management’s discussion & analysis for the year ended...

Management’s Discussion & Analysis For the Year Ended December 31, 2012

Suite 600 – 888 Dunsmuir Street, Vancouver, BC, V6C 3K4 Tel: (604) 669-4999 Fax: (604) 682-3727

www.alterrapower.ca

Management’s Discussion and Analysis

ALTERRA POWER CORP. | Twelve Month Report 2012 2

TABLE OF CONTENTS

INTRODUCTION ............................................................................................................................ 3

CORE BUSINESS AND STRATEGY ................................................................................................... 3

HIGHLIGHTS AND UPDATES FOR THE YEAR ENDED DECEMBER 31, 2012 ................................... 5

OPERATIONS REVIEW ................................................................................................................... 7

EXPANSION AND DEVELOPMENT PROJECTS – INFORMATION, UPDATES AND OUTLOOK ........ 12

EARLY STAGE DEVELOPMENT AND EXPLORATION PROJECTS – INFORMATION, UPDATES AND OUTLOOK .................................................................................................................................... 14

SELECTED ANNUAL INFORMATION ............................................................................................ 17

REVIEW OF RESULTS FOR THE YEAR ENDED DECEMBER 31, 2012 ............................................ 17

SUMMARY OF QUARTERLY RESULTS .......................................................................................... 19

QUARTERLY FINANCIAL REVIEW FOR THE THREE MONTHS ENDED DECEMBER 31, 2012 ........ 20

LIQUIDITY AND CAPITAL RESOURCES ......................................................................................... 22

TRANSACTIONS WITH RELATED PARTIES ................................................................................... 23

OFF-BALANCE SHEET ARRANGEMENTS ...................................................................................... 23

OTHER RISKS AND UNCERTAINTIES ............................................................................................ 24

CRITICAL ACCOUNTING POLICIES AND MANAGEMENT ESTIMATES .......................................... 24

FUTURE ACCOUNTING STANDARDS ........................................................................................... 30

MANAGEMENT'S REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING AND DISCLOSURE CONTROLS AND PROCEDURES .............................................................................. 33

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING .............................................. 33

DISCLOSURE OF OUTSTANDING SHARE DATA ........................................................................... 34

ALTERNATIVE PERFORMANCE MEASURES ................................................................................. 34



March 27, 2013

INTRODUCTION

The following Management’s Discussion and Analysis (“MD&A”) is intended to help the reader understand the significant factors that have affected Alterra Power Corp.’s and its subsidiaries’ (the “Company”) performance and such factors that may affect its future performance. The MD&A should be read in conjunction with the Company’s audited consolidated financial statements for the year ended December 31, 2012 and the related notes thereto. All figures are expressed in U.S. dollars except where otherwise indicated. Reference to C$ are to Canadian dollars. The Company reports its consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The Company’s significant accounting policies are set out in Note 3 of the audited consolidated financial statements. This MD&A refers to various non-Generally Accepted Accounting Principles (“GAAP”) measures, such as “net interest”, by which the Company means the effective portion of results that the Company would have reported if each of HS Orka hf (75% for 2 months of the year and 66.6% for the remaining 10 months), the Toba Montrose General Partnership (40%), the Dokie General Partnership (51%), and the Soda Lake facility (100%) had been reported in accordance with Alterra’s actual share ownership for the twelve months ended December 31, 2012. This measure is used by the Company to better manage and evaluate performance at each of the Company’s operating facilities and to further assist the Company’s shareholders in understanding the Company’s holding, but does not have standardized meaning. To facilitate a better understanding of these measures as calculated by the Company, reconciliations have been provided where applicable. Except for historical information contained in this MD&A, the following disclosures are forward-looking statements within the meaning of applicable Canadian provincial securities laws relating to the Company and its operations. Please refer to the cautionary note regarding the risks associated with forward-looking statements at the back of this MD&A and the “Risk Factors” in the Annual Information Form on file with the Canadian provincial securities regulatory authorities. Additional information and disclosure relating to the Company can be found on the Company’s website at www.alterrapower.ca and on the SEDAR website at www.sedar.com. Information contained in or otherwise accessible through our website does not form part of the MD&A and is not incorporated into the MD&A by reference.

CORE BUSINESS AND STRATEGY

The Company is engaged in the operation, development, exploration and acquisition of renewable power projects. The Company operates six power plants totalling 566 mega-watts (“MW”) of capacity, with operations in Canada, Iceland and the United States. As at December 31, 2012, the Company’s operating facilities consisted of a 66.6% net interest in two geothermal power plants in Iceland (Svartsengi and Reykjanes owned and operated through HS Orka hf), a 100% interest in one geothermal power plant in Nevada (“Soda Lake”), a 40% net interest in two run of river hydro power plants in British Columbia (“Toba Montrose”, owned and operated through the Toba Montrose General Partnership) and a 51% net interest in a wind farm in British Columbia (“Dokie 1”, owned and operated through the Dokie General Partnership).

http://www.alterrapower.ca/

http://www.sedar.com/



The Company’s current portfolio of operating facilities is summarized as follows:

Reykjanes Iceland

Svartsengi Iceland

Soda Lake Nevada, US

Toba Montrose BC, Canada

Dokie 1 BC, Canada

Type of generation Geothermal Geothermal Geothermal Run of river hydro

Wind

Capacity 100 MW 72 MW 15 MW 235 MW 144 MW

Forecast annual electricity generation

798,000 MWh

460,000 MWh

84,000 MWh

727,000 MWh

330,000 MWh

% included in consolidated financial statements

100% 100% 100% 40% under equity income

51% under equity income

In addition to the operating facilities, the Company has assets under construction in Iceland with respect to a planned expansion at the Reykjanes facility, three advanced-stage exploration geothermal properties in Iceland (the Eldvörp, Krýsuvík and Trölladyngja properties), several advanced-stage exploration geothermal properties in Nevada (including the McCoy and Desert Queen properties), two advanced-stage development run of river projects and an advanced-stage development wind project in British Columbia (the Upper Toba Valley project and the Dokie 2 wind expansion project) and the Mariposa advanced-stage development geothermal property interest in Chile. The Company’s exploration and development pipeline also includes a number of early-stage properties in British Columbia, the United States, Italy, Chile, Iceland and Peru. The Company was incorporated on January 22, 2008, pursuant to the Business Corporations Act (British Columbia) and effectively commenced operations in February 2008. The Company’s head office is located in Vancouver, British Columbia (“BC”), Canada, it is a reporting issuer in all the provinces of Canada except the Province of Quebec, and its common shares trade on the Toronto Stock Exchange under the symbol AXY. The Company’s mission is to be a leading global renewable power company through continued excellence in production and safety as a premier operator/manager, successful origination and development of new utility-scale projects, and opportunistic acquisitions of other renewable power projects and development assets. To execute this strategy, the Company has assembled a core team of professionals with a depth of exploration, construction, operating, and financial knowledge that allows the Company to confidently advance early stage projects through construction into operation. The Company has a proven ability to develop and deliver large assets at greenfield locations, on-time and on-budget. In addition to maximizing value for its shareholders the core values of the Company include being responsible for the environment in which the Company operates, contributing to the long-term development of host communities and ensuring that employees can work in a safe and secure manner. The Company is committed to maintaining positive relations with employees, the local communities and the government agencies, all of whom are viewed as partners.



HIGHLIGHTS AND UPDATES FOR THE YEAR ENDED DECEMBER 31, 2012

Operations

For the year ended December 31, 2012, the Company’s operating assets performed at a combined 94% of forecast generation (98% of budget), as follows (the performance of each facility is discussed below under the section “Operations Review”):

Facility Forecast (b)

2012 Budget (c) 2012 Actual Net interest % of Forecast % of Budget

Reykjanes 798,000 770,210 760,770 518,167 95% 99%

Svartsengi 460,000 423,350 466,817 317,185 101% 110%

Soda Lake 84,000 78,000 64,421 64,421 77% 83%

Toba Montrose 727,000 699,400 661,409 264,564 91% 95%

Dokie 1 330,000 330,000 297,387 151,667 90% 90%

TOTAL 2,399,000 2,300,960 2,250,804 1,316,004 94% 98%

Generation MWh (a)

(a)

- MWh refers to mega-watt hours. (b)

- Long-term forecast annual generation (c)

- Budgeted annual generation, which reduces long-term forecast annual generation for planned maintenance outages

In February 2012, HS Orka hf (“HS Orka”) received ISK 4.7 billion ($37.5 million) from the issuance of HS Orka shares from treasury. A group of Icelandic pension funds (“Jarðvarmi”), which previously held a 25.0% interest in HS Orka, exercised an option to increase its stake to 33.4% by purchasing new shares of HS Orka, adjusting the Company’s interest in HS Orka from 75.0% to 66.6%.

Subsequent to this the Company received an unsolicited offer from an Icelandic consortium to purchase the Company’s remaining 66.6% interest in HS Orka. The Company continues to discuss the sale of HS Orka with prospective purchasers.

During the third quarter, the Company (through HS Orka) signed a contract with Iceland Drilling Ltd. to have two new wells drilled at its Reykjanes reservoir in Iceland as well as one work-over of an existing well. Drilling commenced in November 2012 and one well was completed at the Reykjanes field in January 2013, and initial indications for the completed production well are positive. Drilling for the remaining well is expected to be completed by the spring of 2013. The expected cost for the drilling program is $9 million, which will be paid from cash reserves at HS Orka. The new capacity expected to result from the drilling will be used for the planned 80 MW expansion and as reserve capacity for the existing 100 MW plant.

On December 31, 2012 the Toba Montrose General Partnership (“TMGP”) declared equity distributions of C$7.0 million to the partners, of which the Company’s portion was C$2.8 million. The cash was received by the Company subsequent to the year-end.

In the twelve months ended December 31, 2012 the Dokie General Partnership (“DGP”) completed funding of a C$8.9 million required loan reserve and also paid or declared equity distributions of C$4.0 million to the partners, of which the Company’s portion was C$2.0 million. All outstanding distributions were received subsequent to the year-end.

In December 2012, the Company and Fiera Axium Infrastructure (“Fiera Axium”) became partners at Toba Montrose and Dokie 1, when a consortium of Canadian investors led by Fiera



Axium purchased GE Energy Financial Services' (“GE EFS”) partnership interests, and now owns a 60% interest in Toba Montrose and a 49% interest in Dokie 1. The Company’s ownership interests in these facilities are unchanged at 40% and 51% respectively and the Company continues to be the operator of both facilities.

A major rockslide occurred at Toba Montrose in December 2012 affecting the Montrose penstock. Repairs are expected to be completed by the summer of 2013. Repairs and business interruption costs are fully insured (subject to policy deductibles).

Project Development, Expansion and Exploration

The Company expects to acquire a 10% interest in a 50 MW portfolio of five photovoltaic solar farms (“ABW Solar”) being built in Ontario by First Solar Inc. subject to fulfillment of certain conditions precedent. Construction of ABW Solar began in 2012 following receipt of certain key permits and continued throughout the year.

In April 2012, an agreement was signed with BC Hydro and Power Authority (“BC Hydro”) allowing the Upper Toba run of river hydroelectric project (“Upper Toba Project”) to interconnect to the BC Hydro Saltery Bay substation.

The Company subsequently signed an agreement with a contractor to carry out design work for the Upper Toba project. The Company is currently focused on design and preparation for the initial 62 MW portion of the project (the “Jimmie Creek” project).

In May 2012, the Company signed a Resource Development Agreement (“RDA”) with the Klahoose First Nation for the Upper Toba project, establishing the framework under which the Company and the Klahoose First Nation will work together to advance the project. The Company now has agreements in place with all First Nations affected by the project.

The Company entered into an agreement in May 2012 to acquire a portfolio of early stage wind development assets in coastal BC with potential generation capacity in excess of 1,000 MW.

The Sliammon First Nation and the Company signed an RDA in June 2012 that will facilitate the development of the transmission infrastructure for the Bute Inlet run of river hydroelectric project.

In October of 2012, the Company entered into an agreement with Energy Development Corporation (“EDC”), a Philippines-based global leader in the geothermal power industry, for the continued development of the Mariposa geothermal project in Chile and five of the Company’s Peruvian geothermal concessions. If advanced into a formal joint venture, EDC will be entitled to earn a 70% interest by funding the next $58.3 million in project expenditures at Mariposa and $8.0 million in project expenditures on the Peruvian concessions. Throughout the fourth quarter of 2012 and into 2013 the Company and EDC have been actively documenting the next-phase agreement toward full partnership, while EDC continues to conduct its due diligence in parallel. The Company expects final arrangements to be completed within the first half of 2013.



Financial

The Company reported steady gross earnings of 24% of revenues for the twelve months ended December 31, 2012, marginally down from the six months ended December 31, 2011 (25% gross earnings).

The Company’s 2012 net interest in revenue and project EBITDA was $87.2 million and $46.8 million respectively. While these results are not directly comparable to the six months ended December 31, 2011, pro forma financial information for the twelve months ended December 31, 2011 is shown in the Operations Review below, for comparative purposes.

For the twelve months ended December 31, 2012, the Company generated positive cash flow from operations of $12.1 million and ended the year with positive working capital of $29.3 million.

In March 2012, the US Department of the Treasury awarded and paid a grant of $2.1 million to the Company’s Soda Lake division under the American Recovery and Reinvestment Act of 2009.

OPERATIONS REVIEW

Reykjanes and Svartsengi geothermal facilities, Iceland (66.6% interest)

The Company, through its Icelandic subsidiary HS Orka, produces and sells electricity from two operating geothermal plants (Reykjanes and Svartsengi) located in the Reykjanes peninsula of Iceland. The Reykjanes plant has 100 MW of generation capacity and is budgeted to generate 798,000 MWh of electricity annually, while the Svartsengi plant has 72 MW of generation capacity and is budgeted to generate 460,000 MWh of electricity as well as 150 thermal MW of hot water for district heating. HS Orka sells power to a number of commercial and retail customers including power sold under two long term power purchase agreements (“PPAs”): one with Landsvirkjun, an energy company owned by the Icelandic state, that terminates at the end of 2019 and one with Norðurál Grundartangi ehf (together with its affiliates, “Norðurál”), an operator of aluminum smelters in Iceland, which terminates in June 2026.

All obligations of HS Orka are non-recourse to the Company. The remaining portion of the Company’s investment in HS Orka may not be fully recoverable if there were an incurred event of default.

The Company has commenced drilling of two new wells at its Reykjanes reservoir in Iceland as well as one work-over of an existing well. The primary purpose of the wells is to be used for the planned 80 MW expansion and as reserve capacity for the existing 100 MW plant. Drilling commenced on these wells in November 2012 and one well was completed in early 2013 and the remaining well is expected to be completed by spring of 2013.

The operating results of the Reykjanes and Svartsengi facilities are shown below and reflect the Company’s actual ownership interest during the period, specifically 75% interest from January 1 to February 29, 2012 and 66.6% interest for the remainder of 2012 (six months ended December 31, 2011 – 75% interest) in the facilities:



Actual

($000 except where specified)

Twelve months ended

December 31, 2012

Six months ended

December 31, 2011

Generation (MWh) 835,352 457,090

Revenue 38,560 24,190

EBITDA (a)16,440 7,339

a – EBITDA is a non-GAAP measure. Please refer to the section “Alternative Performance Measures” for the definition of EBITDA applied in this calculation

Overall, the combined performance of the Reykjanes and Svartsengi facilities was 98% of forecast generation for the twelve months ended December 31, 2012.

Due to both the change in the Company’s year-end and the change in ownership of HS Orka in 2012, the results are not directly comparable. Pro forma information is shown below which reflects what the results would have been had Alterra consolidated 66.6% of HS Orka for the twelve month period ended December 31, 2012 and 2011:

Pro forma

($000 except where specified)

Twelve months ended

December 31, 2012 (b)

Twelve months ended


Generation (MWh) 817,459 838,292

Revenue 38,367 44,516

EBITDA (a)15,214 15,369

a – EBITDA is a non-GAAP measure. Please refer to the section “Alternative Performance Measures” for the definition of EBITDA applied in this calculation.

b –This information is based on annual reporting from HS Orka, it includes purchase price adjustments for below market contracts, and has been translated at the average rate of exchange for the twelve month period. Here and elsewhere all pro forma information has not been audited or reviewed by the Company’s auditors and is provided for additional comparative information only.

Generation and revenue decreased against the prior year, primarily due to the expiration of a 35 MW contract in October 2011 which resulted in a scaling back of production, coupled with a 7.8% weakening of the ISK against the US Dollar, and a decline in aluminum prices that were on average 15.2% lower in 2012 than in 2011. In 2012 approximately 34% of HS Orka's revenue was indexed to the price of aluminum (2011: 44%). New sales contracts have been entered into in 2013 which will require an increase in generation going forwards.

EBITDA increased by 6.7% in ISK primarily due to a reduction of non-recurring expenses in 2012 related to the Nordural contract arbitration. In US dollars EBITDA decreased by 1.0% due to weakening of the Icelandic Krona.

Soda Lake geothermal facility, Nevada, USA (100% interest)

The Company’s Soda Lake facility consists of two binary geothermal power production plants currently operating at a maximum of 15 MW gross capacity. The Soda Lake facility sells its entire net electrical output to NV Energy, Inc. under two 30 year PPAs that terminate in 2017 and 2021.

The operating results of the Soda Lake facility are shown below and reflect the Company’s 100% interest in the facility:



($000 except where specified) Pro forma

Twelve months ended

December 31, 2012

Six months ended

December 31, 2011

Twelve months ended


Generation (MWh) 64,421 33,664 71,970

Revenue 4,406 2,405 5,163

EBITDA (a)

(614) 809 949

Actual

a – EBITDA is a non-GAAP measure. Please refer to the section “Alternative Performance Measures” for the definition of EBITDA applied in this calculation. b - This financial information has been prepared from the financial results of Soda Lake.

Generation and revenue in 2012 were down against the pro forma comparative period due to additional downtime for maintenance activities in the power plant plus delays in bringing two geothermal wells online. One of the wells was placed into production during the fourth quarter of 2012 and generation capacity is expected to increase by 0.5 MW in 2013.

EBITDA is lower than the pro forma comparative period, due in part to lower revenues, increased maintenance expense in 2012, as well as additional costs associated with the removal of a pump from one production well and the installation of the two new pumps at the end of the year.

During 2012 the Company received a $2.1 million grant under Section 1603 of the American Recovery and Reinvestment Act of 2009, US Department of the Treasury, with respect to certain facility improvements.

Toba Montrose hydroelectric facility, British Columbia, Canada (40% interest)

The Company holds a 40% economic interest and 51% voting interest in TMGP which owns and operates the Toba Montrose run of river hydroelectric facility. The remaining 60% economic interest in TMGP is held by Fiera Axium. After 35 years of operations, the Company’s economic interest in TMGP will increase from 40% to 51% for no additional consideration.

TMGP sells electricity to BC Hydro under a PPA that expires in May 2045. The Toba Montrose hydroelectric facility is expected to generate a long term average of 727,000 MWh of electricity annually.

The Toba Montrose hydroelectric facility is EcoLogo certified and receives funding under the Government of Canada’s ecoEnergy for Renewable Power program (the “ecoEnergy program”) of up to C$72.7 million during its first ten years of operations, at a rate of C$10 per MWh.

The Toba Montrose hydroelectric facility’s annual long term generation is projected to vary seasonally in the following proportions:

January – March 4% April – June 32% July – September 52% October – December 12%

TMGP operates the Toba Montrose hydroelectric facility in cooperation with the Klahoose, Sliammon and Sechelt First Nations.



All obligations of TMGP are non-recourse to the Company. The remaining portion of the Company’s investment in TMGP may not be fully recoverable if there were an incurred event of default.

The operating results of the Toba Montrose facility is shown below and reflect the Company’s 40% interest in the facility:


Twelve months ended

December 31, 2012

Six months ended

December 31, 2011

Twelve months ended


Generation (MWh) 264,564 176,159 254,095

Revenue 27,238 18,562 25,830

EBITDA (a)

20,463 14,244 19,011

Actual

a – EBITDA is a non-GAAP measure. Please refer to the section “Alternative Performance Measures” for the definition of EBITDA applied in this calculation.

b – This information has been prepared from the twelve months results of Toba Montrose adjusted to include purchase price adjustments and an assumed purchase of Toba Montrose by the Company on January 1, 2011.

Revenue and generation at the Toba Montrose facility for the twelve month period ended December 31, 2012 is higher than the pro forma comparative period. The increase is due in to an uplift in the firm energy price in the current year against the comparative period pro forma and a 4% increase in flows in 2012. In July 2012 the Toba Montrose achieved a new daily production record of 5,504 MWh.

EBITDA was higher than the comparative period pro forma due to an increase in revenue related to the increased water flow mentioned above offset in part by increased maintenance costs in 2012 in addition to higher water rental charges due to the increased flows in the period.

On December 12, 2012 a naturally occurring rockslide damaged a 300 meter section of the five kilometer penstock (which supplies water from the intake to the power generating plant) at the Montrose facility. Replacement pipe for the 300 meter damaged section has been ordered, and preparations for the repair have begun. The Company expects the facility to return to full operations in the summer of 2013.

The repairs are to be carried out during the first half of 2013 when water flows and power generation are lower. The project's insurers have confirmed that the incident is covered by property and business interruption insurance, and total insurance deductibles related to the rockslide are expected to be less than $1.0 million for the Toba Montrose project (of which the Company’s interest is 40%).

Dokie 1 wind farm, British Columbia, Canada (51% interest)

The Company holds a 51% interest in DGP which owns the Dokie 1 wind farm in northern British Columbia. The remaining 49% interest in DGP is held by Fiera Axium. The Dokie 1 wind farm consists of 48 Vestas V-90 wind turbines, and is expected to generate a combined long term average of 330,000 MWh of electricity annually.

DGP sells electricity to BC Hydro under a PPA that expires in February 2036.

The Dokie 1 wind farm is EcoLogo certified and receives funding under the ecoEnergy program, of up to C$33.3 million during its first ten years of operations, at a rate of C$10 per MWh.



The Dokie 1 wind farm’s annual long term generation is projected to vary seasonally in the following proportions:

January – March 28% April – June 20% July – September 22% October – December 30%

DGP operates the Dokie 1 wind farm in cooperation with the Halfway River, West Moberly and Saulteau First Nations and the McLeod Lake Indian Band.

All obligations of DGP are non-recourse to the Company. The remaining portion of the Company’s investment in DGP may not be fully recoverable if there were an incurred event of default.

The operating results of the Dokie 1 wind farm is shown below and reflect the Company’s 51% interest in the facility:


Twelve months ended

December 31, 2012

Six months ended

December 31, 2011

Twelve months ended


Generation (MWh) 151,667 110,697 167,557

Revenue 17,034 11,913 16,650

EBITDA (a)

10,550 8,404 10,748

Actual

a – EBITDA is a non-GAAP measure. Please refer to the section “Alternative Performance Measures” for the definition of EBITDA applied in this calculation. b – This information has been prepared from the twelve months results of Dokie 1 adjusted to include purchase price adjustments and an assumed purchase of Dokie 1 wind farm by the Company on January 1, 2011.

Despite a reduction in generation in 2012 against the comparative period pro forma, due to lower winds experienced and repairs completed during the fourth quarter of 2012, the revenue generated in 2012 was 7% higher than the comparative period pro forma. A contributing factor is that in May 2012, DGP exercised a one-time right in its PPA to increase its firm energy allotment by 10% but in addition to this the 2011 pro forma revenue includes pre completion revenue which was sold to Powerex at a significantly lower price than the EPA with BC Hydro which contributed to higher overall revenues in 2012.

EBITDA was marginally down against the pro forma comparative period, predominately as a result of increased revenue in the period off-set by an increase in maintenance costs.

Summary Pro Forma Net interest Comparative Results and EBITDA

In summary, the following pro forma results represent what the Company’s net interest in the operating facilities would have been had the Company reported the results representing the Company’s ownership percentage in effect as at December 31, 2012 of HS Orka (66.6%), TMGP (40%), DGP (51%), and Soda Lake (100%) for both calendar years. Pro forma information – twelve months ended December 31, 2012



For the 12 months ended

December 31, 2012

HS Orka

(66.6%)

Toba Montrose

(40%) (a)

Dokie 1

(51%) (a)

Soda Lake

(100%) (a) Total

Production (MWh) 817,459 264,564 151,667 64,421 1,298,111

Revenue 38,367$ 27,238$ 17,034$ 4,406$ 87,045

EBITDA (b, c)15,214 20,463 10,550 (614) 45,613

Pro forma information – twelve months ended December 31, 2011 For the 12 months ended

December 31, 2011

HS Orka

(66.6%)

Toba Montrose

(40%)

Dokie 1

(51%)

Soda Lake

(100%) Total

Production (MWh) 838,292 254,095 167,557 71,970 1,331,914

Revenue 44,516$ 25,830$ 16,650$ 5,163$ 92,159

EBITDA (b, c)

15,369 19,011 10,748 949 46,077

(a) – Actual results for the year ended December 31, 2012. (b) – EBITDA is a non-GAAP measure as defined above. (c) - This financial information has been prepared from the financial results of each operating facility. This information has not been audited

or reviewed by Alterra’s auditors and is purely provided for additional comparative information only.

EXPANSION AND DEVELOPMENT PROJECTS – INFORMATION, UPDATES AND OUTLOOK

ABW Solar project, Ontario, Canada In January 2011, the Company and GE EFS agreed to acquire a 50 MW portfolio of five photovoltaic solar farms being built in Ontario by First Solar, Inc. First Solar, Inc. began construction of ABW Solar in May 2012 with completion of construction expected in the first half of 2013. Completion of the acquisition of ABW Solar by the Company and GE EFS will occur once ABW Solar is built, provided that certain contractual conditions have been met.

The Company and GE EFS have formed the ABW Solar General Partnership to acquire and operate ABW Solar. Provided the aforementioned contractual conditions have been met, the Company will need to make a contribution of approximately $6.0 million to purchase a 10% equity interest in ABW Solar which is projected to occur upon achievement of commercial operations. The Company will serve as the administrative partner. All electricity generated by ABW will be sold to the Ontario Power Authority under 20 year PPAs. The remaining purchase price will be funded through fixed rate long term debt financing which will be non-recourse to the Company. The Company together with GE EFS and First Solar Inc. are currently in late-stage negotiations with lenders for the required debt financing and expect the project to close in the first half of 2013.

Upper Toba hydroelectric project, British Columbia, Canada

In 2010, the Company and GE EFS signed a 40 year PPA with BC Hydro for the Upper Toba project that includes two run of river power plants (Jimmie Creek and Upper Toba River) in close proximity to the Toba Montrose facility, with a combined expected annual average generation of up to 345,000 MWh of electricity. The Company holds a BC Provincial Environmental Assessment Certificate for the Upper Toba project. The Company entered into a development phase agreement with a contractor to perform project optimization and design work and is planning to commence construction in the summer of 2013. Other project advancements included completion of drilling and seismic testing for the powerhouse and intake locations, further hydrology work and firm energy bids on water to wire



suppliers. The Company is currently focused on design and preparation for the initial 62 MW portion of the project (the “Jimmie Creek” project).

The Company has the right to use the excess and unused capacity of TMGP’s transmission line for the Upper Toba project, subject to a priority use agreement with TMGP. The TMGP transmission line was built to interconnect the Toba Montrose hydroelectric facility to the BC Hydro substation at Saltery Bay. In April 2012, TMGP and Upper Toba General Partnership signed an agreement with BC Hydro allowing the Upper Toba project to interconnect to BC Hydro’s Saltery Bay substation.

The Company has Impact Benefit Agreements (“IBAs”) with the Sliammon and Sechelt First Nations for the Upper Toba project. In May 2012, the Company signed an RDA with the Klahoose First Nation, and now has agreements in place with all First Nations affected by the project.

Reykjanes geothermal expansion project, Iceland

The Company plans to expand the Reykjanes plant’s capacity from 100 MW to 180 MW in two phases, subject to completion of modifications to an existing PPA (discussed below) to sell the expansion’s output to Norðurál, and obtaining project financing, both of which may occur in 2013. The first phase would be for a 50 MW expansion (“Reykjanes 3”) for which a 50 MW Fuji turbine generator has previously been purchased and paid for in full. The second phase would be for an additional 30 MW expansion (“Reykjanes 4”) which would follow the Reykjanes 3 expansion, and would require no additional drilling as the unit would utilize the low pressure steam generated from existing operations.

HS Orka has received a permit to proceed with the expansion of the Reykjanes plant from the National Energy Authority of Iceland. The permit allows the Company to install and place into service the new, currently-owned 50 MW turbine, as well as a 30 MW low pressure turbine.

In July 2010, Norðurál initiated arbitration proceedings against HS Orka with respect to the previously mentioned conditional PPA to sell power from Reykjanes 3 and 4 expansions to a planned Norðurál aluminum smelter in Helguvík, Iceland. In December 2011, the arbitrators gave their final ruling and the results of the arbitration were mixed. The Company is currently working with Norðurál to seek a satisfactory resolution to all issues arising out of the award to allow the planned expansion of the Reykjanes plant to proceed.

Dokie 2 wind farm expansion project, British Columbia, Canada

The Company holds a 51% interest in a currently planned expansion of the Dokie 1 wind farm (“Dokie 2 wind farm”) with a projected capacity of up to 156 MW. GE EFS holds the remaining 49% interest. The Company and GE EFS installed four new meteorological towers at the site in late 2011 to complement the previously installed towers (13 in total). During 2012, the Company collected and analysed wind data and furthered project optimization in terms of turbine size, layout and associated costs.

The Dokie 2 wind farm holds a BC Provincial Environmental Assessment Certificate. Amendments to the certificate may be required depending on the final project layout.

The Company has Memoranda of Understanding (“MOU”) for the Dokie 2 wind farm with the Halfway River and West Moberly First Nations and the McLeod Lake Indian Band. The Company plans to negotiate an MOU with the Saulteau First Nations for this expansion phase.



EARLY STAGE DEVELOPMENT AND EXPLORATION PROJECTS – INFORMATION, UPDATES AND OUTLOOK

Iceland

The Company’s development and exploration properties in Iceland include the Eldvörp, Krýsuvík and Trölladyngja geothermal properties, and the Bulandsvirkjun hydroelectric property.

The Eldvörp high-temperature geothermal field is located in the western part of the Reykjanes peninsula, approximately 5 kilometers (“km”) southwest from Svartsengi and approximately 11 km northeast from the Reykjanes geothermal field.

The Krýsuvík high-temperature geothermal field covers approximately 80 square km and is also located in the Reykjanes peninsula, and is part of the Krýsuvík volcanic centre and associated fissure swarm.

The Trölladyngja geothermal field is a sub-field in the northern part of the Krýsuvík geothermal area. Several research and exploration studies have been conducted in the Trölladyngja field since the 1960s. These studies included detailed geological mapping, geophysical surveys and the drilling of four exploration wells. The Trölladyngja geothermal field is currently under review by the government of Iceland for its eligibility for future commercial development.

The Bulandsvirkjun hydroelectric property, owned 50% by HS Orka, is an early-stage development property on the Skaftá River. The Company commenced a pre-feasibility report and environmental assessment in 2012.

The Company has not planned any material expenditure on these properties at this time.

USA

The Company’s advanced-stage properties in the USA are McCoy and Desert Queen and the Company has also invested in a number of other early stage properties in Nevada. The Company does not plan any material expenditure on these properties in 2013.

Chile

In Chile, the Company has drilled three slim diameter holes on the “Mariposa” geothermal system which consists of the Maule and Pellado concessions. Based on exploration results to date, the Company’s independent consultants have calculated an inferred resource of 320 MW available over 30 years. The next phase of activity is expected to include drilling large-diameter rotary holes to confirm rock permeability, reservoir chemistry, fluid chemistry and other resource parameters in order to finalize plant design.

In October 2012, the Company entered into an agreement with EDC for the further development of the Mariposa project on a joint basis. Under this agreement, EDC will have up to six months, subject to extension under certain circumstances, to carry out due diligence on the Mariposa project to make a decision to enter into a formal joint venture with the Company. Under the terms of the proposed joint venture, EDC will be entitled to earn a 70% interest by funding $58.3 million in project expenditures at



Mariposa. Subsequent project equity contributions and all economic sharing would be on a pro rata basis between the partners.

Throughout the fourth quarter of 2012 and into 2013 the Company and EDC have been actively documenting the next-phase agreement toward full partnership, while EDC continues to conduct its due diligence in parallel. The Company expects any final arrangements to be completed within the first half of 2013.

The Company holds a 100% interest in two other properties in Chile, the Los Cristales property and the Tres Puntas property, which are not part of the EDC agreement.

The Los Cristales property is a 68,000 hectare concession located in the Maule region, 400 km south of the City of Santiago and 50 km southeast of the Pehuenche hydro power plant which is served by a 220 kV transmission line. The concession has good access via a paved road and other secondary roads.

The Tres Puntas property is a 90,000 hectare concession located in the Atacama Region, 800 km north of Santiago, 70 km east of the city of El Salvador and close to a 110 kV transmission line.

Peru

In 2011, the Company was awarded the Crucero, Loriscota, Panejo and Pasto geothermal concessions, which lie in southern Peru’s region of volcanoes and prospective geothermal systems. The concessions include 77,400 hectares of land with favorable geochemistry and near-boiling hot springs. A transmission line lies 45 km to the northwest and there are several roads in the area.

The Company was awarded further concessions in 2011 including Tutupaca Norte, Atarani and Suche. These concessions cover 59,900 hectares, and are part of another area of active volcanoes in the Yucamani trend. The Company was also awarded the Sara Sara concession, further to the north which includes the northernmost volcano in the trend. Based on 2012 field work, the Sara Sara concession area has been reduced to the most favourable section covering 6,900 hectares. All concessions awarded have been awarded exploration concessions.

During the first half of 2012 the Company carried out exploration activities in the Sara Sara concession area and has been working on synthesizing geochemical data from several other concessions. Additional geological and geochemical work was carried out in September of 2012 on the southern concessions. The Company has also been engaged in extensive community consultations in its holdings resulting in several community permits.

In October 2012, the Company entered into an agreement with EDC for the development of five of the Company's Peruvian geothermal concessions. Under this agreement, EDC will have up to six months, subject to extension under certain circumstances, to carry out its due diligence on the projects to make a decision to advance them into a formal joint venture. Under the terms of the proposed joint venture, EDC will be entitled to earn a 70% interest by funding $8.0 million in project expenditures on the five Peruvian concessions. Subsequent project equity contributions and all economic sharing would be on a pro rata basis between the partners.

Throughout the fourth quarter of 2012 and into 2013 the Company and EDC have been actively documenting the next-phase agreement toward full partnership, while EDC continues to conduct its



due diligence in parallel. The Company expects any final arrangements to be completed within the first half of 2013.

The Company continues to explore and hold in good standing the other concessions it holds in Peru and may consider partnering on these concessions to further advance exploration.

Italy

The Company was awarded the Mensano and Roccastrada geothermal leases in March 2011. These concessions are located near the historic Larderello geothermal field in Tuscany that has generated electricity for nearly 100 years. The Company is actively reviewing a number of options for the exploration phase of these properties, including a potential joint venture with an industry partner to fund further exploration and development costs.

The Roccastrada concession covers 27,190 hectares, and is characterized by the presence of high heat flow and hot springs.

The Mensano concession covers 21,265 hectares, and is located about 20 km northeast of the town of Larderello. The area is characterized by the presence of a large heat flow anomaly and numerous thermal springs.

Field work has been completed at Mensano and Roccastrada to confirm the presence of high enthalpy resources. The field work included geological, geophysical and geochemical prospecting suitable to define the best location and targets for exploration wells to be drilled in later phases of exploration. Review of these geophysical surveys and development of conceptual models of the concessions is in progress.

British Columbia, Canada

Other hydroelectric development projects

The Company has rights to 37 run of river hydroelectric power projects in British Columbia, primarily in the southwestern region of the province.

In 2008, the Company had submitted its Bute Inlet project proposal to the BC Environmental Assessment Office, the Canadian Environmental Assessment Agency and the Major Projects Management Office. The proposal organized 16 run of river projects into three interconnected groups with an estimated potential annual generation of 2.8 million MWh. The Company subsequently decided to place this application on hold to allow for further analysis and data collection.

The Company has signed IBAs with the Homalco and Sechelt First Nations to advance the hydro power opportunities of the Bute Inlet Project within the traditional territories of these First Nations. In June 2012, the Company also signed a RDA for the project with the Sliammon First Nation.

The Company has rights to other run of river hydroelectric power projects with a combined potential average annual generation of approximately 2.2 million MWh of electricity. The Company continues to collect hydrological data, conduct engineering work and perform other required studies on these projects.



The Company also holds a Crown Land Tenure, an accepted water license application and an investigative use permit for the Fir Point 1,000 MW pumped storage development project.

Geothermal

In July 2011, the Company was awarded two geothermal exploration concessions in the Upper Lillooet area of British Columbia covering 4,942 hectares. The area is a known geothermal resource area and hosts hot springs and other geothermal manifestations including volcanic activity. The Company undertook data compilation and synthesis in the first half of 2012 and a modest field program in August 2012. Analysis of the results is nearing completion.

SELECTED ANNUAL INFORMATION The Company’s key financial results as summarized below have been prepared in accordance with IFRS. ($000s, except per share amounts)

Selected Financial Information

Year Ended Six Months Ended Year Ended

December 31, December 31, June 30,

2012 2011 2011

Total revenues 61,112$ 34,660$ 63,329$

Loss for the period attributable to the owners of the Company (19,849) (13,813) (11,491)

Loss per share attributable to the owners of the Company - basic and diluted (0.04) (0.03) (0.04)

Total assets 712,530 701,224 819,713

Total current liabilities 38,557 37,391 51,753

Total long-term liabilities 309,926 309,734 365,922

Total equity 364,047 354,099 402,038

REVIEW OF RESULTS FOR THE YEAR ENDED DECEMBER 31, 2012

The year ended December 31, 2012 (“current period”) results are for a full twelve month period, whereas the comparative period results shown are for only the six month period ended December 31, 2011 (“comparative period”) as the Company changed their fiscal year end in 2011 resulting in a short fiscal year. Due to this change in year-end and the effect of seasonality, the financial results for the current period and the six month comparative period are not directly comparable. The Company recorded a net loss attributable to the owners of the Company for the current period of $19.9 million (loss of $0.04 per common share), compared to a net loss of $13.8 million for the comparative period (loss of $0.03 per common share), the movement is predominantly due to movements in other gains and losses explained further below.

Gross Profit from Operations

Gross profit from operations was $14.5 million for the current period, compared to $8.6 million for the comparative period. The gross profit from operations is comprised of geothermal operations only and includes 100% of the results from HS Orka and Soda Lake.



Revenue

Revenue in the current period was $61.1 million and $34.7 million in the comparative period. The breakdown in revenue was as follows:

HS Orka operations (Reykjanes and Svartsengi) 100% consolidated - $56.7 million (comparative period: $32.3 million), which included $1.7 million recorded for amortization of below-market contracts (comparative period: $1.2 million).

Soda Lake - $4.4 million (comparative period: $2.4 million).

The Company’s ownership of TMGP and DGP is accounted for using the equity method of accounting, whereby the revenue and costs associated with the Toba Montrose hydroelectric facility and the Dokie 1 wind farm are not included in consolidated revenue but are instead included in the Company’s share of profit of equity-accounted investees. The proportionate share of revenue from the two facilities included in equity income for the current period was as follows:

Toba Montrose hydro facility - $27.2 million (representing the Company’s 40% share) (comparative period: $18.6 million).

Dokie 1 wind farm - $17.0 million (representing the Company’s 51% share) (comparative period: $11.9 million).

Cost of sales

Cost of sales for the current period totalled $46.6 million, compared to $26.0 million in the comparative period. Cost of production in the current period included:

HS Orka - $39.2 million (comparative period: $23.3 million).

Soda Lake - $7.4 million (comparative period: $2.7 million).

The proportionate share of production costs (including depreciation and amortization) from the Toba Montrose hydro facility and the Dokie 1 wind farm are not included in consolidated cost of sales but are instead included in equity income for the current period as follows:

Toba Montrose hydro facility - $12.0 million (representing the Company’s 40% share) (comparative period: $6.1 million).

Dokie 1 wind farm – $10.6 million (representing the Company’s 51% share) (comparative period: $5.1 million).

Income (expenses)

Total other income (expenses) for the current period resulted in a net expense of $34.4 million, compared to a net expense of $31.2 million for the comparative period.

General and administrative expenses were $14.9 million compared to $9.8 million in the comparative period. The decrease against the comparative period (after taking into account the different periods presented due to the change in year-end) is due to efficiencies from the merger with Plutonic Power Corporation, in addition to a reduction in legal and professional costs in the current period as the comparative period included legal fees related to the Norðurál arbitration as well as professional fees



incurred in conjunction with the Company’s conversion to IFRS. These costs were not repeated in 2012.

The Company’s share of equity income for the current period was $3.3 million, compared to equity income of $7.8 million for the comparative period. Equity income for the current period includes the Company’s 40% share of TMGP income of $2.0 million (comparative period: $6.4 million), the Company’s 51% share of Dokie 1 loss of $0.1 million (comparative period: income of $3.0 million), and the Company’s net interest in Blue Lagoon income of $1.4 million (comparative period: loss of $1.6 million). The variability in the Company’s share of equity income is largely due to the change in year-end and seasonality.

Financing costs incurred in the current period were $9.8 million, compared to $5.3 million for the comparative period. The decrease against the comparative period (after taking into account the different periods presented due to the change in year-end) is due to a reduction in indexation on Icelandic loans and foreign exchange.

Financing income earned in the current period was $2.8 million, compared to $1.3 million for the comparative period. The increase against the comparative period is primarily due to interest income on cash proceeds from the share issuance by HS Orka in the current period.

Other gains and losses for the current period totaled a net loss of $15.1 million, compared to a net loss of $23.9 million for the comparative period. Highlights of other gains and losses in the current period and comparative period include:

A $9.3 million non-cash loss resulting from the change in the fair value of the long term bonds payable in the current period (comparative period: $2.4 million gain). As partial consideration for its acquisition of shares of HS Orka, the Company has long term bond liabilities with a fair value of $121.1 million as at December 31, 2012. The bonds contain certain embedded derivatives related to the price of aluminum and have therefore been recorded at fair value at each reporting date with the change in the fair value recorded in the statement of operations.

A $2.8 million non-cash loss resulting from the change in the fair value of derivatives for the current period (comparative period: $24.5 million non-cash loss). HS Orka has two PPAs under which the sales price of the power sold is based on the market price of aluminum. The indexing of the sales price to the price of aluminum is an embedded derivative and has therefore been recorded at fair value at each reporting date with the change in the fair value recorded in the statement of operations.

A $1.3 million loss on foreign exchange was incurred for the current period, compared to a loss of $1.8 million for the comparative period.

A $1.8 million write off in development costs in the current period, compared to a write off of $0.01 million in the comparative period.

SUMMARY OF QUARTERLY RESULTS

As mentioned previously, seasonality has an impact on our quarterly operating results. In addition, the Company has a number of non-cash derivatives which can fluctuate significantly from quarter to quarter. The following table summarizes information regarding the Company’s operations on a



quarterly basis for the last eight quarters expressed in thousands of US dollars, except for per share amounts. Financial information is reported under IFRS for all quarters. The quarter ended March 31, 2011 has been adjusted to reflect the final purchase price adjustments on the acquisition of control of HS Orka.

December 31, September 30, June 30, March 31,

Three months ended: 2012 2012 2012 2012

Revenue 17,156$ 13,326$ 14,242$ 16,388$

Gross profit 4,526 2,189 3,127 4,682

Income (expense) (20,976) 15,853 (14,413) (14,890)

Income tax recovery (expense) 1,190 (3,373) 1,630 373

Net income (loss) attributable to owners of the Company (13,630) 9,825 (7,746) (8,298)

Earnings (loss) per share attributable to owners of the Company (basic and diluted) (0.02) 0.02 (0.02) (0.02)

December 31, September 30, June 30, March 31,

Three months ended: 2011 2011 2011 2011

Revenue 17,651$ 17,009$ 17,582$ 18,901$

Gross profit 3,769 4,856 4,785 5,525

Income (expenses) (10,832) (20,357) (31,717) 12,279

Income tax recovery (expense) 174 4,084 3,358 (5,867)

Net income (loss) attributable to owners of the Company (6,031) (7,782) (21,142) 11,667

Earnings (loss) per share attributable to owners of the Company (basic and diluted) (0.01) (0.02) (0.05) 0.04

QUARTERLY FINANCIAL REVIEW FOR THE THREE MONTHS ENDED DECEMBER 31, 2012 The Company recorded net loss of $15.3 million for the three months ended December 31, 2012, (the “current quarter”) compared to a net loss of $6.9 million for the three months ended December 31, 2011 (the “comparative quarter”), an increase of $8.4 million. This increase in net loss was primarily caused by changes in the fair value of bonds payable and embedded derivatives as well as other non-cash items. Net loss attributable to the owners of the Company for the current quarter was $13.6 million (net loss of $0.02 per common share), compared to a net loss of $6.0 million for the comparative quarter (net loss of $0.01 per common share).

Gross profit from operations

Gross profit from operations was $4.5 million for the current quarter, compared to $3.8 million for the comparative quarter, an increase of $0.7 million. The gross profit from operations is comprised of geothermal operations only and includes 100% of the results from HS Orka and Soda Lake.

Revenue

Revenue, all from geothermal operations, in the current quarter was $17.2 million, or $0.5 million lower than the comparative quarter. The breakdown in revenue was as follows:

HS Orka operations (Reykjanes and Svartsengi) 100% consolidated - $15.7 million (comparative quarter: $16.5 million), which included $0.4 million recorded for amortization of below-market contracts (comparative quarter: $0.7 million). The decrease in revenue from the comparative quarter was primarily due to unfavorable foreign exchange fluctuations.

Soda Lake - $1.5 million (comparative quarter: $1.2 million). The increase is due to portfolio energy credit sales sold in November 2012 which are normally sold earlier in the year.



The Company’s ownership of TMGP and DGP is accounted for using the equity method of accounting. The proportionate share of revenue from the two facilities included in equity income for the current quarter was as follows:

Toba Montrose hydro facility - $2.8 million (representing the Company’s 40% share) (comparative quarter: $1.3 million). The increase was primarily due to higher water flow in the current quarter.

Dokie 1 wind farm - $4.0 million (representing the Company’s 51% share) (comparative quarter: $6.2 million). The decrease was due to reduced generation due to lower winds.

Cost of sales

Cost of sales for the current quarter totalled $12.6 million, compared to $13.9 million in the comparative quarter, a decrease of $1.3 million. Cost of production in the current quarter included:

HS Orka - $10.6 million (comparative quarter: $12.0 million). The decrease was due primarily to foreign exchange fluctuations and lower operating costs as a result of lower transmission and power purchase costs.

Soda Lake - $2.0 million (comparative quarter: $1.9 million).

The proportionate shares of production costs from the Toba Montrose hydro facility and the Dokie 1 wind farm are not included in consolidated cost of sales but instead are included in equity income for the current quarter as follows:

Toba Montrose hydro facility - $4.1 million (representing the Company’s 40% share) (comparative quarter: $2.8 million). The increase was primarily due to repairs and maintenance costs incurred in the current quarter.

Dokie 1 wind farm – $3.5 million (representing the Company’s 51% share) (comparative quarter: $1.8 million). The increase was primarily due to costs incurred in the current quarter on repair work required due to lightning damage and a transformer failure which were both fully insurable events, and insurance proceeds were received subsequent to December 31, 2012.

Income (expenses)

Total other income (expenses) for the current quarter resulted in a net expense of $21.0 million, compared to a net expense of $10.8 million for the comparative quarter, an increase in net expenses of $10.2 million. This increase in net expenses is due to a number of factors as described below:

General and administrative expenses were lower than the comparative quarter at $4.3 million in the current quarter compared to $5.6 million, a decrease of $1.3 million. This decrease is largely due to efficiencies gained from the merger with Plutonic Power Corp. and lower legal fees related to the Norðurál arbitration in the current quarter.

Finance costs incurred in the current quarter were $2.5 million, consistent in comparison to $2.4 million for the comparative quarter.

Other gains and losses for the current quarter totaled a net loss of $11.0 million, compared to a net gain of $2.2 million for the comparative quarter. Highlights of other gains and losses in the current and comparative quarters include:



A $1.6 million non-cash loss resulting from the change in the fair value of the long term bonds payable in the current quarter (comparative quarter: $0.3 million loss), a net negative change of $1.3 million.

A $5.5 million non-cash loss resulting from the change in the fair value of derivatives in the current quarter (comparative quarter: $0.1 million non-cash loss), a net negative change of $5.4 million which is due to the decrease in aluminum forward prices.

A $3.8 million loss on foreign exchange was recorded in the current quarter, due to unfavorable movements in exchange rates in the current quarter, compared to a gain of $2.6 million for the comparative quarter, a net negative change of $6.4 million.

A $0.1 million non-cash loss resulting from write off of development costs in the current quarter (comparative quarter: $nil).

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2012, the Company had consolidated cash and cash equivalents of $39.2 million (December 31, 2011: $22.2 million), an increase of $17.0 million.

The increase in consolidated cash and cash equivalents was due primarily to cash flows generated from operations for the period, the receipt of $37.5 million by HS Orka from the issuance of treasury shares to Jarðvarmi, a $2.1 million grant received by Soda Lake from the US Department of the Treasury, and borrowings of $8.1 million. This was partially offset by investment of $4.5 million in short term investments, investment of $10.5 million in plant and equipment, principal loan repayment of $17.3 million and development costs of $10.1 million in 2012.

Cash and cash equivalents consist of cash and term deposits that are redeemable prior to maturity on demand and without economic penalty to the Company. The Company’s exposure to credit risk on its cash and term deposits is limited by maintaining the majority of its cash and term deposits with major banks that have high credit ratings. Other than in Iceland, where cash is being held in preparation for the 80 MW expansion at Reykjanes, a minimal amount of cash is held by banks in the countries where the Company’s subsidiaries operate to fund their operating needs.

At December 31, 2012, the Company had restricted cash of $4.5 million (December 31, 2011: $4.5 million), dedicated to loan payments in accordance with a collateral agreement with HS Orka’s lenders. The Company also had short term investments of $4.5 million (December 31, 2011: $nil). Excluding HS Orka and the cash held at the equity-accounted investees, the Company had cash of $2.9 million at December 31, 2012 (December 31, 2011: $16.1 million).

Working capital is defined as current assets minus current liabilities. Working capital calculations or changes are not measures of financial performance, nor do they have standardized meanings under IFRS. Readers are cautioned that this calculation may differ among companies and analysts and therefore may not be directly comparable.

The Company’s consolidated working capital at December 31, 2012 was $29.3 million compared to $4.6 million at December 31, 2011. The increase was due primarily to the cash received from the issuance of treasury shares to Jarðvarmi, new borrowings, and the US Department of the Treasury grant as discussed above. Excluding HS Orka, the Company had working capital of $3.6 million at December 31, 2012 (December 31, 2011: $13.2 million).



As stated above, in March 2012, Jarðvarmi invested ISK 4.7 billion ($37.5 million) in HS Orka through the purchase of 878,205,943 treasury shares at a price of ISK 5.35 per share. This price represented a 15.6% increase over the original price paid by Jarðvarmi of ISK 4.63 per share for their initial 25% stake. These funds are currently being held by HS Orka where the proceeds will substantially fund the remaining equity requirements for the 80 MW of planned expansions which would increase the Reykjanes geothermal plant capacity from 100 MW to 180 MW.

The Company has available, if needed, a revolving line of credit of C$20.0 million provided by its Chairman with a maturity date of January 1, 2014. During the year ended December 31, 2012, the Company drew C$8.05 million on the line of credit to fund its operations at the parent company level. Further draws on this line of credit may be necessary in the foreseeable future, however these amounts will be partially offset by the receipt of the Company’s share of distributions from operating assets.

The Company is currently exploring a number of options on how to fund its future cash requirements, including any needed project equity for construction of the Upper Toba run of river hydroelectric project which is planned for 2013.

Consolidated long-term debt consists of: a) $121.1 million of the present value of the bonds assumed by Magma Energy Sweden A.B. (“Magma Energy Sweden”) for the acquisition of HS Orka that mature in December 2016; b) $140.2 million, representing 100% of HS Orka’s debt which has annual principal repayments and the matures primarily between 2016 and 2023 and; c) $8.1 million drawn on the line of credit under the aforementioned working capital facility. The Company’s proportionate share of TMGP’s long term-debt is $185.9 million (representing the Company’s 40% share) which has annual principal repayments until 2045, and the Company’s proportionate share of DGP’s long-term debt is $90.3 million (representing the Company’s 51% share) which has annual principal repayments until 2030. TMGP and DGP long term debt are not recorded by the Company as these two investments are recorded as equity investments. The HS Orka, Magma Energy Sweden, TMGP and DGP loans are non-recourse to the Company other than the remaining portion of the Company’s historic investment in these entities, which may not be fully recovered in the event of an incurred default. All entities are expected to generate sufficient cash flow to service and repay their existing long-term loans, except for Magma Energy Sweden which is a holding Company that generates no cash flow of its own.

TRANSACTIONS WITH RELATED PARTIES

During the year, the Company borrowed $8.1 million (C$8.05 million) under an existing credit facility with the Company’s Chairman whereby the Company has the ability to borrow up to C$20.0 million on a revolving basis at an interest rate of 8% per annum, compounded daily and payable monthly. In addition, a standby fee in the amount of 1% of the credit facility and a drawdown fee in the amount of 1.5% of the amount advanced is payable in cash. As at December 31, 2012, the Company has a balance owing of $8.1 million and has paid interest and drawdown fees totaling $0.2 million during the year.

OFF-BALANCE SHEET ARRANGEMENTS

The Company does not have any off-balance sheet arrangements.



OTHER RISKS AND UNCERTAINTIES

The ability of the Company to be a viable operator and developer of renewable power is dependent upon a number of factors and risks and uncertainties that include, but are not limited to, the following: extensive regulation by various levels of government; successful completion of hydrological, geothermal and wind studies to confirm that resources are sufficient to generate enough electricity to provide a suitable return on investment for future projects; receipt and renewal of licences; environmental and other permits to build and operate the projects; the successful negotiation of further long-term contracts with purchasers of electricity; industry risk and competition; the ability to obtain sufficient equity and long-term debt financing to construct further projects; support from First Nations, other indigenous people or local communities that may have a claim to the land base where the Company’s projects lie; community and stakeholder support and the ability to connect the projects to the local or regional transmission line; successful design, construction and operation of the generation facilities and related transmission lines; and restrictions on foreign exchange or repatriation.

Fluctuations and changes in weather and wind patterns will impact operational results for the Company’s hydro and wind operations.

For further information regarding the Company’s operational risks, please refer to the section entitled “Risk Factors” in the Annual Information Form for the year ended December 31, 2012.

CRITICAL ACCOUNTING POLICIES AND MANAGEMENT ESTIMATES

The preparation of consolidated financial statements requires that the Company’s management make assumptions and estimates of effects of uncertain future events on the carrying amounts of the Company’s assets and liabilities at the end of the reporting period. Actual results may differ from those estimates as the estimation process is inherently uncertain. Actual future outcomes could differ from present estimates and assumptions’ potentially having a material future effect on the Company’s consolidated financial statements. Estimates are reviewed on an ongoing basis and are based on historical experience and other facts and circumstances. Revisions to estimates and the resulting effects on the carrying amounts of the Company’s assets and liabilities are accounted for prospectively.

The Company believes the following selected accounting policies and issues are critical to understanding the estimates, assumptions and uncertainties that affect the amounts reported and disclosed in the Company’s consolidated financial statements and related notes. See note 3 of the Company’s audited consolidated financial statements for the Company’s significant accounting policies. A – Consolidation i) Business combinations

Acquisitions of subsidiaries and businesses (other than entities which were already under the control of the parent) are accounted for using the acquisition method. The cost of the business combination is measured as the aggregate of the fair value (at the date of exchange) of assets given, liabilities incurred or assumed, and equity instruments issued by the Company in exchange for control of the acquiree. The acquiree’s identifiable assets and liabilities that meet the conditions for recognition are



recognized at their fair value at the acquisition date except for certain assets and liabilities which are

recognized and measured in accordance with the related IFRS guidance.

Goodwill arising on acquisition is recognized as an asset and is measured as the fair value of consideration paid including the recognized amount of any non-controlling interest in the acquiree and fair value of previously held investments in the acquiree less the fair value of the net identifiable assets and liabilities recognized. If the Company's interest in the fair value of the acquiree's net identifiable assets and liabilities exceeds the fair value of consideration paid, the excess is recognized immediately in the statement of operations as a bargain purchase. Transaction costs, other than those associated with the issuance of debt or equity securities that the Company incurs in connection with a business combination, are expensed as incurred.

ii) Acquisitions and disposals of non-controlling interests

Transactions that result in changes in ownership interests while retaining control are accounted for as transactions with equity holders in their capacity as equity holders. As a result no gain or loss on such changes is recognized in the statement of operations and no change in the carrying amounts of assets (including goodwill) or liabilities is recognized. All changes as a result of acquisitions and disposals of non-controlling interests is recognized directly in the statement of equity.

iii) Subsidiaries

Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from the entity’s activities. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases. The accounting policies of subsidiaries have been changed when necessary to align them with the policies adopted by the Company.

iv) Investments in associates and jointly controlled entities

Associates are those entities in which the Company has significant influence, but not control, over the financial and operating policies. Significant influence is presumed to exist when the Company holds between 20% and 50% of the voting power of another entity. Jointly controlled entities are those entities over whose activities the Company has joint control, established by contractual agreement. Investments in associates and jointly controlled entities are accounted for using the equity method (equity accounted investees) and are recognized initially at cost. The Company’s investment includes goodwill identified on acquisition, net of any accumulated impairment losses. The consolidated financial statements include the Company’s share of the net income and equity movements of equity accounted investees, after adjustments to align the accounting policies with those of the Company, from the date that significant influence or joint control commences until the date that significant influence or joint control ceases. When the Company’s share of losses exceeds its interest in an equity accounted investee, the carrying amount of that interest, including any long-term investments, is reduced to nil, and the recognition of further losses is discontinued except to the extent that the Company has an obligation to make, or has made, payments on behalf of the investee. The Company has a 40% interest in TMGP, a joint venture, which owns and operates the Toba Montrose Facility, and



a 51% interest in DGP, a joint venture, which owns and operates the Dokie Wind Farm. The Company accounts for its investments in TMGP and DGP under the equity method.

The Company, through HS Orka, has a 33.2% interest in Bláa Lðnið ehf., 23.9% in Hreyfing Eignarhaldsfélag ehf. and 24.4% interest in Blue Lagoon International ehf., Hótel Bláa Lónið ehf. (collectively “Blue Lagoon hf”). The Company equity accounts for its investment in Blue Lagoon hf.

v) Transactions eliminated on consolidation

Intra-group balances and transactions, and any unrealized income and expenses arising from intra-group transactions, are eliminated in preparing the consolidated financial statements. Unrealized gains arising from transactions with equity accounted investees are eliminated against the investment to the extent of the Company’s interest in the investee. Unrealized losses are eliminated in the same way as unrealized gains, but only to the extent that there is no evidence of impairment.

B - Plant and equipment

i) Recognition and measurement

Plant and equipment is measured at cost, less accumulated depreciation and accumulated impairment losses. Costs include expenditures that are directly attributable to the acquisition of the asset. The cost of self-constructed assets includes the cost of materials and direct labour, any other costs directly attributable to bringing the assets to a working condition for their intended use and capitalized borrowing costs. When parts of an item of plant and equipment have different useful lives, they are accounted for separately. The major categories include power plants, boreholes, electrical systems, hot water and cold water distribution systems, transmission lines, housing, other operating assets and furniture and equipment. Major additions to plant and equipment, including betterments, are capitalized and repairs and maintenance are expensed. Gains and losses on disposal of an item of plant and equipment are determined by comparing the proceeds from disposal with its carrying amount, and are recognized on a net basis within other gains and losses in the statement of operations.

ii) Depreciation

Depreciation of the cost of plant assets (once in operation) less its residual value is recognized on a straight-line basis over the estimated useful life of the asset. HS Orka’s facility components have estimated useful lives that range from 5 to 50 years, Soda Lake’s facility components range from 2 to 20 years and TMGP’s facility components range from 2 to 70 years. For all other plant and equipment items depreciation of the cost of such asset less its residual amount is provided on a declining balance method with annual rates ranging from 20% to 30%. Depreciation methods, useful lives and residual values are reviewed at each reporting date and adjusted if appropriate.

C - Derivative financial instruments, including hedge accounting

Derivatives are recognized initially at fair value. Attributable transaction costs are recognized in the statement of operations as incurred. Subsequent to initial recognition, derivatives (including embedded derivatives) are measured at fair value, and changes therein are accounted for as described below.



Cash Flow Hedges

On initial designation of a hedge, the Company formally documents the relationship between the hedging instrument(s) and hedged item(s), including the risk management objectives and strategy in undertaking the hedge transaction, together with the methods that will be used to assess the effectiveness of the hedging relationship. The Company makes an assessment, both at the inception of the hedge relationship as well as on an ongoing basis, whether the hedging instruments are expected to be highly effective in offsetting the changes in the fair value or cash flows of the respective hedged items during the period for which the hedge is designated, and whether the actual results of each hedge are within a range of 80 – 125 percent. For a cash flow hedge of a forecasted transaction, the transaction should be highly probable to occur and should present an exposure to variations in cash flows that could ultimately affect reported net income.

When a derivative is designated as a hedging instrument in a hedge of the variability in cash flows attributable to a particular risk associated with a recognized asset or liability or a highly probable forecasted transaction that could affect profit or loss, the effective portion of changes in the fair value of the derivative is recognized in other comprehensive income and presented in unrealized gains/losses on cash flow hedges in equity. The amount recognized in other comprehensive income is removed and included in the statement of operations in the same period as the hedged cash flows affect profit or loss under the same line item in the statement of other comprehensive income. Any ineffective portion of changes in the fair value of the derivative is recognized immediately in the statement of operations.

If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The cumulative gain or loss, previously recognized in other comprehensive income and presented in unrealized gains/losses on cash flow hedges in equity, remains at its originally designated amount until the forecasted transaction affects profit or loss. When the hedged item is a non-financial asset, the amount recognized in other comprehensive income is transferred to the carrying amount of the asset when the asset is recognized. If the forecasted transaction is no longer expected to occur, then the balance in other comprehensive income is recognized immediately in the statement of operations. In other cases the amount recognized in other comprehensive income is transferred to the statement of operations in the same period that the hedged item affects profit or loss. The Company does not currently apply hedge accounting, with the exception of the TMGP interest rate swap which is designated as a cash flow hedge of the underlying variable rate debt.

Other derivatives and separable embedded derivatives

The Company holds certain derivative financial instruments to economically hedge certain of its foreign currency and interest rate risk exposures. Hedge accounting is not applied to these instruments. Embedded derivatives are separated from the host contract and accounted for separately if (a) the economic characteristics and risks of the host contract and the embedded derivative are not closely related, (b) a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and (c) the combined instrument is not measured at fair value through profit or loss.



Changes in the fair value of derivatives not designated as a hedge and separable embedded derivatives are recognized immediately in the statement of operations. HS Orka has two long-term power sales agreements which contain embedded derivatives. Income from these agreements is directly correlated to changes in the future price of aluminum.

D - Intangible assets

i) Goodwill

Business acquisitions are accounted for using the purchase method whereby assets acquired and liabilities assumed are recorded at fair value as of the date of the acquisition with the excess of the purchase price over such fair value recorded as goodwill. Goodwill is not amortized. The Company performs an impairment test for goodwill at each financial year end and when events or changes in circumstances indicate that the related carrying amount may not be recoverable. If the carrying amount of an operating segment to which goodwill has been allocated exceeds the recoverable amount, an impairment loss is recognized for the amount in excess. The impairment loss is allocated first to reduce the carrying amount of goodwill allocated to the operating segment to nil and then to the other assets of the operating segment based on the relative carrying amounts of those assets. Impairment losses recognized for goodwill are not reversed in subsequent periods should the value recover. Upon disposal or abandonment of a project, the carrying amount of goodwill allocated to that segment is derecognized and included in the calculation of the gain or loss on disposal or abandonment.

ii) Development – Hydro, wind and geothermal development costs

Expenditures on research activities, which are undertaken with the prospect of surveying areas where exploitation probability is uncertain and in order to gain new scientific or technical knowledge, are recognized in the statement of operations when incurred. Development expenditures are capitalized only if such costs can be measured reliably, the product or process is technically and commercially feasible, future economic benefits are probable, and the Company intends to and has sufficient resources to complete development and to use or sell the asset. The Company capitalizes direct costs associated with its hydro, wind and geothermal development projects. Such costs include acquisition costs, exploration and development costs (including materials, direct labour, directly attributable overhead costs and borrowing costs), net of any recoveries and grants. Costs associated with successful projects are amortized over the useful life of the projects upon commencement of commercial production. Costs of unsuccessful projects are written off in the statement of operations in the period the project is abandoned or impaired. The recovery of hydro, wind and geothermal development costs is typically dependent upon the successful completion of the projects or their sale. The successful completion of a project is typically dependent upon receiving the necessary environmental and other licenses, the contractual arrangements to complete the development and construction of these projects, entering into a power purchase agreement, obtaining the necessary project financing to successfully complete the development and construction of the project, and the long-term generation and sale of electricity on a



profitable basis. From time to time the Company may acquire or dispose of a wind, hydro or geothermal property interest pursuant to the terms of an option agreement. Where the options are exercisable entirely at the discretion of the Company or the optionee, the amounts payable or receivable are recorded as property costs or recoveries when the payments are made or received. Although the Company has taken steps to verify the title to development properties in which it has an interest, in accordance with industry standards for the current stage of exploration of such properties, these procedures do not guarantee the Company’s title. Property title may be subject to unregistered prior agreements or transfers and title may be affected by undetected defects.

iii) Service concession arrangements

The Company recognizes an intangible asset arising from a service concession arrangement when it has the right to charge for usage of the concession infrastructure. An intangible asset received as consideration for providing construction or upgrade services in a service concession arrangement is measured at fair value upon initial recognition. Subsequent to initial recognition, the intangible asset is measured at cost, which includes capitalized borrowing costs, less accumulated amortization and accumulated impairment losses. DGP’s power sales agreement (“PPA”) with British Columbia Hydro and Power Authority (“BC Hydro”) is considered a service concession arrangement.

iv) Other intangible assets

Intangible assets include project permits and licenses, prepaid land tenure license amounts, First Nations IBAs and Memorandum of Understanding (“MOU”) costs for Toba Montrose and the Dokie Wind 1 respectively, and software. Payments made to First Nations under the terms of the IBAs and MOUs were capitalized to intangible assets prior to the commencement of commercial operations, after which time such payments are expensed in the statement of operations.

v) Amortization

Amortization is based on the cost of an asset less its residual value.

Amortization is recognized in the statement of operations on a straight-line basis over the estimated useful lives of intangible assets, other than goodwill and development costs, from the date that they are available for use.

HS Orka has software that is amortized on a straight-line basis over terms varying from 5-10 years. IBAs and MOUs recorded in TMGP and DGP are amortized over the life of the agreement.

Amortization methods, useful lives and residual values are reviewed at each reporting date and adjusted if appropriate.

E - Income taxes

Income tax expense is comprised of current and deferred income tax. Current tax and deferred income tax are recognized in the statement of operations except to the extent that it relates to a business combination, or items recognized directly in equity or in other comprehensive income.



Current income tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred income tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes.

Deferred income tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred income tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority.

Deferred income tax is not recognized for:

temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit or loss;

temporary differences related to investments in subsidiaries and jointly controlled entities to the extent that it is probable that they will not reverse in the foreseeable future; and

taxable temporary differences arising on the initial recognition of goodwill.

A deferred tax asset is recognized for unused tax losses, tax credits and deductible temporary differences, to the extent that it is probable that future taxable profits will be available against which they can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

F – Foreign Currency

The Company has determined that the functional currency of the Company and each of its subsidiaries, except Magma Energy (U.S.) Corp., Soda Lake Holdings I, LLC, Soda Lake Holdings II, LLC, Amor IX LLC, Soda Lake Limited Partnership, and Soda Lake Resources Partnership (the “US subsidiaries”) and HS Orka, is the Canadian dollar. The functional currency of the US subsidiaries is the U.S. dollar and the functional currency of HS Orka is the Icelandic Krona (“ISK”). Monetary assets and liabilities and other financial instruments carried at fair value denominated in a currency other than the functional currency of the Company and its subsidiaries are translated into the functional currency at the exchange rate in effect on the balance sheet date while non-monetary assets and liabilities, and revenues and expenses are translated using exchange rates in effect at the time of each transaction. Gains and losses from these translations are included in the results from operations.

FUTURE ACCOUNTING STANDARDS

The Company has not applied the following new and revised IFRSs that have been issued but are not yet effective:



Accounting standards effective years commencing on or after January 1, 2013 Amendments to IAS 1 Presentation of Financial Statements allows companies the option to present profit or loss and other comprehensive income in either a single statement or in two separate but consecutive statements. However, the amendments to IAS 1 require additional disclosures to be made in the other comprehensive income section such that items of other comprehensive income are grouped into two categories: (a) items that will not be reclassified subsequently to profit or loss; and (b) items that will be reclassified subsequently to profit or loss when specific conditions are met. Income tax on items of other comprehensive income is required to be allocated on the same basis. The Company intends to adopt the amendments in its financial statements for the annual period beginning on January 1, 2013. As the amendments only require changes in the presentation of items in other comprehensive income, the Company does not expect the amendments to IAS 1 to have a material impact on the financial statements. IFRS 10 Consolidated Financial Statements establishes control as the single basis for consolidation of entities, regardless of the nature of the investee. An entity has control over an investee when it has power over it; it is exposed, or has the rights, to variable returns from its involvement with the investee; and has the ability to use its power over the investee to affect those returns. IFRS 10 replaces the guidance from IAS 27 Consolidated and Separate Financial Statements that addresses when and how an investor should prepare consolidated financial statements and replaces all of SIC-12 Consolidation – Special Purpose Entities. IFRS 11 Joint Arrangements requires a venturer to classify its interest in a joint arrangement as a joint venture or joint operation. A joint operation is a joint arrangement whereby the parties that have joint control have rights to the assets and the obligations for the liabilities. A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. The determination whether a joint arrangement constitutes a joint operation or a joint venture is based on the parties’ rights and responsibilities under the arrangement and thus the existence of a separate legal vehicle is no longer the main factor in making such determination. Joint ventures will be accounted for using the equity method of accounting thereby eliminating the option available under existing IFRS to use either the proportionate consolidation method or the equity method. Joint operations are accounted for by a venturer by recognizing its share of the assets, liabilities, revenues and expenses of the joint operation.

IFRS 12 Disclosure of Interest in Other Entities sets out the required disclosures relating to an entity’s interest in subsidiaries, joint arrangements, associates and unconsolidated structured entities. An entity is required to disclose information that enables users of its financial statements to assess the nature of, and risks associated with, its interests in other entities and the effects of those interests on its financial statements. In June 2012, the IASB issued Consolidated Financial Statements, Joint Arrangements and Disclosures of Interests in Other Entities: Transition Guidance (Amendments to IFRS 10, IFRS 11 and IFRS 12), which is effective with the adoption of the applicable standard to which the amendments relate to, i.e. IFRS 10, IFRS 11 and IFRS 12. The amendments simplify the process of adopting IFRS 10 and provide additional relief from certain disclosures. The Company intends to adopt IFRS 10, IFRS 11 and IFRS 12, including the amendments issued in June 2012, in its financial statements for the annual period beginning on January 1, 2013. The Company



does not expect IFRS 10 and IFRS 11 to have a material impact on the financial statements. The Company expects that adoption of IFRS 12 will increase the current level of disclosure of interests in other entities. IFRS 13 Fair Value Measurement establishes a single framework for measuring fair value where it is required by other standards. IFRS 13 applies to all transactions (whether financial or non-financial) for which IFRSs require or permit fair value measurements, with the exception of share-based payment transactions accounted for under IFRS 2 Share-based Payment and leasing transactions within the scope of IAS 12 Leases, and measurements that have some similarities to fair value but are not fair value such as net realizable value under IAS 2 Inventories or value in use under IAS 36 Impairment of assets. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e. an exit price). The Company intends to adopt IFRS 13 prospectively in its financial statements for the annual period beginning on January 1, 2013. The Company does not expect IFRS 13 to have a material impact on the financial statements. Amendments to IAS 19 Employee Benefits changes the accounting for defined benefit plans and termination benefits. The most significant change relates to the accounting for changes in defined benefit obligations and plan assets. The amendments require the recognition of changes in defined benefit obligations and in fair value of plan assets when they occur, and hence eliminate the “corridor approach” permitted under the previous version of IAS 19 and accelerate the recognition of past service costs. The amendments require all actuarial gains and losses to be recognized immediately through other comprehensive income in order for the net pension asset or liability recognized in the consolidated statement of financial position to reflect the full value of the plan deficit or surplus. The Company intends to adopt the amendments to IAS 19 in its financial statements for the annual period beginning on January 1, 2013. The Company does not expect the amendments to have a material impact on the financial statements. In December 2011 the IASB published Offsetting Financial Assets and Financial Liabilities and issued new disclosure requirements in IFRS 7 Financial Instruments: Disclosures. The effective date for the amendments to IAS 32 Financial Instruments: Presentation is annual periods beginning on or after January 1, 2014. The effective date for the amendments to IFRS 7 is annual periods beginning on or after January 1, 2013. These amendments are to be applied retrospectively. The amendments to IAS 32 clarify that an entity currently has a legally enforceable right to set-off if that right is not contingent on a future event and enforceable both in the normal course of business and in the event of default, insolvency or bankruptcy of the entity and all counterparties. The amendments to IAS 32 also clarify when a settlement mechanism provides for net settlement or gross settlement that is equivalent to net settlement. The amendments to IFRS 7 contain new disclosure requirements for financial assets and liabilities that are offset in the statement of financial position or subject to master netting arrangements or similar arrangements. The Company intends to adopt the amendments to IFRS 7 in its financial statements for the annual period beginning on January 1, 2013, and the amendments to IAS 32 in its financial statements for the annual period beginning January 1, 2014. The Company has not yet assessed the impact of the standard or determined whether it will adopt the standards early. IFRS 9 Financial Instruments was issued in November 2009 and covers the classification and measurement of financial assets as part of its project to replace IAS 39 Financial Instruments: Recognition and Measurement. In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize



financial liabilities at fair value through earnings. If this option is elected, entitles would be required to reverse the portion of the fair value change due to own credit risk out of earnings and recognize the change in other comprehensive income. IFRS 9 is applicable for periods beginning on or after January 1, 2015. The Company has not yet assessed the impact of the standard or determined whether it will adopt the standard early.

MANAGEMENT'S REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING AND DISCLOSURE CONTROLS AND PROCEDURES

The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting and disclosure controls and procedures. Any system of internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

The Company’s management, with the participation of its Chief Executive Officer and Interim Chief Financial Officer, have evaluated the effectiveness of the Company’s disclosure policy and procedures. Based on the results of that evaluation, the Company’s Chief Executive Officer and Interim Chief Financial Officer have concluded that, as at December 31, 2012, the Company’s disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed by the Company in reports it files is recorded, processed, summarized and reported within the appropriate time periods and forms.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in the Company’s internal controls over financial reporting during the year that have materially affected, or are reasonably likely to materially affect, its internal controls over financial reporting. Future changes to internal controls over financial reporting may be deemed to constitute a material modification (either individually or when considered collectively) and therefore any material changes to internal controls over financial reporting will be disclosed as they occur. The change in Chief Financial Officer took place in February 2013 and is not expected to impact the Company’s internal controls over financial reporting.

Limitations of Controls and Procedures The Company’s management, including the Chief Executive Officer and Interim Chief Financial Officer, believe that any disclosure controls and procedures or internal controls over financial reporting, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, they cannot provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been prevented or detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by unauthorized override of the control. The design of any systems of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no



assurance that any design will succeed in achieving its stated goals under all potential future conditions. Accordingly, because of the inherent limitations in a cost effective control system, misstatements due to error or fraud may occur and not be detected.

DISCLOSURE OF OUTSTANDING SHARE DATA At March 27, 2013, the Company had the following common shares, stock options and warrants outstanding:

Common shares 466,374,814

Stock options (vested and unvested) 14,867,621

Warrants -

Total 481,242,435

ALTERNATIVE PERFORMANCE MEASURES

Net Interest “Net Interest” means the effective portion of results that the Company would have reported if each of HS Orka hf (75% for 2 months and 66.6% for the remainder of the year), the Toba Montrose General Partnership (40%), the Dokie General Partnership (51%), and Soda Lake facility (100%) had been reported in accordance with Alterra’s actual share ownership for the twelve months ended December 31, 2012. EBITDA EBITDA is defined by the Company as earnings before interest, taxes, foreign exchange, depreciation and amortization, as well as before deductions for other gains and losses, amortization of below market contracts, and value assigned to options granted less share of income (loss) of equity accounted investees plus the Company’s interest in EBITDA of its equity accounted investees. The Company discloses EBITDA as it is a measure used by analysts and by management to evaluate the Company's performance. As EBITDA is a non-IFRS measure, it may not be comparable to EBITDA calculated by others. In addition, as EBITDA is not a substitute for net earnings, readers should consider net earnings in evaluating the Company’s performance.

The following reconciles loss for the year to EBITDA:

Year endedDecember 31, 2012

Loss for the year (20,082)$

Adjustments:

Income tax expense 180

Share of income of equity investees (3,281)

Share of EBITDA of equity investees 32,431

Other gains and losses 15,074

Finance costs 9,798

Finance income (2,754)

Amortization of below market contracts (1,913)

Amortization, depreciation, depletion and accretion 13,825

Stock based compensation 1,414

EBITDA 44,692$



CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain of the statements and information in this MD&A constitute “forward-looking information” within the meaning of applicable Canadian provincial securities laws relating to the Company and its operations. All statements, other than statements of historical fact, are forward-looking statements. Such statements may include, but is not limited to: statements with respect to future events or future performance; the capacity and electricity generation expectations of projects; management’s expectations regarding our growth; results of operations; business prospects and opportunities; determining the feasibility of building the Upper Toba and Dokie Expansion projects; expansion programs at the Reykjanes power plant; programs to upgrade and develop the Company’s inferred and indicated geothermal resources; permitting for the Company’s expansion, development and exploration programs; negotiation of a power purchase agreement related to an expansion of the Reykjanes power plant; estimates of recoverable geothermal energy “resources” or power generation capacities; and permitting and regulatory requirements related to any such plans. Such forward-looking information reflects management’s current beliefs and is based on information currently available to management. Often, but not always, forward-looking statements can be identified by the use of words such as “anticipate”, “believe”, “forecast”, “plan”, “expect”, “is expected”, “budget”, “estimates”, “goals”, “intend”, “targets”, “aims”, “appears”, “likely”, “typically”, “potential”, “probable”, “continue”, “strategy”, “proposed”, or “project” or variations (including negative variations) of such words and phrases or may be identified by statements to the effect that certain actions “may”, “could”, “should”, “would” or “shall” be taken, occur or be achieved.

A number of known and unknown risks, uncertainties and other factors, may cause our actual results or performance to materially differ from any future results or performance expressed or implied by the forward-looking information. Such factors include, but are not limited to: hydrological studies may not confirm that water flows are sufficient to generate enough electricity to support our planned hydro expansion or development programs; wind studies may not confirm that wind resources are sufficient to generate enough electricity to support our planned wind expansion or development programs; failure to discover and establish economically recoverable and sustainable geothermal resources through our exploration and development programs; geothermal exploration and development programs are highly speculative, are characterized by significant inherent risk and costs, and may not be successful; our financial performance depends on our successful operation of power plants, which is subject to various operational risks; our renewable power resources may decline over time and may not remain adequate to support the operation of our power plants; imprecise estimation of renewable power resources or power generation capacities; imprecise estimation of resources and reserves of geothermal energy; variations in project parameters and production rates; meteorological or geological occurrences beyond our control may compromise our operations and their capacity to generate power; inability to obtain the financing we need to pursue our growth strategy; the high cost of placing power plants into commercial production; non-contracted power prices are subject to dramatic and unpredictable fluctuations; industry competition may impede our ability to access suitable renewable power resources; we may be unable to enter into PPAs on terms favourable to us, or at all; the cancellation or expiry of government initiatives to support renewable energy generation may adversely affect our business; impact of significant capital cost increases; unexpected or challenging geological conditions; changes to regulatory requirements, both regionally and internationally, governing development, geothermal resources, production, exports, taxes, labour standards, occupational health, land use, environmental protection, project safety and other matters; failure to obtain or maintain necessary licenses, permits and approvals from government authorities; the success of our business relies on attracting and retaining key personnel; the risk of human error; our officers and directors may have conflicts of interests arising out of their relationships with other companies; we may face adverse claims to our title; developments regarding aboriginal, First Nations and indigenous peoples; fluctuations in foreign currency exchange and interest rates may affect our financial results; we may not be able to successfully integrate businesses or projects that we acquire in the future; our insurance policies may be insufficient to cover losses; the governments of the countries in which the Company undertakes its activities may take action which results in fines or other penalties levied against the Company; aluminum price risk with respect to certain contracts the Company has in Iceland; risks associated with inter-regional transmission grids; host country economic, social and political conditions can negatively affect our operations;



the fluctuation of our common share price could result in investors losing a significant part of their investment; we currently have no dividend payment policy; if the Company chooses to issue additional equity securities it could negatively impact the trading price of our common shares; the risk of volatility in global financial conditions, as well as significant decline in general economic conditions; and other exploration, development and operating risks. There may be other factors that cause unanticipated or unintended actions, events or results. These factors are not intended to represent a complete list of the risk factors that could affect us. Additional risk factors are discussed in the section entitled “Risk Factors” in this MD&A. These factors should be considered carefully and investors should not place undue reliance on forward-looking information. The forward-looking information contained in this MD&A is based upon what management believes to be reasonable assumptions, including, but not limited to: the effects of any increase in power production from our operations; the success and timely completion of planned exploration, development and expansion programs; our ability to comply with local, state, provincial and federal regulations dealing with operational standards and environmental protection measures; our ability to negotiate and obtain PPAs on favourable terms; our ability to obtain necessary regulatory approvals, permits and licences in a timely manner; the availability of materials, components or supplies; our ability to solicit competitive bids for drilling operations, construction or other relevant third party services and obtain access to critical resources; the growth rate in net electricity consumption; support and demand for renewable power generation; government initiatives to support the development of renewable power generation; the accuracy of volumetric reserve estimation methodology and probabilistic analysis used to estimate the quantity of potentially recoverable energy; the accuracy of the analysis used to estimate renewable resources and reserves; environmental, administrative or regulatory barriers to the exploration and development of resources on our properties; geological, geophysical, geochemical and other conditions at our properties; the reliability of technical data, including extrapolated temperature gradient, geophysical and geochemical surveys and geothermometer calculations; capital expenditure estimates; availability of capital to fund exploration, development and expansion programs; our competitive position; and general economic conditions. Forward-looking information is also based upon the assumption that none of the identified risk factors that could cause actual results to differ materially from the forward-looking information will occur. There can be no assurance that the forward-looking information included in this MD&A will prove to be accurate, as actual results and future events could differ materially from those anticipated in such information. Accordingly, investors should not place undue reliance on forward-looking information. Forward-looking information is made as of the date of this MD&A and, other than as required by applicable securities laws, we assume no obligation to update or revise such forward-looking information to reflect new events or circumstances.

management’s discussion & analysis for the year ended...

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