quantities.

We are committed to paying the following royalties to Pon et al.:

- 3.5% of the gross revenues received from the sale of electric power generated from binary technology

- 4% of the gross revenues received from the sale of electric power generated from flash technology

- 10% of the gross proceeds from the sale of unprocessed resources

- 10% for resources used at a commercial facility for direct heat exchange

- 12.5% of the gross value received from the sale of hydrocarbon resources

5. Salton Sea Energy

This lease was purchased from Iceland America Energy in the 4^thquarter of 2011. The primary term of the lease shall be for a term of five (5) years from the effective date. The lessee may extend the primary term of the lease from five (5) years to ten (10) years by paying the lessor a bonus of $100.00 per acre prior to expiry of the primary term. The bonus to extend the primary term of the lease to ten (10) years was paid in February 2007. The lease will be in effect so long as substances are produced in commercial quantities from any of the lands. There are no annual fees or rentals due to the lessor.

We are committed to pay the lessor the following royalties:

- 2% of the sale of any by-products

- 3% of the gross proceeds of the sale of electric power produced by binary technology

- 3.5% of the gross proceeds of the sale of electric power produced by flash technology

- 4% of the gross proceeds of the sale of electric power produced by dry steam technology

- 10% of the sale of any substance used or sold to a commercial facility other than an electric power generating facility

6. SF Pacific Properties

This lease was purchased from Iceland America Energy in the 4^thquarter of 2011. The lease excludes surface rights. The lease shall be for a term of three (3) years commencing on the effective date with annual increase in the primary term rents. If at the time of expiration of the initial three-year term, the lessee demonstrates that they are engaged in the construction of a geothermal power project on or near the property the primary term shall be extended for an addition three (3) years (the extended term). This lease is currently in the extended term. This lease shall continue for so long as the resource continues to be produced in commercial quantities.

To keep this lease in good standing we must pay the following rents annually in advance:

First Year: $5,766.00 ($3.00/acre) + an initial bonus payment of $10,000

Second Year: $7,688.00 ($4.00/acre)

Third Year: $9,610.00 ($5.00/acre)

Fourth Year: $11,532.00 ($6.00/acre)

Fifth Year: $13,454.00 ($7.00/acre)

Sixth Year: $15,376.00 ($8.00/acre)

If the lessee achieves any of the following milestones during the primary term of the lease, a one-time additional bonus payment of $50,000 will be due to the lessor:

- receipt and acceptance by lessee of a geothermal resource evaluation report confirming the likelihood that the resource will support the development of a 40 MW or larger geothermal power project on or near the property and/or

- receipt and acceptance by lessee of a power purchase agreement from a utility company or wholesale purchaser of electrical power which identifies the property as the source of some or all of the resource to be used for the generation of electrical power.

We are committed to pay the lessor the following royalties:

- 2.5% of the gross revenues received from the sale of electric power for the first ten (10) years of commercial operation of such facility, 3.5% for the next ten (10) years of commercial operation (years 10-20) and 5% from and after 20 years of commercial operation of the facility

- 10% of resources used at a commercial facility other than an electric power generating facility

- 10% of resources produced from the property and sold to a non-affiliate

Overriding Royalties to ORNI 5

IAE acquired the following leases from ORNI 5: Atkinson et al., BLM CACA-43302, Pon et al, and Salton Sea Energy. IAE entered into an agreement to pay to ORNI 5 certain overriding royalties from the operation of electrical generating facilities in the prospect area. The commencement date is October 25, 2010.

ORNI 5 shall be paid the following royalties:


	-	0.5% of the revenues received from electrical generation from the commencement date until the fifteenth (15^th) anniversary of the commencement date
	-	0.75% of the revenues, if any, from the fifteenth anniversary until the term of the agreement expires

This agreement continues until the fiftieth (50^th) anniversary of the commencement date or until IAE nor any transferee or successor or assignee holds any estate or interest within the prospect area.

Overriding Royalties to Layman Energy Associates

IAE entered into an agreement with Layman Energy Associates (LEA) which applies to the whole New Truckhaven Resource Area. Under this agreement LEA shall be paid 0.7% of the gross sale proceeds from the sale of electric power generated by any geothermal power project developed by IAE or its successors in interest in the New Truckhaven Resource Area.

NEW TRUCKHAVEN DESCRIPTION, HISTORY AND DEVELOPMENT

The Imperial Valley is one of the world's premier geothermal areas and the New Truckhaven property covers a broad thermal anomaly identified in shallow and 1500-ft deep gradient holes and two deep production test holes. The deep test wells encountered temperatures from 350-375°F (177-190°C) across permeable intervals between approximately 3000 and 6000 feet depth, and a maximum bottom hole temperature of 394°F. Thermal gradient and deep test well data is supplemented by extensive gravity, seismic, carbon dioxide soil-gas flux, magnetotelluric, magnetic, and resistivity studies conducted between 1979 and 2009.NGP has identified reservoir delineation and confirmation drilling targets and is preparing permit applications. NGP is evaluating multiple sources of water supply, transmission line access points, and the regional market for PPAs. These activities are part of an overall feasibility study for the project. GeothermEx has generated a heat in place estimate based upon a Monte Carlo statistical approach which yields a 90% probability projected output of 45.5 MW for the lands within the NGP lease area. The project, assuming it proceeds through feasibility, is not expected to begin producing power prior to the current 30% ITC/grant expiration date, December 31, 2013.

PERMITTING

The following is a summary of the primary permits required for the New Truckhaven project:

1.	In July 2011, we applied to BLM for approval of a proposed New Truckhaven Unit Area in which NGP Truckhaven LLC would be the Unit Operator. This would allow coordinated exploration on the mixed private, state and federal leases. That application is pending.

2.	The two previously drilled existing exploration wells at New Truckhaven have permits and access rights previously issued by the County of Imperial, California Division of Oil, Gas and Geothermal Resources, BLM, Imperial Irrigation District, California Regional Water Quality Control Board, Imperial County Air Pollution Control District, and the California Department of Parks and Recreation. These permits are being transferred to NGP Truckhaven LLC.

3.	Authorizations and permits will be required from various agencies and entities for additional drilling and power plant development.

EAST BRAWLEY

LOCATION

The Company also acquired from IAE private geothermal leases covering six square miles (3843 net mineral acres) of land at East Brawley, California.

EAST BRAWLEY LEASES

Particulars with respect to our East Brawley leases are as follows:


	Owner	Acreage	Effective Date	Expiry Date

1	Arie de Jong Family Trust	4985.99	March 1, 2009	February 28, 2013 (primary term) February 28, 2018 (extended term)
2	Jordan et al.	660.00	February 1, 2011	January 31, 2013 (primary term) January 31, 2018 (extended term)
3	Rutherford Family Trust	953.36	June 13, 2008	June 12, 2012 (primary term) June 12, 2012 (extended term)
4	Rutherford Family Trust	160.00	June 13, 2008	June 12, 2012 (primary term) June 12, 2012 (extended term)

1. Arie de Jong Family Trust

This lease was purchased from Iceland America Energy in the 4^thquarter of 2011. This lease shall be for a term of four (4) years from the effective date. An extended term will be granted if at the time of expiration of the primary term the lessee can demonstrate that they have engaged in research to support geothermal drilling, engaged in geothermal drilling or construction, received a resource evaluation report supporting the development of a 20 MW or larger project, or accepted a power purchase agreement. The extended term shall be for an additional four (4)

years. An additional bonus of $25,000 shall be paid concurrently with lessee’s notice of exercise to extend term.

To keep the lease in good standing we must make the following advance royalty payments annually:

First Year: $25.00/surface acre + $9.00/surface acre bonus
Second Year: $25.00/surface acre
Third Year: $40.00/surface acre
Fourth Year: $40.00/surface acre
Fifth Year: $40.00/surface acre
Sixth Year: $40.00/surface acre
Seventh Year: $50.00/surface acre
Eighth Year: $50.00/surface acre
Any remaining years of the extended term: $50.00 + CPI increases / surface acre

Upon lessee selling or using the resources in commercial quantities, lessee’s rental payment obligations will terminate beginning the following calendar month and royalty payments will begin. All bonuses and rental payments shall be treated as advanced royalties and shall be deducted from royalties payable after resources are used in commercial quantities.

We are committed to paying lessor the following royalties:


	-	2% of the gross revenues from direct heat exchange
	-	4.25% of the gross revenues from the sale of electricity or from the use of resources at a commercial facility other than an electric power-generating facility
	-	10% of the gross revenues from the sale of unprocessed resources
	-	12.5% of the gross revenues from any sale of hydrocarbon resources

2. Jordan et al.

This lease was purchased from Iceland America Energy in the 4^thquarter of 2011. On the IAE NGP transaction closing date $264,000 was due to lessor. This lease shall be for a term of two (2) years from the effective date. An extended term will be granted if at the time of expiration of the primary term lessee can demonstrate that they have engaged in research to support geothermal drilling, engaged in geothermal drilling or construction, received a resource evaluation report supporting the development of a 20 MW or larger project, or accepted a power purchase agreement.

To keep the lease in good standing we must pay the following rental payments annually:

First Year: $10/surface acre and $30/subsurface acre
Second Year: $10/surface acre and $30/subsurface acre
Third Year: $10/surface acre and $30/subsurface acre
Fourth Year: $10/surface acre and $30/subsurface acre
Fifth Year: $10/surface acre and $30/subsurface acre
Sixth Year: $10/surface acre and $30/subsurface acre
Seventh Year: $10/surface acre and $30/subsurface acre

Additional monthly bonus payments due on the 10^thof each month for the amount of $8,000 will commence on the first anniversary date of the effective date of the first amendment. These payments will continue on a monthly basis until royalties are due.

We are committed to paying lessor the following royalties:


	-	10% on the gross value received from the sale of resources
	-	3.2% of the gross revenues received from the sale of electric power for the first five (5) years, 4% for the next 10 years of commercial operation (years 6 through 15) and 5% from and after 15 years of commercial operation

3. Rutherford Family Trust (953.36 acres)

This lease was purchased from Iceland America Energy in the 4^thquarter of 2011. This lease shall be for a term of four (4) years from the effective date. An extended term will be granted if at the time of expiration of the primary term lessee can demonstrate that they have engaged in research to support geothermal drilling, engaged in geothermal drilling or construction, received a resource evaluation report supporting the development of a 20 MW or larger project, or accepted a power purchase agreement. The extended term shall be for an additional four (4) years.

To keep this lease in good standing we must pay the following advance royalty payments:


	-	On the effective date of this lease an initial bonus payment of $5.00/surface acre and $5.00/subsurface acre will maintain the agreement for the duration of the primary term. If the agreement is extended an additional bonus of $25,000 shall be paid concurrently with lessee’s notice to exercise of extended term.
	-	Fifth Year: $5.00/surface acre and $5.00/subsurface acre
	-	Sixth Year: $6.00/surface acre and $6.00/subsurface acre
	-	Seventh Year: $7.00/surface acre and $7.00/subsurface acre
	-	Eighth Year and through the remaining years of the extended term: $10.00 per acre

Upon lessee selling or using the resource in commercial quantities, advance royalty payment obligations terminate and lessee will commence payment of royalties, subject to a credit for advance royalties paid.

We are committed to paying lessor the following royalties:


	-	3.5% of the gross revenues received from the sale of electric power
	-	5% of the gross revenues from the use of resources used at a commercial facility other than an electric power generating facility
	-	10% of the gross value received from the sale of resources

4. Rutherford Family Trust (160 acres)

construction, received a resource evaluation report supporting the development of a 20 MW or larger project, or accepted a power purchase agreement. The extended term shall be for an additional four (4) years.

To keep this lease in good standing we must pay the following advance royalty payments:


	-	On the effective date of this lease an initial bonus payment of $5.00/surface acre and $5.00/subsurface acre will maintain the agreement for the duration of the primary term. If the agreement is extended an additional bonus of $25,000 shall be paid concurrently with lessee’s notice to exercise of extended term.
	-	Fifth Year: $5.00/surface acre and $5.00/subsurface acre
	-	Sixth Year: $6.00/surface acre and $6.00/subsurface acre
	-	Seventh Year: $7.00/surface acre and $7.00/subsurface acre
	-	Eighth Year and through the remaining years of the extended term: $10.00 per acre

We are committed to paying lessor the following royalties:


	-	3.5% of the gross revenues received from the sale of electric power
	-	5% of the gross revenues from the use of resources used at a commercial facility other than an electric power generating facility
	-	10% of the gross value received from the sale of resources

Layman Energy Associates, Inc. Agreement

IAE entered into an agreement with Layman Energy Associates, Inc. (LEA) in exchange for LEA assigning their leases to IAE and providing resource data. At the commencement of the construction of the first electric power generation facility at South Brawley or East Brawley, LEA will be paid a development fee of $20,000 per gross megawatt of installed power capacity plus a one-time additional cash payment of $685,000. At every subsequent power generation facility at East Brawley or South Brawley LEA will be paid a development fee of $18,000 per gross megawatt of installed power. In addition, LEA shall receive an overriding royalty of 0.5% of the gross revenue for the sale of geothermal electric power from the first electric power generating facility constructed at each of Sough Brawley and/or East Brawley. If by the fourth (4th) anniversary of the effective date of the agreement, drilling has not commenced on an exploratory well, then LEA shall be paid $50,000 for each of the projects that has not been developed in accordance with the terms.

EAST BRAWLEY DESCRIPTION, HISTORY AND DEVELOPMENT

The East Brawley property includes part of the centre of a thermal anomaly immediately south of recent drilling by Ram Power at its Orita project. The existing wells on the East Brawley property report temperatures between 500-580°F (250-304°C). Ram Power released test results from the Orita-2 well, located 1/2 mile north of the East Brawley property: the well was reportedly tested at 8-10 MW with resource temperatures of 570°F (299°C).

NGP is commencing work for well permits including preliminary siting of exploratory wells.

SOUTH BRAWLEY

LOCATION AND DESCRIPTION

The Company also acquired from IAE a 50% leasehold on three square miles (1920 acres) of private land at the South Brawley geothermal area. NGP will determine if a secure land position can be established. No physical work is planned in the immediate future.

SOUTH BRAWLEY LEASES

Particulars with respect to our South Brawley leases are as follows:


	Owner	Assessor’s Parcel Numbers	Acreage	Effective Date	Expiry Date

1	Smith Brothers Geothermal LLC	040-200-01 040-190-04 040-190-01 040-090-02	1920 surface 50% minerals	March 28, 2007	March 27, 2041

1. Smith Brothers Geothermal LLC

This lease was purchased from Iceland America Energy in the 4th quarter of 2011. The lease contains an undivided 50% interest in all minerals, oil, gas, other hydrocarbon substances, geothermal rights and other minerals under the leased lands. This lease shall commence on the effective date and continue for the total period(s) of the preliminary term and any production term. The preliminary term shall commence upon the effective date and continue until the earliest of the third anniversary of the effective date, the commencement of any production term, or the termination of the lease. At any time prior to the expiration of the three (3) year preliminary term, lessee may extend the term for a period of up to 30 years by delivering notice of such election to lessee. The lease shall be in effect up to a maximum of 34 years from the effective date.

To keep the lease in good standing we must make the following payments:


	-	On the effective date the lessee shall pay the lessor $10,000 as a signing bonus.
	-	On the commencement date of any production term, and on or before the 25^thday of each calendar month during any production term, lessee shall pay to lessor $2,083.33 in minimum rent
	-	Within 30 days after the lessee’s entry in to a power purchase agreement the lessee shall pay the lessor $10,000 as a bonus.

We are committed to paying the lessor the following royalties:


	-	2.5% of gross revenues from the sale of electric power for years 1 through 10 and thereafter 3.5%
	-	0.35% as a “pass through royalty” for wells directionally drilled from the surface of leased lands outside of any participating area under, across, or through land other than the leased land.

Layman Energy Associates, Inc. Agreement

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, cash flows and results of operations for the fiscal years ended June 30, 2011, June 30, 2010, and June 30, 2009, should be read in conjunction with our consolidated financial statements and related notes attached thereto.

The Company’s subsidiary NGP I has been operating commercially at its Blue Mountain power plant since November 2009. The Company has incurred net losses over the past several years and has accumulated a deficit of $44.0 million as at June 30, 2011. Under the Company’s currently anticipated power production forecast its subsidiary, BM Holdco, which holds a 100% interest in NGP I, is not able to service its loan with EIG for the full loan term. In addition, cash generation for the quarter ending December 2011 has been reduced by a fire during September 2011, reducing the cash available to fund the minimum interest payments under the EIG loan. No cash from the Blue Mountain project is available to the Company until the EIG loan balance is paid down to a target level as defined in the agreement, which was $64.8 million at June 30, 2011. As at June 30, 2011, BM Holdco owed $91.3 million to EIG and NGP I owed $93.2 million to John Hancock Life Insurance Company (“John Hancock”). Consequently, material uncertainties exist which may cast significant doubt upon the Company’s ability to continue as a going concern. NGP I must increase power production to enable BM Holdco to reduce the EIG loan balance which is necessary to continue to meet cash payment obligations and to meet the interest coverage ratio covenant. To date, the Company’s testing and stimulation program has not resulted in a significant increase in the power generation outlook. Work to optimize the wellfield configuration is continuing, and the Company is negotiating with lenders regarding a restructuring of the loan terms of the EIG loan. If the Company is unable to increase power production sufficiently, a restructuring of the EIG loan will be required to maintain compliance with loan terms. As at June 30, 2011 and as of November 30, 2011, the outcome of these activities is unknown and subject to considerable uncertainty.

The Company’s ability to continue as a going concern is dependent on its available cash and its ability to continue to raise funds to support corporate operations and the development of other properties. The consolidated financial statements do not include any adjustments that might result from the outcome of these uncertainties and such adjustments would be material.

Accounting Policies

Our significant accounting policies are discussed in Note 2 to the financial statements.

The preparation of financial statements in accordance with GAAP 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 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:

Depreciation of property, plant and equipment for the year ended June 30, 2011 amounted to $7,124,369 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 long-term liabilities, in particular the EIG loan:

The long-term liabilities are accounted for using the effective interest method. This method requires that future cash flows associated with the liability be estimated. In the case of the EIG 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 15 to the financial statements. The EIG loan terms include a debt service covenant of 1.4:1. This debt service covenant is likely to be breached at December 31, 2011, at which time EIG will have the right to demand payment or exercise its security. In addition, under the Company’s current power production forecast, the Company is not able to service the EIG loan for the full loan term. Accordingly the Company has entered into negotiations with EIG regarding a potential change of the loan terms. As at June 30, 2011 and as of November 30, 2011, the outcome of these negotiations is unknown, and subject to considerable uncertainty. Under normal circumstances, the Company would update its estimate of the future cash flows associated with the EIG loan, resulting in a gain or loss on change of estimate being recognized in the income statement. As at the end of June 2011, the Company has however determined that it is not possible to make a reliable estimate of the cash flows associated with the loan. Accordingly the Company has continued to use the forecast that was in place when the last reasonable estimate possible. 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 fair value of 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 fair value of the cash settled option at June 30, 2011 was reduced to zero due to the current expectation that the Company will not be able to service the EIG loan for the full loan term without higher power production and / or a restructuring of the loan terms.

The calculation of the fair value of the asset retirement obligation:

The ultimate amount of the site restoration and reclamation costs that will have to be incurred is uncertain due to uncertainty regarding the extent of the liability and the costs that will have to be incurred to settle the liability. In addition, the timing of the settlement of the obligation is uncertain.

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.

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.

The calculation of the fair value of warrants:

The amounts included in the financial statements in respect of the Share purchase warrants, Finders’ warrants and EIG warrants were calculated using a Monte Carlo simulation. The value of the warrants was determined using a Monte Carlo simulation model rather than the Black-Scholes model due to the accelerated exercise of warrants based on price, which leads to uncertainty regarding the expected life of the warrants. The Monte Carlo simulation also included inputs such as the volatility of the Company’s share price and the expected divided yield. None of these can be determined with certainty.

Recognition and measurement of contingent liabilities:

Under the terms of its PPA with NVE, NGP I is liable for the replacement cost of power under certain circumstance, particularly if production falls below the minimum specified in the PPA. This liability only arises if the replacement cost is above the contract price. In addition, the NGP I is liable for the replacement cost of PCs if the contractual minimum is not supplied. NGP I has cash collateralized letters of credit in favour of NVE in respect of this contingent liability.

Cash flow forecasts used for the purpose of impairment testing:

Property, plant and equipment, intangible assets and resource property interests are assessed for impairment at the end of each reporting period as described in Note 2, Summary of significant accounting policies. The identification of impairment indicators as well as determination of assumptions used in impairment tests involve significant judgement. A cash generating unit is considered to be impaired if the carrying amount exceeds the undiscounted cash flows expected from its 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.

The Company made the following changes to its accounting policies during the year ended June 30, 2011:


	i)	CICA handbook section 3870, Stock-based Compensation and Other Stock-based Payments

Under the Company’s previous accounting policy for stock-based compensation, the Company accrued compensation costs in respect of share options granted during the period based on the assumption that all instruments subject only to a service requirement will vest. The effect of actual forfeitures was recognized as they occurred.

During the year ended June 30, 2011, the Company changed its policy to base accruals of compensation cost on the best available estimate of the number of options or other equity instruments that are expected to vest and to revise that estimate, if necessary, if subsequent information indicates that actual forfeitures are likely to differ from initial estimates.

Prior to the year ended June 30, 2010, the Company had not had any options forfeited, and accordingly an estimate of no forfeitures was reasonable for all options granted prior to the most recent grant. The change in the accounting policy will allow for the effect of the recent increase in forfeitures to be incorporated into the determination of the stock-based payment expense, and will accordingly give rise to more relevant and reliable information in the Company’s financial statements. In addition, the change aligns the treatment of stock-based compensation with the treatment that would have been required under both US GAAP and International Financial Reporting Standards (“IFRS”).

The effect of the change was to reduce the stock-based compensation expense for the year ended June, 2011 by $11,522. The change did not affect prior reporting periods.


	ii)	CICA handbook section 1582, Business Combinations, section 1601, Consolidated Financial Statements and section 1602, Non-controlling interests

The abovementioned sections were released in January 2009 and adopted by the Company during the year ended June 30, 2011. The adoption of the new standards results in a number of changes to the treatment of acquisitions, notably the measurement of non-controlling interests at fair value by the parent group, the requirement to expense acquisition costs, and the accounting for contingent consideration as a financial liability, measured at fair value. The adoption of the new standard did not affect the Company’s financial statements for the year ended June 30, 2011.


	iii)	CICA handbook section 3855, Financial Instruments

In June 2009, the CICA amended Section 3855, Financial Instruments - Recognition and Measurement, to clarify the application of the effective interest method after a debt instrument has been impaired. This Section has also been amended to clarify when an embedded prepayment option is separated from its host debt instrument for accounting purposes. This amendment was adopted during the year ended June 30, 2011, but did not affect the Company’s financial statements.


	iv)	EIC 175, Multiple Deliverable Revenue Arrangements

In December 2009, the CICA issued EIC 175, Multiple Deliverable Revenue Arrangements, replacing EIC 142, Revenue Arrangements with Multiple Deliverables. This abstract provides updated guidance on whether multiple deliverables exist, how the deliverables in an arrangement should be separated and the consideration allocated; requires, in situations where a vendor does not have vendor-specific objective evidence or third party evidence of selling price, that the entity allocate revenue in an arrangement using estimated selling prices of deliverables; eliminates the use of the residual method and requires an entity to allocate revenue using the relative selling price method; and requires expanded qualitative and quantitative disclosures regarding significant judgments made in applying this guidance. The adoption of EIC 175 has not affected the Company’s financial statements.

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 resource property interests. 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, 2010 and 2011, have been capitalized.

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 based on applying a capitalization rate to the average amount of accumulated expenditures for the Blue Mountain Geothermal 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 Geothermal 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 was 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.

IFRS:

The Company has adopted 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 ended September 30, 2011.

Summary of segmental results


2011	Blue Mountain project	Crump Geyser project	Other projects	Corporate and reconciling items	Total
Revenue	$ 24,828,743	$ 28,074	$ -	$ -	$ 24,856,817
Net loss	4,331,814	408,257	785,642	3,081,263	8,606,976
Segment assets	178,553,501	3,016,568	4,022,695	7,459,839	193,052,603
Segment liabilities	160,071,246	2,553,906	216,167	379,456	163,220,775


2010	Blue Mountain project	Crump Geyser project	Other projects	Corporate and reconciling items	Total
Revenue	$ 11,839,010	$ -	$ -	$ -	$ 11,839,010
Net loss	15,047,745	-	266,750	2,666,956	17,981,451
Segment assets	181,850,600	642,011	1,278,856	3,502,314	187,273,781
Segment liabilities	160,685,006	-	148,630	650,509	161,484,145

The Company completed construction of its Blue Mountain geothermal power plant during the second quarter of the 2010 fiscal year. Prior to completion of the Blue Mountain power plant, the Company’s net loss arose primarily from the activities of its corporate head office.

June 30, 2011 compared to June 30, 2010

The year ended June 30, 2011 is the first full year that the Company’s Blue Mountain geothermal plant has been in full operation and includes the effect of a seven day maintenance outage during November 2010 and a pump malfunction during July 2010. The year ended June 30, 2010 includes the revenue generated during the first eight months after the substantial completion of the plant, a period during which the Company was still ramping up production. An electrical incident during January 2010 also shut down production for several weeks during January and February 2010, negatively impacting revenue and profitability for the 2010 financial year. A settlement regarding this incident was reached during the quarter ended September 2010, and $1.0 million is included in revenue for the 2011 financial year relating to this settlement.

Gross margin, before taking into account depreciation and amortization, and excluding non-operations revenue, amounted to $18.6 million (78%) for the year, compared to $9.1 million (77%) for the comparative period. Direct cost of energy production for the year included $528,789 expensed in respect of the Company’s recent wellfield testing program, as well as significant repairs and maintenance following the pump malfunction in July.
Operating expenses, which are comprised of general and administrative expenses and resource property expenses (incurred at the Company’s development properties) increased from $4.9 million in 2010 to $5.7 million in 2011, an increase of 15%. Whilst the increase can partly be explained by the rise of the Canadian dollar (at 2010 exchange rates, the increase would have been only 11%), the increase arose predominantly because of higher stock-based compensation expense (an increase of $316,315) and resource property costs (which increased to $148,315 due to increased site investigation work and payments made under lease contracts).

The Net Loss for the year amounted to $8,606,976 or 8 cents per share, compared to $17,981,451 or 19 cents per share in 2010. Interest expense increased by $1,913,382, even though the Company closed the $98.5 million 4.14% John Hancock financing during September 2010, setting funds aside for a drilling program at Blue Mountain and repaying a portion of the 14% EIG loan, mostly because all interest had been capitalized to the Blue Mountain project until plant completion. The Company recognized a non-cash fair value gain of $2,722,396 on the cash settled option during the year, compared to a loss of $901,552 in 2010. Non-cash gains resulting from changes in estimates relating to the EIG loan amounted to $3,547,153 in 2011 and $3,038,446 in 2010. Financing expenses relate primarily to prepayment fees on the EIG loan, incurred at the time of the John Hancock loan closing. The 2010 fee of $600,000 arose when a loan repayment was made from grant proceeds.

A private placement during September 2010 raised net proceeds of $9.5 million. Capital spending related mostly to the drilling program at Blue Mountain. The Company also purchased three properties in California’s Imperial Valley from IAE for approximately $680,000 cash and 6,074,069 shares during the fourth quarter of the 2011 financial year.

The Company’s financial statements included 100% of the Crump project until October 2010, at which time NGP and Ormat formed a joint venture to develop the project. 50% of the results of CGC are included thereafter, using the proportionate consolidation method.

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 facility shutdown between January 16 and February 23, 2010, due to a short-circuit caused by faulty layout of underground cables, but also due to certain legal expenses that had previously been deferred as future financings costs 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 $17,981,451 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 $18,403,777, offset by a non-cash change in estimate adjustment of $3,038,446. 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 EIG loan. $893,011 of financing expenses includes a prepayment penalty incurred when the EIG 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 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 EIG 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”).

B. Liquidity and Capital Resources

Cash resources and liquidity

Cash and cash equivalents as at June 30, 2011 amounted to $9,461,451, which included $3,677,148 held by NGP I or BM Holdco for the Blue Mountain plant, which is not available for use by the rest of the Group due to the terms of the EIG loan, which prevent any cash being distributed from BM Holdco until target note balances are met. Cash available to the rest of the Group amounted to $5,784,303. On July 21, 2011, NGP I received an additional $7,869,212 government grant under the ARRA, which was used to fund a repayment of the EIG loan. No cash from the Blue Mountain project is available to the Company until the EIG loan balance is paid down to a target level as defined in the agreement, which was $64.8 million at June 30, 2011.

As at June 30, 2011, the Company owed $91.3 million to EIG as well as $93.2 million to John Hancock. Under the Company’s currently anticipated power production forecast its subsidiary, BM Holdco, which holds a 100% interest in NGP I, is not able to service the EIG loan for the full loan term. If the Company is unable to increase power production sufficiently, a restructuring of the EIG loan will be required to maintain compliance with loan terms. In addition, cash generation for the quarter ending December 2011 has been reduced by a fire during September 2011, reducing the cash available to fund the minimum interest payments under the EIG loan. Accordingly the Company’s ability to continue as a going concern is dependent on its available cash and its ability to continue to raise funds to support corporate operations and the development of other properties.

The Company’s other resource property projects are currently funded by equity financing in combination with government grants. Development of the Crump Geyser project is taking place as a joint venture with Ormat, under which Ormat provides financing and project management for the project. Ormat will fund 100% of the initial development activities of CGC in the amount of $15 million and pay the Company $2.5 million in instalments over a three year period, $300,000 of which has been received (of which $200,000 was received in October 2011). After the initial development expenses funded by Ormat are expended, the parties will each be responsible for funding 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 its share of costs up to $15 million. The Company believes it may not currently have sufficient working capital on hand to meet its expected capital requirements for fiscal 2012, and the Company is working with advisors to raise additional funds. In order to conserve cash in current market conditions, the Company has reduced its expenditures on certain project development and other activities.

On October 29, 2009, the Company was awarded two grants from the DOE under the ARRA geothermal technologies program. The program calls for cost sharing grants on exploration and drilling work. The Company was awarded $1.8 million for the Crump Geyser geothermal project and $1.6 million for the North Valley geothermal project, which was subsequently transferred to the Pumpernickel project. As at June 30, 2011, the Company had received $443,513 (2010 – $134,189) for Crump Geyser and $30,982 (2010 – $17,269) for North Valley.

Cash and cash equivalents as at September 30, 2011 amounted to $13,594,125, which included $9,594,715 held by NGP I or BM Holdco for the Blue Mountain plant, which is not available for use by the rest of the Group. Cash available to the rest of the Group amounted to $3,999,410.

Financial instruments

Financial instruments carried on the balance sheet include cash and cash equivalents, restricted cash, accounts receivable, marketable securities, accounts payable and accrued liabilities, long-term payables, lease obligations, long-term liabilities and derivatives, namely the cash settled option. As at June 30, 2011, the Company had not entered into any hedging arrangements.

The table below presents a maturity analysis of the Company’s financial liabilities that shows the remaining contractual maturities as at June 30, 2011:


	Carrying amount	Contractual cash flows	Within 1 year	1 – 5 years	More than 5 years
Long-term leases	$32,109	$36,531	$9,530	$27,001	$-
Long-term payables	494,563	572,787	276,980	295,807	-
John Hancock loan	78,804,412	123,078,402	10,057,969	37,898,299	75,122,134

The EIG loan is not included in the table because the Company was not able to make a reasonable estimate of the future cash flows associated with the loan at June 30, 2011 or as at the date of this report.

BM Holdco originally entered into a loan agreement with EIG, a Washington based investment management firm, on August 29, 2008. On September 3, 2010 BM Holdco and EIG entered into an Amended and Restated Note Purchase Agreement. The principal terms of the amended and restated EIG loan are:


-	14% interest per annum, payable quarterly, over a 15 year term maturing November 30, 2023;
-	6% interest per annum may be deferred if enough cash is not available to fund the full interest payments;
-	The principal is repaid from available cash flow – the lender has the right to receive cash interest plus 60% of available project cash distributed to BM Holdco from NGP I, which increases to 100% while target loan 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 BM Holdco (See Note 19);
-	EIG released the NGP I security held in respect of the EIG loan upon closing of the John Hancock loan but has retained its lien on the equity interests in BM Holdco which holds the equity interest in NGP I;
-	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, is payable if optional prepayments are made;


-	An Alternative Yield Maintenance Premium (“AYMP”) of 15% is payable on principal repayments from equity issuances, proceeds of asset dispositions, grant proceeds or tax equity proceeds before March 2, 2012; and
-	If repayments are made before the date mentioned above and reduce the balance of the loan below $70m, the YMA becomes payable.
-	The loan is denominated in USD.

The EIG loan is repaid from cash distributed to BM Holdco by NGP I. These distributions are subject to the terms of the John Hancock loan. The EIG loan terms include a debt service covenant of 1.4:1. This debt service covenant is likely to be breached at December 31, 2011, at which time EIG will have the right to demand payment or exercise its security. In addition, under the Company’s current power production forecast, BM Holdco will not be able to service the EIG loan for the full loan term, and a reduction in power production caused by a fire at the plant during September 2011 has decreased the cash available to make the next interest payment when due. Accordingly the Company has entered into negotiations with EIG regarding a potential change of the loan terms. As of November 30, 2011, the outcome of these negotiations is unknown, and subject to considerable uncertainty.

On September 3, 2010, NGP I closed a financing with John Hancock for $98.5 million. The DOE has guaranteed 80% of the principal and interest of the loan.

The principal terms of the John Hancock loan are:


-	A maturity date of December 31, 2029;
-	A blended interest rate of 4.14%;
-	Payments are made quarterly, consisting of a blend of principal and interest;
-	Cash distributions from NGP I are not allowed if the debt service coverage ratio falls below 1.2;
-	If the forecast debt service coverage ratio falls below 1.45:1, the NGP I is required to restore the ratio by retaining cash in the project for remedial work or loan repayments;
-	The John Hancock loan is a senior secured obligation of NGP I and John Hancock has first priority security interest in 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.
-	The loan is denominated in USD.

Both the EIG and the John Hancock loans have fixed interest rates.

All cash and cash equivalents held by US group companies are denominated in USD. Cash and cash equivalents held by Canadian companies of $5,500,062 was denominated in CAD and $24,084 was denominated in USD.

Commitments for capital expenditure

Commitments for capital expenditure amounted to $119,638 as at June 30, 2011.

Plan of Operations

Our plan of operations for the fiscal year ending June 30, 2012 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 a $1.3 million stimulation, testing and injection redistribution program at Blue Mountain that will demonstrate sustainable higher power production at the project, resulting in a forecast complying with both the PPA and John Hancock covenants.

-	Raise additional, lower cost capital to partially repay EIG and at the same time negotiate loan terms with which the Company can comply.

-	Develop and fund further drilling at Blue Mountain to take advantage of additional plant capacity.

-	Capitalize on opportunities to fund development of additional projects, particularly at New Truckhaven.

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 $1.3 million reserved from the John Hancock loan and the joint venture financing that is committed under the Ormat Joint Venture agreement. However, additional capital is required for further drilling at Blue Mountain to increase power generation to plant capacity.

Project Financing: As of November 15, 2011, $1.3 million from the John Hancock loan is reserved to fund continuing stimulation and re-distribution of injection to optimize power production. The Company does not expect sufficient Blue Mountain income to provide for further project investment and meet the terms of the EIG loan.

The Company continues to believe future Blue Mountain financing, potentially incorporating some of the project’s tax benefits, will be successful. The Company must increase power production and further repay the EIG loan to maintain interest coverage covenant compliance. The Company will breach the covenanted EIG loan Debt Service Coverage Ratio at December 31, 2011 and anticipates difficulty meeting the minimum cash payment early in 2012.

Permitting: Our permitting activities are continuing as projects develop. For more detailed information respecting the status of required permits, please refer to the heading "Property, plants and equipment" under Item 4.D. above.

Potential Acquisitions: We intend to continue our growth opportunistically, as funding, partnering and other opportunities permit.

Outstanding Share Data

As at June 30, 2011, we had 122,410,573 common shares issued and outstanding. As of June 30, 2011, the following rights to purchase our securities were outstanding:


(a)	Stock options	8,427,500
(b)	EIG warrants	4,500,000
(c)	Share purchase warrants	20,675,000
(d)	Finders’ warrants*	1,000,000

* The finders’ warrants entitle the holder to acquire a unit (consisting of one common share and one share purchase warrant).

No options or warrants have been exercised subsequent to our 2011 fiscal year end, but 20,000 stock options with exercise prices between CAD0.45 and CAD0.64 expired. As of November 30, 2011, our issued and outstanding share capital consisted of 122,410,573 common shares. 8,407,500 common shares were issuable pursuant to options granted to purchase our securities, and 27,175,000 common shares were issuable pursuant to various warrants granted. If all these were exercised, it would result in a fully-diluted share capital of 157,993,073 common shares.

As of November 30, 2011, the following rights to purchase our securities were outstanding:


(a)	Stock options	8,407,500
(b)	EIG warrants	4,500,000
(c)	Share purchase warrants	20,675,000
(d)	Finders’ warrants*	1,000,000

C. Research and Development, Patents, Licenses etc.

The Company has not been involved in any research or development activities during the last three years, apart from the development of its resource property interests, as discussed above.

D. Trend Information

The Company currently derives the majority of its revenue from its Blue Mountain power plant. The Company’s most reasonable current forecast of future power production assumes a decline of approximately 2.5% per year in power production. All the production from the Blue Mountain plant is sold to NVE under a PPA which includes a 1% annual increase in the price for electricity supplied. Accordingly revenue is currently expected to decline by approximately 1.5% per year, assuming success of the ongoing wellfield testing and stimulation program.

The following table sets forth our revenues, net (loss) profit and net (loss) profit per share presented by quarter for the past two fiscal years.


		Revenue		Net (loss) profit			Net (loss) profit per
							share
							(Basic and diluted)

Quarter ended
June 2011	$	5,893,010	$	(2,683,956	)	$	(0.02	)
March 2011		6,326,960		(1,425,757	)		(0.01	)
December 2010		5,779,830		20,231			0.00
September 2010		6,857,017		(4,517,498	)		(0.05	)
June 2010		6,231,221		(3,679,944	)		(0.04	)
March 2010		2,963,744		(5,664,233	)		(0.06	)
December 2009		2,644,045		(6,801,687	)		(0.07	)
September 2009		Nil		(1,835,587	)		(0.02	)

Prior to start-up of the Blue Mountain power plant, the Company’s net loss arose primarily from the activities of its corporate head office. The Blue Mountain power plant began operating during the quarter ended December 2009. The quarter ended March 2010 was negatively affected by the electrical plant outage and consequent Force Majeure declaration referred to above. The quarter ended September 2010 includes a portion of the settlement in respect of the electrical incident, but was also negatively affected by a pump replacement. The quarter ended December 2010 was favourably affected by non-cash gains (approximately $3.6 million) associated with deferring loan costs and reducing the value of the cash settled option that resulted from a downward revision of the longer term forecast of power production at Blue Mountain. The quarter ended March 2011 includes a non-cash gain of $901,186 on the revaluation of the cash settled option. The quarter ended June 30, 2011 includes a further $1.1 million non-cash gain on revaluation of the cash settled option. Observable trends in the quarterly information presented may not be meaningful.

E. Off-balance Sheet Arrangements

As at June 30, 2011, the Company has provided, as operating security, $3,805,672 in letters of credit to NVE under the revised terms of the 20-year PPA. NVE letters of credit are cash collateralized by deposits at Bank of the West, a US bank.

Under the terms of its loan with John Hancock the Company has provided reserve funds (included in restricted cash) of $8,478,011 for a debt service reserve, as well as reserves for drilling expenditure, plant maintenance and property tax. Under the John Hancock loan terms if the forecasted DSCR falls below 1.45 the Company must fund a third party approved plan to restore the coverage ratio, either from higher power production or loan repayment.

The Company has an obligation to pay NVE its replacement power cost above the PPA price, for any shortfall in the supply of power and/or Portfolio Energy (environmental) Credits beyond contractual allowances, for a maximum of three years, unless the shortfall relates to a Force Majeure event, such as the January 2010 electrical failure, or an NVE emergency.

The Company has issued two additional letters of credit, secured by cash, in the amounts of $50,000 each, to the State of Oregon’s Department of Geology and Mineral Industries and Nevada Division of Minerals, as reclamation bonds.

The Company has no other material off-balance sheet arrangements, such as guarantee contracts, derivative instruments or any other obligations that trigger financing, liquidity, market or credit risk to the Company.

F. Tabular Disclosure of Contractual Obligations at June 30, 2011

The Company has commitments in respect of geothermal lease payments and work commitments under its geothermal leases as well as other operating leases commitments.


Contractual	Payments due by period
obligations	Total	Less than 1	1 – 3 years	4 – 5 years	After 5 years
		year
Long-term debt *	$123,078,402	$10,057,969	$19,341,147	$18,557,152	$75,122,134
Long-term payables	572,787	276,980	295,807	-	-
Capital lease obligations	36,531	9,530	19,060	7,941	-
Operating leases	1,076,523	234,555	481,816	360,152	-
Resource property leases	7,182,115	694,424	1,199,983	1,142,968	4,144,740
Work commitments	1,369,510	283,182	557,743	320,480	208,105
Purchase obligations	1,305,248	1,305,248	-	-	-
Total contractual obligations *	134,621,116	12,861,888	21,895,556	20,388,693	79,474,979

* Excludes the EIG loan

The EIG loan is not included in the table because the Company is not able to make a reasonable estimate of the future cash flows associated with the loan.

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 35 years of geothermal engineering, exploration and resource assessment, business management and project finance experience. Mr Fairbank was the founder Nevada Geothermal Power Inc. and had overall responsibility for the development of the Blue Mountain Geothermal Project from discovery through completion of the Faulkner 1 geothermal power plant. He founded Fairbank Engineering Ltd. in 1986, specializing in international geothermal and mineral resource development. Mr. Fairbank is a long-standing member and a current Director of the Geothermal Resource Council, a Past President of the Canadian Geothermal Energy Association and a Director of the Geothermal Resources Council.

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).

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R. Gordon Bloomquist, Ph.D.
Director since March 2003

Mr. Bloomquist, an internationally recognized geothermal expert, is providing consulting services to the World Bank, the German Development Bank (KfW) and US AID regarding geothermal energy projects in African Rift area and is also working with the World Bank on a project in the South Pacific. 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 Finance Committee for the 2015 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 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).

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Gavin Cooper, CA
Director since June 2009

Mr. Cooper is the principal of Gavin Cooper & Associates, providing consulting and financial and corporate administration services to primarily reporting issuers. Mr. Cooper has more than 25 years of experience in senior executive management roles and acts as CFO and corporate secretary and sits on the boards of various TSX Venture Exchange listed companies. Mr. Cooper is the Chief Financial Officer of Nevaro Capital Corporation (formerly VRB Power Systems Inc.), was formerly the President and CEO and a Director of Catamaran Ferries International Inc, Director of Finance & Administration at Yarrows Ltd, Vice President and Director Pacific Engineered Materials Inc. Mr. Cooper is a member of the Canadian Institute of Chartered Accountants.

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 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.

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The following information relates to our non-director/officer senior management and consultants upon whose work we are dependent:

Kim Niggemann, B.Sc., Geologist
V.P. Resource Operations & External Affairs

Ms. Niggemann is the V.P. Resource Operations & External Affairs 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 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 Blue Mountain Geothermal Power Plant in Humboldt County, Nevada.

Max Walenciak P.Eng
Senior V.P. Development & Plant Operations

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 was responsible for engineering, equipment procurement and contractor selection, and construction for the Company's 'Faulkner 1' geothermal power plant, well field and transmission line at Blue Mountain, Nevada. Mr. Walenciak is responsible for power plant and well field operations, and directs activities for the Company’s development projects.

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Stuart D. Johnson
Vice President, Resource Development

Stuart Johnson is a nationally recognized expert in the design and application of exploration, development and production methods to utilize geothermal resources for electrical power production. Mr. Johnson has managed successful resource development for projects within the Western United States and Latin America. Specifically, he has played important roles in the development of commercially-producing fields in California (Heber, and East Mesa), Nevada (Steamboat Hills, Jersey Valley, Brady/Desert Peak, Dixie Valley, Soda Lake, Stillwater, Beowawe), Hawaii (Puna) and Utah (Roosevelt Hot Springs). Additionally, he is also known for his innovation in the geothermal sector, having directed award-winning geothermal silica co-production research and designed pioneer scale inhibition programs that are now industry standard. He is active in market development and promoting public awareness of geothermal energy as a principal source of sustainable energy.

Mr. Johnson holds an M.S. in Economic Geology from the University of Wisconsin, Madison and a B.A. in Geology from Western Michigan University. Mr. Johnson is a past President of the Geothermal Resources Council (2003 - 2004) and sits on their Board of Directors (1996 -Present). As well, he currently serves as an Advisory Board Member to the Great Basin Geothermal Research Center and has also served on the Board of Directors of the Geothermal Energy Association. He is the recipient of the Geothermal Resources Council Pioneer Award and of an R&D 100 Award for research on nano-silica production from geothermal brines.

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 Director
NGP Chile Ltda.	Brian D. Fairbank Stephanie Diane Ashton Cesar Andres Lopez Alarcon	President, and Director Director Director
Desert Valley Gold Co.	Brian Fairbank Andrew Studley	President, CFO, Director and Secretary Treasurer
Nevada Geothermal Power US Holdings Inc.	Brian Fairbank Andrew Studley Markus Christen	President Secretary and Treasurer Director
Nevada Geothermal Power Company	Brian Fairbank Andrew Studley Markus Christen	President and Director Treasurer, Secretary and Director Director
Nevada Geothermal Operating Company LLC	Brian Fairbank Andrew Studley Markus Christen	Director Director Director
Nevada Geothermal Power Holding Company LLC	Brian Fairbank Andrew Studley Markus Christen R.Scott McInnis	Director Director Director Director

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NGP Blue Mountain Holdco LLC	Brian Fairbank Andrew Studley Markus Christen Scott McInnes (1)	Director Director Director Director
NGP Blue Mountain Holdco II LLC	Brian Fairbank Andrew Studley Markus Christen	President CFO and Secretary Vice President
NGP Blue Mountain Holdco III LLC	Brian Fairbank Andrew Studley Markus Christen	President CFO and Secretary Vice President
NGP Blue Mountain Holdco IV LLC	Brian Fairbank Andrew Studley Markus Christen	President CFO and Secretary Vice President
NGP Blue Mountain I LLC	Brian Fairbank Andrew Studley Markus Christen Scott McInnes (1)	President, CEO, and Director CFO, Secretary, and Director Vice President and Director Director
NGP Blue Mountain II LLC	Brian Fairbank Andrew Studley Markus Christen	President CFO and Secretary Vice President
NGP Blue Mountain III LLC	Brian Fairbank Andrew Studley Markus Christen	President CFO and Secretary Vice President
NGP Blue Mountain IV LLC	Brian Fairbank Andrew Studley Markus Christen	President CFO and Secretary Vice President
NGP North Valley Inc.	Brian Fairbank Andrew Studley	President and Director Secretary and Treasurer
NGP (Crump I)	Brian Fairbank Andrew Studley	President and Director Secretary and Treasurer
NGP (Pumpernickel I)	Brian Fairbank Andrew Studley	President and Director Secretary and Treasurer
NGP Truckhaven LLC	Brian Fairbank Andrew Studley Markus Christen	Director Director Director
Nevada Geothermal Power East Brawley LLC	Brian Fairbank Andrew Studley Markus Christen	Director Director Director
Nevada Geothermal Power South Brawley LLC	Brian Fairbank Andrew Studley Markus Christen	Director Director Director Director

(1) Mr. McInnes is an independent director.

Family Relationships

There are no family relationships between any of the persons named above.

Other Relationships

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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	To

Brian Fairbank	President	April 1995	Present
	Chief Executive Officer	May 1995

Andrew Studley	Chief Financial Officer and	Aug. 2007	Present
	Secretary

Summary Compensation Table

Set out below is a summary of the compensation paid to the Company’s directors and members of its administrative, supervisor or management bodies during the last fiscal year:


Name and principal position	Year	Salary ($)	Option-based awards ($)⁽¹⁾	All other compensation ($)	Total compensation ($)
Brian D. Fairbank, President & CEO	2011	$271,688	$140,109	$605	$412,402
Andrew T. Studley CFO & Secretary	2011	183,797	26,947	2,500	213,244
Markus Christen Director	2011	-	35,925	683,071	718,996
Max Walenciak Senior VP Operations and Development	2011	211,983	26,947	34,884	273,815
Kim Niggemann, VP Resource operations and external affairs	2011	173,771	26,947	$1,995	202,713
Domenic Falcone, Director	2011	-	35,868	82,846	118,714
James Yates, Director	2011	-	71,736	20,168	91,904
Gavin Cooper, Director	2011	-	35,868	28,754	64,622
Gordon Bloomquist, Director	2011	-	62,768	17,971	80,739

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⁽¹⁾The fair value of the option based awards was determined as CAD 0.36 per option at the date of the grant using the Black-Scholes option pricing model, and the following assumptions:
     Risk free interest rate: 1.7%
     Expected life: 3 years
     Expected volatility: 72%
     Expected dividend yield: 0%
⁽²⁾CAD amounts have been converted at an average exchange rate of $1.0016 CAD for every 1 USD.

The following table sets forth stock options granted by us during the fiscal year ended June 30, 2011, to our named executive officers and directors:


				Market Value
		% of Total		of Securities
		Options		Underlying
	Number of	Granted to	Exercise or	Options on the
	options	Employees in	Base Price	Date of Grant	Expiration
Name	granted	Financial Year	(CAD/Security)	(CAD/security)	Date
Brian D. Fairbank	390,000	23.0%	0.75	0.75	Dec. 21, 2015
Andrew T. Studley	75,000	4.4%	0.75	0.75	Dec. 21, 2015
Max Walenciak	75,000	4.4%	0.75	0.75	Dec. 21, 2015
Kim Niggemann	75,000	4.4%	0.75	0.75	Dec. 21, 2015
Markus Christen	100,000	5.9%	0.75	0.75	Dec. 21, 2015
Dominic Falcone	100,000	5.9%	0.75	0.75	Dec. 21, 2015
James Yates	200,000	11.8%	0.75	0.75	Dec. 21, 2015
Gavin Cooper	100,000	5.9%	0.75	0.75	Dec. 21, 2015
Gordon Bloomquist	175,000	10.3%	0.75	0.75	Dec. 21, 2015

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The following table sets forth details of all exercises of stock options during the fiscal year ended June 30, 2011 by our named executive officers and directors:


				Value of
				Unexercised in-
				the-Money Options
	Securities		Unexercised	at
	Acquired or	Aggregate Value	Options at June 30,	June 30,2011 ⁽²⁾
Name	Exercised	Realized ⁽¹⁾(CAD)	2011	(CAD)
Brian D. Fairbank	-	-	2,039,000	-
Andrew T. Studley	-	-	527,000	-
Max Walenciak	-	-	510,000	-
Kim Niggemann	-	-	440,000	-
Markus Christen	-	-	900,000	-
Dominic Falcone	-	-	950,000	-
James Yates	-	-	558,000	-
Gavin Cooper	-	-	350,000	-
Gordon Bloomquist	-	-	605,000	-

⁽¹⁾ “Aggregate Value Realized” is calculated by determining the difference between the market value of the securities underlying the options at the date of exercise and the exercise price of the options and is not necessarily indicative of the value (i.e. loss or gain) actually realized.

⁽²⁾ This represents the closing price of the Company’s shares on the Exchange (being CAD0.18) on the last day the shares traded on June 30, 2011 less the per option exercise price.

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, 2011 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 CAD1,000 per month, or CAD1,500 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.

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(e)	A committee chairman receives the aggregate sum of CAD18,000 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 CAD12,000 per fiscal year, regardless of the number of committees that such person may contribute to.

The Company paid Markus Christen, a director of the Company, the sum of $681,979 for consulting services during the 2011 fiscal year pursuant to an agreement dated January 12, 2007 (See “Related Party Transactions” below). 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.

C. Board Practices

Terms of Office


Name	Position	Office Held Since	Expiration of Current Term of Office
Brian D. Fairbank	President, CEO, Director	Director since April, 1995.	December, 2011 for directorship. Not applicable for other positions listed.
R. Gordon Bloomquist	Director	Director since March, 2003.	December, 2011
Markus K. Christen	Director	Director since January, 2003.	December, 2011
Domenic J. Falcone	Director	Director since January, 2004.	December, 2011
Gavin Cooper	Director	Director since June, 2009.	December, 2011
James 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 proper time, the incumbent directors continue in office until their successors are elected. Our last annual general meeting was held on December 7, 2010.

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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:


	Compensation
	and	Corporate
Audit	Nominating	Governance

Domenic Falcone*	Gavin Cooper*	Domenic Falcone *
James Yates	Markus Christen	James Yates
Gavin Cooper	Domenic Falcone	Markus Christen
Gordon Bloomquist	James Yates	Gavin Cooper

* Chairman of the Committee

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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. 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.

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D. Employees

The Company had 35 employees as of the end of the fiscal year ended June 30, 2011. There has been no material change in the number of employees during the past three financial years.


	2011	2010	2009
Canadian employees	20	18	12
US employees	15	15	17

Total	35	33	29

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 30, 2011.


		Number of
		Common
	Number of	Shares Subject	Current
	Common Shares	to Options or	Percentage	Exercise	Expiry
Name		Warrants	Ownership	Price	Date
				(CAD)
Brian Fairbank	5,508,053	162,000	4.5%	$0.45	Jan 21/14
		80,000		$0.45	Mar 4/14
		160,000		$0.45	Mar 19/14
		1,000,000		$0.65	Apr 04/12
		390,000		$0.75	Dec 21/15
		180,000		$1.03	May 28/13
		67,000		$1.22	Oct 16/14
Andrew Studley	nil	250,000	0.0%	$0.80	Aug 1/12
		50,000		$1.15	Nov 21/12
		90,000		$1.03	May 28/13
		100,000		$0.45	Mar 19/14
		75,000		$0.75	Dec 21/15
James Yates	nil	150,000	0.0%	$0.65	Apr. 4/12
		90,000		$1.03	May 28/13
		35,000		$0.45	Mar 19/14
		83,000		$1.22	Oct 16/14
		200,000		$0.75	Dec 21/15

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		Number of
		Common
	Number of	Shares Subject	Current
	Common Shares	to Options or	Percentage	Exercise	Expiry
Name		Warrants	Ownership	Price	Date
				(CAD)
Markus Christen	200,000	475,000	0.16%	$0.65	Apr 4/12
		90,000		$1.03	May 28/13
		100,000		$1.02	July 11/13
		100,000		$1.08	Aug 14/13
		35,000		$0.45	Mar 19/14
		100,000		$0.75	Dec 21/15
Gordon Bloomquist	95,000	255,000	0.08%	$0.65	Apr 4/12
		90,000		$1.03	May 28/13
		35,000		$0.45	Mar 19/14
		50,000		$1.22	Oct 16/14
		175,000		$0.75	Dec 21/15
Domenic Falcone	100,000	475,000	0.08%	$0.65	Apr 4/12
		90,000		$1.03	May 28/13
		100,000		$1.08	Aug 14/13
		100,000		$0.45	Mar 4/14
		85,000		$0.45	Mar 19/14
		100,000		$0.75	Dec 21/15
Gavin Cooper	nil	250,000	0.0%	$0.54	May 28/14
		100,000		$0.75	Dec 21/15

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.

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Stock Option Plan

On December 7, 2010, we 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 11, 2011 the maximum number of shares reserved for issuance under the Plan was 12,241,057 common shares, of which a total of 8,407,500 have been granted, 8,092,500 are vested and 3,833,557 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 30, 2011, we had 122,410,573 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:


		Percentage
Name	Amount Owned	of Class
Wellington Management Company, LLP⁽¹⁾	6,295,200	5.14%

(1)	As of September 30, 2011, Wellington Management, in its capacity as investment adviser, may be deemed to beneficially own 6,295,200 shares of the Issuer which are held of record by clients of Wellington Management.

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.

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Host Country Record Shareholders

As of October 31, 2011, Computershare Investor Services Inc., our registrar and transfer agent reported that we had 122,410,573 common shares issued and outstanding. Of those common shares, 74,725,728 (61%) common shares were registered to Canadian residents (25 shareholders), 45,714,752 (37%) common shares were registered to residents of the United States (53 shareholders) and 1,970,093 (2%) common shares were registered to residents of other foreign countries (4 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 provided financial advisory services in connection with arranging financing for the Blue Mountain Project. The Company paid Mr. Christen a monthly fee ranging from $12,000 to $20,000 during the term of the contract, as well as success fees upon the closing of the EIG and John Hancock loans. During fiscal 2011, the Company paid $651,538 (2010 – $252,307 and 2009 – $1,117,981) to Mr. Christen for consulting services and success fees.

(b) Amounts Payable to Directors, Officers, Key management personnel and Affiliated Companies

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As at June 30, 2011, a total of $47,266 (2010 - $71,693 and 2009 - $111,357) was owing to directors, officers and companies controlled by directors of the Company. This amount is included in accounts payable and accrued liabilities, is unsecured and payable on demand. As at June 30, 2011, $7,734 was receivable from CGC.

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.

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:

Consolidated financial statements for the year ended June 30, 2011;
Consolidated financial statements for the year ended June 30, 2010;

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. The Company is not involved in any current legal proceedings, but could be affected by a lawsuit discussed below under “Significant Changes”.

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.

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B. Significant Changes

No significant change has occurred since the date of the Company’s financial statements for the year ended June 30, 2011, except for the following:

A pentane pump failure and associated fire on September 16, 2011 has affected power generation during September and October, reducing the cash available to fund the minimum interest payments under the EIG loan.
On November 28, 2011, Californians for Renewable Energy filed a lawsuit against the DOE, the secretary of the DOE, the US Department of the Treasury, the Treasury secretary and the Federal Financing bank, attacking the loan guarantees issued under Section 1705 of the Energy Policy Act. The Section was added to the Energy Policy Act by the 2009 ARRA. The Complaint contends that the award of Section 1705 Guarantees was procedurally defective and requests that the loan guarantees be determined to be invalid. The Company is one of the recipients of such a loan guarantee. We are currently assessing the implications of the lawsuit, but if the lawsuit were upheld, it is likely to have a material impact on the Company. The Company believes that the lawsuit is unlikely to be upheld.

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-V 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 Board

Period Ended	High	Low	High	Low
2011	CAD	CAD	USD	USD

November 30	0.13	0.10	0.13	0.10
October 31	0.14	0.08	0.14	0.07
September 30	0.16	0.09	0.17	0.09
August 31	0.20	0.14	0.22	0.14
July 31	0.21	0.17	0.22	0.18
June 30	0.25	0.18	0.25	0.18

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	TSX Venture Exchange		Over-the-Counter Bulletin Board

Period Ended	High	Low	High	Low
2011	CAD	CAD	USD	USD

4^thQuarter June 30	0.65	0.18	0.68	0.18
3^rdQuarter March 31	0.76	0.58	0.77	0.58
2^ndQuarter December 31	0.88	0.59	0.89	0.58
1^Stquarter September 30	0.70	0.48	0.68	0.46

2010
4^thQuarter June 30	0.84	0.54	0.82	0.50
3^rdQuarter March 31	1.04	0.71	1.00	0.67
2^ndQuarter December 31	1.26	0.88	1.21	0.82
1^Stquarter September 30	1.15	0.60	1.07	0.52

Annual 2011	0.88	0.18	0.89	0.18
Annual 2010	1.04	0.48	1.00	0.46
Annual 2009	1.24	0.35	1.22	0.26
Annual 2008	1.31	0.28	1.28	0.22
Annual 2007	1.35	0.66	1.33	0.55

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.

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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.

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. Notice of Articles and Articles

On November 30, 2005 we adopted Notice of Articles and Articles 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.

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Our Articles also provide that the directors may, from time to time: (1) authorize the Company 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 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.

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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 rules.

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.	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)

	2.	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)

	3.	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. (Referenced by Exhibit 4.148)

	4.	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 (now EIG). (Referenced by Exhibit 4.149)

	5.	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)

	6.	Assignment of geothermal lease dated June 10, 2010, between NGPC and NGP Crump 1 with regards to the ‘O’Keeffe Ranch Geothermal Lease Agreement’ effective August 1, 2005. (Referenced by Exhibit 4.151)

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	7.	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)

	8.	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)

	9.	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)

	10.	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)

	11.	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)

	12.	Assignment and Assumption of Geothermal Leases dated November 30, 2010 between NGP Crump 1 and Crump Geothermal Company with regards to the ‘O’Keeffe 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)

	13.	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)

	14.	Assignment and Assumption Agreement dated November 30, 2010 between NGP Crump 1 and Crump Geothermal Company LLC. (Referenced by Exhibit 4.159)

	15.	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)

	16.	Asset purchase agreement between Nevada Geothermal Power Inc. and Iceland America Energy Inc. dated May 31, 2011. (Referenced by Exhibit 4.161)

	17.	Asset purchase amending agreement between Nevada Geothermal Power Inc. and Iceland America Inc. dated June 15, 2011. (Referenced by Exhibit 4.162)

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	18.	Lease between Sun Life Assurance Company of Canada, as to a 50% interest and Concert Real Estate Corporation, as to a 50% interest (collectively the “Landlord”) and Nevada Geothermal Power Inc. (Tenant) dated February 18, 2011. (Referenced by Exhibit 4.163)

	19.	Quitclaim Deed between Iceland America Energy, Inc. and Nevada Geothermal Power East Brawley LLC, dated May 31, 2011. (Referenced by Exhibit 4.164)

	20.	Quitclaim Deed between Iceland America Energy, Inc. and Nevada Geothermal Power South Brawley LLC, dated May 31, 2011. (Referenced by Exhibit 4.165)

	21.	Quitclaim Deed between Iceland America Energy, Inc. and NGP Truckhaven LLC, dated May 31, 2011. (Referenced by Exhibit 4.166)

	22.	Assignment of Geothermal Lease CACA 43302 from Iceland America Energy Inc. to NGP Truckhaven LLC effective July 1, 2011. (Referenced by Exhibit 4.167)

	23.	Federal Geothermal Lease CACA 43302 effective October 1, 2009. (Referenced by Exhibit 4.168)

	24.	Geothermal Lease and Agreement between SF Pacific Properties, LLC and Iceland America Energy, LLC effective April 1, 2006. (Referenced by Exhibit 4.169)

	25.	Geothermal Lease and Agreement between Pon et al and Iceland America, Inc., effective March 26, 2011. (Referenced by Exhibit 4.170)

	26.	Assignment of Geothermal Lease CACA 43003 from Layman Energy Associates, Inc. to NGP Truckhaven LLC effective July 1, 2011. (Referenced by Exhibit 4.171)

	27.	Layman Energy Associates Inc., amendment to Geothermal Lease CACA 43003 for removal of sections 6 and 8. (Referenced by Exhibit 4.172)

	28.	Assignment of Geothermal Lease Agreement between RLF Nevada Properties, LLC and Blue Mountain Research & Development LLC effective May 6, 2011. (Referenced by Exhibit 4.173)

	29.	Lease amending agreement between Sun Life Assurance Company of Canada, as to a 50% interest and Concert Real Estate Corporation, as to a 50% interest (collectively the “Landlord”) and Nevada Geothermal Power Inc. (Tenant) dated May 9, 2011. (Referenced by Exhibit 4.174)

	30.	Geothermal Lease and Agreement between Salton Sea Energy Investments, Inc. and ORNI 5 LLC effective February 8, 2002. (Referenced by Exhibit 4.175)

	31.	Geothermal Lease and Agreement between Atkinson/Hughes and ORNI 5 LLC effective February 2, 2002. (Referenced by Exhibit 4.176)

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	32.	Geothermal Lease Agreement effective July 5, 2011 by and between the State Of Oregon, acting by and through the Department of State lands and Crump Geothermal Company, LLC. (Referenced by Exhibit 4.177)

	33.	Geothermal Lease Agreement between Jordon/Kramer and Iceland America Energy Inc. effective February 1, 2008. (Referenced by Exhibit 4.178)

	34.	First Amendment to the Geothermal Lease and Agreement between Jordon/Kramer and Iceland America effective February 1, 2011. (Referenced by Exhibit 4.179)

	35.	Geothermal Lease Agreement between DeJong Family Trust and Iceland America Energy Inc, effective March 1, 2009. (Referenced by Exhibit 4.180)

	36.	Second Amendment to the Geothermal Lease and Agreement between Jordon/Kramer and Iceland America Energy Inc, effective February 1, 2009. (Referenced by Exhibit 4.181)

	37.	Geothermal Lease and Agreement between Rutherford Family Trust I and Iceland America Energy Inc, effective June 13, 2008. (Referenced by Exhibit 4.182)

	38.	Geothermal Lease and Agreement between Rutherford Family Trust II and Iceland America Energy Inc, effective June 13, 2008. (Referenced by Exhibit 4.183)

	39.	Geothermal Lease and Agreement between Smith Brothers Geothermal LLC and Pacific: Hydro US Holdings Inc., effective June 30, 2007. (Referenced by Exhibit 4.184)

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").

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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 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.

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The following investments by non-Canadians are subject to notification under the Investment Act:

1.	an investment to establish a new Canadian business; and

2.	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 CAD5 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 CAD312 million or more by a WTO investor (2011 threshold);

3.	indirect acquisition of control of Canadian business with assets of CAD5 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 CAD50 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; and

5.	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 CAD312-million threshold, which will be raised progressively over the next four years to CAD600 million and then to CAD1 billion, with further increases based on a prescribed formula. When the new regulations come into force, the threshold calculation will be based on ‘enterprise value’.

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 45 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

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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 non-resident insurer” or an “authorized foreign bank”, both within the meaning of the Income Tax Act (Canada) (the "ITA") and the regulations thereunder (the "Regulations").

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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 non-resident 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 property that was taxable Canadian property for the common shares of NGP.

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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 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.

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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 institution;
-	a person subject to the alternative minimum tax;
-	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.

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Distributions

Subject to the discussion below of the consequences of our potentially 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, 2013, 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 years ended June 30, 2010 and June 30, 2011. 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.

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.

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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.

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.

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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 years ended June 30, 2010 and June 30, 2011. 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 taxable years ended June 30, 2010 and June 30, 2011. 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 taxable year ending June 30, 2012 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 taxable year ended June 30, 2009 as well as any other 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.

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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.

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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.

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.

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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 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 minimis quantities 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.

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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.

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

137

received on common shares and any gain recognized in the disposition of common shares with respect to the Company and each lower-tier PFIC.

Certain information reporting requirements

Certain U.S. Investors who are individuals are required 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.

We file Annual Reports and other information with the 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 840 – 1140 West Pender 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.

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ITEM 11 Quantitative and Qualitative Disclosures about Market Risk

The Company’s activities expose it to market risk, which is risk that the fair value of future cash flows of a financial instrument will fluctuate because of the changes in market prices. Market risk includes currency risk, interest rate risk and other price risk. The Company does not participate in the use of financial instruments to mitigate these risks and has no designated hedging transactions. The Board approves and monitors the risk management processes. The Board’s main objectives for managing risks are to ensure liquidity, the fulfillment of obligations, the continued development of the Company’s geothermal properties, and to limit exposure to risks. The types of risk exposure and the way in which such exposures are attempted to be managed are as follows:

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.


	June 30, 2011			June 30, 2010
	Carrying amount of asset (liability)	10% increase in value of CAD	10% decrease in value of CAD	Carrying amount of asset (liability)	10% increase in value of CAD	10% decrease in value of CAD
Effect on net income
Cash and cash equivalents denominated in USD in Canadian operations	$ 24,084	$ (2,318)	$ 2,318	$ 804,190	$ (88,576)	$ 88,576
Accounts payable and accrued liabilities in USD in Canadian operations	(12,631)	1,216	(1,216)	-	-	-
Effect on other comprehensive income
Cash and cash equivalents denominated in CAD	5,500,062	610,907	(499,864)	989,575	109,953	(89,961)
Accounts receivable denominated in CAD	45,361	5,038	(4,123)	25,056	2,784	(2,278)
Accounts payable and accrued liabilities denominated in CAD	(367,073)	(40,772)	33,360	(650,508)	(72,279)	59,137

139

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 liabilities have a fixed interest rate of 14% for the EIG loan and 4.14% for the John Hancock loan, respectively, and are subject to fair value interest rate risk. The long-term liabilities are carried at amortized cost and changes in market interest rates will not affect income.


	June 30, 2011			June 30, 2010
	Carrying amount of asset (liability)	1% increase in interest rates	1% decrease in interest rates	Carrying amount of asset (liability)	1% increase in interest rates	1% decrease in interest rates
Effect on net income
Cash and cash equivalents with floating interest rates	$ 5,316,281	$ 59,712	$ (57,420)	$ 5,468,231	$ 109,685	$ (71,850)
Short-term restricted cash with floating rates	3,000,023	38,673	(561)	-	-	-
Long-term restricted cash with floating rates	9,383,660	113,789	(10,125)	4,005,672	15,263	(27)

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 market prices.


	June 30, 2011			June 30, 2010
	Carrying amount of asset (liability)	50% increase in share price	50% decrease in share price	Carrying amount of asset (liability)	50% increase in share price	50% decrease in share price
Effect on other comprehensive income
Marketable securities	$ 16,592	$ 8,296	$ (8,296)	$ 71,388	$ 35,694	$ (35,694)

Revenue, from excess electricity produced, is also influenced by market prices for electricity. A reasonably possible change in market prices for electricity should not have had a material impact on the Company’s financial statements.

140

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

The Company is in compliance with all the material terms of its loan agreements as of November 30, 2011.

The Company expects to successfully complete a mitigation program and reduce the currently forecast rate of resource temperature decline to something close to the initially anticipated 2.5% per year. If the mitigation program is unsuccessful the Company would have to raise funds for and develop another mitigation program if it is to continue to comply with the requirements of its PPA with NVE and the John Hancock loan covenants.

If the current mitigation program is successful additional drilling, which requires funding, will remain necessary to meet the terms of the EIG loan. The Company expects to breach the EIG debt service coverage ratio at December 31, 2011 and anticipates difficulty making the minimum interest payment early in 2012. In the event of a default EIG 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. The Company is working with advisors and EIG to develop a plan to manage the EIG loan.

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 communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

141

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 Code of Federal Regulations 240.13a-15(e) or 240.15d – 15(e)) as of June 30, 2011. 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, 2011.

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 Code of Federal Regulations 240.13a-15(f) or 240.15d – 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, 2011, 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, 2011.

This annual report includes an attestation report of the company’s registered public accounting firm, Deloitte and Touche LLP, regarding internal control over financial reporting.

142

Changes in Internal Control over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting identified that occurred during the period covered by this annual report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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” within the meaning of Item 16A(b) of Form 20-F. Mr. Falcone possesses the educational and professional qualifications and experience to qualify as such. In addition to Mr. Falcone, Gavin Cooper, CA, also qualifies as an audit committee financial expert.

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.

143

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.

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.

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’s independence.

144

Audit Fees

The aggregate fees 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, 2011 was $228,519 (2010: $117,028). These services also include those that are normally provided in connection with statutory and regulatory filings or engagements for those fiscal years.

Audit Related Fees

For the fiscal year ended June 30, 2011, 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 $30,909 (2010: $51,388). This amount includes administration charges, out of pocket expenses and fees billed for review engagements.

Tax Fees

For the fiscal year ended June 30, 2011, the aggregate fees billed for tax compliance, tax advice and tax planning by Deloitte & Touche LLP were $95,329 (2010: $78,124). In 2011 these fees related primarily to the preparation of tax returns.

All Other Fees

For the fiscal year ended June 30, 2011, the aggregate fees billed by Deloitte & Touche LLP for professional services, other than those services listed above, totalled $142,882 (2010: $303,445). In 2011 this amount related primarily to assistance with grant applications and restructuring activities.

ITEM 16D. Exemption from the Listing Standards for Audit Committees

Not Applicable.

145

ITEM 16E Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Not Applicable.

ITEM 16F Change in Registrant’s Certifying Accountant

Not Applicable.

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 30 therein). For a history of exchange rates in effect for Canadian dollars as against U.S. dollars, see Page 11 of this Annual Report.

The following financial statements are filed as part of the Annual Report:


-	Consolidated financial statements for the year ended June 30, 2011.

ITEM 18 Financial Statements

See Item 17.

146

ITEM 19 Exhibits

The following exhibits are being filed as part of this Annual Report, or are incorporated by reference where indicated:


	Description of Exhibit

1. *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 Holders

2.1	Specimen Certificate of Common Stock.⁽¹⁾

2.2	Incentive Stock Option Plan adopted November 30, 2005 (Also listed under Exhibit 4.34).⁽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⁾

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⁾

147


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⁾

2.11	Incentive Stock Option Plan adopted November 29, 2007. ⁽⁷⁾

2.12	Incentive Stock Option Plan adopted December 7, 2010. ⁽⁷⁾

2.13	Finders' Fee Agreement between Nevada Geothermal Power and KBH Capital Corp dated August 20, 2010. ⁽⁷⁾

2.14	Form of Finder’s Option for the Purchase of Units between Nevada Geothermal Power Inc. and Global Resource Investments Ltd., dated September 24, 2010. ⁽⁷⁾

2.15	Form of Finder’s Option for the Purchase of Units between Nevada Geothermal Power Inc. and KBH Capital Corp. dated September 24, 2010. ⁽⁷⁾

2.16	Form of Finder’s Option for the Purchase of Units between Nevada Geothermal Power Inc. and Jacob Securities Inc. dated September 24, 2010. ⁽⁷⁾

149


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⁾

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⁾

150


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 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’Keeffe Ranch Geothermal Lease Agreement between Noramex Corporation and O’Keeffe Ranch regarding Crump Geyser, effective date of August 1, 2005. ⁽¹⁾

151


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 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⁾

152


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⁾

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⁾

153


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, 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 2^nd,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⁾

154


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⁾

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⁾

155


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⁾

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⁾

156


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⁾

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⁾

157


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 8^th, 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, 2008. ⁽³⁾

158


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⁾

159


4.122	Cash Settled Option issued by NGP Blue Mountain HoldCO LLC. to Trust Company of the West for Note Holder (Boilermaker-Blacksmith Pension Trust) of NGP I, 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 I, 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 I, 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 I, 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 I, pursuant to Note Purchase Agreement. Dated: August 29, 2008. ⁽³⁾

160


4.136	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 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 2^nd, 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)}

161


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⁾

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⁾(5)

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’Keeffe 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⁾

164


8.	Subsidiaries

8.1	List of Subsidiaries ⁽⁷⁾

11.	Code of Ethics

11.1	Code of Business Conduct and Ethics (incorporated as part of Item 15.1) ⁽¹⁾

12.	302 Certification

12.1	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. ⁽⁷⁾

12.2	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. ⁽⁷⁾

13.	906 Certification

13.1	Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ⁽⁷⁾

⁽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.

⁽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.

165

⁽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 December 1, 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⁾Incorporated by reference, to the same exhibit number, to the Company’s Annual Report on Form 20-F, for the year ended June 30, 2010, as filed with the Securities and Exchange Commission on December 21, 2010.

⁽⁷⁾Filed herewith.

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 21, 2011


ITEM 16D	Exemptions from the Listing Standards for Audit Committees	144

ITEM 16E	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	145

ITEM 16F	Change in Registrant’s Certifying Accountant	145

ITEM 16G	Corporate Governance	145

PART III

ITEM 17	Financial Statements	145

ITEM 18	Financial Statements	145

ITEM 19	Exhibits	146

	Signatures	165

	-	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;
	-	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;
	-	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.

-	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.


2.17	Warrant Certificate for US purchasers dated September 24, 2010, with an exercise price of Canadian $0.70. ⁽⁷⁾

2.18	Warrant Certificate for Canadian purchasers dated September 24, 2010, with an exercise price of Canadian $0.70. ⁽⁷⁾

2.19	Form of Warrant issued to Trust Company of the West for 1,000,000 shares with an exercise price of Canadian $1.50 dated September 2, 2010. ⁽⁷⁾

2.20	Form of Warrant issued to TCW Energy Fund XIV, L.P. for 1,092,619 shares with an exercise price of Canadian $1.50 dated September 2, 2010. ⁽⁷⁾

2.21	Form of Warrant issued to TCW Energy Fund XIV-A, L.P. for 1,222,782 shares with an exercise price of Canadian $1.50 dated September 2, 2010. ⁽⁷⁾

2.22	Form of Warrant issued to TCW Energy XIV Blocker (NGP Blue Mountain), L.L.C. for 934,599 shares with an exercise price of Canadian $1.50 dated September 2, 2010. ⁽⁷⁾

2.23	Form of Warrant issued to TEP Equity Holdings Cayman Blocker, Ltd. For 250,000 shares with an exercise price of Canadian $1.50 dated September 2, 2010. ⁽⁷⁾

4. Material Contracts

4.1	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⁾


4.157	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⁾

4.159	Assignment and Assumption Agreement dated November 30, 2010. ⁽⁶⁾

4.160	Parent Company Guarantee dated November 30, 2010. ⁽⁶⁾

4.161	Asset purchase agreement between Nevada Geothermal Power Inc. and Iceland America Energy Inc. dated May 31, 2011. ⁽⁷⁾

4.162	Asset purchase amending agreement between Nevada Geothermal Power Inc. and Iceland America Inc. dated June 15, 2011. ⁽⁷⁾

4.163	Lease between Sun Life Assurance Company of Canada, as to a 50% interest and Concert Real Estate Corporation, as to a 50% interest (collectively the “Landlord”) and Nevada Geothermal Power Inc. (Tenant) dated February 18, 2011. ⁽⁷⁾

4.164	Quitclaim Deed between Iceland America Energy, Inc. and Nevada Geothermal Power East Brawley LLC, dated May 31, 2011. ⁽⁷⁾

4.165	Quitclaim Deed between Iceland America Energy, Inc. and Nevada Geothermal Power South Brawley LLC, dated May 31, 2011. ⁽⁷⁾

4.166	Quitclaim Deed between Iceland America Energy, Inc. and NGP Truckhaven LLC, dated May 31, 2011. ⁽⁷⁾

4.167	Assignment of Geothermal Lease CACA 43302 from Iceland America Energy Inc. to NGP Truckhaven LLC effective July 1, 2011. ⁽⁷⁾

4.168	Federal Geothermal Lease CACA 43302 effective October 1, 2009. ⁽⁷⁾

4.169	Geothermal Lease and Agreement between SF Pacific Properties, LLC and Iceland America Energy, LLC effective April 1, 2006. ⁽⁷⁾

4.170	Geothermal Lease and Agreement between Pon et al and Iceland America, Inc., effective March 26, 2011. ⁽⁷⁾

4.171	Assignment of Geothermal Lease CACA 43003 from Layman Energy Associates, Inc. to NGP Truckhaven LLC effective July 1, 2011. ⁽⁷⁾

4.172	Layman Energy Associates Inc., amendment to Geothermal Lease CACA 43003 for removal of sections 6 and 8. ⁽⁷⁾


4.173	Assignment of Geothermal Lease Agreement between RLF Nevada Properties, LLC and Blue Mountain Research & Development LLC effective May 6, 2011. ⁽⁷⁾

4.174	Lease amending agreement between Sun Life Assurance Company of Canada, as to a 50% interest and Concert Real Estate Corporation, as to a 50% interest (collectively the “Landlord”) and Nevada Geothermal Power Inc. (Tenant) dated May 9, 2011. ⁽⁷⁾

4.175	Geothermal Lease and Agreement between Salton Sea Energy Investments, Inc. and ORNI 5 LLC effective February 8, 2002. ⁽⁷⁾

4.176	Geothermal Lease and Agreement between Atkinson/Hughes and ORNI 5 LLC effective February 2, 2002. ⁽⁷⁾

4.177	Geothermal Lease Agreement effective July 5, 2011 by and between the State Of Oregon, acting by and through the Department of State lands and Crump Geothermal Company, LLC. ⁽⁷⁾

4.178	Geothermal Lease Agreement between Jordon/Kramer and Iceland America Energy Inc. effective February 1, 2008. ⁽⁷⁾

4.179	First Amendment to the Geothermal Lease and Agreement between Jordon/Kramer and Iceland America effective February 1, 2011. ⁽⁷⁾

4.180	Geothermal Lease Agreement between DeJong Family Trust and Iceland America Energy Inc, effective March 1, 2009. ⁽⁷⁾

4.181	Second Amendment to the Geothermal Lease and Agreement between Jordon/Kramer and Iceland America Energy Inc, effective February 1, 2009. ⁽⁷⁾

4.182	Geothermal Lease and Agreement between Rutherford Family Trust I and Iceland America Energy Inc, effective June 13, 2008. ⁽⁷⁾

4.183	Geothermal Lease and Agreement between Rutherford Family Trust II and Iceland America Energy Inc, effective June 13, 2008. ⁽⁷⁾

4.184	Geothermal Lease and Agreement between Smith Brothers Geothermal LLC and Pacific: Hydro US Holdings Inc., effective June 30, 2007. ⁽⁷⁾