CLEAN POWER PURE ENERGY 2015 ANNUAL REPORT

Transcription

1 CLEAN POWER PURE ENERGY 2015 ANNUAL REPORT

2 TABLE OF CONTENTS Forward Looking Statement Company Overview Letter from the Chairman Board of Directors Corporate Directory 2015 Annual Results MD&A Financial Statements FORWARD-LOOKING STATEMENT This Annual Report contains certain forward-looking statements and information within the meaning of applicable securities laws. All statements, other than statements of historical fact, are forwardlooking statements or information. This information may involve known and unknown risks, assumptions and uncertainties, and other factors which may cause the Company s actual results, performance or achievements to be materially different from the future results, performance or achievements implied by such statements or information. Specifically, forward-looking statements within this annual report relate to, among other things: estimates regarding construction scheduling at Jimmie Creek, successful development and construction of our pre-operational projects and properties, the growth of the clean energy business generally, success of our expansion programs in Iceland, prospective generation, results of operations and financial position. These statements reflect the current views of Alterra Power Corp. ( Alterra or the Company ) with respect to future events and are necessarily based upon a number of assumptions and estimates that, while considered reasonable by the Company, are inherently subject to significant business, economic, political and social uncertainties and contingencies. These statements and information reflect the Company s current views with respect to future events and are necessarily based upon a number of assumptions that, while considered reasonable by the Company, are inherently subject to significant operational, business, economic and regulatory uncertainties and contingencies. These assumptions include, among others, the expected power generation from our operations, the success and timely completion of planned development, expansion and construction programs, and modeling and budgeting based on historical trends, our ability or inability to obtain financing or refinancing to pursue our growth strategy and business plans, current conditions and expected future developments. Forward-looking statements and information also involve known and unknown risks that may cause actual results to differ materially from those expressed by such statements or information, and the Company has made assumptions and estimates based on or related to many of these factors. These risks include volatility of renewable energy resources, inherent risks in operating and constructing power plants and development programs related to the same, contractual risks related to credit facilities, partnership and power purchase agreements, prospective power, currency and commodity price fluctuations, health, safety, social and environmental risks and risks related to reliance on third parties. Additional risks, assumptions and influential factors are set out in the Company s management discussion analysis and Alterra s most recent annual information form, copies of which are available on SEDAR at Although Alterra has attempted to identify important factors that could cause actual results to differ materially, given the inherent uncertainties in such forward-looking statements and information, there may be other factors that cause results not to be as anticipated, estimated, described or intended. Investors are cautioned against undue reliance on any such forward-looking statements or information, which apply only as of their dates. Other than as specifically required by law, Alterra undertakes no obligation to update any forward-looking statements or information to reflect new information. Shannon Turbines - TX Jimmie Creek - Power Line Annual Report Alterra Power Corp Front cover; Dokie Turbine - BC Reykjanes Geothermal Plant - Iceland Toba Montrose - BC

3 COMPANY OVERVIEW Toba Montrose - BC Alterra Power Corp. is a leading global renewable energy company, operating six power plants totaling 757 MW of generation capacity including the Shannon wind project intexas, British Columbia's largest run-of-river hydro facility and largest wind farm, and two geothermal facilities in Iceland. Alterra owns a 349 MW share of this capacity, generating over 1,600 GWh of clean power annually. Alterra is also constructing the 62 MW Jimmie Creek run-of-river hydroelectric project in British Columbia, which is expected to be in operation by Q (51% owned by Alterra). Upon completion of Jimmie Creek, Alterra will operate seven power plants totaling 819 MW of capacity and will own a 381 MW share of this capacity, generating over 1,700 GWh of clean power annually. Alterra has an extensive portfolio of exploration and development projects and a skilled international team of developers, builders and operators to support its growth plans. Alterra Power Corp trades on the Toronto Stock Exchange under the symbol AXY and OTC in the United States as MGMXF Annual Report Alterra Power Corp 02

4 LETTER FROM THE CHAIRMAN Jimmie Creek Construction - BC ROSS BEATY Executive Chairman Alterra Power Corp. had another strong year in 2015, marked by successful completion of the 204 MW Shannon wind farm in Texas, which drove 33% growth in renewable power assets operated by Alterra from 568 MW at the end of 2014 to 757 MW at the end of Alterra owns a 349 MW share respectively. We expect further growth in 2016 when our 62 MW 51%-owned Jimmie Creek run-of-river hydro project in British Columbia is completed mid-year. Longer term, we expect further growth from new wind and solar assets in the USA, that will take advantage of new tax incentives there, as well as our hydro assets in Canada and geothermal and hydro assets in Iceland. We have completed financings of nearly $1 billion over the past two years to support our two construction projects in Texas and British Columbia, and to further other development activities. In addition, our existing producing assets which include the Dokie wind farm, and Toba Montrose hydro operations in B.C. and the Svartsengi and Reykjanes geothermal plants in Iceland had another good year highlighted by record generation at our British Columbia assets. Once again I want to give credit for our strong growth to our small but wonderful management team. Alterra s outstanding results of safe, on-time and on-budget construction and operation speak for themselves. These are terrific achievements and would not have happened without the dedication and enormous competence of the whole team. I know I speak for all of Alterra s shareholders in thanking them. I also thank our many financial stakeholders who help our business succeed, including our First Nations partners at our British Columbia operations, and our lenders and financial partners like Axium Infrastructure, Manulife, and AMP Capital in Canada, and Starwood, Berkshire Hathaway and Citi in the USA, as well as Jarðvarmi slhf and our consortium of European bank lenders in Iceland. Finally, we could not be successful without the skillful work of all of our contractors and advisors, and the support and encouragement of the communities and regions where we work. Our success in turn helps build their success. Our power operations are extremely long lived assets that provide sustainable and predictable wealth creation for so many. Late in 2015 I had the opportunity to attend the Paris COP 21 climate talks, which ended successfully with a pact by 170 nations to take more aggressive action to combat climate change. We at Alterra are all about this mission we provide truly sustainable electricity generation based on the free and permanent energy sources of the sun, the wind, the earth s heat and flowing water. And we do it profitably. Clean energy generation is a rapidly growing business globally and we expect to continue to benefit from being part of this global energy transition. In 2016 we expect to complete construction of Jimmie Creek and embark on several new clean power projects in North America and Iceland. I am especially excited about our 2016 prospects to realize more value from our Icelandic assets and look forward to a continuing stream of good news there during the year. Our Icelandic team is strong and we have multiple growth prospects in front of us that will be advanced during the year. In addition we will engage more with investors during the year to demonstrate how Alterra Power has become a compelling investment proposition. I therefore look forward with optimism as we continue to satisfy our mission of building a larger, stronger company with a lower cost of capital and a more diversified suite of clean energy assets. Ross Beaty Chairman May Annual Report Alterra Power Corp

5 GEOTHERMAL BOARD OF DIRECTORS Dokie Jimmie - BC Creek Construction - BC ROSS BEATY Executive Chairman Mr. Beaty is a geologist and resource company entrepreneur with over 40 years of experience in the international minerals industry. He is the founder of Alterra Power Corp (formally Magma Energy Corp), Pan American Silver Corp., and several other resource companies, many of which have been successfully divested. Mr. Beaty is a Director of The Nature Trust of BC and patron of the Beaty Biodiversity Center at the University of British Columbia. DONALD McINNES Executive Vice Chairman Mr. McInnes, founder of Plutonic Power (merged with Alterra Power in 2011). Past Chair of Prostrate Cancer Canada, and of the Clean Energy Association of BC. He is a former director of the Duke of Edinburgh s Award British Columbia and Yukon Division and a former Governor of the British Columbia Business Council. Currently a Director of True Gold Mining Inc. JAMIE BRUCE Director Mr. Bruce has over 22 years experience in the corporate finance and investment banking industry. He is a senior partner of Capital West Partners, a private investment banking firm specializing in investment advisory services. Mr. Bruce is well-known as both a financial and business leader and has served widely in public and private companies, crown corporations and not-for-profit organizations. JOHN CARSON Director Mr. Carson is graduate of the University of Chicago and Purdue University and is a highly experienced renewable energy business leader with a core expertise in structuring and leading financial transactions. Former senior positions held in GE Energy Financial Services (Renewable Energy Group), Terra-Gen Power and Noble Environmental Power. DAVID CORNHILL Director Mr. Cornhill has over 26 years of experience in the energy industry. He is the founder, Chairman and CEO of AltaGas Income Trust, one of Canada s largest energy infrastructure groups, focused on gas and power infrastructure and renewable energy (wind and hydro). Mr. Cornhill also sits on several private and public boards including AltaGas Utility Group and Ivey Business School. KERRI FOX Director Ms. Fox has over 20 years of experience in banking and corporate financing in the renewable energy sector. Previously Ms. Fox ran the Global Export & Project Finance business for Fortis Bank New York, and currently heads the North American Project & Structured Finance business for Banco Bilbao Vizcaya Argentina SA. DONALD SHUMKA Director Shannon - TX Mr. Shumka is a graduate of Harvard University with over 42 years of experience in management and financial consulting. Mr. Shumka is currently Managing Director of Walden Management Ltd., a financial consulting firm. Mr. Shumka is active in the not for profit sector and is currently the Chair of the British Columbia Arts Council Annual Report Alterra Power Corp 04

6 CORPORATE INFORMATION GEOTHERMAL HEAD OFFICE: Svartsengi - Iceland ALTERRA POWER CORP Address: Dunsmuir Street Vancouver, BC V6C 3K4 Canada info@alterrapower.ca Web: Telephone: Toll Free: Fax: SUBSIDIARY OFFICES: POWELL RIVER Address: 4493D Marine Avenue Powell River, BC V8A 4Z3 Canada Telephone: HS ORKA HF Address: Brekkustíg Reykjanesbær Iceland Telephone: COMPANY INFORMATION SENIOR MANAGEMENT Toll Free: ROSS BEATY Executive Chairman info@alterrapower.ca JOHN CARSON Chief Executive Officer Web: LYNDA FREEMAN Chief Financial Officer Stock Exchange/Symbol: TSX: AXY OTC: MGMXF MURRAY KROEKER VP Solar Power & Engineering Issued & Outstanding: 468,652,409 shares (as of Dec 31, 2015) ÁSGEIR MARGEIRSSON CEO, HS Orka CUSIP Number: PAUL RAPP VP Wind & Geothermal Power Transfer Agent: Computershare Investor Services Inc JONATHAN SCHINTLER VP Project Finance, Merger & Acquisitions Auditor: PricewaterhouseCoopers LLP JAY SUTTON VP Hydro Power Financial Year-End: December 31 SHANNON D. WEBBER General Counsel Annual Report Alterra Power Corp

7 MANAGEMENT S DISCUSSION & ANALYSIS FOR THE YEAR ENDED DECEMBER 31, 2015 SHANNON TURBINES - TX

8 TABLE OF CONTENTS INTRODUCTION CORE BUSINESS AND STRATEGY HIGHLIGHTS FOR THE YEAR ENDED DECEMBER 31, 2015 AND SUBSEQUENT EVENTS OPERATIONS REVIEW CONSTRUCTION PROJECTS - INFORMATION, UPDATES AND OUTLOOK DEVELOPMENT PROJECTS - INFORMATION, UPDATES AND OUTLOOK SELECTED ANNUAL INFORMATION FINANCIAL REVIEW FOR THE YEAR ENDED DECEMBER 31, 2015 SUMMARY OF QUARTERLY RESULTS QUARTERLY FINANCIAL REVIEW FOR THE THREE MONTHS ENDED DECEMBER 31, 2015 LIQUIDITY AND CAPITAL RESOURCES TRANSACTIONS WITH RELATED PARTIES OUTLOOK OFF-BALANCE SHEET ARRANGEMENTS CRITICAL ACCOUNTING POLICIES AND MANAGEMENT ESTIMATES FINANCIAL INSTRUMENTS AND RELATED RISKS OTHER RISKS AND UNCERTAINTIES FUTURE ACCOUNTING STANDARDS MANAGEMENT'S REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING DISCLOSURE OF OUTSTANDING SHARE DATA ALTERNATIVE PERFORMANCE MEASURES Twelve Month Report 2015 Management's Discussion & Analysis 2

9 March 15, 2016 INTRODUCTION The following Management s Discussion and Analysis ( MD&A ) is intended to help the reader understand the significant factors that have affected the performance of Alterra Power Corp. and its subsidiaries (the Company or "Alterra") and such factors that may affect its future performance. This MD&A has been prepared as of March 15, 2016 and it should be read in conjunction with the audited consolidated financial statements of the Company for the year ended December 31, 2015 and the related notes thereto. All figures are expressed in United States ( USA ) dollars except where otherwise indicated. References to C$ are to Canadian dollars and references to ISK are to Icelandic Krona. 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 certain measures that are not standardized under IFRS, such as net interest, by which the Company means the effective portion of operating results that the Company would have reported if each of HS Orka hf (66.6%, HS Orka ), the Toba Montrose General Partnership (40%, Toba Montrose GP ), the Dokie General Partnership (25.5%, Dokie GP ), Shannon Group Holdings, LLC (50%, "Shannon Group LLC") and Soda Lake (100% until Soda Lake was sold on January 30, 2015) had been reported in accordance with the Company's actual share ownership for the year ended December 31, 2015 (the current year") and for the year ended December 31, 2014 ("comparative year"). This measure along with the use of adjusted earnings before interest, taxes, depreciation and amortization ( Adjusted EBITDA"), are non-ifrs measures, and used by Alterra to better manage and evaluate Company performance and to further assist the Company s shareholders in understanding the Company s holdings, but does not have standardized meaning. To facilitate a better understanding of these measures presented by the Company, qualifications, definitions and reconciliations have been provided in the section Alternative Performance Measures. Certain statements contained in this MD&A are forward-looking information within the meaning of applicable Canadian securities laws relating to the Company and its operations. Please refer to the cautionary note regarding the risks associated with forward-looking information at the back of this MD&A and under the heading Risk Factors in the Company's Annual Information Form on file with the Canadian securities regulatory authorities. Additional information and disclosure relating to the Company, can be found on the Company s website at and on the SEDAR website at Information contained in or otherwise accessible through our website does not form part of the MD&A. Twelve Month Report 2015 Management's Discussion & Analysis 3

10 CORE BUSINESS AND STRATEGY The Company is engaged in the ownership, operation, development and acquisition of renewable power projects. The Company operates six power plants totaling 757 megawatts ( MW ) of capacity, with operations in Canada, USA and Iceland, and has another power plant totaling 62 MW of capacity under construction, which is expected to be fully operational by summer The Company s current portfolio of operating and construction facilities is summarized as follows: OPERATING CONSTRUCTION Reykjanes Svartsengi Location Iceland Iceland British Columbia Toba (b) Montrose Dokie 1 Shannon Jimmie Creek British Columbia Texas, USA British Columbia Type of generation Geothermal Geothermal Run of river hydro Wind Wind Run of river hydro Capacity (MW) (Toba) 88 (Montrose) Long-term annual electricity generation (MWh) % included in consolidated financial statements 745, , , , , , % 100% 40% (equity investment) 25.5% (equity investment) 50% (equity investment) 51% (equity investment) Ownership entity HS Orka HS Orka Toba Montrose GP Alterra net interest Dokie GP Shannon Group LLC Jimmie Creek LP (a) 66.6% 66.6% 40.0% 25.5% 50.0% 51.0% (a) Jimmie Creek ownership entity is the Jimmie Creek Limited Partnership ("Jimmie Creek LP") (b) Consists of the East Toba (147MW) and Montrose Creek (88 MW) power plants, collectively "Toba Montrose" Twelve Month Report 2015 Management's Discussion & Analysis 4

11 The Company also has development projects in several locations as follows: Location Project Net ownership Technology Canada Bute Inlet 100% Hydro Dokie 2 51% Wind Tahumming 100% Hydro South Toba projects 100% Hydro Coastal wind projects 100% Wind Multiple early stage projects 100% Hydro Iceland Reykjanes 3-4 (potential expansion) 67% Geothermal Eldvörp / Krýsuvík / Trölladyngja 67% Geothermal Búlandsvirkjun 33% Hydro Hvalá 39% Hydro Brúarvirkjun 67% Hydro Skúfnavatnavirkjun 39% Hydro Multiple early stage projects 67% Geothermal/Hydro USA Soda Lake Solar 100% Solar Multiple wind projects 100% Wind Chile Mariposa 30% Geothermal Peru Multiple early stage projects 30% Geothermal Italy Mensano / Roccastrada 45% Geothermal The Company was incorporated on January 22, 2008, pursuant to the Business Corporations Act (British Columbia) and effectively commenced operations in February The Company s head office is located in Vancouver, British Columbia ( BC ), Canada, it is a reporting issuer in all the provinces and territories 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 development, construction, operating, and financial knowledge that allows the Company to advance early stage projects through development, construction, and into operation. The Company has a proven ability to develop and deliver large operating 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, local communities and government agencies, all of whom are viewed as partners. Twelve Month Report 2015 Management's Discussion & Analysis 5

12 HIGHLIGHTS FOR THE YEAR ENDED DECEMBER 31, 2015 AND SUBSEQUENT EVENTS Operations On-target production: The Company achieved 99.6% of its budgeted generation for the year, as follows: Total 2015 Generation (MWh) Net Interest Facility Budget (a) Actual Budget (a) Actual % of Budget Reykjanes 789, , , , % Svartsengi 497, , , , % Soda Lake (b) 6,000 6,991 6,000 6, % Toba Montrose 716, , , , % Dokie 1 330, ,795 84,405 86, % Shannon (c) 38,853 38,383 19,427 19, % TOTAL 2,378,841 2,406,570 1,253,345 1,248, % Here and in the table below; (a) Includes planned maintenance outages. (b) The facility was sold on January 30, (c) Measured from commencement of operations on December 10, 2015 at 50% sponsor equity. Twelve Month Report 2015 Management's Discussion & Analysis 6

13 Record generation at BC assets; earn-out payment: Both Toba Montrose and Dokie 1 achieved record generation in 2015, breaking previous records from 2014 and 2011 respectively. On December 26, Dokie 1 achieved a performance hurdle entitling the Company to a C$0.8 million earn-out payment, which was received in February Commercial operations achieved at Shannon: Financial closing: On June 30, the Company closed a $286.8 million construction loan which was supported by a $218.8 million tax equity investment commitment. On the same day, the Company entered into a partnership agreement resulting in each party owning 50% of the project. Commercial operations: On December 10, construction of the 204 MW wind farm was completed and Shannon commenced commercial operations. All 119 turbines were successfully placed in service and the construction was completed on time and on budget. Tax equity funding: On December 14, the tax equity investment was fully funded, with proceeds used to retire the construction loan facility in full. Under the partnership agreement between the sponsors and the tax equity investors, 99% of taxable earnings and tax credits will be allocated from the project to the tax equity investors, as well as a minority allocation of cash that will vary under certain conditions, until the tax equity investors achieve an agreed yield, which is expected to occur within ten years of the commercial operations date. Initial return of capital: On December 29, Alterra received a $3.5 million return of capital from Shannon Group LLC representing unused construction contingency funds ($7.0 million returned to Shannon Group LLC). New Project Construction Jimmie Creek construction continues: Construction for the 62 MW hydro project continued and is on time and on budget. Progress during the year included completion of the switchyard, penstock, intake and tie-in to the transmission line as well as commissioning of the intake. At the powerhouse, all of the electrical and mechanical equipment has been delivered to the site and the installation of the generators has commenced. The facility is expected to commence generation in the summer of Project Development Acquisition of South Toba hydroelectric projects: In October the Company agreed to acquire the water rights for four hydro development projects (the South Toba projects: Chusan, Powell, Eldred North and Eldred South) which are all located near the Toba Montrose and Jimmie Creek projects and are situated along the Toba Montrose transmission line. First Nation agreement signed for Tahumming hydro project: The Company signed an agreement with the Klahoose First Nation to jointly develop the 15 MW Tahumming hydro project in British Columbia, near the Toba Montrose and Jimmie Creek projects. Completed step-up acquisition of Icelandic hydro projects: In October 2015 HS Orka increased its ownership interest to 52.5% in the 55 MW Hvalá and 10 MW Skúfnavatnavirkjun hydro projects through a step-up acquisition of subsidiary Vesturverk ehf. ("Vesturverk"). USA wind projects: The Company executed land leases for two wind projects with generation capacity of up to 350 MW. Mariposa drilling project in Chile postponed: In October 2015, Energy Development Corporation ("EDC"), our majority partner on the project, elected to postpone the previously scheduled 2015 drilling program in response to lower commodity prices which have negatively impacted the near-term project economics. Twelve Month Report 2015 Management's Discussion & Analysis 7

14 Financial / Other Adjusted EBITDA: Consolidated and net interest Adjusted EBITDA decreased by 10% to $46.4 million and $37.0 million respectively, primarily due to fluctuations in foreign exchange as the Canadian dollar weakened 19% against the comparative year. In originating currency, Adjusted EBITDA increased year on year at Toba Montrose, Dokie 1 and HS Orka. Revenue: Consolidated revenue decreased by 18% ($57.8 million against $71.0 million) and net interest revenue decreased by 16% ($71.6 million against $85.2 million) predominantly due to fluctuations in foreign exchange and the sale of the Soda Lake facility in January 2015, slightly offset by commencement of operations at Shannon and higher winds at Dokie 1. Average annual rates Distributions received: The Company received distributions as follows: Toba Montrose: Toba Montrose GP declared and paid equity distributions in the amount of C$18.0 million, the Company's share being C$7.2 million. Dokie 1: Dokie GP declared and paid a C$3.5 million distribution, the Company's share being C$0.9 million. Blue Lagoon hf: Blue Lagoon hf declared and paid a distribution of which HS Orka's share was $2.7 million. HS Orka: HS Orka declared and paid a distribution of $2.4 million, the Company's share being $1.6 million. The distribution was a flow through of the 2014 Blue Lagoon hf distribution. Subsequent to year end, Dokie GP and Toba Montrose GP paid distributions of C$12.0 million and C$5.0 million, the Company's share being C$3.1 million and C$2.0 million, respectively. The Twelve Month Report 2015 Management's Discussion & Analysis 8

15 Other: Dokie GP distribution was a record high distribution and reflected the strong performance of the asset in New power purchase agreement: HS Orka signed a power purchase agreement with Thorsil ehf., which is planning to construct and operate a silicon metal plant in Helguvík, Iceland to supply up to 32 MW of the plant's power needs. The delivery of power under the contract is subject to several conditions on behalf of both parties. Sale of Soda Lake facility: On January 30, 2015, the Company sold the 15 MW Soda Lake geothermal facility and related development assets to an affiliate of Cyrq Energy, Inc. ("Cyrq") for proceeds of $8.5 million plus potential additional compensation over the next five years upon the achievement of certain earn-out provisions. Alterra retained the rights to develop a 40 MW solar project at the site. HS Orka receives grants for 2016 deep drilling program: HS Orka has been awarded three grants totaling $12.6 million related to the deep drilling program, and plans to commence drilling a 4-5 km deep production well at the Reykjanes geothermal field. The well is expected to reach temperatures in excess of 400 C. At December 31, 2015 $5.0 million had been received relating to these grants. OPERATIONS REVIEW HS Orka (Reykjanes and Svartsengi geothermal facilities), Iceland (66.6% interest) The Company holds a 66.6% economic interest in HS Orka, which produces and sells electricity from two operating geothermal plants (Reykjanes and Svartsengi) located in the Reykjanes peninsula of Iceland. The remaining 33.4% economic interest in HS Orka is held by Jarðvarmi slhf, a consortium of Icelandic pension funds. The Reykjanes plant has 100 MW of generation capacity and is expected to generate a long-term average of 745,000 MWh of electricity annually, while the Svartsengi plant has 74 MW of generation capacity and is expected to generate a long-term average of 520,000 MWh of electricity as well as 190 MW (thermal) of capacity for hot water for district heating. The Company sells power to a number of commercial and retail customers including power sold under long-term power purchase agreements ("PPAs"), with Landsvirkjun, Norðurál ehf (together with its affiliates "Norðurál") and Advania with the majority of the power being sold under these contracts expiring in The Company also signed a long-term PPA with Thorsil ehf., which is planning to construct and operate a silicon metal plant in Helguvík, Iceland. Under the contract, the Company would supply up to 32 MW of the plant's power needs. The delivery of the power from the Company is subject to several conditions on behalf of both parties. In 2015, 25.9% of the Company s revenue in Iceland was linked to forward aluminum prices (2014: 26.2%). HS Orka also holds a 30% interest in Blue Lagoon hf., which operates the Blue Lagoon geothermal spa in Iceland. The Company also provides and sells various by-products to companies located near the two power plants, including geothermal brine and steam, gas, and fresh water. The Company commenced a fluid reinjection program at the Reykjanes geothermal field in 2013 to mitigate recent decreases in generation at the Reykjanes plant and to enhance future field stability, whereby a portion of geothermal fluids extracted in the current operations will be re-injected into the field to maintain or increase subsurface pressure and optimize the resulting electrical output. The Company successfully drilled a large-diameter reinjection well in 2014, and based on positive results from that Twelve Month Report 2015 Management's Discussion & Analysis 9

16 well, the Company drilled a second nearby injection well. A pipeline from the plant to the reinjection wells was constructed in late 2015 and reinjection commenced in early March. The Company is constructing a new discharge system for the Svartsengi plant that will enable additional geothermal fluid to be extracted from the reservoir resulting in increased power generation and increased warm fluid sales to other customers. The system is expected to be completed in the summer of The Company has also completed drilling for two new production wells at Svartsengi that will be connected to the Svartsengi plant in In addition, the Company recently completed a 20% expansion of the plant's district heating capability. The operating results of HS Orka (including Reykjanes and Svartsengi) are shown below and reflect the Company s net ownership interest of 66.6%. (All tabular amounts in $000s except where specified) Year ended December 31, Generation (MWh) 818, ,208 Revenue 38,219 43,890 Adjusted EBITDA 18,800 20,543 The Adjusted EBITDA decrease is entirely due to foreign exchange (in ISK Adjusted EBITDA is up 3% from 2014), while revenue decreased due to foreign exchange as well as a transfer of certain employees directly to HS Veitur hf ("HS Veitur"), where formerly the employees costs were recharged and recorded in income. Excluding the non-cash impact of these items, revenue increased 9% year on year (in ISK) primarily due to increased retail sales (as shown below). * Adjusted EBITDA was translated into originating currency using ISK to USD rates of and for 2015 and 2014, respectively. Soda Lake geothermal facility, Nevada, USA On January 30, 2015, the Company sold its interest in the Soda Lake facility and certain geothermal development assets to an affiliate of Cyrq for proceeds of $8.5 million. The Company may receive additional compensation over the next five years on the achievement of certain performance-related or "earn-out" provisions currently valued at $1.0 million. Twelve Month Report 2015 Management's Discussion & Analysis 10

17 Toba Montrose hydroelectric facility, British Columbia, Canada The Company operates and holds a 40% economic interest (51% voting interest) in the 235 MW Toba Montrose project which is held by Toba Montrose GP and has been in operation since May The remaining 60% economic interest in the project is held by an investor consortium led by a fund that is managed by Axium Infrastructure Inc. ("Axium"). The Company s economic interest in the project will increase from 40% to 51% in May 2045 for no additional consideration. Toba Montrose sells 100% of its electricity to the British Columbia Hydro and Power Authority ( BC Hydro ) under a 35-year PPA that expires in May 2045 and the facility is expected to generate a longterm average of 727,000 MWh of electricity annually. Toba Montrose 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 (until 2020), at a rate of C$10 per MWh. The Company anticipates the 10 year restraint will come into effect rather than the C$72.7 million cap. Toba Montrose s annual long-term generation is projected to vary seasonally in the following proportions: Q1 - January - March 4% Q2 - April - June 32% Q3 - July - September 52% Q4 - October - December 12% Alterra operates the Toba Montrose facility in cooperation with the Klahoose, Sliammon and Sechelt First Nations. Generation for the current year was a record 111% of forecast. The project achieved its annual forecasted generation on October 8, nearly two months ahead of forecast and 13 days earlier than in 2014, which was the previous best year of generation. The operating results of Toba Montrose are shown below and reflect the Company s 40% interest: Year ended December 31, Generation (MWh) 316, ,376 Revenue 24,738 28,597 Adjusted EBITDA 18,825 21,029 Revenue and Adjusted EBITDA declined from the comparative year entirely due to weakening of the Canadian dollar, as revenue increased 1% in Canadian dollars (as shown below). Twelve Month Report 2015 Management's Discussion & Analysis 11

18 * Adjusted EBITDA was translated into originating currency using the CAD to USD rates of and for 2015 and 2014, respectively. Dokie 1 wind farm, British Columbia, Canada The Company operates and holds a 25.5% ownership interest in the 144 MW Dokie 1 project which is held by Dokie GP and has been in operation since February The remaining 74.5% interest in the project is held by an investor consortium led by Axium. Dokie 1 is expected to generate a long-term average of 330,000 MWh of electricity annually. Dokie 1 sells 100% of its electricity to BC Hydro under a 25-year PPA that expires in February Dokie 1 is EcoLogo certified and receives funding under the ecoenergy program of up to C$33.3 million during its first ten years of operations (until 2021), at a rate of C$10 per MWh. The Company anticipates the 10 year restraint will come into effect rather than the C$33.3 million cap. Dokie 1 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% Alterra operates the Dokie 1 facility in cooperation with the Halfway River, West Moberly and Saulteau First Nations, and the McLeod Lake Indian Band. The operating results of Dokie 1 are shown below and reflect the Company s 25.5% interest: Year ended December 31, Generation (MWh) 86,648 72,949 Revenue 7,906 7,631 Adjusted EBITDA 5,735 5,065 Generation and revenue increased by 19% and 4% respectively due to higher winds. The increased revenue plus lower operating costs resulted in a 13% increase in Adjusted EBITDA. The increases in Twelve Month Report 2015 Management's Discussion & Analysis 12

19 revenue and Adjusted EBITDA were partially offset by the weakening of the Canadian dollar, as revenue increased 20% in Canadian dollars against the prior year (as shown below). * Adjusted EBITDA was translated into originating currency using the CAD to USD rates of and for 2015 and 2014, respectively. Shannon wind farm, Clay County, Texas, USA The Company operates and holds a 50% sponsor equity ownership interest in the 204 MW Shannon project which commenced operations on December 10, The remaining 50% sponsor interest in the project is held by Starwood Energy Group Global, LLC ("Starwood"), with tax equity held by affiliates of Citicorp North America, Inc. and Berkshire Hathaway Energy (the Tax Equity Investors ). Shannon is expected to generate a long-term average of 794,000 MWh of electricity annually. On June 30, 2015, affiliates of the Company and Starwood ("the Sponsors") entered into a partnership agreement and completed a $286.8 million construction credit facility for the project, supplied by affiliates of Citibank, N.A., Santander Bank, N.A. and the Royal Bank of Canada, which consisted of a $212.2 million loan plus $74.6 million in letters of credit. On December 10, 2015, Shannon achieved commercial operations with all 119 turbines placed into operation. On December 14 the $218.8 million tax equity investment was funded by the Tax Equity Investors. The proceeds from the tax equity investment were used to fully retire the construction loan facility and enabled a $7.0 million return of equity representing unused contingency (Alterra's share was $3.5 million). One of the primary incentives for renewable energy in the United States has been the production tax credits ("PTC") program, whereby companies that generate electricity from renewable energy sources, including wind, are eligible for tax credits which provide a tax benefit for each unit of generation for the first ten years of the facility s operation. For Shannon, the Tax Equity Investors are allocated 99% of Shannon's taxable income (losses) and a minority portion of the cash generated until they achieve an agreed after-tax investment return (the "Flip Point"). After the Flip Point, the Tax Equity Investors will be allocated 5% of cash distributions and taxable income (losses), and the Sponsors will be allocated 95% of all cash distributions and taxable income. There is no project debt associated with Shannon, however, the project has certain requirements with respect to the allocation of cash distributions, taxable income (losses) and tax credits amongst the Sponsors and Tax Equity Investors. Twelve Month Report 2015 Management's Discussion & Analysis 13

20 During the year there were three insurable events at Shannon: two floods due to heavy rainfall, and a grass fire. The damage from the floods and fire was fully insured subject to deductibles. Payment has been received in full for the fire claim while the final payment for the flood claims is expected in the first quarter of Shannon was constructed under a construction services agreement with M.A. Mortenson Company, and the project s main power transformer was manufactured and installed by Siemens Energy, Inc. General Electric Company ( GE ) supplied 119 wind turbines for the project, and an affiliate of GE is providing operations and maintenance services for the turbines under a long-term contract. The project will sell the majority of its power under a 13-year power hedge with Citigroup Energy Inc. which commences in June Prior to this 100% of the power is sold on the merchant spot market. Year ended December 31, 2015 (a) 2014 Generation (MWh) 19,192 Revenue 273 Adjusted EBITDA 35 (a) Here and elsewhere, the 50% net interest in Shannon reflects the Company's 50% share in sponsor equity. Under the partnership agreement between the Sponsors and the Tax Equity Investors, 99% of taxable earnings (losses) and tax credits will be allocated from the project to the Tax Equity Investors, as well as a minority allocation of cash that will vary under certain conditions, until the Tax Equity Investors achieve an agreed yield, which is expected to occur within ten years of the commercial operations date. Shannon commenced operations on December 10, Results were roughly in line with expectations for this stub period. Summary Comparative Results and Adjusted EBITDA The following results represent the Company s net interest in generation, revenue and Adjusted EBITDA: For the year ended December 31, 2015 HS Orka Toba Montrose Dokie 1 Soda Lake Shannon (66.6%) (40%) (25.5%) (100%) (a) (50%) Development and head office (b) Net interest total Consolidated Results Generation (MWh) 818, ,976 86,648 6,991 19,192 1,248,295 1,235,951 Total revenue 38,219 24,738 7, ,585 57,835 Gross profit 10,632 16,915 4, ,568 16,131 Adjusted EBITDA 18,800 18,825 5, (6,564) 36,983 46,410 (a) The facility was sold on January 30, (b) Included in development and head office Adjusted EBITDA is general development expenses of $1.4 million For the year ended December 31, 2014 HS Orka Toba Montrose Dokie 1 Soda Lake (66.6%) (40%) (25.5%) (100%) Development and head office (a) Net interest total Consolidated Results Generation (MWh) 846, ,376 72,949 68,555 1,303,088 1,339,138 Total revenue 43,890 28,597 7,631 5,050 85,168 70,952 Gross profit (loss) 11,309 19,607 3, ,529 17,092 Adjusted EBITDA 20,543 21,029 5, (6,308) 41,277 51,579 (a) Included in development and head office Adjusted EBITDA is general development expenses of $0.3 million Certain of the comparative year figures have been reclassified to conform to the current year s presentation Twelve Month Report 2015 Management's Discussion & Analysis 14

21 CONSTRUCTION PROJECTS - INFORMATION, UPDATES AND OUTLOOK Jimmie Creek hydroelectric project, British Columbia, Canada The Company, in partnership with Axium, is constructing the Jimmie Creek project, which is expected to be completed on time and on budget. Jimmie Creek will sell 100% of its power to BC Hydro under a 40-year PPA beginning in The project is located in close proximity to Toba Montrose and will have a nameplate capacity of 62 MW, projected annual output of 159,000 MWh and is expected to commence generation in the summer of The Jimmie Creek facility will use excess, unused capacity on the Toba Montrose transmission line that connects Toba Montrose to the BC Hydro substation at Saltery Bay. Jimmie Creek LP has Impact Benefit Agreements with the Sliammon and Sechelt First Nations and a Resource Development Agreement with the Klahoose First Nation. In October 2014, the Company closed a C$176.5 million non-recourse construction and term loan facility for the project. The conversion of the facility into a term loan is expected in the third quarter of 2016, and the loan will mature in The Company jointly owns the project with its partner Axium on a 51% and 49% ownership basis, respectively, through Jimmie Creek LP. The Company does not expect to make any further equity contributions towards the construction of Jimmie Creek, which is now being funded by the construction loan facility and equity contributions by Axium. Jimmie Creek is being constructed under an Engineering, Procurement, and Construction Management contract with SNC-Lavalin Inc. The construction is on schedule and budget and progress to date is as follows: Road, bridge and camp construction were completed in Intake construction, commissioning and headpond filling were completed in the first quarter of Penstock construction is complete and all construction areas have been remediated. Penstock filling is scheduled for late March Construction of the switchyard is complete and tie-in of the Jimmie Creek project to the Toba Montrose transmission line was performed in late February At the powerhouse, all of the electrical and mechanical equipment has been delivered to the site and the installation of the generators has commenced. Installation and testing of the ancillary electrical and mechanical equipment is ongoing and is expected to be completed in April Generator testing is scheduled to commence in May DEVELOPMENT PROJECTS - INFORMATION, UPDATES AND OUTLOOK Reykjanes geothermal expansion project, Iceland The Company continues to assess a potential expansion of the Reykjanes plant capacity from 100 MW to up to 180 MW, subject to further confirmation of resource and other factors. The Company commenced a fluid reinjection program at the Reykjanes geothermal field in 2013 (discussed above under Operations Review). The results of the reinjection program may impact the projected timing and size of the Reykjanes expansion. The expansion project received its operating permit in Twelve Month Report 2015 Management's Discussion & Analysis 15

22 HS Orka commenced an arbitration in 2014 to determine the validity of a PPA with Norðurál signed in 2007 to sell power from the Reykjanes expansion to a proposed new aluminum smelter in Helguvík, Iceland. The Company anticipates results from the arbitration proceedings in mid A separate, related action was filed against Alterra by Century Aluminum Company and Norðurál on April 1, 2015 in Monterey County, California. That action was dismissed by the California court in late August 2015; however Norðurál filed a second action against Alterra in British Columbia in December The Company considers the current action to be without merit. Mariposa geothermal project, Chile The Mariposa geothermal system, which consists of the Maule and Pellado concessions, has an maximum inferred resource potential of 320 MW. Under the terms of a joint venture agreement, EDC holds a 70% interest in Mariposa and is responsible for funding 100% of the next $58.3 million in project expenditures to further advance the project. After the completion of the initial funding, project equity contributions and economic sharing will be on a pro rata basis between the partners. The project holding company was established in 2013 and EDC became the managing partner for the project at that time. The Company accounts for the project as an equity investment. In October 2015, EDC elected to postpone the previously scheduled 2015 drilling program in response to the current low commodity prices which have negatively impacted the project's forecasted economics. The joint venture will resume the drilling program when certain development conditions are met. Work on the project continues in the meantime, including engineering work for the power plant and transmission interconnection, an environmental impact assessment and other development activities. Significant site infrastructure (roads, water supply, camps) has been completed and will remain in place to support the rescheduled drill program. As of December 31, 2015 EDC had spent approximately $32.7 million towards the Mariposa project. Dokie 2 wind project, British Columbia, Canada The Company holds a 51% interest in a wind generation project adjacent to Dokie 1 ( Dokie 2 ) with a projected capacity of up to 156 MW. During 2015, the Company received notice from an affiliate of GE Energy Financial Services ("GE EFS") that it does not intend to proceed with advancement of Dokie 2. The Company expects to complete an agreement with GE EFS to transfer its 49% ownership interest in Dokie 2 to the Company for nominal consideration. In 2014, the Company wrote off the deferred costs and goodwill associated with the Dokie 2 project due to a decline in the economic outlook surrounding renewable energy as a result of the latest Integrated Resource Plan produced by the BC Government. The Company has maintained all existing permits and licenses in good standing and may look to further develop the project in the future when market outlook improves. The Company has no expenses related to Dokie 2 planned in Iceland The Company s development projects in Iceland include the Eldvörp, Krýsuvík and Trölladyngja geothermal projects and the Búlandsvirkjun, Hvalá, Brúarvirkjun and Skúfnavatnavirkjun hydroelectric projects. HS Orka owns 50% of the 155 MW Búlandsvirkjun early-stage hydroelectric development project. During the year, HS Orka further increased its ownership interest of Vesturverk to 52.5%. Vesturverk owns the 55 MW Hvalá and 10 MW Skúfnavatnavirkjun early-stage hydroelectric development projects. The 9 MW Brúarvirkjun hydroelectric project is 100% owned by HS Orka. Twelve Month Report 2015 Management's Discussion & Analysis 16

23 In May 2015 the National Energy Authority in Iceland awarded the Company research permits for the Hvalá and Skúfnavatnavirkjun hydro projects. The Company has not made any material expenditure on these projects during the year. USA In the fourth quarter the Company executed land leases for two wind projects with a potential generation capacity of up to 350 MW. The Company plans to continue development of these projects in 2016 through further resource assessment and other activities. The Company holds the rights to develop a 40 MW solar project at the Soda Lake geothermal plant site. The Company is currently focused on acquiring or developing further early-stage wind or solar projects in the US to take advantage of the recently extended PTC program. In January 2015, the Company sold its geothermal development assets in the USA (McCoy, Desert Queen, Granite Springs, and Hawthorne along with certain other properties adjacent to the Soda Lake facility) to Cyrq as part of the sale of the Soda Lake facility. Peru In January 2014, the Company completed a joint venture with EDC covering certain of the Company's geothermal development assets in Peru, including concessions and applications for concessions. Under the agreement, EDC obtained a 70% interest in the portfolio and plans to fund 100% of the next $6.0 million of development costs. During 2014, EDC provided notice to proceed for further investigations under the joint venture for the Ticsani, San Pedro, Ancoccollo, Casiri and Pinchollo Libre projects, while certain other concessions and geothermal applications contained within these projects were not renewed. In January 2016, EDC provided notice to withdraw from the Pinchollo Libre project but continues to coordinate with the government for the grant of authorizations for the other projects that are under application. Upon granting of the geothermal concessions, the joint venture is expected to perform further exploration to identify potential geothermal resources. The joint venture has not made any material expenditures on these projects to date. Italy In 2011, the Company was awarded the Mensano and Roccastrada geothermal concessions, located near the historic Larderello geothermal field that has generated electricity for nearly 100 years in the Tuscany region of Italy. The Company holds a 45% interest in a joint venture with an affiliate of Graziella Green Power ("Graziella"). The joint venture is currently advancing the Mensano and Roccastrada geothermal concessions as well as a geothermal pilot project (Castelnuovo) near the Mensano concession. Graziella is currently funding all development activities under the joint venture (and will fund approximately the next $4.0 million in development activities). Current development activities included seismic analysis and certain project permitting activities. Twelve Month Report 2015 Management's Discussion & Analysis 17

24 In January 2015, the governor of the Tuscany region issued a moratorium on geothermal exploration activities in the region which was subsequently lifted in the third quarter of As of December 31, 2015 Graziella had spent approximately $2.1 million towards the projects. British Columbia, Canada The Company has rights to 39 run of river hydroelectric power projects in British Columbia as well as certain early-stage wind projects, primarily in the southwestern region of the province. Bute Inlet project The Bute Inlet development project consists of 17 run of river projects organized into three interconnected groups with an estimated potential average annual generation of 2.8 million MWh. There was limited spend on the project in 2015, however, the Company has maintained all existing permits and licenses and has now completed all hydrology studies. The Company may look to further development of the project in the future when market outlook improves. Other hydroelectric development projects The Company holds water rights for other run of river hydroelectric power projects in British Columbia with a combined potential average annual generation of approximately 2.2 million MWh. The Company also holds a British Columbia Crown land tenure and an accepted water license application for the 1,000 MW Fir Point pumped storage project and performed several early-stage development activities in the current year. On March 12, 2015, the Company signed a memorandum of understanding with the Klahoose First Nation to jointly develop the 15 MW Tahumming hydroelectric project, which is in the Toba Valley near the Toba Montrose and Jimmie Creek projects. Because of its size, the project may qualify for a PPA process with BC Hydro under its Standing Offer Program. The Company is currently conducting further engineering, environmental and hydrology studies to confirm the project s viability and prepare for submission into the Standing Offer Program. On October 20, 2015, the Company announced that it had agreed to acquire the water rights for four hydroelectric development projects from Sigma Engineering (the South Toba projects: Chusan, Powell, Eldred North and Eldred South). The projects are located approximately kilometers from Alterra's existing Toba Montrose and Jimmie Creek projects, and are situated along the Toba Montrose transmission line. Each project is expected to have between MW of generation capacity, and could be eligible for PPAs under BC Hydro's Standing Offer Program. The transfers of the water licenses are expected to be completed in the second quarter of The Company is currently maintaining all of its hydroelectric projects in British Columbia in good standing for future development opportunities. Coastal wind projects The Company holds exclusive investigative licenses for wind development projects at several coastal locations in British Columbia including Banks Island, Porcher Island, McCauley Island and Knob Hill. Meteorological towers are installed at four locations. Development activities in the current period consisted of ongoing wind resource monitoring and continuing studies of the projects' potential. Twelve Month Report 2015 Management's Discussion & Analysis 18

25 SELECTED ANNUAL INFORMATION The Company s key financial results summarized below have been prepared in accordance with IFRS: Year ended December 31, Revenues $ 57,835 $ 70,952 $ 63,872 Net loss (17,306) (34,774) (116,261) Loss for the year attributable to the owners of the Company (16,717) (36,340) (110,831) Loss per share attributable to the owners of the Company - basic and diluted (0.04) (0.08) (0.24) Total assets 593, , ,608 Total current liabilities 168,944 46,895 44,032 Total long-term liabilities (a) 224, , ,719 Total equity 199, , ,857 (a) December 31, 2014 balance includes liabilities associated with held for sale investments REVIEW OF RESULTS FOR THE YEAR ENDED DECEMBER 31, 2015 The Company recorded a net loss of $17.3 million versus a net loss of $34.8 million for the comparative year primarily due to changes in non-cash items discussed below under "other income (expenses)". Net loss attributable to the owners of the Company was $16.7 million versus a net loss of $36.3 million for the comparative year (net loss per common share of $0.04 and $0.08 per common share for each year, respectively). Gross profit from operations Consolidated gross profit from operations was $16.1 million versus $17.1 million in the comparative year, as follows: Revenue Consolidated revenue was $57.8 million versus $71.0 million for the comparative year, broken down as follows: HS Orka operations (Reykjanes and Svartsengi) 100% consolidated - $57.4 million (2014: $65.9 million). The decrease is due to foreign exchange as well as a transfer of certain employees directly to HS Veitur (the latter of which impacted revenue by $6.2 million). Previously, the employees cost for work performed for HS Veitur were recharged and recorded in income. Excluding the impact of these items, in ISK, revenue was up year on year 9% due to increased retail sales. Soda Lake - $0.4 million (2014: $5.1 million). The Soda Lake facility was sold on January 30, The Company's share of revenue from Toba Montrose, Dokie 1 and Shannon (recorded as equity income) was as follows: Twelve Month Report 2015 Management's Discussion & Analysis 19

26 Toba Montrose - $24.7 million (2014: $28.6 million). Despite higher water flows and generation, revenue declined exclusively as a result of the weakening of the Canadian dollar. In Canadian dollars revenue was up 1%. Dokie 1 - $7.9 million (2014: $7.6 million). Revenue was higher due to increased generation at Dokie 1, partially offset by the weakening of the Canadian dollar. In Canadian dollars revenue was up 20%. Shannon - $0.3 million (2014: $nil). Shannon achieved commercial operations on December 10, 2015 and is currently selling power on the merchant market until the power hedge commences in June Cost of sales Cost of sales totaled $41.7 million, compared to $53.9 million in the comparative year, and included: HS Orka - $41.4 million (2014: $49.0 million). The decrease is due to fluctuations in foreign exchange as well as a reduction in employee costs due to the transfer of employees directly to HS Veitur. Excluding the impact of these items, in ISK, consistent with the increase in revenue, cost of sales was up 9% year on year. Soda Lake - $0.3 million (2014: $4.9 million). The Soda Lake facility was sold on January 30, The Company s share of cost of sales (including depreciation and amortization) for Toba Montrose, Dokie 1 and Shannon is as follows: Toba Montrose - $7.8 million (2014: $9.0 million). The decrease was primarily due to the weakening of the Canadian dollar. Dokie 1 - $3.5 million (2014: $4.1 million). The decrease in cost of sales was from the weakening of the Canadian dollar, a reduction in personnel costs and lower recurring maintenance costs. Shannon - $0.5 million (2014: $nil). Shannon achieved commercial operations on December 10, Other income (expenses) Total other income (expenses) resulted in a net loss of $37.2 million (2014: $47.3 million), reflecting the changes below: An $18.5 million loss on foreign exchange as a result of unfavorable movements in exchange rates (2014: $4.6 million loss). A $22.3 million non-cash loss resulting from the change in the fair value of derivatives primarily driven by changes in aluminum prices and foreign exchange (2014: $11.8 million non-cash loss). A $1.7 million non-cash gain resulting from the change in the fair value of the long-term holding company bonds (Sweden), primarily due to interest rate and aluminum price movements (2014: $2.6 million non-cash loss). The bonds payable were assumed by the Company in conjunction with the acquisition of its interest in HS Orka, and carried at fair value of $118.0 million at December 31, The bonds are partially linked to the price of aluminum and are recorded at fair value at each reporting date with the change in the fair value recorded in the statement of operations. A $1.9 million gain in other income related to the sale of Soda Lake, the gain associated with the deconsolidation of Shannon Group LLC, and the gain associated with the Dokie 1 earn-out (2014: $0.5 million income). Twelve Month Report 2015 Management's Discussion & Analysis 20

27 General and administrative expenses decreased to $9.9 million in the current year (2014: $10.4 million) due to fluctuations in foreign exchange and a reduction in professional fees. The Company s share of income from equity investments was $22.1 million (2014: $12.2 million) as follows: For the year ended December 31, Share of equity income (loss) Toba Montrose GP $ 5,931 $ 7,298 Dokie GP 1,826 $ 536 Blue Lagoon 7,099 $ 4,742 Shannon Group LLC 7,866 $ Construction and development projects (597) (376) Total equity income $ 22,125 $ 12,200 The increase in equity income is mainly due to the recognition of $7.9 million of income at Shannon that primarily consists of non-cash gains relating to valuation of the power hedge. Shannon equity income is calculated using the hypothetical liquidation at book value method (refer to the Company's audited consolidated financial statements for further information). The results from the Blue Lagoon geothermal spa in Iceland increased over the previous year as a result of increased attendance as well as a $2.0 million gain that resulted from the dilution of HS Orka's investment from 33% to 30% during the year. Finance costs increased to $12.6 million (2014: $8.6 million) primarily due to interest expense related to the North American holding company loan facility (the Holdco Facility ) that was funded in the third and fourth quarters of Finance income decreased to $1.8 million (2014: $2.7 million) primarily due to decreased interest income at HS Orka due to the sale of short-term investments and fluctuations in foreign exchange as well as a lower cash balance due to capital spend at HS Orka during the year. SUMMARY OF QUARTERLY RESULTS Seasonality has an impact on the Company s quarterly operating results. Most prominently, generation at Toba Montrose is higher in the summer months due to spring freshet and Dokie 1 generation levels are higher in the winter months. In addition, the Company has a number of financial derivatives with mark-to market valuations that can fluctuate significantly from quarter to quarter. These fluctuations are non-cash in nature. The following table summarizes information regarding the Company s operations on a quarterly basis for the last eight quarters. Financial information is reported under IFRS for all quarters. Twelve Month Report 2015 Management's Discussion & Analysis 21

28 December 31, 2015 Three months ended September 30, 2015 June 30, 2015 March 31, 2015 Revenue $ 15,680 $ 12,232 $ 13,522 $ 16,401 Gross profit 4,333 2,870 3,887 5,041 Other income (expense) (15,224) (1,488) 2,147 (22,619) Income tax recovery (expense) ,307 Net income (loss) (10,178) 2,305 6,838 (16,271) Net income (loss) attributable to owners of the Company (8,023) 1,170 5,016 (14,880) Earnings (loss) per share attributable to owners of the Company (basic and diluted) (0.02) (0.03) December 31, 2014 Three months ended September 30, 2014 June 30, 2014 March 31, 2014 Revenue $ 19,365 $ 16,209 $ 16,453 $ 18,925 Gross profit 5,044 3,105 2,704 6,239 Other income (expense) (35,206) (723) 4,512 (15,886) Income tax expense (3,181) (31) (1,255) (96) Net income (loss) (33,343) 2,351 5,961 (9,743) Net income (loss) attributable to owners of the Company (31,747) 1,459 4,072 (10,124) Earnings (loss) per share attributable to owners of the Company (basic and diluted) (0.07) (0.02) FINANCIAL REVIEW FOR THE THREE MONTHS ENDED DECEMBER 31, 2015 The Company recorded a net loss of $10.2 million ($33.3 million net loss in the comparative quarter) resulting primarily from changes in non-cash items discussed below under "other income (expenses)". Net loss attributable to the owners of the Company was $8.0 million versus $31.7 million for the comparative quarter (net loss of $0.02 and $0.07 per common share, respectively). Gross profit from operations Consolidated gross profit from operations was $4.3 million versus $5.0 million in the comparative quarter, as follows: Revenue Consolidated revenue was $15.7 million, or $3.7 million lower than the comparative quarter, broken down as follows: HS Orka operations (Reykjanes and Svartsengi) 100% consolidated - $15.7 million (comparative quarter: $18.1 million). The decrease is due to foreign exchange as well as a transfer of certain employees directly to HS Veitur (the latter of which impacted revenue by $1.7 million). Soda Lake - $nil (comparative quarter: $1.3 million). The decrease reflects the sale by the Company of the Soda Lake facility on January 30, Twelve Month Report 2015 Management's Discussion & Analysis 22

29 The Company's share of revenue from Toba Montrose, Dokie 1 and Shannon is as follows: Toba Montrose - $3.0 million (comparative quarter: $5.2 million). The decrease is due to lower flows in the fourth quarter combined with the weakening of the Canadian dollar. Dokie 1 - $2.7 million (comparative quarter: $2.5 million). Revenue was higher at Dokie 1 due to higher winds with revenue in Canadian dollars up 28%. The weakening of the Canadian dollar partially offset the strong performance during the quarter. Shannon - $0.3 million (2014: $nil). Cost of sales Cost of sales totaled $11.3 million, compared to $14.3 million in the comparative quarter, and included: HS Orka - $11.3 million (comparative quarter: $13.1 million). The decrease is due to fluctuations in foreign exchange as well as a transfer of certain employees directly to HS Veitur. Soda Lake - $nil (comparative quarter: $1.2 million). The decrease reflects the sale by the Company of the Soda Lake facility on January 30, The Company s share of cost of sales (including depreciation and amortization) for Toba Montrose, Dokie 1 and Shannon is as follows: Toba Montrose - $1.8 million (comparative quarter: $2.4 million). The decrease was primarily due to the weakening of the Canadian dollar. Dokie 1 - $0.8 million (comparative quarter: $1.0 million). The decrease was primarily due to the weakening of the Canadian dollar. Shannon - $0.5 million (2014: $nil). Other income (expenses) Total other income (expenses) resulted in a net loss of $15.2 million ($35.2 million for the comparative quarter), reflecting the changes below: A $3.3 million loss on foreign exchange was recorded due to the weakening of the Canadian dollar ($2.1 million loss in the comparative quarter). A $7.9 million non-cash loss resulting from the change in the fair value of derivatives that was primarily driven by changes in aluminum prices and foreign exchange (comparative quarter: $9.0 million non-cash loss). A $1.8 million non-cash gain resulting from the change in the fair value of the long-term holding company bonds (Sweden) primarily due to decreased interest rates and partially offset by aluminum price movements (comparative quarter: $4.5 million non-cash gain). A $0.5 million gain in other income primarily due to the Dokie 1 earn-out related to the partial sale of Dokie GP in December 2013 (comparative quarter: $0.9 million loss). General and administrative expenses increased to $3.2 million ($3.0 million in the comparative quarter) due to increased legal costs related to the Norðurál arbitration. During the quarter there was no impairment of development costs or goodwill (2014: $24.5 million write-down) The Company s share of equity income for the quarter was $0.9 million ($0.9 million for the comparative quarter) as follows: Twelve Month Report 2015 Management's Discussion & Analysis 23

30 For the quarter ended December 31 Share of equity income (loss) Toba Montrose GP $ (1,486) $ (328) Dokie GP 1, Blue Lagoon Shannon Group LLC 428 Construction and development projects (105) (132) Total equity income $ 874 $ 867 The change in equity income is due to higher generation at Dokie 1 and income from Shannon partially offset by lower water flows at Toba Montrose and the weakening of the Canadian dollar. Finance costs increased to $2.9 million ($2.2 million for the comparative quarter) primarily due to interest expense related to the second tranche of the Holdco Facility that was funded in the fourth quarter of Finance income decreased to $0.2 million ($0.5 million in the comparative quarter) primarily due to lower interest income at HS Orka related to the sale of short-term investments and fluctuations in foreign exchange as well as a lower cash balance due to capital spend at HS Orka during the year. LIQUIDITY AND CAPITAL RESOURCES At December 31, 2015, the Company had consolidated cash and cash equivalents of $10.3 million (December 31, 2014: $63.2 million). The decline in cash is primarily due to funding of the Company's equity contribution into Shannon plus HS Orka's capital expenditures and loan repayments. Cash and cash equivalents consist of cash and call 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 call deposits is limited by maintaining the major part of its cash and call deposits with major banks that have high credit ratings. Other than at HS Orka, 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, 2015, the Company had restricted cash of $10.8 million (December 31, 2014: $9.7 million). $4.5 million is dedicated to loan payments in accordance with a collateral agreement with HS Orka s lenders, $5.7 million is held by HS Orka related to a grant that was received (of which HS Orka is a recipient and administrator) in relation to the deep drilling program and will be distributed to HS Orka's partners on the project, and $0.6 million is held in escrow for one of the Company's holding company bondholders (Sweden). The Company also had short-term investments of $7.7 million (December 31, 2014: $4.3 million). Excluding HS Orka and the cash held at the equity-accounted investees, the Company had cash of $3.9 million at December 31, 2015 (December 31, 2014: $38.2 million). Subsequent to year end, the Company received distributions from Toba Montrose GP and Dokie GP of C$2.0 million and C$3.1 million, respectively, as well as C$0.8 million from achieving the Dokie 1 earnout. The Company has access to a revolving line of credit with the Company's Chairman of C$20.0 million (with a current maturity of March 31, 2017, and no amounts drawn at this time) and other sources of funding to finance acquisitions or further development. 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 Twelve Month Report 2015 Management's Discussion & Analysis 24

31 therefore may not be directly comparable. The Company s consolidated working capital deficit at December 31, 2015 was $123.3 million compared to a positive working capital of $46.2 million at December 31, The decrease was primarily due to the holding company bonds (Sweden) being reclassified as short-term (the bonds mature in July and December 2016) and spend associated with the construction of Shannon. Excluding HS Orka, the Company had a working capital deficit of $115.8 million at December 31, 2015 (December 31, 2014: positive $39.9 million). Further excluding the holding company bonds (Sweden), which the Company is in the process of refinancing, the Company has a positive working capital of $2.2 million. In 2014, the Company completed the Holdco Facility with proceeds received in two tranches: tranche A totaling C$67.3 million was funded on August 15, 2014, and tranche B totaling C$22.5 million was funded on December 19, 2014, primarily to support the Company's equity investments into the Jimmie Creek and Shannon projects. The Holdco Facility is secured by the future cash flows from, and indirect equity interests in, the Company's investments in Toba Montrose GP, Dokie GP and Jimmie Creek LP. The Company s consolidated long-term debt is as follows: December 31, 2015 Holding company bonds (Sweden) $ 117,977 Holdco Facility (North America) 62,377 HS Orka loans 75, ,539 Less current portion: Holding company bonds (Sweden) 117,977 HS Orka loans 17, ,386 Long-term portion $ 120,153 At December 31, 2015 consolidated long-term debt consisted of: a) $118.0 million representing the fair value of the holding company bonds (assumed by Magma Energy Sweden) in conjunction with the acquisition of HS Orka, which mature in July and December 2016; b) $62.4 million related to the Holdco Facility which matures in February 2023; and c) $75.2 million, representing 100% of HS Orka s corporate debt (though the Company only owns 66.6% of HS Orka) which matures primarily between 2016 and The Company s 40% share of Toba Montrose GP s long term-debt is $127.7 million and matures in 2045, and the Company s 25.5% share of Dokie GP s long-term debt is $27.7 million which matures in The Company's 51% share of Jimmie Creek LP's long-term debt is $56.3 million (representing the Company's share of the $110.5 million drawn as of December 31, 2015 net of financing fees, from the C$176.5 million facility) which has annual principal repayments starting in 2017 until The long-term debt of Toba Montrose GP, Dokie GP, and Jimmie Creek LP are not consolidated by the Company as these investments are recorded as equity investments. The Holdco Facility and the loans at HS Orka, Magma Energy Sweden, Toba Montrose GP, Dokie GP, and Jimmie Creek LP are nonrecourse to the Company other than the remaining portion of the Company s investment in these entities, which may not be fully recovered in the event of an incurred default. All project companies are expected to generate sufficient cash flow to service and repay their existing long-term loans. The holding company bonds (Sweden) are serviced by dividends from HS Orka (partial support, remainder funded by the Company's cash flow) and the Holdco Facility is serviced by dividends from the Toba Montrose, Dokie 1 and Jimmie Creek projects. The Holdco Facility matures in 2023, and has no scheduled principal payments until then. The Company currently plans to retire the holding company bonds (Sweden) through refinancings in 2016, for which the Company is currently in negotiations. The Icelandic Krona ("ISK") denominated bond and three US dollar bonds are non-recourse to the Company and are secured by HS Orka shares. Twelve Month Report 2015 Management's Discussion & Analysis 25

32 ISK denominated Bond US Dollar Bonds Balance at December 31, 2015 $ 48,642 $ 69,335 Maturity July 16, 2016 December 14, 2016 Interest rate 1.5% 3.5% Number of shares of HS Orka pledged as security 996,821,339 2,515,640,459 % of outstanding HS Orka shares pledged as security 12.7% 32.1% Should the Company be unable or elect not to refinance the ISK denominated bond, the Company would own 53.9% of HS Orka and would continue to consolidate their results. If the Company lost the collateral supporting both bonds, the Company's share of HS Orka would be reduced to 21.8%, resulting in loss of control and the Company would no longer consolidate the HS Orka results. Management does not consider this to be a likely outcome. There is no project debt associated with Shannon, however, the project has certain requirements with respect to the allocation of cash distributions, taxable income and tax credits amongst the Sponsor and Tax equity Investors. The following are the contractual maturities of the Company s financial liabilities, including estimated interest payments: December 31, 2015 Contractual cash flows Less than one year (a) 1-2 years 2-5 years After 5 years Accounts payable and accrued liabilities $ 13,660 $ 13,660 $ $ $ Other liabilities 10,689 10,689 Long-term debt 302, ,604 20,790 50,593 88,768 Embedded derivatives 65,710 8,362 8,170 21,269 27,909 Interest rate swaps 3, , Total $ 396,052 $ 176,166 $ 29,750 $ 73,365 $ 116,771 (a) Long-term debt due in "less than one year" includes the maturities of the holding company bonds (Sweden), which the Company is currently in the process of refinancing. Shannon guaranty Tax equity investors in US wind projects generally require sponsor guaranties as a condition to their investment. To support the tax equity investment at Shannon, the Company executed a guaranty effective on funding of the tax equity investment by the Shannon tax equity investors indemnifying them against certain breaches of project level representations, warranties and covenants and other events. The Company believes the indemnification covers matters which are substantially under the Company s control, and are very unlikely to occur. Twelve Month Report 2015 Management's Discussion & Analysis 26

33 TRANSACTIONS WITH RELATED PARTIES a) Revolving credit agreement The Company holds a revolving credit facility with the Company's Chairman. At December 31, 2015, the borrowing amount available under the facility was C$20.0 million with a maturity date of March 31, Subsequent to year end, the maturity date was extended to March 31, The credit facility makes funds available on a revolving basis at an interest rate of 8% per annum, compounded and payable monthly. In addition, a standby fee in the amount of 0.75% of the credit facility, and a drawdown fee in the amount of 1.5% of amounts advanced, are payable in cash. At December 31, 2015, there were no amounts outstanding under the credit agreement (December 31, 2014: $nil). During the year the Company borrowed and repaid C$2.7 million and paid interest, standby and drawdown fees of C$0.2 million (C$1.8 million for the year ended December 31, 2014). b) Developer and construction management fee On June 30, 2015, the Company received a $1.5 million developer fee and a $0.8 million construction management fee from Shannon Wind, LLC (a subsidiary of Shannon Group LLC). OUTLOOK For the 2016 and 2017, management expects the Company to achieve (net interest): ($000s except where specified) Generation (GWh) 1,610 1,706 Total revenue 92, ,496 Adjusted EBITDA 40,721 48,328 Forecasts of 2016 and 2017 generation for hydro and wind projects are based on resource assessments of average annual generation at each project, adjusted for planned maintenance outages reflects expectations for a partial year of generation from Jimmie Creek, which is expected to commence commercial operations in the summer of Forecast generation for geothermal facilities is based on historical generation, assuming the recently drilled new wells at Svartsengi are placed in service and reinjection at Reykjanes is successful, in each case, on schedule (see "Operations Review" above) generation estimates reflect a full year of generation from all seven operating projects. The 2016 projections for revenue and Adjusted EBITDA are based on internal budgets and models for revenue and costs for all operating projects (prepared in accordance with IFRS), and modest escalation for other expenses and revenue streams. Shannon revenue estimates reflect commencement of the long-term power hedge on June 1, 2016, with power sales occurring prior to this and in excess of the contractual hedge quantity calculated using estimated merchant pricing. Lower merchant prices seen to date in 2016 are reflected in the revenue and Adjusted EBITDA estimates. Anticipated head office cost and development spend has been included in Adjusted EBITDA and reflects budgeted spend for the year. HS Orka forecasted revenue reflects forecasted aluminum prices for a portion of revenue (25.9% in 2015), as well as lower generation in 2016 than 2017, as the anticipated positive impact from the reinjection program at Reykjanes is not expected to be substantially realized until Until full realization of the reinjection program has occurred, additional power purchases will be necessary in Twelve Month Report 2015 Management's Discussion & Analysis 27

34 order to meet demand. Such purchases, while still profitable, achieve a lower gross margin than if such sales resulted from power generated by our power plants. The 2017 outlook for revenue and Adjusted EBITDA (other than for HS Orka, discussed above) reflects modest inflation and a full year of the Shannon hedge and Jimmie Creek operations. Revenue and Adjusted EBITDA projections have been converted from their originating currency to USD at a rate of C$1.34, ISK129 and Euro1.97 for both 2016 and This section of the MD&A provides management's generation, revenue and Adjusted EBITDA estimates for 2016 and 2017 on a net interest basis. The information and estimates contained within this section are forward-looking statements and forward-looking financial information, subject to the cautionary notes regarding the risks and assumptions associated with such statements discussed herein under the heading Cautionary Note Regarding Forward-Looking Statements. Readers are cautioned that actual results may vary from the above noted forward-looking financial information. OFF-BALANCE SHEET ARRANGEMENTS The Company does not have any off-balance sheet financial arrangements. CRITICAL ACCOUNTING POLICIES AND MANAGEMENT ESTIMATES The preparation of consolidated financial statements requires that 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 discloses significant accounting policies in its financial statements, see note 3 of the Company s audited consolidated financial statements. The following are new accounting standards adopted during the year: IFRS 8 - Operating segments Operating segments (amendments to IFRS 8) was amended to require disclosure of the judgments made by management in aggregating operating segments, including a description of the segments which have been aggregated and the economic indicators which have been assessed in determining that the aggregated segments share similar economic characteristics. The amendment is effective for annual periods commencing on or after July 1, The adoption of this standard has no impact on the consolidated financial statements. IAS 19 - Employee benefits Employee benefits (amendments to IAS 19) was amended to clarify the application of IAS 19 to plans that require employees or third parties to contribute toward the cost of benefits. The amendment is effective for annual periods beginning on or after July 1, There is an additional amendment to clarify the guidance on discount rates for post-employment benefit obligations. The adoption of this standard did not have an impact on the consolidated financial statements. Twelve Month Report 2015 Management's Discussion & Analysis 28

35 Management believes areas of judgment and key sources of estimation uncertainty that have the most significant effect on the amounts recognized in the consolidated financial statements are: Impairment of assets; geothermal, hydro and wind development costs, and goodwill The carrying amounts of the Company s non-financial assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset s recoverable amount is estimated. For goodwill and intangible assets that have indefinite useful lives or that are not yet available for use, an impairment test is performed at least annually (at the same time) or when events or changes in circumstances indicate that the related carrying amount may not be recoverable. An impairment loss is recognized if the carrying amount of an asset or its related cash generating unit ( CGU ) exceeds its estimated recoverable amount. The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset or CGU. Goodwill acquired in a business combination is allocated to groups of CGUs that are expected to benefit from the synergies of the combination. Impairment losses are recognized in the statement of operations. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to such CGU or group of CGUs, and then to reduce the carrying amounts of other assets in the CGU (or group of CGUs) on a pro rata basis. An impairment loss recognized in respect of goodwill is not reversed. In respect of other assets, impairment losses are reversed if there has been a change in the estimates used to determine the recoverable amount and only to the extent that the asset s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no impairment loss had been recognized. Fair value of financial instruments including embedded derivatives The fair value of the bonds receivable is determined using an income approach by discounting future interest and principal repayments using an interest rate of 5% plus indexation to the Icelandic Consumer Price Index. The fair value of the interest rate swaps is measured using observable future market interest rates (0.73% to 2.51%). The fair value of the embedded derivatives and holding company bonds (Sweden) is determined using observable market interest rates (0.86% to 5.84%) and the London Metals Exchange forward market price of aluminum. The value of the remaining Dokie GP earn-out payment is based on the likelihood of the project achieving its generation target in The fair value is based on a 50% probability of the generation target being met in the year, discounted at a rate of 6%. The Company reached the generation target in 2015 and received the related payment in early The Soda Lake earn-out payments are based on probabilities of achieving generation, pricing and development targets over the next two to five years discounted at a rate of 8%. Twelve Month Report 2015 Management's Discussion & Analysis 29

36 Income taxes (i) Current income tax Income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from, or paid to, the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted at the reporting date in the countries where the Company operates and generates taxable income. Current income tax relating to items recognized directly in other comprehensive income or equity is recognized in other comprehensive income or equity and not in profit or loss. (ii) Deferred tax Deferred tax is provided using the balance sheet method on temporary differences between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes at the reporting date. Deferred tax assets are recognized for all deductible temporary differences, the carry-forward of unused tax credits and any unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences, and the carry-forward of unused tax credits and unused tax losses can be utilized. Deferred tax is not recognized for: temporary differences on the initial recognition of goodwill or an asset or liability in a transaction that is not a business combination and, at the time of the transactions, affects neither accounting profit nor taxable profit or loss; and temporary differences related to investments in subsidiaries, associates and interests in joint ventures where the timing of the reversal of the temporary differences can be controlled by the parent, investor or venture and it is probable that the temporary difference will not reverse in the foreseeable future. The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilized. Unrecognized deferred tax assets are reassessed at the end of each reporting period and are recognised to the extent that it has become probable that future taxable profit will be available to allow the deferred tax asset to be recovered. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted by the end of the reporting period. Deferred tax relating to items recognized in other comprehensive income or equity is recognized in other comprehensive income or equity and not in profit or loss. Deferred tax assets and deferred tax liabilities are offset, if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority. Amortization of plant and equipment 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 Twelve Month Report 2015 Management's Discussion & Analysis 30

37 estimated useful lives that range from 5 to 50 years, Toba Montrose GP s facility components range from 2 to 70 years, and Shannon Group LLC's facility components range from 3 to 45 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 55%. Depreciation methods, useful lives and residual values are reviewed at each reporting date and adjusted when appropriate. Pension fund obligations The Company s net obligation in respect of defined benefit multi-employer pension plans or pension fund commitments at HS Orka is calculated separately for each plan by estimating the amount of future benefits that current and former employees have earned in return for their service in the current and prior periods. That benefit is discounted to determine its present value. The calculation is performed annually by qualified actuaries using a method based on earned benefits. Remeasurements of the net defined liabilities related to actuarial gains and losses are recognized in other comprehensive income, and other expenses related to the defined benefit plans are recognized as incurred in the statement of operations. Short-term employee benefit obligations are measured on an undiscounted basis and are expensed as the related service is provided. A liability is recognized for the amount expected to be paid under shortterm cash bonus or profit-sharing plans if the group has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee, and the obligation can be estimated reliably. Contributions to the defined contribution pension plan is recognized as an employee benefit expense in profit or loss in the period during which services are rendered by employees. Bond receivable The bond receivable is paid in annual installments and matures in No amounts are outstanding as at December 31, 2015; however, there have been indications of an uncertain financial position of the bond holder (the municipality of Reykjanesbær) and thus there is some uncertainty about the full recoverability of the bond. Long-term receivable The long-term receivable is due from HS Veitur due to its share of a pension liability. HS Veitur has disputed the amount and the Company believes the agreement in place to still be valid. Initial investment of Jimmie Creek and Shannon The Company's economic interest in the assets, liabilities, revenue and expenses, and cash flows of Jimmie Creek LP is accounted for under the equity method (as the partnership is a joint venture). The Company's initial investment in Jimmie Creek LP was recorded at a fair value of $42.1 million based on a discounted cash flow model and discount rate of 6.8%. A 0.5% change in the discount rate would have resulted in an increase of $3.5 million or decrease of $3.0 million in the initial fair value of the Company's investment in Jimmie Creek LP. The Company's economic interest in the assets, liabilities, revenue and expenses and cash flows of Shannon Group LLC are accounted for under the equity method (as the partnership is a joint venture). The Company's initial investment in Shannon Group LLC was recorded at fair value of $62.7 million based on the purchase price paid by Starwood for its 50% investment. Twelve Month Report 2015 Management's Discussion & Analysis 31

38 FINANCIAL INSTRUMENTS AND RELATED RISKS The Company is exposed to a variety of financial risks as a result of our operations, including credit risk, liquidity risk and market risk (which includes interest rate risk, currency risk and commodity price risk). The Company's overall risk management strategy seeks to reduce potential adverse effects on our financial performance. Risk management is carried out under policies approved by the Board of Directors. The risks associated with our financial instruments, and the policies for mitigating those risks are set out below. Credit risk The Company s exposure to credit risk is influenced mainly by the individual characteristics of each customer. Over 41% (down from the 53% in 2014, due to the removal of one customer associated with the sale of Soda Lake) of the Company s consolidated revenue is attributable to sales transactions with two customers (Norðurál and Advania hf). The Company has set a credit policy where all new customers are evaluated with respect to payment history and other factors and credit limits are set. Customers that are behind in payments are prohibited to make further transactions with the Company until they settle their debt or the Company's collection department approves further transactions based on an agreement. The Company establishes an allowance for impairment that represents its estimate of incurred losses in respect of trade and other receivables. The Company s exposure to credit risk and management of this risk has not changed from the previous year with the exception of the bond receivable and long-term receivable at HS Orka. There have been indications of an uncertain financial position of the bond holder (the municipality of Reykjanesbær) and thus there is some uncertainty about the recoverability of the bond. Separately HS Veitur has disputed the amount of the long-term receivable although the Company believes the agreement in place to still be valid. Liquidity risk Liquidity risk is the risk that the Company will be unable to meet its financial obligations as they become due. The Company manages liquidity risk by ensuring that it has sufficient cash, credit facilities and other financial resources available to meet its obligations. The Company forecasts cash flows for a period of at least 12 months to identify financial requirements. These requirements are met through a combination of cash flows from operations, credit facilities and accessing capital markets. The Company s exposure to liquidity risk and management of this risk has not changed from the previous year. At December 31, 2015 and 2014, the Company s current liabilities consisted of trade and other payables, current portions of debt and other financial instruments, government grants received at HS Orka during the year, and at December 31, 2014 there was a contingent liability related to the purchase of Shannon. The Company s cash and cash equivalents together with projected project cash flow and available credit facility over the next 12 months are expected to be sufficient to pay these current liabilities. The Company believes that HS Orka, Toba Montrose GP, Dokie GP and Jimmie Creek LP have the ability to sustain themselves and pay their long-term interest and debt obligations as they become due. This debt is non recourse to the Company. The Company has plans to refinance the long-term bond liabilities of Magma Energy Sweden A.B., assumed in conjunction with the acquisition of HS Orka that expire in Should the Company be unable to refinance the ISK denominated bond, and returns the shares held as collateral, the Company would own 53.9% of HS Orka and would continue to consolidate their results. If the Company in unsuccessful in refinancing both bonds, and returns all shares held as collateral, the Company's share of HS Orka will be reduced to 21.8%, resulting in loss of control and the Company would no longer consolidate the HS Orka results. Management does not consider this to be a likely outcome. Twelve Month Report 2015 Management's Discussion & Analysis 32

39 The Company believes cash flows from its investments in Toba Montrose GP, Dokie GP, and future Jimmie Creek LP cash flows will be sufficient to pay its interest on the holding company loan facility over the term of the loan. Market risk The significant market risk exposures to which the Company is exposed are interest rate risk, currency risk and commodity price risk. a) Interest rate risk Interest rate risk is the risk that the future cash flows and fair values of the Company s investments and debts will fluctuate because of changes in market interest rates. b) Currency risk The functional currency of the Company and each of its subsidiaries, except the U.S. subsidiaries and HS Orka, is the Canadian dollar, the functional currency of the U.S. subsidiaries is the U.S. dollar; and the functional currency of HS Orka is the Icelandic Krona. The carrying amounts of monetary assets and liabilities denominated in currencies other than the functional currencies are subject to fluctuations in the underlying foreign currency exchange rates. Gains and losses on such items are included as a component of net loss for the year. The Company and its subsidiaries undertake transactions in the following currencies: U.S. dollar, Canadian dollar, Icelandic Krona, Swedish Krona, Swiss Franc, Euro and Japanese Yen. The Company does not currently economically hedge against foreign exchange rate risk, but may economically hedge single, large transactions with forward foreign exchange agreements for shorter periods. HS Orka does not hedge its currency risk on its long-term debt denominated in foreign currencies. The reporting currency selected for the presentation of these consolidated financial statements is the U.S. dollar. For presentation purposes, all assets and liabilities are translated from the functional currency into U.S. dollars at the exchange rate in effect at the balance sheet date. As a result, reported amounts of all assets and liabilities will fluctuate with changes in the underlying functional currency to the U.S. dollar exchange rate. Gains and losses arising from translation of the consolidated financial statements into U.S. dollars are recognized in other comprehensive income (loss). c) Commodity price risk HS Orka has entered into two PPAs for the sale of electrical power wherein the sales price of such power is based on the forward market price of aluminum. Therefore, the revenues and profitability of HS Orka's operations are significantly exposed to fluctuations in the price of aluminum (the percentage of HS Orka s sales linked to the price of aluminum was 25.9% in 2015, down from 26.2% in 2014). The bonds that were issued as partial consideration for the purchase of HS Orka are also partially subject to adjustments based on the price of aluminum. Therefore, the principal amounts owed on the due date, and the annual interest payments thereon, subject to caps and floors, may fluctuate with the price of aluminum. Shannon Group LLC will sell the majority of its output under a long-term power hedge agreement with Citigroup Energy Inc. beginning in June 2016 and until that time all power sales will be subject to merchant prices. Twelve Month Report 2015 Management's Discussion & Analysis 33

40 Financial instrument classification At December 31, 2015, the Company recognized the following financial instruments at fair value: Assets: Short-term investments $ 7,670 Bonds receivable 2,087 Long-term receivable and other assets 1,282 $ 11,039 Liabilities: Embedded derivatives $ 65,710 Interest rate swaps 3,139 Holding company bonds (Sweden) 117,977 $ 186,826 The bond receivable and the majority of the short-term investments are classified as financial assets at fair value through profit and loss and during the year $0.3 million was recognized in finance income on the statement of operations. Included in long-term receivable and other assets is the fair value of the Company's remaining potential earn-out payment related to the 2013 partial sale of Dokie 1. Dokie 1 exceeded the generation target for 2015 which resulted in a gain of $0.3 million, recorded in other income and expenses on the statement of operations. The embedded derivatives and interest rate swaps are classified as financial liabilities at fair value through profit and loss. During the year the fair value of the embedded derivatives resulted in a loss of $22.3 million included in change in fair value of derivatives on the statement of operations. The interest rate swaps are related to the Holdco Facility and generated a loss of $2.5 million from the change in fair value recorded in other comprehensive loss. The change in the fair value of the holding company bonds (Sweden) during the year resulted in a gain of $1.7 million recorded in the statement of operations. OTHER RISKS AND UNCERTAINTIES The ability of the Company to be a viable operator and developer of renewable power projects 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, solar, 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 power purchase agreements or financial hedge agreements for power sales; industry risk and competition; the ability to obtain sufficient equity and long-term debt financing to construct further projects; the ability to refinance the Magma Sweden bonds; 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. Twelve Month Report 2015 Management's Discussion & Analysis 34

41 Fluctuations and changes in weather and wind patterns will impact operational results for the Company s hydro, wind and geothermal operations. For further information regarding the Company s operational risks, please refer to the section entitled Risk Factors in the Company's most recently filed Annual Information Form. FUTURE ACCOUNTING STANDARDS At December 31, 2015, a number of standards and interpretations, and amendments thereto, had been issued by the IASB, which are not effective for these consolidated financial statements. Those which may be relevant to the Company s consolidated financial statements are set out below: IFRS 9: Financial instruments Financial instruments, addresses the classification, measurement and recognition of financial assets and financial liabilities. The complete version of IFRS 9 was issued in July 2014 and replaces IAS 39. The requirements of this standard represent a significant change from the existing requirements in IAS 39 in respect of financial assets. The standard contains three primary measurement categories for financial assets: amortized cost, fair value through other comprehensive income, and fair value through profit and loss. A financial asset would be measured at amortized cost if it is held within a business model whose objective is to hold assets in order to collect contractual cash flows, and the asset s contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the principal outstanding. All other financial assets would be measured at fair value. The new standard also requires a single impairment method to be used, adds guidance on the classification and measurement of financial liabilities, and provides a new general hedge accounting standard. The effective date is January 1, 2018 but may be adopted early at the Company's discretion. The Company is currently evaluating the impact of these amendments. IFRS 15 - Revenue from contracts with customers Revenue from contracts with customers is a new standard superseding IAS 18 - Revenue, IAS 11 - Construction contracts and related interpretations. The new standard is effective for interim periods within years beginning on or after January 1, The Company is currently evaluating the impact of these amendments. IFRS 16 - Leases Leases specifies how an issuer will recognize, measure, present and disclose leases. The standard provides a single lessee accounting model, requiring lessees to recognize assets and liabilities for all leases unless the lease term is 12 months or less, or the underlying asset has an insignificant value. The effective date is January 1, The Company is currently evaluating the impact that adoption of the standard is expected to have on its consolidated financial statements. MANAGEMENT'S REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING AND DISCLOSURE CONTROLS AND PROCEDURES Disclosure controls and procedures Disclosure controls and procedures have been designed to provide reasonable assurance that material information related to the Company is identified and communicated as appropriate on a timely basis. The Company's management, with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and Twelve Month Report 2015 Management's Discussion & Analysis 35

42 procedures as at December 31, Based on this evaluation, they concluded that our disclosure controls and procedures were effective as at December 31, 2015 in providing reasonable assurance that the information required to be disclosed in reports we filed or submitted under Canadian securities legislation was recorded, processed, summarized and reported within the time periods specified in those rules. Internal control over financial reporting Internal controls over financial reporting have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The Company's management, with the participation of its Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, and used the Internal Control Integrated Framework published by The Committee of Sponsoring Organizations of the Treadway Commission (COSO) to evaluate the effectiveness of our controls for the year ended December 31, Based on this evaluation, management concluded that our internal control over financial reporting was effective as at December 31, 2015 and provided a reasonable assurance of the reliability of our financial reporting and preparation of the financial statements. 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 any material changes to internal controls over financial reporting will be disclosed as they occur. Limitations of Controls and Procedures The Company s management, including the Chief Executive Officer and Chief Financial Officer, believes 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. The Company s management is not aware of any misstatements due to error or fraud. Twelve Month Report 2015 Management's Discussion & Analysis 36

43 DISCLOSURE OF OUTSTANDING SHARE DATA At March 15, 2016, the Company had the following common shares, stock options and warrants outstanding: Common shares 468,669,703 Stock options (vested and unvested) 19,381,133 Warrants Total 488,050,836 ALTERNATIVE PERFORMANCE MEASURES Net Interest Net Interest means the effective portion of operating results that the Company would have reported if each of HS Orka (66.6%), Toba Montrose GP (40%), Dokie GP (25.5%), Shannon Group LLC (50%) and Soda Lake (100% until the sale of Soda Lake on January 30, 2015) had been reported in accordance with the Company s actual share ownership for the year, as opposed to consolidating 100% of HS Orka (with an allocation to non-controlling interest), and Soda Lake (until the date of sale) and equity accounting for Toba Montrose GP, Dokie GP and Shannon Group LLC. Adjusted EBITDA Adjusted EBITDA is defined by the Company as earnings before interest, taxes, foreign exchange, depreciation and amortization, as well as before adjustments for changes in the fair value of holding company bonds (Sweden) and derivatives, write-offs of development costs, other income (expense) except business interruption insurance proceeds, amortization of below market contracts, value assigned to options granted, share of results of equity investments, the Company s proportionate interest in Adjusted EBITDA of its equity investments and non-recurring items (insurance deductibles, litigation and arbitration costs). Adjusted EBITDA has been calculated on a consistent basis with the prior year. The Company discloses Adjusted EBITDA as it is a measure used by analysts and by management to evaluate the Company's performance. As Adjusted EBITDA is a non-ifrs measure, it may not be comparable to Adjusted EBITDA calculated by others. In addition, Adjusted EBITDA is not a substitute for net earnings. Readers should consider net earnings in evaluating the Company s performance. Readers should also consider the risks and assumptions in estimates of Adjusted EBITDA discussed under the heading Cautionary Note Regarding Forward-Looking Statements. Twelve Month Report 2015 Management's Discussion & Analysis 37

44 The following reconciles consolidated loss for the year to Adjusted EBITDA: Year ended December 31, 2015 Loss for the year $ (17,306) Adjustments: Income tax recovery (3,747) Share of results of equity investments (22,125) Share of Adjusted EBITDA of equity investments 29,957 Change in the fair value bonds payable (1,655) Change in the fair value of derivatives 22,285 Foreign exchange loss 18,459 Other income (1,927) Finance costs 12,643 Finance income (1,808) Amortization of below market contracts (1,657) Amortization, depreciation, depletion and accretion 11,179 Stock based compensation 662 Other non-recurring items 1,450 Adjusted EBITDA $ 46,410 Year ended December 31, 2014 Loss for the year $ (34,774) Adjustments: Income tax expense 4,563 Share of results of equity investments (12,200) Share of Adjusted EBITDA of equity investments 32,854 Change in the fair value bonds payable 2,601 Change in the fair value of derivatives 11,846 Foreign exchange loss 4,566 Write-down of development costs and plant and equipment 22,439 Write-off of goodwill 2,018 Other income (511) Finance costs 8,602 Finance income (2,738) Amortization of below market contracts (2,038) Amortization, depreciation, depletion and accretion 13,245 Stock based compensation 574 Other non-recurring items 532 Adjusted EBITDA $ 51,579 Certain of the comparative year figures have been reclassified to conform to the current year s presentation. Twelve Month Report 2015 Management's Discussion & Analysis 38

45 The following reconciles net interest income (loss) for the year to net interest Adjusted EBITDA: Year ended December 31, 2015 HS Orka Toba Montrose Dokie 1 Soda Lake Shannon Development and head office Total net Interest Income (loss) for the year before income tax $ (2,253) $ 5,931 $ 1,826 $ 167 $ 7,866 $ (17,837) $ (4,300) Adjustments: Share of results of equity investments (4,728) (136) (15,026) (19,890) Share of Adjusted EBITDA of equity investments 3, (597) 3,468 Change in the fair value bonds payable (1,655) (1,655) Change in the fair value of derivatives 14,842 14,842 Foreign exchange (gain) loss (1,120) 20,141 19,021 Other (income) expense (69) (61) 1,344 (1,927) (713) Finance costs 1,939 8,964 2,222 9,731 22,856 Finance income (1,055) (47) (19) (223) (1,344) Amortization of below market contracts (1,094) (15) (1,109) Amortization, depreciation, depletion and accretion 7,410 4,046 1, ,337 Stock based compensation Unrealized gain on cash flow hedge (9,346) (9,346) Other non-recurring items ,154 Adjusted EBITDA $ 18,800 $ 18,825 $ 5,735 $ 152 $ 35 $ (6,564) $ 36,983 Twelve Month Report 2015 Management's Discussion & Analysis 39

46 Year ended December 31, 2014 HS Orka Toba Montrose Dokie 1 Soda Lake Development and head office Total net Interest Income (loss) for the year before income tax $ 3,065 $ 7,298 $ 536 $(5,229) $ (29,584) $ (23,914) Adjustments: Share of results of equity investments (3,158) (7,459) (10,617) Share of Adjusted EBITDA of equity investments 4,753 (376) 4,377 Change in the fair value bonds payable 2,601 2,601 Change in the fair value of derivatives 7,889 7,889 Foreign exchange loss (121) 4,748 4,627 Write-off of development costs and plant and equipment 5,341 17,098 22,439 Write-off of goodwill 2,018 2,018 Other (income) expenses (959) (146) (511) (1,616) Finance costs 2,566 10,401 2,656 4,750 20,373 Finance income (1,692) (75) (27) (198) (1,992) Amortization of below market contracts (1,235) (183) (1,418) Amortization, depreciation, depletion and accretion 8,122 4,628 2,046 1, ,846 Stock based compensation Unrealized gain on cash flow hedge (283) (283) Other non-recurring items Adjusted EBITDA $ 20,543 $ 21,029 $ 5,065 $ 948 $ (6,308) $ 41,277 Certain of the comparative year figures have been reclassified to conform to the current year s presentation. Net interest cash position - December 31, 2015 HS Orka Toba Montrose Dokie 1 Shannon Development and head office Total Total $ 6,449 $ 17,562 $ 7,664 $ 7,380 $ 3,896 $42,951 Net interest 66.6% 40.0% 25.5% 50.0% 100.0% Net interest cash position $ 4,295 $ 7,025 $ 1,954 $ 3,690 $ 3,896 $20,860 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 securities laws relating to the Company and its operations. All statements, other than statements of historical fact, are forward-looking information. Such statements may include, but are not limited to: statements with respect to future events or future performance, including the Outlook section above; the capacity and electricity generation expectations of projects; management s expectations regarding our growth; results of operations; business prospects and opportunities; timing of completion and the cost of construction of the Jimmie Creek; expansion programs at the Reykjanes power plant; the timing of completion of the acquisitions of the South Toba projects; programs to upgrade and develop the Company s geothermal resources; permitting for the Company s expansion and development programs; 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, "outlook", 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. Twelve Month Report 2015 Management's Discussion & Analysis 40

47 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 development programs; wind studies may not confirm that wind resources are sufficient to generate enough electricity to support our planned wind development programs; failure to discover and establish economically recoverable and sustainable geothermal resources through our development programs; geothermal 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 renewable resources; variations in project parameters and generation rates; meteorological or geological occurrences beyond our control may compromise our operations and their capacity to generate power; inability to obtain the financing or refinancing we need to pursue our growth strategy and business plans; we may be required to spend significant funds to advance development or construction before obtaining financing; financing arrangements and associated covenants may restrict our ability to pursue future financings and potentially limit our future business dealings; the significant 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; risk that we are subject to litigation or arbitration that has an adverse outcome; 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; we may experience delays or be impacted by unexpected capital cost increases; unexpected or challenging geological conditions; changes to regulatory requirements, both regionally and internationally, governing development, renewable resources, generation, 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 other 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; merchant price risk for the non-contracted portion of sales at Shannon; risk of under delivery of generation under the power hedge at Shannon; 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; 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 Other risks and uncertainties in this MD&A. These factors should be considered carefully and investors should not place undue reliance on forward looking information. The 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 generation 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 geo-thermometer calculations; capital expenditure estimates; availability of capital to fund exploration, development and expansion programs; our competitive position; and general economic conditions. information is also based upon the Twelve Month Report 2015 Management's Discussion & Analysis 41

48 assumption that none of the identified risk factors that could cause actual results to differ materially from the information will occur. There can be no assurance that the 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 information. 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 information to reflect new events or circumstances. Forward-Looking Financial Information Forward-looking statements include forward-looking financial information or financial outlook within the meaning of applicable securities laws, such as expected generation, revenue and Adjusted EBITDA for 2016 and Alterra is providing this information as of the date of this MD&A, in particular, under the heading Outlook on a net interest basis (reflecting ownership percentage), in order to assist readers to better understand the expected results and impact of the Company s operating and construction projects expected to be commissioned in the near term. Readers are cautioned that this information may not be appropriate for any other purpose. Consequently, readers should not place undue reliance on this information. Management does not intend to update this information except as may be required by applicable law. Forward-looking financial information constitutes forward-looking statements within the context of applicable securities laws and as such, is subject to the same risks, uncertainties and assumptions as are set out above. Additional risks, uncertainties and assumptions, include, but are not limited to: Estimated Generation: Management s estimated generation numbers for hydro and wind facilities are based on resource assessments of average annual generation at each project location, adjusted for planned maintenance outages. In respect of Jimmie Creek, these numbers reflect a partial year of generation in 2016 (assuming commencement of commercial operations in summer 2016). Forecast generation for geothermal facilities is based on historical generation, assuming the recently drilled new wells at Svartsengi are placed in service and reinjection at Reykjanes is successful. Other relevant assumptions include consistent water, wind and geothermal resource production, minimal delays due to unplanned maintenance or other outages, and the forward-looking risks, uncertainties and assumptions set out above. Estimated Total Revenue: The Company s outlook for revenue is based on internal budgets and models for all of the Company s operations, including estimated generation and the unit pricing the Company expects to receive under its power purchase agreements and hedge agreements, or in absence of such agreements or where such agreements incorporate merchant price markets, the estimated merchant prices. Additional assumptions include the timing for commencement of commercial operations at Jimmie Creek, the start of a long-term power hedge for Shannon on June 1, 2016, the expected results from the reinjection program at Reykjanes and forecast merchant and aluminum prices. While the Company s operations remain subject to the risks and uncertainties discussed above, revenue estimates are particularly sensitive to fluctuations in exchange and inflation rates and to actual water, wind and geothermal resource production. Estimated Adjusted EBITDA: Management s estimations of the Company s Adjusted EBITDA are based on an internal budgets and models for all of the Company s operations, estimated generation, estimated revenue, operational expenses, head office costs and development spend. For each of the Company s operations, management estimates operating earnings by subtracting estimated costs (such as operational and maintenance expenditures, salaries, insurance premiums and royalties) from estimated revenues. While certain of these cost estimates are predictable and relatively fixed, many vary due to inflation and other factors, whether third-party driven or otherwise, that are not within the control of the Company. Anticipated head office cost and development spend has been deducted from project Adjusted EBITDA and reflects budgeted spend for the year. Estimated Adjusted EBITDA is presented on a net interest basis for all of the Company s operations and may be subject to the additional risks and uncertainties discussed elsewhere herein. Forward-Looking Financial Information & Development Operations: Alterra s estimates of generation, revenue and Adjusted EBITDA reflect only the Company s six operating projects and Jimmie Creek (which is expected to commence commercial operations in summer 2016) on a net interest basis. The forecasts include anticipated development or head office expenses but not project capital spend or capitalized development costs and consequently, readers are cautioned to consider the information in this MD&A and the accompanying financial statements as a whole. Twelve Month Report 2015 Management's Discussion & Analysis 42

49 CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2015 AND 2014 (expressed in United States dollars) JIMMIE CREEK PIPE BRIDGE BC

50 MANAGEMENT S RESPONSIBILITY FOR FINANCIAL REPORTING The accompanying consolidated financial statements of Alterra Power Corp. ( Alterra ) are the responsibility of management. These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and where appropriate, include management s best estimates and judgments. Management maintains a system of internal controls designed to provide reasonable assurance that assets are safeguarded from loss or unauthorized use, and that financial information is accurate and reliable. The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and is ultimately responsible for reviewing and approving the consolidated financial statements. The Board carries out this responsibility principally through its Audit Committee. The Board of Directors appoints the Audit Committee, and all of its members are independent directors. The Audit Committee meets periodically with management and the shareholders auditors to review consolidated financial statements and reports prepared by management, internal controls, audit results, accounting principles and related matters. The consolidated financial statements, upon recommendation from the Audit Committee, are then sent to the Board of Directors for final approval. PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, was appointed by the shareholders at the last annual meeting to examine the consolidated financial statements and provide an independent professional opinion. John B. Carson John B. Carson Chief Executive Officer Lynda D. Freeman Lynda D. Freeman Chief Financial Officer Vancouver, Canada March 15,

51 Independent Auditor s Report To the Shareholders of Alterra Power Corp. We have audited the accompanying consolidated financial statements of Alterra Power Corp., which comprise the consolidated balance sheets as at December 31, 2015 and December 31, 2014 and the consolidated statements of operations, comprehensive loss, cash flows and changes in equity for the years then ended, and the related notes, which comprise a summary of significant accounting policies and other explanatory information. Management s responsibility for the consolidated financial statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. Auditor s responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion. 45

52 Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Alterra Power Corp. as at December 31, 2015 and December 31, 2014 and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. signed PricewaterhouseCoopers LLP Chartered Professional Accountants Vancouver, British Columbia March 15,

53 Consolidated Balance Sheets (expressed in thousands of United States dollars) Note December 31, 2015 December 31, 2014 Assets Current assets Cash and cash equivalents 39 $ 10,345 $ 63,216 Restricted cash 6 10,766 9,672 Short-term investments 7,670 4,321 Trade and other receivables 12,354 11,414 Inventories 3,716 3,381 Current portion of bonds receivable Prepaid expenses ,676 93,108 Investment in associates 7 174, ,391 Bonds receivable 14 1,491 1,988 Long-term receivable and other assets 15 5,518 14,540 Prepaid lease and royalty fee 16 3,900 3,901 Plant and equipment , ,513 Development costs 18 58,229 73,298 Deferred income tax 35 2,898 Other intangible assets 1,330 1,995 Goodwill 22 10,698 10, , ,538 Assets held for sale 28 11,566 Total assets $ 593,014 $ 623,212 Liabilities Current liabilities Accounts payable and accrued liabilities $ 13,660 $ 17,890 Current portion of long-term debt ,386 17,752 Current portion of embedded derivatives 32 8,362 4,898 Current portion of interest rate swaps Other liabilities 23 10,689 5, ,944 46,895 Long-term debt , ,378 Pension fund obligations 25 15,779 14,856 Embedded derivatives 32 57,348 39,166 Interest rate swaps 26 2, Below market contracts 27 15,908 17,923 Deferred income tax 35 13,340 15, , ,375 Liabilities held for sale 28 1,928 Total liabilities $ 393,764 $ 409,198 The accompanying notes are an integral part of the consolidated financial statements 1 47

54 Consolidated Balance Sheets (expressed in thousands of United States dollars) Equity Note December 31, 2015 December 31, 2014 Share capital 29 $ 362,905 $ 362,570 Contributed surplus 6,387 5,733 Accumulated other comprehensive loss (20,628) (24,192) Deficit (222,740) (205,723) Total equity attributable to owners of the Company 125, ,388 Non-controlling interest 30 73,326 75,626 Total equity 199, ,014 Total liabilities and equity $ 593,014 $ 623,212 Commitments (note 34) Financial instruments - liquidity risk (note 32) Subsequent events (notes 8, 9, 17, and 31) Approved by the Board of Directors and authorized for issue on March 15, 2016 "Ross Beaty" Ross Beaty (Director) "James Bruce" James Bruce (Director) The accompanying notes are an integral part of the consolidated financial statements 48

55 Consolidated Statements of Operations (expressed in thousands of United States dollars, except for number of shares and per common share amounts) Year ended December 31, Note Revenues Energy sales $ 57,835 $ 70,353 Portfolio energy credit sales ,835 70,952 Cost of sales 37 (41,704) (53,860) Gross profit 16,131 17,092 Other income (expenses) General and administrative 38 (9,895) (10,365) General development expenses (1,417) (315) Share of results of equity investments ,125 12,200 Finance income 1,808 2,738 Finance costs (12,643) (8,602) Change in the fair value of bonds payable 1,655 (2,601) Change in the fair value of derivatives (22,285) (11,846) Foreign exchange loss (18,459) (4,566) Write-down of development costs and plant and equipment 19,21,28 (22,439) Write-off of goodwill 22 (2,018) Other income 1, (37,184) (47,303) Loss before income tax (21,053) (30,211) Income tax recovery (expense) 35 3,747 (4,563) Loss for the year $ (17,306) $ (34,774) Attributable to: Owners of the Company $ (16,717) $ (36,340) Non-controlling interest (589) 1,566 $ (17,306) $ (34,774) Weighted average shares outstanding (thousands) Basic and diluted 468, ,047 Loss per share attributable to owners of the Company Basic and diluted $ (0.04) $ (0.08) The accompanying notes are an integral part of the consolidated financial statements 49

56 Consolidated Statements of Comprehensive Loss (expressed in thousands of United States dollars) Year ended December 31, Note Loss for the year $ (17,306) $ (34,774) Other comprehensive income (loss) Items that may be reclassified to profit and loss: Effective portion of change in fair value of cash flow hedges, net of tax (10,321) (7,241) Net change in fair value of cash flow hedges transferred to statement of operations, net of tax 2,048 1,485 Foreign currency translation adjustment 10,247 (24,816) Change in fair value of available-for-sale investments (4) (238) Items that will never be reclassified to profit and loss: Defined benefit plan actuarial losses 25 (567) (454) Tax on items that will never be reclassified to profit and loss Comprehensive loss for the year $ (15,789) $ (65,947) Attributable to: Owners of the Company $ (13,453) $ (60,491) Non-controlling interest (2,336) (5,456) Comprehensive loss for the year $ (15,789) $ (65,947) The accompanying notes are an integral part of the consolidated financial statements 50

57 Consolidated Statements of Cash Flows (expressed in thousands of United States dollars) Year ended December 31, Note Operating activities Loss for the year $ (17,306) $ (34,774) Items not affecting cash Amortization, depreciation, depletion and accretion 11,179 13,245 Amortization of below market contracts 27 (1,657) (2,038) Share of results of equity-accounted investees (22,125) (12,200) Change in fair value of bonds payable (1,655) 2,601 Change in fair value of derivatives 22,285 11,846 Finance income and costs, net 10,835 5,864 Unrealized foreign exchange loss 18,459 4,566 Deferred income tax expense (recovery) 35 (3,747) 4,563 Stock-based compensation Development costs and plant and equipment write-down 22,439 Goodwill written off 2,018 Other (1,325) 96 Distribution received from Toba Montrose GP 8 5,463 12,117 Distribution received from Dokie GP 9 1,182 1,325 Distribution received from Blue Lagoon 12 2,679 2,812 Interest received 991 1,859 Interest paid (9,439) (7,600) Taxes paid 35 (340) Change in non-cash working capital items 39 (5,425) (2,132) Cash generated by operating activities 11,056 26,841 Financing activities New borrowings 31 2, ,942 Financing fees on holding company loan facility 24 (3,472) Repayment of loans 24 (19,713) (66,272) Other (857) (642) Cash generated by (used in) financing activities (18,458) 56,556 Investing activities Purchase of plant and equipment 17 (18,224) (9,087) Hydro development costs 20 (740) (47,695) Wind development costs 21 (37,581) (5,698) Proceeds from deep drilling program grants 23 4,978 Return of Jimmie Creek capital 10 20,336 Return of Shannon capital 11 3,500 Proceeds from sale of Soda Lake 28 8,326 Equity contribution in Shannon 11 (6,927) Developer and construction management fees (Shannon) 11 2,250 Net proceeds from sale (acquisition) of short-term investments (3,987) 3,102 Restricted cash 4,229 (5,172) Security deposits (29) (10,330) Investment in associates (78) (1,782) Other 145 (2,703) Cash used in investing activities (44,138) (59,029) Effect of foreign exchange on cash (1,331) (2,827) Decrease in cash and cash equivalents (52,871) 21,541 Cash and cash equivalents - beginning of year 63,216 41,743 Cash classified as held for sale 28 (68) Cash and cash equivalents - end of year $ 10,345 $ 63,216 Supplementary cash information (note 39) The accompanying notes are an integral part of the consolidated financial statements 5 51

58 Consolidated Statements of Changes in Equity (expressed in thousands of United States dollars, except for number of common shares) Accumulated Common shares other Non - Number of Contributed comprehensive controlling Total Note shares Amount surplus income (loss) Deficit interest equity Balance, January 1, ,699,444 $ 362,420 $ 5,136 $ (282) $ (169,142) $ 81,725 $ 279,857 Shares issued to employees , Value assigned to options granted Foreign currency translation adjustment (17,916) (6,900) (24,816) Dividend from HS Orka hf (643) (643) Effective portion of change in fair value of cash flow hedge, net of tax (7,241) (7,241) Net change in fair value of cash flow hedge transferred to statement of operations, net of tax 1,485 1,485 Change in fair value of available-for-sale investments (238) (238) Defined benefit plan actuarial losses, net of taxes (241) (122) (363) Income (loss) for the year (36,340) 1,566 (34,774) Balance, December 31, ,263,361 $ 362,570 $ 5,733 $ (24,192) $ (205,723) $ 75,626 $ 214,014 Balance, January 1, ,263,361 $ 362,570 $ 5,733 $ (24,192) $ (205,723) $ 75,626 $ 214,014 Shares issued to employees 29 1,323, Options exercised 29 65, (8) 15 Value assigned to options granted Foreign currency translation adjustment 11,841 (1,594) 10,247 Dividend from HS Orka hf (800) (800) Effective portion of change in fair value of cash flow hedges, net of tax (10,321) (10,321) Net change in fair value of cash flow hedges transferred to statement of operations, net of tax 2,048 2,048 Change in fair value of available-for-sale investments (4) (4) Acquisition of subsidiary at HS Orka hf with non-controlling interest Defined benefit plan actuarial losses, net of taxes (300) (153) (453) Loss for the year (16,717) (589) (17,306) Balance, December 31, ,652,409 $ 362,905 $ 6,387 $ (20,628) $ (222,740) $ 73,326 $ 199,250 The accompanying notes are an integral part of the consolidated financial statements 52 6

59 1) DESCRIPTION OF BUSINESS AND NATURE OF OPERATIONS Alterra Power Corp. was incorporated on January 22, 2008, pursuant to the Business Corporations Act of British Columbia, Canada. Alterra Power Corp. and its subsidiary companies (collectively the Company ) are engaged in the development, construction and operation of renewable power projects. The Company s operating facilities consist of a 66.6% net interest in two geothermal power plants in Iceland ("Svartsengi" and "Reykjanes"), a 40% net interest in two run of river hydro power plants ("Toba Montrose"), a 25.5% net interest in a wind farm ("Dokie 1") in British Columbia and a 50% net interest in the sponsor equity in Shannon wind farm ("Shannon") located in Texas. The Company has a 51% net interest in the Jimmie Creek hydro project ("Jimmie Creek") located in British Columbia which is currently under construction and is expected to achieve commercial operation in the summer of In addition to the operating facilities and construction asset Jimmie Creek, the Company also has the following development assets: Location Project Net ownership Technology Canada Bute Inlet 100% Hydro Dokie 2 51% Wind Tahumming 100% Hydro South Toba projects 100% Hydro Coastal wind projects 100% Wind Multiple early stage projects 100% Hydro Iceland Reykjanes 3-4 (potential expansion) 67% Geothermal Eldvörp / Krýsuvík / Trölladyngja 67% Geothermal Búlandsvirkjun 33% Hydro Hvalá 35% Hydro Brúarvirkjun 67% Hydro Skúfnavatnavirkjun 35% Hydro Multiple early stage projects 67% Geothermal/Hydro USA Soda Lake Solar 100% Solar Multiple wind projects 100% Wind Chile Mariposa 30% Geothermal Peru Multiple early stage projects 30% Geothermal Italy Mensano / Roccastrada 45% Geothermal The recovery of the carrying values of the Company s projects and properties is typically dependent upon the successful completion or sale of the projects. The successful completion of a project is typically dependent upon receiving environmental and operating permits, completing contractual arrangements for the development and construction of the project, entering into a power purchase agreement or financial hedge for power sales, obtaining any necessary project financing, and the long-term generation and sale of electricity on a profitable basis. The carrying value of the Company s projects and properties represents net costs to date less amounts amortized and/or written off or fair value allocated to assets on acquisition, and does not necessarily represent current or future values. 7 53

60 1) DESCRIPTION OF BUSINESS AND NATURE OF OPERATIONS (Continued) At December 31, 2015 the Company has a working capital deficit due to its holding company bonds (Sweden) of $118.0 million being classified as a current liability. These bonds were issued in conjunction with the acquisition of HS Orka hf ("HS Orka") and mature in July and December The Company has plans to retire the bonds through refinancings in 2016, for which the Company is currently in negotiations (note 24). 2) BASIS OF PRESENTATION Statement of compliance These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ( IFRS ) as issued by the International Accounting Standards Board ( IASB ). The Company s significant accounting policies are described in note 3. These consolidated financial statements were authorized for issue by the Board of Directors on March 15, ) SIGNIFICANT ACCOUNTING POLICIES a) Basis of measurement These consolidated financial statements have been prepared on the historical cost basis except for the following material items in the consolidated balance sheets: derivative financial instruments (interest rate swaps), which are measured at fair value; embedded derivatives in electricity power sales contracts, which are measured at fair value; financial liabilities designated as fair value through profit or loss (bonds payable), which are measured at fair value; available-for-sale financial instruments (short-term investments), which are measured at fair value; defined benefit pension obligation, which is measured at the present value of the pension obligation; and assets and liabilities classified as held for sale, which are measured at fair value less costs to sell. b) Functional and presentation currency The reporting currency selected for the presentation of these consolidated financial statements is the United States dollar ( U.S. dollar ). For presentation purposes, consolidated assets and liabilities are translated into U.S. dollars at the exchange rate in effect at the balance sheet date. Consolidated revenues and expenses are translated into U.S. dollars at rates in effect at the time of the underlying transactions. Gains and losses arising from translation of the consolidated financial statements into U.S. dollars are recognized in other comprehensive income (loss). The Company has determined that the functional currency of the Company and each of its subsidiaries, except Magma Energy (U.S.) Corp., Soda Lake Solar, LLC, Alterra Shannon Investments, LLC, Alterra Shannon Holdings, LLC, Shannon Group Holdings, LLC, Shannon Partnership Holdings, LLC, Shannon Wind Holdings, LLC, Shannon Wind, LLC, Alterra Management Services, LLC, and Alterra Texas Holdings, LLC, (the US Subsidiaries ), and HS Orka, is the Canadian dollar ("C$"). The functional currency of the U.S. 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. 8 54

61 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) c) Basis of consolidation These consolidated financial statements include the accounts of the Company and the following directly or indirectly wholly-owned subsidiaries: Magma Energy (U.S.) Corp., Magma Energy Chile Limitada, Magma Energia Geotermica S.A., Isla Verde Energia S.A., Magma Energy Sweden A.B., Magma Energy Iceland ehf., Soda Lake Solar, LLC, Plutonic Power Corporation ( Plutonic ), Plutonic Hydro Inc., Plutonic TMP Holdings Inc., Bute Hydro Inc., Plutonic Dokie Holdings Inc., Plutonic Dokie Expansion Holdings Inc., Stave Point Holdings Inc., Dalgleish Hydro Inc., Plutonic Solar Inc., Plutonic ABW Holdings Inc., Plutonic Upper Toba Holdings Inc., Salal Geothermal Inc., Alterra Quaye Holdings Inc., B.C. Ltd., South Banks Island Wind Holdings Inc., Porcher Island Wind Holdings Inc., Soren Hill Wind Holdings Inc., McCauley Island Wind Holdings Inc., B.C. Ltd., B.C. Ltd., Knight Hydro Inc, Zoltan Hydro Inc, Powell Hydro Inc., Plutonic Development Corp., Alterra Renewable Holdings Corp., Alterra Renewable Holdings I Corp., Alterra Renewable Holdings II Corp., Alterra Renewable Holdings III Corp., Alterra Jimmie GP Corp., Jimmie Creek GP Inc., Alterra Texas Holdings, LLC, Alterra Shannon Investments, LLC, Alterra Shannon Holdings, LLC, and Alterra Management Services, LLC. At December 31, 2015, the Company held a 66.6% interest in HS Orka, which owns and operates the Svartsengi and Reykjanes geothermal plants in Iceland. The Company consolidates the assets, liabilities, revenue and expenses of HS Orka in full, recognizing at December 31, 2015 the remaining 33.4% noncontrolling interest in equity. In October 2015, HS Orka further increased their ownership of Vesturverk ehf. ("Vesturverk") to 52.5% and consequently the Company now consolidates their results. Vesturverk owns the 55 MW Hvalá and 10 MW Skúfnavatnavirkjun early-stage hydroelectric development properties in Iceland. 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 consideration transferred 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 applicable 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 9 55

62 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) 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 are 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 Toba Montrose General Partnership ("Toba Montose GP,") a joint venture, which owns and operates Toba Montrose, a 25.5% interest in Dokie General Partnership ("Dokie GP"), a joint venture, which owns and operates Dokie 1, and a 50% interest in Shannon Group Holdings, LLC ("Shannon Group LLC"), a joint venture, which owns and operates Shannon. The Company also equity accounts for the following investments in construction and development properties; a 51% investment in Jimmie Creek Limited Partnership ("Jimmie Creek LP"), a joint venture that owns Jimmie Creek, a 45% interest in Magma Energy Italia, a joint venture that owns the Mensano and Roccastrada geothermal projects, a 30% interest in Compania de Energia Limitada, a joint venture that owns the Mariposa project in Chile (comprised of the Maule and Pellado concessions), and a 30% interest in a joint venture that owns concessions in Peru. The Company, through HS Orka, also owns a 30% interest in Bláa Lðnið ehf (the "Blue Lagoon"). The Company equity accounts for its investment in Blue Lagoon. d) Cash and cash equivalents Cash and cash equivalents comprise cash balances and call deposits that are readily convertible to cash or that have original maturities at acquisition of three months or less

63 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) e) Restricted cash Restricted cash is comprised of cash that is not available for immediate use. f) Short-term investments Short-term investments are comprised of investments in short-term debt securities and shares with original maturities of greater than three months and the Company's available-for-sale short-term investments. g) Financial instruments i) Non-derivative financial assets The Company initially recognizes loans, receivables and deposits on the date that they originate. All other financial assets (including assets designated at fair value through profit or loss) are recognized initially on the trade date at which the Company becomes a party to the contractual provisions of the financial instrument. The Company derecognizes a financial asset when the contractual rights to the cash flows from the asset expire, or it transfers the rights to receive the contractual cash flows on the financial asset in a transaction in which substantially all the risks and rewards of ownership of the financial asset are transferred. Any interest in transferred financial assets that is created or retained by the Company is recognized as a separate asset or liability. The Company classifies non-derivative financial assets into the following financial asset categories: financial assets at fair value through profit or loss, loans and receivables and available-for-sale financial assets. Financial assets at fair value through profit or loss A financial asset is classified at fair value through profit or loss if it is classified as held for trading or is designated as such upon initial recognition. Financial assets are designated at fair value through profit or loss if (a) such financial assets eliminates or significantly reduces an accounting mismatch, (b) the Company manages such assets and makes purchase and sale decisions based on their fair value in accordance with the Company s documented risk management or investment strategy or (c) the financial asset contains one or more embedded derivatives. Upon initial recognition attributable transaction costs are recognized in the statement of operations as incurred. Financial assets at fair value through profit or loss are measured at fair value, and changes therein are recognized in the statement of operations. The Company's bonds receivable, short-term investments, and earn-out interests are classified at fair value through profit or loss with the exception of the Company's available-for-sale short-term investments. Loans and receivables Loans and receivables are financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are recognized initially at fair value plus any directly attributable 11 57

64 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) transaction costs. Subsequent to initial recognition loans and receivables are measured at amortized cost using the effective interest method, less any impairment losses. Loans and receivables are comprised of cash and cash equivalents, restricted cash, trade and other receivables and long-term receivable accounts. Available-for-sale financial assets Available-for-sale financial assets are non-derivative financial assets that are designated as availablefor-sale and that are not classified in any of the previous categories. Subsequent to initial recognition, they are measured at fair value and changes therein, other than impairment losses and foreign currency differences on available-for-sale debt instruments, are recognized in other comprehensive income and presented within equity in the fair value reserve. When an investment is derecognized, the cumulative gain or loss in other comprehensive income is transferred to the statement of operations. Investments in equity securities that do not have a quoted market price and whose fair value cannot be reliably measured are recorded at cost. The Company's available-for-sale short-term investment consists of shares held in Greenbriar Capital Corp ("Greenbriar"). ii) Non-derivative financial liabilities The Company initially recognizes debt securities issued and subordinated liabilities on the date that they originate. All other financial liabilities (including liabilities designated at fair value through profit or loss) are recognized initially on the trade date at which the Company becomes a party to the contractual provisions of the instrument. The Company derecognizes a financial liability when its contractual obligations are discharged, cancelled or expired. The Company classifies non-derivative financial liabilities as financial liabilities at fair value through profit or loss or other financial liabilities. Financial liabilities at fair value through profit or loss A financial liability is classified at fair value through profit or loss if it is classified as held for trading or is designated as such upon initial recognition. Financial liabilities are designated at fair value through profit or loss if (a) such liability eliminates or significantly reduces an accounting mismatch, (b) the Company manages such instruments based on their fair value in accordance with the Company s documented risk management or investment strategy or (c) the financial liability contains one or more embedded derivatives. Upon initial recognition, attributable transaction costs are recognized in the statement of operations as incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in the statement of operations. The Company has designated interest rate swaps and holding company bonds (Sweden) which contain embedded derivatives as financial liabilities at fair value through profit or loss. Other financial liabilities The Company classifies all other non-derivative financial liabilities as other financial liabilities. Such financial liabilities are recognized initially at fair value plus any directly attributable transaction costs

65 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) Subsequently, these financial liabilities are measured at amortized cost using the effective interest rate method. Other financial liabilities are comprised of accounts payable and accrued liabilities, and long-term debt (excluding holding company bonds (Sweden)). Financial assets and liabilities are offset and the net amount presented in the balance sheet when, and only when, the Company has a legal right to offset the amounts and intends either to settle on a net basis or to realize the asset and settle the liability simultaneously. iii) Share capital Common shares Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity, net of any tax effects. iv) 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, of 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 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 equity. The amount recognized in accumulated other comprehensive income is removed and included in profit or loss in the same period as the hedged item affects profit or loss under the same line item in the statement of operations. Any ineffective portion of changes in the fair value of the derivative is recognized immediately in profit or loss. 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 accumulated other comprehensive income remains there until the forecasted transaction affects profit or loss. When the hedged item is a non-financial asset, the amount recognized in accumulated other comprehensive income is 13 59

66 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) transferred to the carrying amount of the asset when the asset is recognized. If the forecast transaction is no longer expected to occur, then the balance in accumulated other comprehensive income is recognized immediately in profit and loss. The Company applies hedge accounting for the Toba Montrose GP interest rate swap, the Shannon Group LLC power hedge and the holding company loan facility interest rate swaps which are designated as cash flow hedges. Other derivatives and separable embedded derivatives 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. 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. Changes in the fair value of derivatives not designated as a hedge and separable embedded derivatives are recognized immediately in the statement of operations. h) Inventories Inventories are measured at the lower of cost and net realizable value. The cost of inventories is based on the first-in first-out principle, and includes expenditures incurred in acquiring the inventories and bringing them to their existing location and condition. Net realizable value is the estimated selling price in the ordinary course of business less the estimated cost of completion and selling expenses. Inventories consist of supplies inventory. i) 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 of the Company's plant and equipment include power plants, substations, turbines, boreholes, electrical systems, hot water and cold water distribution systems, transmission lines, housing, penstock, intake, roads, 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

67 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) 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, the Toba Montrose facility components range from 2 to 70 years, and the Shannon facility components range from 3 to 45 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 55%. Depreciation methods, useful lives and residual values are reviewed at each reporting date and adjusted when appropriate. j) Assets held for sale An asset is classified as held for sale if management is committed to a plan to sell, the asset is available for immediate sale, an active plan to locate a buyer is initiated, the sale is highly probable (within 12 months of classification as held for sale, subject to limited exceptions), the asset is being actively marketed for sale at a sales price reasonable in relation to its fair value, and actions required to complete the plan indicate that it is unlikely that plan will be significantly changed or withdrawn. Any asset classified as held for sale is measured at the lower of its carrying value or fair value less costs to sell. k) Intangible assets i) Development hydro, wind, solar 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, solar 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 considered impaired. The recovery of the 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 ("PPA") or power hedge, 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

68 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) From time to time the Company may acquire or dispose of a wind, hydro, solar or geothermal property interest pursuant to the terms of an option agreement. When 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 development 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. ii) 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. Dokie GP s PPA with British Columbia Hydro and Power Authority ( BC Hydro ) is considered a service concession arrangement. iii) Other intangible assets Other intangible assets include project permits and licenses, prepaid land tenure license amounts, First Nations Impact Benefits Agreements ( IBA ), First Nations Resource Development Agreements ( RDA ) and Memoranda of Understanding ( MOU ) costs recorded in Toba Montrose GP, Dokie GP and Jimmie Creek LP respectively, development costs acquired through a Membership Interest Purchase Agreement ("MIPA") to acquire the companies that became Shannon Wind, LLC, and software. Payments made to First Nations under terms of the IBAs, RDAs and MOUs are capitalized to intangible assets prior to the commencement of commercial operations, after which time they are amortized over the life of the project. Any payments made subsequent to the commencement of commercial operations are expensed in the statement of operations. iv) Amortization Amortization is based on the cost of an asset less its residual value. Amortization of intangibles, other than goodwill and development costs, is recognized in the statement of operations on a straight-line basis over the estimated useful lives of intangible assets 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 Toba Montrose GP and Dokie GP, and the Dokie GP service concession arrangement are amortized over the life of the agreements. Amortization methods, useful lives and residual values are reviewed at each reporting date and adjusted if appropriate

69 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) l) Impairment i) Non-derivative financial assets A financial asset not carried at fair value through profit or loss is assessed at each reporting date to determine whether there is objective evidence that it is impaired. A financial asset is impaired if objective evidence indicates that a loss event has occurred after the initial recognition of the asset, and that the loss event had a negative effect on the estimated future cash flows of that asset that can be estimated reliably. In assessing collective impairment, the Company uses historical trends of the probability of default, timing of recoveries and the amount of loss incurred, adjusted for management s judgment as to whether current economic and credit conditions are such that the actual losses are likely to be greater or less than suggested by historical trends. ii) Non-financial assets The carrying amounts of the Company s non-financial assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset s recoverable amount is estimated. For goodwill and intangible assets that have indefinite useful lives or that are not yet available for use, an impairment test is performed at least annually (at the same time) or when events or changes in circumstances indicate that the related carrying amount may not be recoverable. An impairment loss is recognized if the carrying amount of an asset or its related cash generating unit ( CGU ) exceeds its estimated recoverable amount. The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset or CGU. Goodwill acquired in a business combination is allocated to groups of CGUs that are expected to benefit from the synergies of the combination. Impairment losses are recognized in the statement of operations. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to such CGU or group of CGUs, and then to reduce the carrying amounts of other assets in the CGU (or group of CGUs) on a pro rata basis. An impairment loss recognized in respect of goodwill is not reversed. In respect of other assets, impairment losses are reversed if there has been a change in the estimates used to determine the recoverable amount and only to the extent that the asset s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no impairment loss had been recognized

70 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) m) Income taxes (i) Current income tax Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from, or paid to, the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted at the reporting date in the countries where the Company operates and generates taxable income. Current income tax relating to items recognized directly in other comprehensive income or equity is recognized in other comprehensive income or equity and not in profit or loss. (ii) Deferred tax Deferred tax is provided using the balance sheet method on temporary differences between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes at the reporting date. Deferred tax assets are recognized for all deductible temporary differences, the carry-forward of unused tax credits and any unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences, and the carry-forward of unused tax credits and unused tax losses can be utilized, Deferred tax is not recognized for: temporary differences on the initial recognition of goodwill or an asset or liability in a transaction that is not a business combination and, at the time of the transactions, affects neither accounting profit nor taxable profit or loss; and temporary differences related to investments in subsidiaries, associates and interests in joint ventures where the timing of the reversal of the temporary differences can be controlled by the parent, investor or venture and it is probable that the temporary difference will not reverse in the foreseeable future; and The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilized. Unrecognized deferred tax assets are reassessed at the end of each reporting period and are recognised to the extent that it has become probable that future taxable profit will be available to allow the deferred tax asset to be recovered. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted by the end of the reporting period. Deferred tax relating to items recognized in other comprehensive income or equity is recognized in other comprehensive income or equity and not in profit or loss. Deferred tax assets and deferred tax liabilities are offset, if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority

71 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) n) Provisions A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefit will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. The unwinding of the discount is recognized as a finance cost. o) Grants Grants related to assets are initially recognized as deferred income at fair value if there is reasonable assurance that they will be received and the Company will comply with the conditions associated with the grant; they are then recognized in profit or loss as other income on a systematic basis over the useful life of the asset. Grants that compensate the Company for expenses incurred are recognized in profit or loss on a systematic basis in the periods in which the expenses are recognized. Grants received by HS Orka during the year are included in other liabilities. p) Decommissioning liability The Company recognizes the fair value of decommissioning liabilities in the period in which a reasonable estimate of such costs can be made. The decommissioning liability is recognized at fair value and recorded as a liability with a corresponding increase to the carrying amount of the related long-lived asset. A decommissioning liability has been recognized at Shannon Group LLC due to explicit requirements in the land lease agreements. No decommissioning liability has been recognized for Toba Montrose GP, Dokie GP, or the Svartsengi and Reykjanes geothermal facilities due to the long service life of these assets and due to the low probability that these projects would ever be abandoned due to the renewable nature of the resource used to generate electricity. Annually management assess the continued longevity of an operating project and will recognize a decommissioning liability when abandonment is foreseen. q) Revenue recognition Revenue is recognized at the time of generation and recorded measurement of delivery to the purchasing party. Between measurements usage is estimated based on prior usage. Sales of renewable energy credits, which occur at Shannon and prior to the sale at the Soda Lake plant, are recognized in revenue when pervasive evidence of an arrangement for sale exists, the selling price is fixed or determinable, risk and rewards of ownership have passed to the purchaser and collectability is reasonably assured. Revenue is recognized from the ecoenergy for Renewable Power program upon metered eligible production of electricity, up to an annual maximum of 727,000 megawatt-hour ( MWh ) for Toba Montrose and 330,000 MWh for Dokie 1, based on a fiscal year with 365 days for a period of 10 years respectively from the commencement of commercial production. Amortization of below market contracts recorded on the acquisition of HS Orka are recognized on a straight-line basis over the remaining life of the respective contract and included in revenue

72 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) r) Stock-based compensation Compensation expense for stock options granted is measured at fair value using the Black-Scholes valuation model and is recognized over the vesting period of the options granted. In situations where stock options are granted to employees working on specific projects or properties, the expense is capitalized against that project or property. The value assigned to stock options shown on the balance sheet as contributed surplus is subsequently reduced if the options are exercised and the amount so reduced is then credited to share capital. Any values assigned to stock options that have expired or vested stock options that are cancelled remain in contributed surplus. s) Employee benefits The Company s net obligation in respect of defined benefit multi-employer pension plans or pension fund commitments at HS Orka is calculated separately for each plan by estimating the amount of future benefits that current and former employees have earned in return for their service in the current and prior periods. That benefit is discounted to determine its present value. The calculation is performed annually by qualified actuaries using a method based on earned benefits. Remeasurements of the net defined liabilities related to actuarial gains and losses are recognized in other comprehensive income, and other expenses related to the defined benefit plans are recognized as incurred in the statement of operations. Short-term employee benefit obligations are measured on an undiscounted basis and are expensed as the related service is provided. A liability is recognized for the amount expected to be paid under shortterm cash bonus or profit-sharing plans if the group has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee, and the obligation can be estimated reliably. Contributions to the defined contribution pension plan is recognized as an employee benefit expense in profit or loss in the period during which services are rendered by employees. t) Lease accounting At inception of long-term power sales arrangements, the Company determines whether such an arrangement is or contains a lease. A specific asset is the subject of a lease if fulfilment of the arrangement is dependent on the use of that specified asset. An arrangement conveys the right to use the asset if the arrangement conveys to the purchaser the right to control the use of the underlying asset. At inception or upon reassessment of the arrangement, the Company separates payments and other consideration that is required by such an arrangement into those for the lease and those for other elements on the basis of their relative fair values. Agreements meeting the criteria as leases, which transfer to counterparties substantially all the risks and rewards of ownership of assets but not necessarily legal title, are classified as finance leases. When the Company is a lessor under finance leases the amounts due under the leases, after deduction of unearned finance income, are included in lease receivable (in the balance sheet). The finance income is recognized in finance income (in the statement of operations) over the periods of the leases so as to give a constant rate of return on the new investment in the leases. All leases are categorized as operating leases

73 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) u) Finance income and costs Finance income comprises interest income on funds invested and dividend income from other investments. Interest income is recognized as it accrues in the statement of operations, using the effective interest rate method. Dividend income is recognized in the statement of operations on the date that the Company s right to receive payment is established. Finance costs are comprised of interest expense on borrowings and unwinding of the discount on provisions. Borrowing costs that are not directly attributable to the acquisition, construction or production of a qualifying asset are recognized in the statement of operations using the effective interest rate method. v) Comparative figures Certain of the comparative year figures have been reclassified to conform to the current year s presentation. w) Changes in accounting standards The Company has adopted the following new IFRS standards, along with any consequential amendments, effective January 1, These changes were made in accordance with the applicable transitional provisions. The nature and impact of each new standard and amendment applicable to the Company are described below: IFRS 8 - Operating segments Operating segments (amendments to IFRS 8) was amended to require disclosure of the judgments made by management in aggregating operating segments, including a description of the segments which have been aggregated and the economic indicators which have been assessed in determining that the aggregated segments share similar economic characteristics. The amendment is effective for annual periods commencing on or after July 1, The adoption of this standard has no impact on the consolidated financial statements. IAS 19 - Employee benefits Employee benefits (amendments to IAS 19) was amended to clarify the application of IAS 19 to plans that require employees or third parties to contribute toward the cost of benefits. The amendment is effective for annual periods beginning on or after July 1, There is an additional amendment to clarify the guidance on discount rates for post-employment benefit obligations. The adoption of this standard did not have an impact on the consolidated financial statements. At December 31, 2015, a number of standards and interpretations, and amendments thereto, had been issued by the IASB, which are not effective for these consolidated financial statements. Those which may be relevant to the Company s consolidated financial statements are set out below: IFRS 9: Financial instruments Financial instruments, addresses the classification, measurement and recognition of financial assets and financial liabilities. The complete version of IFRS 9 was issued in July 2014 and replaces IAS 39. The requirements of this standard represent a significant change from the existing requirements in IAS 39 in respect of financial assets. The standard contains three primary measurement categories for financial assets: amortized cost, fair value through other comprehensive income, and fair value through profit and loss. A financial asset would be measured at amortized cost if it is held within a business model whose 21 67

74 3) SIGNIFICANT ACCOUNTING POLICIES (Continued) objective is to hold assets in order to collect contractual cash flows, and the asset s contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the principal outstanding. All other financial assets would be measured at fair value. The new standard also requires a single impairment method to be used, adds guidance on the classification and measurement of financial liabilities, and provides a new general hedge accounting standard. The effective date is January 1, 2018 but may be adopted early at the Company's discretion. The Company is currently evaluating the impact of these amendments. IFRS 15 - Revenue from contracts with customers Revenue from contracts with customers is a new standard superseding IAS 18 - Revenue, IAS 11 - Construction contracts and related interpretations. The new standard is effective for interim periods within years beginning on or after January 1, The Company is currently evaluating the impact of these amendments. IFRS 16 - Leases Leases specifies how an issuer will recognize, measure, present and disclose leases. The standard provides a single lessee accounting model, requiring lessees to recognize assets and liabilities for all leases unless the lease term is 12 months or less, or the underlying asset has an insignificant value. The effective date is January 1, The Company is currently evaluating the impact that adoption of the standard is expected to have on its consolidated financial statements. 4) CRITICAL JUDGMENTS IN APPLYING ACCOUNTING POLICIES The critical judgments that the Company s management has made in the process of applying the Company s accounting policies, apart from those involving estimations (note 5), that have the most significant effect on the amounts recognized in the Company s consolidated financial statements are as follows: (a) Determination of cash generating units In performing impairment assessments of assets that cannot be assessed individually are grouped together, in management's judgment, into the smallest group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. (b) Determination of functional currency The functional currency for each of the Company s subsidiaries, joint ventures and investments in associates is the currency of the primary economic environment in which the entity operates. Determination of functional currency may involve certain judgments to determine the primary economic environment and the Company reconsiders the functional currency of its entities if there is a change in events and conditions which determined the primary economic environment. (c) Purchase price allocations Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make assumptions, estimates and judgments regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities. As a result, the purchase price allocation impacts the Company s reported assets and liabilities and future net earnings due to the allocation's impact on future depreciation and amortization expense and impairment tests

75 4) CRITICAL JUDGMENTS IN APPLYING ACCOUNTING POLICIES (Continued) (d) Determining control or significant influence of an investee The determination of whether the Company has control or significant influence over an investee requires the Company to make assumptions and judgments in evaluating the classification requirements. 5) KEY SOURCES OF ESTIMATION UNCERTAINTY The preparation of consolidated financial statements requires that the Company s management makes assumptions and estimates of effects of uncertain future events on the carrying amounts of the Company s assets and liabilities at the end of each reporting period. The estimation process is inherently uncertain, therefore future outcomes could differ from present estimates and assumptions, potentially having a material effect on the Company s future results and disclosures. Revisions to estimates and the resulting effects on the carrying amounts of the Company s assets and liabilities are accounted for prospectively. Aspects of the Company s financial reporting that require the use of significant assumptions and that have a significant risk of resulting in a material adjustment to the carrying amounts of the Company s assets and liabilities are as follows: (a) Impairment of assets; geothermal, hydro, and wind development costs, plant and equipment and goodwill (notes 17 and 19-22) (b) Fair value of financial instruments including embedded derivatives (note 32) (c) Income taxes (note 35) (d) Amortization of plant and equipment (note 17) (e) Pension fund obligations (note 25) (f) Bond receivable (note 14) (g) Long-term receivable (note 15) (h) Initial investment of Jimmie Creek and Shannon (notes 10 and 11) 6) RESTRICTED CASH As at December 31, 2015, there is $10.8 million in restricted cash (December 31, $9.7 million). HS Orka has $4.5 million of its cash balance dedicated to loan payments in accordance with a collateral agreement concluded in March 2010 with HS Orka s lenders (December 31, 2014 $4.5 million). HS Orka holds an additional $5.7 million related to a grant that HS Orka is participating in and administering, which was received and is to be distributed to HS Orka's partners in the project (see also note 23). The remaining $0.6 million is held in escrow for the Company's holding company bondholders (Sweden)

76 7) INVESTMENT IN ASSOCIATES Note December 31, 2015 December 31, 2014 Toba Montrose GP 8 $ 21,961 $ 26,977 Dokie GP 9 8,020 8,269 Jimmie Creek LP 10 34,034 40,809 Shannon Group LLC 11 62,392 Blue Lagoon 12 24,484 20,834 Geothermal development projects: Mariposa 13 18,579 22,525 Peru concessions 13 2,007 2,395 Italy Other investments 2,177 2,587 Total $ 174,457 $ 125,391 8) INVESTMENT IN TOBA MONTROSE GP a) The Company holds a 51% non-participating and voting interest in the partnership and 40% nonvoting and participating interest in Toba Montrose GP (economic interest). In 2046, the Company s economic interest will increase to 51% for no additional consideration and its partner s economic interest in Toba Montrose GP will decrease from 60% to 49%. b) The Company's economic interest in the assets, liabilities, revenue and expenses and cash flows of Toba Montrose GP is accounted for under the equity method of accounting (as the partnership is a joint venture). Amounts included in these consolidated financial statements are further described as follows: Investment in Toba Montrose GP Investment at January 1, 2014 $ 39,879 Share of comprehensive income 2,453 Distributions received (12,117) Foreign exchange (3,238) Investment at December 31, 2014 $ 26,977 Share of comprehensive income 4,873 Distributions received (5,463) Foreign exchange (4,426) Investment at December 31, 2015 $ 21,961 The following tables summarize the financial information of Toba Montrose GP as included in its own financial statements, adjusted for fair value adjustments at acquisition, and reconcile the financial information to the Company's carrying value of Toba Montrose GP: 24 70

77 8) INVESTMENT IN TOBA MONTROSE GP (Continued) December 31, 2015 December 31, 2014 Cash and cash equivalents $ 17,562 $ 15,185 Trade and other receivables 1,798 2,532 Prepaid expenses 3,018 3,291 Plant and equipment 396, ,526 Intangible assets 5,572 7,660 Other assets 1,215 1, , ,072 Accounts payable and accrued liabilities 4,757 6,263 Long-term debt 319, ,288 Interest rate swaps 42,859 48, , ,674 Net assets (100%) $ 58,900 $ 72,398 Share of net assets (40%) 23,560 28,959 Purchase price adjustments (1,599) (1,982) Share of net assets (40%) $ 21,961 $ 26,977 Year ended December 31, 2015 Year ended December 31, 2014 Revenue $ 61,845 $ 71,492 Cost of sales (9,460) (10,905) Depreciation and amortization (10,116) (11,570) Interest expense (22,409) (26,002) Property insurance proceeds 1,979 Other expenses (5,204) (7,876) Unrealized gain (loss) on interest rate swaps (2) 708 Net income (100%) $ 14,654 $ 17,826 Share of net income (40%) 5,862 7,130 Purchase price adjustments Share of net income (40%) $ 5,931 $ 7,298 Year ended Year ended December 31, 2015 December 31, 2014 Other comprehensive loss (100%) $ (2,646) $ (12,113) Share of other comprehensive loss (40%) (1,058) (4,845) Share of net income (40%) 5,931 7,298 Share of comprehensive income (40%) $ 4,873 $ 2,

78 8) INVESTMENT IN TOBA MONTROSE GP (Continued) Toba Montrose GP's other comprehensive loss consists solely of changes in the value of the effectively hedged portion of Toba Montrose GP's interest rate swap hedging instrument. The Company s 40% share of long-term debt repayments as at December 31, 2015 is as follows: Principal Interest Total 2016 $ 1,591 $ 8,192 $ 9, ,692 8,086 9, ,800 7,979 9, ,914 7,865 9, ,036 7,749 9,785 Thereafter 120, , ,777 Total $ 129,204 $ 159,477 $ 288,681 Note: The debt repayments in the table above do not include the effect of purchase price adjustments assumed upon acquisition. Toba Montrose GP is subject to certain covenants regarding its loan agreements and as at December 31, 2015 was in compliance with all debt covenants. Subsequent to year end, Toba Montrose GP declared and paid a C$5.0 million distribution of which the Company's share was C$2.0 million. 9) INVESTMENT IN DOKIE GP a) The Company holds a 25.5% interest in Dokie GP. b) The Company's economic interest in the assets, liabilities, revenue and expenses and cash flows of Dokie GP is accounted for under the equity method (as the partnership is a joint venture). Amounts included in these consolidated financial statements are further described as follows: Investment in Dokie GP Investment at January 1, 2014 $ 9,648 Share of comprehensive income 536 Distributions received (1,147) Foreign exchange (768) Investment at December 31, 2014 $ 8,269 Share of comprehensive income 1,826 Distributions received (669) Foreign exchange (1,406) Investment at December 31, 2015 $ 8,

79 9) INVESTMENT IN DOKIE GP (Continued) The following tables summarize the financial information of Dokie GP as included in its own financial statements, adjusted for fair value adjustments at acquisition, and reconcile the financial information to the Company's carrying value in Dokie GP: December 31, 2015 December 31, 2014 Cash and cash equivalents $ 7,664 $ 3,508 Restricted cash (debt service reserve) 4,990 6,280 Trade and other receivables 3,656 4,294 Prepaid expenses Plant and equipment Intangible assets 128, , , ,253 Accounts payable and accrued liabilities 412 2,577 Long-term debt 108, , , ,504 Net assets (100%) $ 36,258 $ 38,749 Share of net assets (25.5%) 9,246 9,881 Purchase price adjustments (1,226) (1,612) Share of net assets (25.5%) $ 8,020 $ 8,269 Year ended December 31, 2015 Year ended December 31, 2014 Revenue $ 31,005 $ 29,927 Cost of sales (6,948) (8,173) Depreciation and amortization (6,928) (8,023) Interest expense (8,712) (10,414) Other expenses (1,494) (1,789) Net income (100%) $ 6,923 $ 1,528 Share of net income (25.5%) 1, Purchase price adjustments Share of net income and comprehensive income (25.5%) $ 1,826 $

80 9) INVESTMENT IN DOKIE GP (Continued) The Company s 25.5% share of long-term debt repayments as at December 31, 2015 is as follows: Principal Interest Total 2016 $ 885 $ 1,987 $ 2, ,925 2, ,356 1,860 3, ,392 1,764 3, ,616 1,662 3,278 Thereafter 22,271 9,546 31,817 Total $ 28,300 $ 18,744 $ 47,044 Note: The debt repayments in the table above do not include the affect of purchase price adjustments assumed upon acquisition. In 2009, Dokie GP entered into a 25 year PPA with BC Hydro to supply all the electricity generated by Dokie 1 to BC Hydro. Completion of construction and sale of electricity to BC Hydro commenced in February As this PPA is determined to fall within International Financial Reporting Interpretations Committee ("IFRIC") 12 Service Concession Arrangements, the costs associated with the construction of this project have been classified as an intangible asset. As at December 31, 2015, Dokie GP recorded an amount of $125.5 million (December 31, 2014: $157.2 million) in its books, of which the Company s proportionate interest is $32.0 million (December 31, 2014: $40.1 million). Dokie GP is subject to certain covenants regarding its loan agreements and as at December 31, 2015 was in compliance with all debt covenants. The Company achieved a C$0.8 million earn-out from Axium Infrastructure Inc. ("Axium") related to the partial sale of Dokie 1 in 2013 as a result of the generation target being met in Subsequent to year end, Dokie GP declared and paid a C$12.0 million distribution of which the Company's share was C$3.1 million. 10) INVESTMENT IN JIMMIE CREEK LP a) In 2014, the Company entered into a partnership agreement with Axium and following completion of project financing (see below), Axium owns 49% of the project and as a result the Company derecognized the assets and liabilities associated with the Jimmie Creek construction project and recorded a 51% interest in the Jimmie Creek LP at fair value. The Company completed a C$176.5 million non-recourse loan facility in The construction plus term non-recourse loan facility is priced at a fixed rate of 5.26% and will amortize over 40 years upon achievement of commercial operation, except for the final 10% of principal which will be paid at maturity. Prior to closing the financing, the construction of the project was solely funded by the Company, resulting in advances in excess of its required equity contribution. On October 17, 2014, the Company received a return of excess equity of $20.3 million. Jimmie Creek is being constructed under an engineering, procurement, construction and management ("EPCM") contract with an affiliate of SNC Lavalin Inc. During the year, intake and penstock construction was completed along with construction of the tailrace outlet structures and removal of the lower river diversion with work continuing on the powerhouse and installation of the generators. b) The Company's economic interest in the assets, liabilities, revenue and expenses, and cash flows of Jimmie Creek LP is accounted for under the equity method (as the partnership is a joint venture). The Company's initial investment in Jimmie Creek LP was recorded at a fair value of $42.1 million based on a discounted cash flow model and discount rate of 6.8%. A 0.5% change in the discount rate would have 28 74

81 10) INVESTMENT IN JIMMIE CREEK LP (Continued) resulted in an increase of $3.5 million or decrease of $3.0 million in the initial fair value of the Company's investment in Jimmie Creek LP. Amounts included in these consolidated financial statements are further described as follows: Investment in Jimmie Creek LP Initial investment at October 14, 2014 $ 42,131 Share of comprehensive income Foreign exchange (1,322) Investment at December 31, 2014 $ 40,809 Share of comprehensive loss (182) Foreign exchange (6,593) Investment at December 31, 2015 $ 34,034 The following table summarizes the financial information of Jimmie Creek LP as included in its own financial statements, adjusted for fair value adjustments, and reconcile the financial information to the Company's carrying value in Jimmie Creek LP: December 31, 2015 December 31, 2014 Cash reserved for construction activities $ 5,080 $ 2,960 Cash held in escrow restricted for construction 5,985 14,565 Other receivables Builders' lien holdback deposits 5,066 1,593 Equity contribution receivable from partner 18,033 21,513 Plant and equipment 127,535 67,831 Intangible assets , ,443 Accounts payable and accrued liabilities 10,019 9,812 Lien holdback liability 5,824 2,033 Long-term debt 110,455 53, ,298 65,539 Net assets (100%) $ 36,459 $ 43,904 Share of net assets (51%) 18,590 22,391 Fair value adjustments 15,444 18,418 Share of net assets (51%) $ 34,034 $ 40,809 Period of initial Year ended investment to December 31, 2015 December 31, 2014 Other expenses $ (532) $ Insurance proceeds 176 Net loss (100%) (356) Share of net loss and comprehensive loss (51%) $ (182) $ 29 75

82 10) INVESTMENT IN JIMMIE CREEK LP (Continued) Long-term debt at December 31, 2015 reflects the amounts drawn on the loan facility (net of transaction fees). Following conversion of the loan from a construction to a term loan, projected to occur in 2016, Jimmie Creek LP will commence making principal repayments in The Company s 51% share of long-term debt repayments is forecast as follows: Principal Interest Total 2016 $ $ 2,498 $ 2, ,134 3,417 4, ,357 3, ,343 3, ,325 3,700 Thereafter 62,899 89, ,502 Total $ 65,022 $ 105,543 $ 170,565 Note: This schedule is based on the Company's net interest of the full loan amount of C$176.5 million, at December 31, 2015 only $110.5 million had been drawn. 11) INVESTMENT IN SHANNON GROUP LLC a) On June 30, 2015, affiliates of the Company and Starwood Energy Group Global, LLC ( Starwood ) (collectively the "Sponsors") entered into a partnership agreement at Shannon Group LLC under which each party owns 50% of the sponsor equity of Shannon Wind Holdings, LLC ("Holdings"), the partnership entity which beneficially owns Shannon. Starwood contributed $62.7 million of cash and the Company contributed assets along with a cash payment of $6.9 million. Prior to entering into the partnership agreement, the Company owned 100% of Shannon Group LLC. Since the project is now under joint control, the Company classifies its ownership as an equity investment. Under the terms of the partnership agreement, the Company will continue to manage the project. On the same day, the Company and Starwood completed a $286.8 million credit facility for Shannon supplied by affiliates of Citibank N.A., Santander Bank, N.A. and the Royal Bank of Canada, consisting of a $212.2 million construction loan plus $74.6 million in various letters of credit. The interest rate on the loan is a spread above the London Interbank Offered Rate. Shannon was constructed in Clay County, Texas under a construction services agreement with M.A. Mortenson Company. The project achieved commercial operations on December 10, 2015 with a total capacity of 204 MW. Following the commissioning of all 119 turbines, Shannon completed tax equity funding with subsidiaries of Berkshire Hathaway Energy and Citicorp North America ("Tax Equity Investors") for $218.8 million. The proceeds were used to retire the full project construction loan and to allow a return of capital to the Company and Starwood of $7.0 million for unused contingency. Shannon will sell the majority of its output under a long-term power hedge agreement with Citigroup Energy Inc. beginning in June 2016 and until that time all power sold will be subject to merchant spot price. One of the primary incentives for renewable energy in the United States has been the production tax credits ("PTC") program, whereby companies that generate electricity from renewable energy sources, including wind, are eligible for tax credits which provide a tax benefit for each unit of generation for the first ten years of the facility s operation. Tax Equity Investors are allocated 99% of Shannon's taxable income (losses) and a minority portion of the cash generated until they achieve an agreed after-tax investment return (the "Flip Point"). After the Flip Point, the Tax Equity Investors 30 76

83 11) INVESTMENT IN SHANNON GROUP LLC (Continued) will be allocated 5% of cash distributions and taxable income (losses), and Shannon Group LLC will be allocated 95% of all cash distributions and taxable income (losses). b) The Company's economic interest in the assets, liabilities, revenue and expenses and cash flows of Shannon Group LLC are accounted for under the equity method (as the partnership is a joint venture). The Company's initial investment in Shannon Group LLC was recorded at fair value of $62.7 million based on the purchase price paid by Starwood for its 50% investment. The Company received a $1.5 million developer's fee upon financial close, which combined with the fair value of the investment resulted in a gain of $1.1 million, as follows: Net assets in Shannon Group LLC prior to deconsolidation: Development costs (note 21) $ 69,098 Other assets 10,360 Accounts payable (15,742) Lien holdback liability (1,742) Other liabilities (5,778) Net assets $ 56,196 Gain on deconsolidation of Shannon Group LLC: Fair value of investment $ 62,702 Developer's fee (note 31) 1,500 Carrying value of net assets (56,196) Cash payment (6,927) Gain on deconsolidation $ 1,079 The continuity of the Company's investment in Shannon Group LLC is as follows: Investment in Shannon Group LLC Initial investment at June 30, 2015 $ 62,702 Share of net income and comprehensive income 3,190 Return of capital (3,500) Investment at December 31, 2015 $ 62,392 Shannon Group LLC equity accounts for the investment in Holdings, the entity that owns and operates Shannon. The following tables summarize the financial information of Shannon Group LLC as included in its own financial statements, adjusted for fair value adjustments at acquisition, and reconcile the financial information to the Company's carrying value of Shannon Group LLC: 31 77

84 11) INVESTMENT IN SHANNON GROUP LLC (Continued) December 31, 2015 Investment in Holdings $ 124, ,813 Accounts payable and accrued liabilities Net assets (100%) 124,783 Share of net assets (50%) $ 62,392 Subsequent to tax equity funding on December 14, 2015, the results of Holdings are calculated in accordance with the hypothetical liquidation at book value ( HLBV ) method. The HLBV method allocates earnings or losses by measuring the distribution amounts that would be due to the members in a hypothetical liquidation of the entity at the net book value of the underlying assets. The HLBV method is consistent with accounting guidance which prescribes using this method for allocations where tax equity investors are present and is the method that most appropriately reflects how an increase or decrease in net assets of the venture will affect cash payments to the investor (both sponsors and tax equity investors) over the life of the venture and upon its liquidation. Period from initial investment to December 31, 2015 Revenue $ 96 General and administrative expenses (329) Loss on settlement of contingent liability (original developer's fee) (743) Gain on power hedge 18,693 Share of income from equity accounted investee 271 Loss on deconsolidation of equity accounted investee (1,956) Insurance deductibles (300) Net income (100%) 15,732 Share of net income (50%) $ 7,866 Period from initial investment to December 31, 2015 Other comprehensive loss (100%) $ (9,352) Share of other comprehensive loss (50%) (4,676) Share of net income (50%) 7,866 Share of comprehensive income (50%) $ 3,190 Shannon Group LLC's other comprehensive loss consists solely of changes in the value of the effectively hedged portion of Shannon's long-term power hedge. Shannon adopted hedge accounting on September 30, 2015 for the long-term power hedge agreement, and from inception of the power hedge on June 30, 2015 to the adoption of hedge accounting a gain of $18.7 million was recorded in the statement of operations

85 11) INVESTMENT IN SHANNON GROUP LLC (Continued) During the year there were three insurable events at Shannon: two floods due to heavy rainfall, and a grass fire. The damage is fully insured subject to deductibles. In accordance with IAS 16: Property, Plant and Equipment (IAS 16) the damaged equipment was written off at September 30, 2015, and the costs to replace the damaged equipment have been capitalized to plant and equipment in the current year. Costs associated with removal of the damaged equipment together with certain other repair-related costs and the deductibles for have been expensed. The property insurance proceeds are recorded as income and are included in the Company s share of results of equity from Shannon Group LLC. Tax equity investors in US wind projects generally require sponsor guaranties as a condition to their investment. To support the tax equity investment in Holdings, the Company executed a guaranty of the tax equity investment by the Tax Equity Investors indemnifying them against certain breaches of project level representations, warranties and covenants and other events. The Company believes the indemnification covers matters which are substantially under the Company s control, and are very unlikely to occur. 12) INVESTMENT IN BLUE LAGOON On January 1, 2015 HS Orka held a 33% interest in Blue Lagoon, which operates the Blue Lagoon geothermal spa in Iceland. During the second quarter of 2015 Blue Lagoon issued additional shares reducing HS Orka's interest from 33% to 30%, which resulted in a gain of $2.0 million to the Company. The gain is included in share of results of equity investments. The following tables summarize the financial information of Blue Lagoon as included in its own financial statements, adjusted for fair value adjustments at acquisition, and reconcile the financial information to the Company's carrying value in Blue Lagoon: December 31, 2015 December 31, 2014 Cash and cash equivalents $ 27,932 $ 14,757 Trade and other receivables 2,607 2,176 Prepaid expenses 2,347 2,381 Plant and equipment 45,201 40,407 Other assets 2,920 3,315 81,007 63,036 Accounts payable and accrued liabilities 5,713 3,672 Other liabilities 7,851 7,230 Long-term debt 25,876 30,232 39,440 41,134 Net assets (100%) $ 41,567 $ 21,902 Share of net assets (30% in 2015 and 33% in 2014) 12,483 7,228 Purchase price adjustments 12,001 13,606 Share of net assets $ 24,484 $ 20,

86 12) INVESTMENT IN BLUE LAGOON (Continued) Year ended December 31, 2015 Year ended December 31, 2014 Revenue $ 60,283 $ 52,916 Cost of sales (36,735) (30,356) Interest expense (829) (1,636) Depreciation (2,032) (1,805) Other income 1,193 (69) Income tax (4,436) (3,814) Net income (100%) $ 17,444 $ 15,236 Share of net income (a) 5,495 5,028 Purchase price adjustments (394) (286) Gain on dilution of HS Orka's investment 1,998 Share of net income (a) $ 7,099 $ 4,742 (a) HS Orka's share of net income represents the 33% in 2014 and for the first half of 2015 and 30% thereafter. In 2015, HS Orka received a dividend of $2.7 million ( $2.8 million) from Blue Lagoon. 13) INVESTMENT IN GEOTHERMAL DEVELOPMENT PROJECTS a) South America: The Company holds a 30% interest in joint ventures with Energy Development Corporation for the development of the Mariposa project in Chile, and certain geothermal development assets in Peru. The continuity of the Company s investment in South American geothermal properties is as follows: Mariposa Peru Total Investment at January 1, 2014 $ 24,478 $ 729 $ 25,207 Initial investment - Peru joint venture - January ,571 2,571 Share of comprehensive loss (55) (55) Write-off of 2013 Peru joint venture (682) (682) Foreign exchange (1,898) (223) (2,121) Investment at December 31, ,525 2,395 24,920 Share of comprehensive loss (326) (326) Foreign exchange (3,620) (388) (4,008) Investment at December 31, 2015 $ 18,579 $ 2,007 $ 20,586 b) Italy: The Company holds a 45% interest in a joint venture with an affiliate of Graziella Green Power. The joint venture is further developing the Mensano and Roccastrada geothermal concessions. The continuity of the Company's investment in Italian geothermal development projects is as follows: 34 80

87 13) INVESTMENT IN GEOTHERMAL DEVELOPMENT PROJECTS (Continued) Italy Projects Investment at January 1, 2014 $ 1,466 Share of comprehensive loss (321) Foreign exchange (150) Investment at December 31, Share of comprehensive loss (89) Foreign exchange (103) Investment at December 31, 2015 $ ) BONDS RECEIVABLE The bonds receivable of $2.1 million at December 31, 2015 (December 31, $2.6 million) are denominated in ISK (December 31, ISK 271 million; December 31, ISK 333 million) and have a stated interest rate of 5% plus indexation to the Icelandic Consumer Price Index. They are paid in annual installments and mature in No overdue amounts are outstanding as at December 31, 2015; however, there have been indications of an uncertain financial position of the bond holder and thus there is some uncertainty about the full recoverability of the bond. 15) LONG-TERM RECEIVABLE AND OTHER ASSETS December 31, 2015 December 31, 2014 Long-term receivable $ 3,875 $ 3,102 Other assets 1,643 11,438 Total $ 5,518 $ 14,540 The long-term receivable represents amounts due from HS Veitur hf ("HS Veitur") due to its share of a pension liability (note 25). HS Veitur has disputed the amount owing, but the Company believes the agreement in place to be valid. Other assets of $1.6 million consist primarily of deposits and potential earn-out payments associated with the partial sale of the Company's interest in Dokie GP in 2013 and with the sale of the Soda Lake geothermal facility in January 2015 (note 28). The Dokie GP earn-out related to 2015 generation was achieved during the year, and the C$0.8 million payment was received in early In 2014, other assets consisted primarily of a $10.1 million cash security deposit with Oncor Electirc Delivery Company, LLC, the transmission service provider for Shannon, which was refunded back to the Company in ) PREPAID LEASE AND ROYALTY FEE In 2011, HS Orka exercised the right to convert a long-term receivable with a municipality into a prepaid royalty fee and land lease. The prepaid royalty fee and land lease is classified as long-term and will be expensed over the life of the lease (60 years)

88 17) PLANT AND EQUIPMENT Cost Plant and Equipment Furniture and Equipment Assets Under Construction Balance, January 1, 2014 $ 334,470 $ 1,241 $ 33,343 $ 369,054 Additions 8, ,241 Disposals (184) (309) (493) Transfer 730 (730) Reclassification of assets held for sale (12,342) (627) (12,969) Effect of movement in exchange rates (32,240) (22) (3,241) (35,503) Balance, December 31, 2014 $ 299,117 $ 308 $ 29,905 $ 329,330 Additions 17, ,050 Disposals (281) (25) (306) Transfer 5,382 (5,382) Effect of movement in exchange rates (5,569) (23) (652) (6,244) Balance, December 31, 2015 $ 316,357 $ 282 $ 24,191 $ 340,830 Depreciation and impairment losses Balance, January 1, 2014 $ (36,109) $ (977) $ $ (37,086) Depreciation for the year (12,039) (62) (12,101) Disposals Reclassification of assets held for sale ,507 Effect of movement in exchange rates 4, ,496 Balance, December 31, 2014 $ (42,567) $ (250) $ $ (42,817) Depreciation for the year (10,404) (22) (10,426) Disposals Effect of movement in exchange rates Balance, December 31, 2015 $ (51,781) $ (232) $ $ (52,013) Carrying amounts: At December 31, 2014 $ 256,550 $ 58 $ 29,905 $ 286,513 At December 31, , , ,817 Total a) Capital commitments The Company commenced construction of a new discharge pipe system for the Svartsengi plant in 2013 and construction will be completed in Once the discharge system is operating, additional geothermal fluid can be extracted from the reservoir resulting in the potential for increased power generation. The Company has also commenced a drilling program for two new production wells at Svartsengi. One well was completed during the year and the second well was completed in early These wells will be connected to the plant in mid Work continued on connecting the reinjection well at Reykjanes and reinjection commenced in March The incremental capital commitment for these projects is approximately $3.9 million in b) Pledge of assets The Company s power plants at Reykjanes and Svartsengi are pledged as collateral for some of the HS Orka loans. The value of collateral required has decreased to $67.4 million (December 31, $83.8 million) due to repayments of these loans during the year (note 24(c))

89 17) PLANT AND EQUIPMENT (Continued) c) Impairment test The Company reviews the carrying values of its long-lived assets, including plant and equipment, on a regular basis as events or changes in circumstances may warrant. Due to the allocation of geothermal property rights and goodwill to the CGU associated with the HS Orka power plants and the Reykjanes expansion (classified as assets under construction) an annual impairment test is performed. See note 22 for key assumptions applied. As the recoverable amount was found to exceed the carrying value, no impairment was taken. d) Assets under construction Assets under construction represent capitalized costs that are related to a planned expansion at Reykjanes. 18) DEVELOPMENT COSTS Notes December 31, 2015 December 31, 2014 Geothermal 19 $ 55,093 $ 56,961 Hydro 20 2, Wind ,098 Total $ 58,229 $ 73,298 19) GEOTHERMAL DEVELOPMENT COSTS The continuity of the Company s geothermal property rights owned in Iceland at December 31, 2015 is as follows: Balance, January 1, 2015 Depletion Foreign exchange Balance, December 31, 2015 Geothermal property rights - operating $ 45,739 $ (753) $ (895) $ 44,091 Geothermal property rights - expansion 11,222 (220) 11,002 $ 56,961 $ (753) $ (1,115) $ 55,

90 19) GEOTHERMAL DEVELOPMENT COSTS (Continued) The continuity of the Company's geothermal development properties for the year ended December 31, 2014 is as follows: Effect of Balance Reporting Balance January 1, Development Currency December 31, 2014 Costs Depletion Translation Reclassification Write-off 2014 USA - Nevada McCoy $ 1,500 $ 34 $ $ $ (1,534) $ $ Desert Queen 1, (1,523) Granite Springs (797) Hawthorne (820) Peru Huaynaputina 155 (2) (153) Casiri 164 (2) (162) Ccollo 154 (3) (151) Ticsani 160 (1) (159) San Pedro 73 (2) (71) Pinchollo 67 (2) (65) Ancoccollo 55 (1) (54) Pasto 209 (4) (205) Atarani 170 (3) (167) Panejo 172 (3) (169) Suche 178 (2) (176) Canada Upper Lillooet 297 (11) (286) Iceland Geothermal property rights - operating 51,502 (834) (4,929) 45,739 Geothermal property rights - expansion 12,435 (1,213) 11,222 $ 70,338 $ 127 $ (834) $ (6,178) $ (6,206) $ (286) $ 56,961 a) Impairment The Company reviews the carrying values of geothermal development properties on an annual basis. The recoverable amounts of the geothermal development assets were determined using discounted cash flow calculations to estimate the value of development properties using cash flows forecast for periods up to 35 years. Key assumptions used in these cash flow forecasts included estimated energy prices which the Company s management determined with reference to expected prices in power purchase agreements, estimated cost to complete construction of the assets and expected operating costs, an after-tax discount rate of 8.1% and inflation rate of 2.0% (refer to note 22 for further information). During the year ended December 31, 2015, no write-downs were recorded (December 31, $0.3 million). Upon reclassification of the geothermal assets in the US to "held for sale" in 2014, the assets were written down to their fair value less costs to sell (note 28)

91 20) HYDRO DEVELOPMENT COSTS The continuity of the Company s hydro development expenditures is as follows: Jimmie Creek Other Hydro Development Total Hydro Development Balance, January 1, 2014 $ 16,960 $ 44 $ 17,004 Engineering and hydrology 43, ,392 Permitting Community consultations Acquisition of 40% of Jimmie Creek (a) 1,737 1,737 Foreign exchange impact (1,487) (13) (1,500) Expenditures reimbursed by partnership (20,336) (20,336) Contribution of Jimmie Creek project to Jimmie Creek LP (41,342) (41,342) Balance, December 31, 2014 $ $ 239 $ 239 Engineering and hydrology Permitting Community consultations Acquisition of Vesturverk 2,199 2,199 Foreign exchange impact (251) (251) Balance, December 31, 2015 $ $ 2,927 $ 2,927 (a) Included in the purchase price of the acquisition of the 49% ownership stake in Jimmie Creek from an affiliate of GE Energy Financial Services ("GE EFS") was C$1.0 million representing GE EFS's portion of the Company's historical cash spend on Dokie 2. a) Jimmie Creek In early 2014, the Company completed the acquisition of the 49% interest in Jimmie Creek LP held by GE EFS which brought its ownership interest to 100%. On October 14, 2014, the Company completed a C$176.5 million non-recourse loan facility and contributed the Jimmie Creek construction project to Jimmie Creek LP and as a result the Company derecognized the assets and liabilities associated with the Jimmie Creek construction project and recorded a 51% interest in Jimmie Creek LP at fair value. The Company accounts for its investment in Jimmie Creek LP as an equity investment (note 10). b) Other hydro projects During the year HS Orka completed a step-up acquisition resulting in 52.5% ownership of Vesturverk ehf. which owns 100% of the 55 MW Hvalá and 10 MW Skúfnavatnavirkjun projects and as a result HS Orka consolidates 100% of these projects. HS Orka also holds the interests in the 9 MW Brúarvirkjun hydro project in Iceland. The Company holds interests in the 15 MW Tahumming hydro project and South Toba projects (each project expected MW generation capacity) located near the Company's existing Toba Montrose and Jimmie Creek projects, and are situated along the Toba Montrose transmission line

92 21) WIND DEVELOPMENT COSTS The continuity of the Company s wind development expenditures is as follows: Shannon Dokie 2 Other Total Balance, January 1, 2014 $ $ 18,942 $ $ 18,942 Acquisition of Shannon 8,265 8,265 Engineering 7, ,213 Permitting Professional services Reclassification to Jimmie Creek (a) (967) (967) Write-off of wind development costs (16,811) (16,811) Foreign exchange impact (29) (1,219) (4) (1,252) Balance, December 31, 2014 $ 16,009 $ $ 89 $ 16,098 Engineering and construction 44, ,270 Professional fees 7,674 7,674 Permitting 1, ,336 Foreign exchange (45) (26) (71) Deconsolidation of Shannon (note 11) (69,098) (69,098) Balance, December 31, 2015 $ $ $ 209 $ 209 (a) Included in the purchase price of the acquisition of the 49% ownership stake in Jimmie Creek from GE EFS was C$1.0 million representing GE EFS's portion of the Company's historical cash spend on Dokie 2. a) Shannon On June 30, 2015, the Company entered into a partnership agreement with Starwood for the Shannon project (note 11) and as a result derecognized the assets and liabilities associated with the project and recorded the remaining 50% interest at fair value. The Company accounts for its investment in Shannon as an equity investment, although the Company continues to manage the project. b) Dokie 2 The Company and GE EFS hold the rights to a wind development project that is adjacent to Dokie 1 ("Dokie 2"), 51% and 49% respectively. As at December 31, 2014, the Company performed an impairment assessment of the project and wrote off the $16.8 million carrying value of the project. The Company may continue to collect data and maintain permits, and may further develop the project in the future when market outlook improves. c) Other Other wind projects consists of projects located on the coast of British Columbia and in the USA. During the year, the Company made payments for permit maintenance, land leases and engaged further development studies. d) Impairment test The Company reviews the carrying values of wind development projects on an annual basis. No impairment was noted in During the year ended December 31, 2014, the Company wrote down 40 86

93 21) WIND DEVELOPMENT COSTS (Continued) $16.8 million in development costs related to Dokie 2 which primarily consisted of non-cash purchase price adjustments. 22) GOODWILL The changes in the carrying value of goodwill are as follows: Balance, January 1, 2014 $ 15,020 Write-off goodwill allocated to development projects (2,018) Goodwill allocated to Jimmie Creek (note 10) (789) Foreign exchange impact (1,301) Balance, December 31, 2014 $ 10,912 Foreign exchange impact (214) Balance, December 31, 2015 $ 10,698 Goodwill arose from the acquisition of HS Orka on August 17, 2010 and Plutonic Power Corporation on May 13, Goodwill is allocated to CGUs at a level no greater than the operating segment level: geothermal, wind and hydro. The recoverable amount of goodwill is determined based on an assessment of the value in use of the applicable CGU. The value in use estimate is based on a discounted cash flow model. As part of this process, assumptions are made in relation to forecast energy output and prices, aluminum prices and foreign exchange rates. Forecast energy is based on geothermal, hydrology and wind data collected or actually generated by existing assets. Price forecasts for energy are determined using prices from current power purchase agreements and prices the Company expects to obtain under future power purchase arrangements. Aluminum prices are determined using forward LME prices through ten years and estimated thereafter. Foreign exchange is determined using forward price curves. Given the inherent uncertainty regarding longer term aluminum prices, energy prices and foreign exchange rates, management considers various possible scenarios and assigns probabilities to the likelihood of occurrence of each of these. The estimated cash flows are discounted using an after-tax rate of 8.1%. The net present value of the future expected cash flows is compared to the carrying value of the Company s investment in these assets, including goodwill, at year end, as a result of this there was no impairment of goodwill in In 2014, the goodwill allocated to Dokie 2 was impaired, resulting in a write-off of $2.0 million (note 21). Additionally, the goodwill allocated to the Jimmie Creek construction project was derecognized as a result of the Company contributing the project to Jimmie Creek LP. The Company now accounts for its investment in Jimmie Creek as an equity investment (note 10)

94 23) OTHER LIABILITIES HS Orka has been awarded three grants related to a deep drilling program, and plans to commence drilling a 4-5 km deep drill hole into a high-temperature hydrothermal system in order to reach temperatures in excess of 400 C. In 2015, $10.7 million was received related to these grants and is included in other liabilities. The Company's share of these grants is $5.0 million and the remaining $5.7 million is to be distributed to HS Orka's partners in the deep drilling project (note 6). In 2014, the other liabilities balance consisted of a contingent liability related to the acquisition of Shannon. When the Company entered into a partnership with Starwood in 2015, the assets and liabilities of Shannon were deconsolidated (note 11). 24) LONG-TERM DEBT The Company s consolidated long-term debt is as follows: December 31, 2015 December 31, 2014 Holding company bonds (Sweden) $ 117,977 $ 120,769 Holding company loan facility (North America) 62,377 74,129 HS Orka loans 75,185 95, , ,130 Less current portion: Holding company bonds (Sweden) 117,977 HS Orka loans 17,409 17, ,386 17,752 Long-term portion $ 120,153 $ 272,378 a) Holding company bonds (Sweden) The movement in bond values from January 1, 2014 to December 31, 2015 were as follows: Balance, January 1, 2014 $ 124,123 Change in fair value 2,601 Foreign exchange loss (5,955) Balance, December 31, ,769 Change in fair value (1,655) Foreign exchange loss (1,137) Balance, December 31, 2015 $ 117,977 The assumptions used in determining the fair values of the bonds at December 31, 2015 and 2014 are as follows: December 31, 2015 December 31, 2014 Discount rates 8.36% % 7.63% % Aluminum prices ($ per tonne) $1,511 - $1,750 $1,774 - $1,906 There has been no significant change in the fair value of the bonds due to credit risk changes. The bonds bear interest at 1.5% and 3.5% per annum, are payable on July 18, 2016 and December 14, 42 88

95 24) LONG-TERM DEBT (Continued) 2016 and the principal amounts determined are 50% linked to aluminum prices at the settlement date subject to a cap and floor. The cap is $3,250/tonne and the floor is $1,500/tonne for the ISK denominated bond and a $1,750/tonne floor for the USD denominated bonds. The Company currently plans to retire the holding company bonds (Sweden) through refinancings in 2016, for which the Company is currently in negotiations. The ISK denominated bond and the three US dollar bonds are non-recourse to the Company and are secured by a portion of the Company's HS Orka shares. Should the Company be unable or elect not to refinance the ISK denominated bond, the Company would own 53.9% of HS Orka and would continue to consolidate their results. If the Company lost the collateral supporting both bonds, the Company's share of HS Orka would be reduced to 21.8%, resulting in loss of control and the Company would no longer consolidate the HS Orka results. Management does not consider this to be a likely outcome. ISK denominated bond US dollar bonds Balance at December 31, 2015 $ 48,642 $ 69,335 Maturity July 16, 2016 December 14, 2016 Interest rate 1.5% 3.5% Number of shares of HS Orka pledged as security 996,821,339 2,515,640,459 % of outstanding HS Orka shares pledged as security 12.7% 32.1% b) Holding company loan facility (North America) In 2014, the Company closed a holding company loan facility with affiliates of AMP Capital Investors Limited. Proceeds from the loan facility were received in two tranches: tranche A totaling C$67.3 million was funded on August 15, 2014, tranche B totaling C$22.5 million was funded on December 19, The loan facility will mature on February 5, 2023, and has no scheduled payments of principal prior to maturity. The interest rate is CDOR plus 6.5% with interest payments made quarterly. The Company entered into two interest rate swaps resulting in all in interest rates of 8.7% - 8.8% (note 26). The loan facility is secured by the future cash flows from the Company's investments in Toba Montrose GP, Dokie GP and Jimmie Creek LP. The loan is recorded at amortized cost net of transaction fees (C$3.4 million). The change in the value of the loan facility is primarily due to foreign exchange

96 24) LONG-TERM DEBT (Continued) c) HS Orka loans The HS Orka loans were comprised of the following at December 31, 2015: Weighted Average Year of Currency Interest Rate Maturity Balance U.S. Dollar (USD) 2.1% $ 14,728 European Euro (EUR) 2.6% ,656 Swedish Krona (SEK) 2.3% ,200 Swiss Franc (CHF) 1.8% ,794 Japanese Yen (JPY) 1.3% ,236 British Pound (GBP) 0.9% ,931 Canadian Dollar (CAD) 1.2% ,993 Icelandic Krona (ISK) 4.6% ,647 $ 75,185 The annual repayments of the loans are as follows: 2016 $ 17, , , , ,350 Thereafter 9,444 $ 75,185 The obligations of HS Orka are non-recourse to the Company other than the Company s historic investment, which may not be recovered in the event of default. The Company s power plants at Reykjanes and Svartsengi are pledged as collateral under the HS Orka loans. The movement in the value of the HS Orka loans is due to repayments of $17.6 million in 2015 and foreign exchange. As at December 31, 2015, the Company was in compliance with all debt covenants. 25) PENSION FUND OBLIGATIONS The Company records a pension fund obligation from HS Orka's defined benefit plan. Certain employees of HS Orka perform services for a third party, HS Veitur, and the two companies share the funding of HS Orka s pension plans. HS Orka has recognized HS Veitur s share of the pension obligation and a corresponding long-term receivable from HS Veitur ($3.9 million at December 31, 2015; and $3.1 million at December 31, 2014). Actuarial gains and losses relating to HS Veitur's share of the pension liability are recognized in profit and loss as they are reimbursable by HS Veitur. According to actuarial assessments, the Company s accrued pension obligation amounted to $15.8 million at December 31, 2015 (December 31, 2014 $14.9 million), discounted at a rate of 2%, taking into account the share in the net assets of the pension fund

97 25) PENSION FUND OBLIGATIONS (Continued) The portion of the increase in the pension fund related to HS Veitur s share is $1.1 million during the year. Pension fund obligations January 1, 2014 $ 15,571 Contributions during the year (642) Current service cost 167 Interest expense 282 Actuarial changes - HS Orka share charged to OCI 454 Actuarial changes - HS Veitur share charged to statement of operations 578 Foreign exchange loss (1,554) Pension fund obligations December 31, 2014 $ 14,856 Contributions during the year (904) Current service cost 71 Interest expense 290 Actuarial changes - HS Orka share charged to OCI 567 Actuarial changes - HS Veitur share charged to statement of operations 1,131 Foreign exchange loss (232) Pension fund obligations December 31, 2015 $ 15,779 The pension obligations are as follows: The pension fund for State employees $ 7,969 The pension fund for Municipality of Hafnarfjörður employees 4,643 The pension fund for Municipality of Vestman Islands employees 3,167 Pension fund obligations December 31, 2015 $ 15,779 26) INTEREST RATE SWAPS The Company entered into two interest rate swaps related to the holding company loan facility (North America) on December 2, 2014 (Swap A) and December 12, 2014 (Swap B). The Company designated the interest rate swaps as accounting cash flow hedges of the interest rate exposure on the holding company loan facility (North America) for the periods of December 2, 2014 to February 5, 2023 and December 12, 2014 to February 5, 2023 respectively. The effective portion of changes in the fair value of the derivative is recognized in other comprehensive income and presented in equity. The amount recognized in accumulated other comprehensive income is removed and included in profit or loss in the same period as the hedged item affects profit or loss under the same line item in the statement of operations. The ineffective portion of changes in the fair value of the derivative is recognized immediately in profit or loss. The fair value of the interest rate swaps are calculated by an independent third party based on the market conditions at the time of reporting. The fair value of the interest rate swaps have been reflected in the financial statements as liabilities at December 31, 2015 as follows: 45 91

98 26) INTEREST RATE SWAPS (Continued) Swap A Swap B Total Interest rate swap $ 2,121 $ 1,018 $ 3,139 Less: current portion of interest rate swap Long-term portion of interest rate swap contracts $ 1,567 $ 725 $ 2,292 As at December 31, 2014: Swap A Swap B Total Interest rate swap $ 796 $ 153 $ 949 Less: current portion of interest rate swap Long-term portion of interest rate swap contracts $ 404 $ (32) $ 372 The Company is subject to enforceable master netting arrangements in the form of ISDA agreements with derivative counterparties. 27) BELOW MARKET CONTRACTS Following the acquisition of HS Orka (in 2010) and Soda Lake (in 2008), existing long-term power sales contracts in place at the time of acquisition of control were recognized at fair value by comparing the contracted prices with the prevailing market prices. The contracted prices were lower than the prevailing market prices. As a result, these contracts were considered to be unfavorable and a liability was recognized at fair value as part of the purchase price allocation for HS Orka and Soda Lake. The Company amortizes the fair value of unfavorable sales contracts over the remaining contract term and records the amount in revenue. A continuity of the Company s below market contracts is as follows: Balance, January 1, 2014 $ 23,024 Amortization to revenue (2,038) Reclassification as held for sale (a) (1,101) Foreign exchange loss (1,962) Balance, December 31, 2014 $ 17,923 Amortization to revenue (1,657) Foreign exchange (358) Balance, December 31, 2015 $ 15,908 (a) The Soda Lake below market contract value at December 31, 2014 was reclassified as held for sale. Refer to note 28. At December 31, 2015, HS Orka has two below market contracts remaining (expiring in 2019 and 2026)

99 28) SALE OF SODA LAKE FACILITY On January 30, 2015, the Company sold its 100% interest in the 15 MW Soda Lake geothermal facility as well as certain geothermal development assets (the "Soda Lake Facility") to an affiliate of Cyrq Energy Inc. for proceeds of $8.5 million plus additional compensation if certain performance related or earn-out provisions are met over periods of up to five years. As a result of the sale, the Company recorded the following gain on sale: Cash proceeds $ 8,500 Working capital adjustment 348 Value of earn-out provisions 1,418 Transaction costs (586) Net proceeds from sale $ 9,680 Carrying value of Soda Lake Facility net assets 9,635 Gain on sale $ 45 During 2015, the Company recorded a write-down of $0.4 million related to the Soda Lake earn-out payments in 2015 as a result of expiration of the PPA bonus. The Soda Lake facility assets and liabilities were classified as held for sale at December 31, The following table summarizes the carrying value, write-down and ending balance of the Soda Lake Facility assets and liabilities at December 31, 2014: Carrying value Write-down Ending balance Cash $ 68 $ $ 68 Accounts receivable Prepaid Plant and equipment (note 17) 11,462 (1,446) 10,016 Geothermal development costs (note 19) 4,674 (3,896) 778 Total assets held for sale 16,908 (5,342) 11,566 Accounts payable Below market contracts (note 27) 1,101 1,101 Deferred revenue Total liabilities held for sale 1,928 1,928 Net assets directly associated with assets held for sale $ 14,980 $ (5,342) $ 9,

100 29) SHARE CAPITAL a) Capital stock At December 31, 2015, the Company had unlimited authorized common shares without par value and 468,652,409 common shares issued and outstanding (December 31, ,263,361). During the year ended December 31, 2015, the Company recorded an issuance of 1,389,048 common shares with a value of $0.3 million ( ,917 shares with a fair value of $0.2 million). This includes the 1,323,620 shares that were awarded to Company employees in 2014 (with a fair value of $0.3 million), which were ratified by the Company's shareholders and approved by the TSX during the year. b) Stock options Under the Company s stock option plan, the Board of Directors may grant options for the purchase of up to a total of 10% of the total number of issued and outstanding common shares of the Company with a cap of 25,000,000. Options granted under the plan vest over time at the discretion of the Board of Directors. Options granted to date have an average vesting period of two years and a life of five years. Exercise prices on options granted under the plan are determined by reference to the market value on the date of the grant. The changes in stock options issued are as follows: Number of options Weighted average exercise price (C$/option) Outstanding, January 1, ,787,902 $ 0.77 Granted 4,560, Forfeited and expired (3,795,808) 1.00 Outstanding, December 31, ,553, Granted 4,322, Forfeited and expired (1,648,580) 1.28 Exercised (65,428) 0.30 Outstanding, December 31, ,161, Exercisable, December 31, ,972,485 $ 0.44 As at December 31, 2015, incentive stock options represented 3.2% (December 31, %) of issued and outstanding common capital. The aggregate intrinsic value of vested share options (the market value of the underlying share less the exercise value) at December 31, 2015 was $0.5 million (December 31, $nil). During the year, 4,322,610 options were granted at a weighted average fair value of C$0.22 per option. The share-based compensation for the years ended December 31, 2015 and 2014 has been recognized in the consolidated financial statements as follows: 48 94

101 29) SHARE CAPITAL (Continued) Balance sheets December 31, 2015 December 31, 2014 Hydro and wind development costs $ $ 23 Statements of operations Cost of sales 1 28 General and administrative General development expenses (5) Total share-based compensation $ 662 $ 597 The fair value of the stock options issued during the year was estimated at the grant date based on the Black-Scholes Option Pricing Model, using the following assumptions: December 31, 2015 December 31, 2014 Expected dividend yield (%) Nil Nil Average risk-free interest rate (%) 0.73% % 1.55% Expected life (years) Expected volatility (%) 50% 55% Expected rate of forfeiture (%) 5% 5% 95

102 30) NON-CONTROLLING INTEREST The following table summarizes the material non-controlling financial information for HS Orka before any intra-group eliminations: December 31, 2015 December 31, 2014 Non-current assets $ 391,147 $ 378,232 Current assets 42,343 46,724 Non-current liabilities (170,429) (163,949) Current liabilities (46,025) (34,582) Net assets 217, ,425 Non-controlling interest % 33.4% 33.4% Proportionate share of HS Orka net assets $ 72,490 $ 75,626 Proportionate share of Vesturverk net assets 836 Total non-controlling interest $ 73,326 $ 75,626 Revenue $ 57,386 $ 65,902 Income (loss) (1,763) 4,688 OCI (loss) (5,232) (21,025) Total comprehensive income (loss) (6,995) (16,337) Income (loss) allocated to non-controlling interest (589) 1,566 OCI (loss) allocated to non-controlling interest $ (1,747) $ (7,022) Cash flow generated by operating activities $ 24,397 $ 21,222 Cash flow used in investment activities (22,408) (6,821) Cash flow used in financing activities (20,048) (20,948) Effect of foreign exchange on cash (550) (2,245) Net decrease in cash and cash equivalents $ (18,609) $ (8,792) 31) RELATED PARTY TRANSACTIONS a) Revolving credit agreement The Company holds a revolving credit facility with the Company's Chairman. At December 31, 2015, the borrowing amount available under the facility was C$20.0 million with a maturity date of March 31, Subsequent to year end, the maturity date was extended to March 31, The credit facility makes funds available on a revolving basis at an interest rate of 8% per annum, compounded and payable monthly. In addition, a standby fee in the amount of 0.75% of the credit facility, and a drawdown fee in the amount of 1.5% of amounts advanced, are payable in cash. At December 31, 2015, there were no amounts outstanding under the credit agreement (December 31, 2014: $nil). During the year the Company borrowed and repaid C$2.7 million and paid interest, standby and drawdown fees of C$0.2 million (C$1.8 million for the year ended December 31, 2014). 96

103 31) RELATED PARTY TRANSACTIONS (Continued) b) Developer fee On June 30, 2015, the Company received a $1.5 million developer's fee (note 11) and a $0.8 million construction management fee from Shannon Wind, LLC (a subsidiary of Holdings). c) Compensation of directors and other key management personnel The remuneration of the Company s directors and other key management personnel during the years ended December 31, 2015 and 2014 was as follows: December 31, 2015 December 31, 2014 Short-term employee benefits (a) $ 1,501 $ 1,882 Termination benefits 226 Share-based compensation Total $ 1,844 $ 2,470 (a) Short-term employee benefits include salaries, bonuses payable within twelve months of the balance sheet date and other annual employee benefits. 32) FINANCIAL INSTRUMENTS Fair Value The carrying value of the Company's cash and cash equivalents, restricted cash, trade and other receivables, accounts payable and accrued liabilities, and other liabilities approximate fair value due to the relative short-term maturity of these financial instruments. The carrying value of the bonds receivable and holding company loan facility (North America), disregarding the effect of financing fees, approximates fair value as a result of the variable interest rates being charged and no significant change in credit risk (both are classified as Level 2 in the fair value hierarchy discussed below), and the carrying value of the HS Orka corporate loans approximates the fair value. Fair value is determined by discounting future interest and principal payments at the market rate of interest. Fair value hierarchy Financial instruments measured at fair value are categorized within a three-tier fair value hierarchy, which prioritizes the inputs in measuring fair value of financial instruments. (1) Level 1: quoted prices (unadjusted) in active markets or identical assets or liabilities; (2) Level 2: valuation techniques using inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices); and (3) Level 3: valuation techniques using inputs for the asset or liability that are not based on observable market data (unobservable inputs)

104 32) FINANCIAL INSTRUMENTS (Continued) The Company's financial instruments carried at fair value are assessed as follows: As at December 31, 2015 Level 1 Level 2 Level 3 Total Assets: Short-term investments $ 7,670 $ $ $ 7,670 Bonds receivable 2,087 2,087 Long-term receivable and other assets 1,282 1,282 $ 7,670 $ 2,087 $ 1,282 $ 11,039 Liabilities: Embedded derivatives $ $ 3,192 $ 62,518 $ 65,710 Interest rate swaps 3,139 3,139 Holding company bonds (Sweden) 117, ,977 $ $ 124,308 $ 62,518 $ 186,826 As at December 31, 2014 Level 1 Level 2 Level 3 Total Assets: Short-term investments $ 4,037 $ 284 $ $ 4,321 Bonds receivable 2,609 2,609 Long-term receivable and other assets $ 4,037 $ 2,893 $ 593 $ 7,523 Liabilities: Embedded derivatives $ $ 2,391 $ 41,673 $ 44,064 Currency and interest rate swaps Interest rate swaps 5,778 5,778 Holding company bonds (Sweden) 120, ,769 $ $ 124,109 $ 47,451 $ 171,560 The amounts included in Level 2 are for the interest rate swaps, and bonds receivable and embedded derivatives held at HS Orka, and the holding company bonds held by Magma Energy Sweden A.B. The fair value of the bonds receivable is determined using an income approach by discounting future interest and principal repayments using an interest rate of 5% plus indexation to the Icelandic Consumer Price Index. The fair value of the interest rate swaps is measured using observable future market interest rates (0.73% to 2.51%). The fair value of the embedded derivatives and holding company bonds payable (Sweden) is determined using observable market interest rates (0.86% to 5.84%) and the London Metals Exchange forward market price of aluminum. Embedded derivatives relating to a contract expiring in 2019 are included in Level 2. The assets recorded as Level 3 in the fair value hierarchy, long-term receivables and other assets, represent $0.3 million of potential earn-out payment related to the partial sale of the Company's interest 52 98

105 32) FINANCIAL INSTRUMENTS (Continued) in Dokie GP and $1.0 million of potential earn-out payments related to the sale of Soda Lake. The Dokie GP earn-out payment is based on achieving the generation target in The fair value is based on a 50% probability of the generation target, discounted at a rate of 6%. The Company reached the generation target in 2015 and received the related payment in early The Soda Lake earn-out payments are based on probabilities of achieving generation, pricing and development targets over the next one to four years discounted at a rate of 8%. The Company recorded a write-down of $0.4 million related to the Soda Lake earn-out payments in 2015 as a result of the PPA bonus criteria not being met. The liability amount included in Level 3 is for embedded derivatives held at HS Orka that relate to a contract that expires in The embedded derivatives are classified as Level 3 as the observable forward market for aluminum only extends to ten years. Level 3 embedded derivatives are sensitive to changes in forward aluminum prices and such changes in forward aluminum prices may result in a significantly higher or lower fair value measurement. At December 31, 2015 projected forward aluminum prices for the period January 1, 2026 to May 28, 2026 are estimated to be within a range of $2,041 to $2,058 per tonne compared to a range of $2,329 to $2,399 at December 31, A reconciliation of the Level 3 embedded derivative liability amount is as follows: Liabilities: January 1, Foreign exchange December 31, 2015 and unrealized loss Settlement 2015 Embedded derivatives $ (41,673) $ (25,092) $ 4,247 $ (62,518) January 1, Foreign exchange December 31, 2014 and unrealized loss Settlement 2014 Liabilities: Embedded derivatives $ (30,388) $ (15,428) $ 4,143 $ (41,673) Changes in one or more of the Level 3 inputs to reasonably possible alternative assumptions would change the fair value measurement significantly. Changes to the fair value of the embedded derivatives would be recognized in the statement of operations. Gains and losses on the bonds receivable, embedded derivatives and holding company bonds were recognized in the statement of operations. There have been no transfers between levels during the year. Financial Risk Management The types of financial risk exposure and the way in which such exposure is managed by the Company are as follows: Credit risk The Company s exposure to credit risk is influenced mainly by the individual characteristics of each customer. Over 41% ( %) of the Company s revenue is attributable to sales transactions with two customers. The Company has set a credit policy where all new customers are evaluated with respect to payment history and other factors and credit limits are set. Customers that are behind in payments are prohibited to make further transactions with the Company until they settle their debt or the Company's 53 99

106 32) FINANCIAL INSTRUMENTS (Continued) collection department approves further transactions based on an agreement. The Company establishes an allowance for impairment that represents its estimate of incurred losses in respect of trade and other receivables. The Company s exposure to credit risk and management of this risk has not changed from the previous year with the exception of the bond receivable and long-term receivable at HS Orka. There have been indications of an uncertain financial position of the bond holder (the municipality of Reykjanesbær) and thus there is some uncertainty about the recoverability of the bond. Separately HS Veitur has disputed the amount of the long-term receivable although the Company believes the agreement in place to still be valid. The Company s maximum exposure to credit risk is the carrying amount of financial assets as presented below: December 31, December 31, Cash and cash equivalents $ 10,345 $ 63,216 Restricted cash 10,766 9,672 Short-term investments 6,974 3,141 Trade and other receivables 12,354 11,414 Long-term receivables and other assets 4,236 14,540 Bonds receivable 2,087 2,609 Total $ 46,762 $ 104,592 The exposure to credit risk for trade and other receivables at the reporting date by significant customer was: December 31, 2015 December 31, 2014 NV Energy $ $ 427 Iceland industrial and power companies 3,336 4,313 Iceland residential customers 6,512 4,977 Receivables from Toba Montrose GP, Dokie GP, Jimmie Creek LP and Shannon Wind, LLC Other receivables 1, Total $ 12,354 $ 11,414 At December 31, 2015, $0.9 million ( $0.7 million) of trade and other receivables were more than 90 days overdue and a total write-off of impaired receivables of $0.1 million was recorded during the year. There are no amounts are outstanding as at December 31, 2015 on the bond receivable at HS Orka, however, there have been indications of an uncertain financial position of the bond holder and thus there is some uncertainty about the recoverability of the bond. Liquidity risk Liquidity risk is the risk that the Company will be unable to meet its financial obligations as they become due. The Company manages liquidity risk by ensuring that it has sufficient cash, credit facilities and other

107 32) FINANCIAL INSTRUMENTS (Continued) financial resources available to meet its obligations. The Company forecasts cash flows for a period of at least 12 months to identify financial requirements. These requirements are met through a combination of cash flows from operations, credit facilities and accessing capital markets. At December 31, 2015, the Company s current liabilities consisted of trade and other payables, current portions of debt and other financial instruments, and grants received at HS Orka during the year. Current liabilities have increased $122.0 million from December 31, 2014 primarily due to the classification of the holding company bonds (Sweden) of $118.0 million as current. These bonds are non-recourse to the Company and the Company intends to retire these bonds through refinancings in 2016, which are currently in negotiation. The Company has successfully executed several financings over the past two years, however there are no guarantees that the bonds will be successfully refinanced. As disclosed in note 24, the holding company bonds are secured by 44.8% of HS Orka shares. The Company believes that HS Orka, Toba Montrose GP, Dokie GP and Jimmie Creek LP have the ability to sustain themselves and pay their long-term interest and debt obligations as they become due. This debt is non recourse to the Company. The Company has plans to refinance the bond liabilities of Magma Energy Sweden A.B., assumed in conjunction with the acquisition of HS Orka that expire in Should the Company be unable or elect not to refinance the ISK denominated bond, and returns the shares held as collateral, the Company would own 53.9% of HS Orka and would continue to consolidate their results. If the Company in unsuccessful in refinancing both bonds, and returns all shares held as collateral, the Company's share of HS Orka will be reduced to 21.8%, resulting in loss of control and the Company would no longer consolidate the HS Orka results. Management does not consider this to be a likely outcome. The Company believes the cash flows from its investments in Toba Montrose GP, Dokie GP, and future Jimmie Creek LP cash flows will be sufficient to pay its interest on the holding company loan facility (North America) over the term of the loan. The following are the contractual maturities of the Company s financial liabilities, including estimated interest payments: December 31, 2015 Carrying amount Contractual cash flows Less than one year (a) 1-2 years 2-5 years After 5 years Accounts payable and accrued liabilities $ 13,660 $ 13,660 $ 13,660 $ $ $ Other liabilities 10,689 10,689 10,689 Long-term debt 255, , ,604 20,790 50,593 88,768 Embedded derivatives 65,710 65,710 8,362 8,170 21,269 27,909 Interest rate swaps 3,139 3, , Total $ 348,737 $ 396,052 $ 176,166 $ 29,750 $ 73,365 $ 116,771 (a) Long-term debt due in "less than one year" includes the maturities of the holding company bonds (Sweden), which the Company is currently in the process of refinancing. Market risk The significant market risk exposures to which the Company is exposed are interest rate risk, currency risk and commodity price risk

108 32) FINANCIAL INSTRUMENTS (Continued) a) Interest rate risk Interest rate risk is the risk that the future cash flows and fair values of the Company s assets and debts will fluctuate because of changes in market interest rates. Financial instruments with fixed interest rate risk The following fixed interest rate instruments are measured at fair value and as a result are subject to interest rate risk: December 31, December 31, Bonds receivable $ 2,087 $ 2,609 Holding company bonds (Sweden) (117,977) (120,769) Total $ (115,890) $ (118,160) Fair value sensitivity analysis for fixed rate instruments A change of 100 basis points ( BPS ) in interest rates at the reporting date would have increased (decreased) income or loss and equity by the amounts shown below. This analysis assumes that all other variables, in particular foreign currency rates and aluminum prices, remain constant. Net income/equity increase (decrease) 100 BPS 100 BPS December 31, 2015 increase decrease Bonds receivable $ (29) $ 31 Holding company bonds (Sweden) 863 (877) Total $ 834 $ (846) Financial instruments with floating interest rate risk The following non-derivative financial instruments are subject to interest rate risk on cash flow: December 31, December 31, Cash and cash equivalents $ 10,345 $ 63,216 Restricted cash 10,766 9,672 Holding company loan facility (North America) (62,377) (74,129) HS Orka variable rate loans (63,538) (81,003) Cash flow sensitivity analysis for floating interest rate instruments A change of 100 BPS in interest rates at the reporting date would have increased (decreased) income or loss and equity by the amounts shown below. This analysis assumes that all other variables, in particular foreign currency rates, remain constant

109 32) FINANCIAL INSTRUMENTS (Continued) Net income/equity increase (decrease) 100 BPS 100 BPS December 31, 2015 increase decrease Cash and cash equivalents $ 103 $ (103) Restricted cash 108 (108) Holding company loan facility (648) 589 HS Orka variable rate loans (635) 635 Total $ (1,072) $ 1,013 Derivative financial instruments The following derivative financial instruments are subject to interest rate risk: December 31 December Embedded derivative liabilities $ (65,710) $ (44,064) Interest rate swaps (3,139) (949) Total $ (68,849) $ (45,013) Sensitivity analysis for derivative instruments A change of 100 BPS in interest rate at the reporting date would have increased (decreased) income or loss and equity by the amounts shown below. This analysis assumes that all other variables, in particular foreign currency rates and aluminum prices, remain constant. Comprehensive income/equity increase (decrease) 100 BPS 100 BPS December 31, 2015 increase decrease Embedded derivative liabilities $ 1,233 $ (1,326) Interest rate swaps 3,817 (3,600) Total $ 5,050 $ (4,926) b) Currency risk The functional currency of the Company and each of its subsidiaries, except the U.S. subsidiaries and HS Orka, is the Canadian dollar, the functional currency of the U.S. subsidiaries is the U.S. dollar; and the functional currency of HS Orka is the Icelandic Krona. The carrying amounts of monetary assets and liabilities denominated in currencies other than the functional currencies are subject to fluctuations in the underlying foreign currency exchange rates. Gains and losses on such items are included as a component of net loss for the year. The Company and its subsidiaries undertake transactions in the following currencies: U.S. dollar, Canadian dollar, Icelandic Krona, Swedish Krona, Swiss Franc, Euro, British Pound and Japanese Yen. The

110 32) FINANCIAL INSTRUMENTS (Continued) Company does not currently economically hedge against foreign exchange rate risk, but may economically hedge single, large transactions with forward foreign exchange agreements for shorter periods. HS Orka does not hedge its currency risk on its long-term debt denominated in foreign currencies. The reporting currency selected for the presentation of these consolidated financial statements is the U.S. dollar. For presentation purposes, all assets and liabilities are translated from the functional currency into U.S. dollars at the exchange rate in effect at the balance sheet date. As a result, reported amounts of all assets and liabilities will fluctuate with changes in the underlying functional currency to the U.S. dollar exchange rate. Gains and losses arising from translation of the consolidated financial statements into U.S. dollars are recognized in other comprehensive income (loss). The Company s exposure to foreign currency risk on its financial assets and liabilities, based on notional amounts, was as follows: December 31, 2015 ISK CHF EUR CAD JPY SEK USD Other currencies Total Cash and cash equivalents $ 4,491 $ 1 $ 32 $ 1,255 $ $ $ 4,562 $ 4 $ 10,345 Restricted cash 568 5,698 4,500 10,766 Short-term investments 6, ,670 Trade and other receivables 7, ,841 2, ,354 Long-term receivable and other assets 3, ,026 5,518 Bonds receivable 2,087 2,087 Other investments Accounts payable and accrued liabilities (10,324) (2,952) (25) (346) (13) (13,660) Other liabilities (10,689) (10,689) Embedded derivatives (65,710) (65,710) Long-term debt (60,289) (20,794) (11,656) (67,370) (6,236) (3,200) (84,063) (1,931) (255,539) Interest rate swaps (3,139) (3,139) Net foreign exchange rate risk $ (44,646) $ (20,793) $ (16,509) $ (69,052) $ (6,236) $ (3,225) $(137,389) $ (1,939) $ (299,789) A 10% strengthening or weakening of the functional currency of the entity and its subsidiary against the following currencies at December 31, 2015 would have increased (decreased) income or loss after tax by the amounts shown below. This analysis assumes that all other variables, in particular, interest rates, remain constant

111 32) FINANCIAL INSTRUMENTS (Continued) Net income increase (decrease) Strengthening 10% 10% Weakening ISK $ 4,943 $ (4,943) CHF 1,779 (1,779) EUR 969 (969) CAD 436 (436) USD 10,174 (10,174) JPY 543 (543) Other currencies 428 (428) Total $ 19,272 $ (19,272) c) Commodity price risk HS Orka has entered into two PPAs for the sale of electrical power whereby the sales price of such power is based on the market price of aluminum. Therefore, the revenues and profitability of HS Orka's operations are significantly exposed to fluctuations in the price of aluminum. The holding company bonds (Sweden) that were issued as partial consideration for the purchase of HS Orka are also partially subject to adjustments based on the price of aluminum. Therefore, the principal amounts owed on the due date, and the annual interest payments thereon, subject to caps and floors, may fluctuate with the price of aluminum. A 10% increase or decrease in the price of aluminum at December 31, 2015 would have respectively decreased or increased net income by $22.6 million and $19.1 million. Toba Montrose GP and Dokie GP are not subject to significant commodity price risk as power is primarily sold at a rate specified by a PPA with BC Hydro. Shannon Group LLC will sell the majority of its output under a long-term power hedge agreement with Citigroup Energy Inc. beginning in June 2016 and until that time all power sales will be subject to merchant prices. 33) CAPITAL DISCLOSURES It is the Company s objective to manage capital in a manner that will safeguard its ability to continue as a going concern in order that it may continue to develop its projects and continue its operations for the benefit of its shareholders. The Company's objectives when managing capital are to: a) minimize dilution to existing equity shareholders of the Company with the continued expansion and development of its projects until the Company can generate sufficient cash flow to finance all of its growth internally; and b) maintain a capital structure which optimizes the cost of capital at acceptable risk levels. The Company manages its common shares and long-term debt as capital. There are no externally imposed requirements. The Company intends to fund its planned expansion and development activities from working capital, project and holding company level financing and distributions from existing operations

112 34) COMMITMENTS The Company has entered into various operating lease and contractual commitments (in addition to the commitments discussed in note 17) that require minimum payments in the aggregate as follows: 2016 $ Thereafter Total commitments $ 1,100 35) INCOME TAXES The significant components of income tax recovery (expense) recognized in the statement of operations are as follows: Deferred income tax recovery (expense): Year ended December 31, 2015 Year ended December 31, 2014 Current year $ 3,755 $ (2,582) Adjustment for prior years (8) (1,981) Income tax recovery (expense) $ 3,747 $ (4,563) Income tax recovery (expense) differs from the amount that would result from applying the Canadian federal and provincial tax rate to loss before income taxes. These differences result from the following items:

113 35) INCOME TAXES (Continued) Year ended December 31, 2015 Year ended December 31, 2014 Canadian statutory federal and provincial income tax rates 26.00% 26.00% Loss before income tax $ (21,053) $ (30,211) Income tax benefit computed at Canadian statutory rates 5,474 7,855 Permanent items and other 1,456 14,237 Change in deferred income tax assets not recognized (409) (23,497) Change in estimates in respect of prior year (8) (1,981) Foreign tax rates different from statutory rate (2,467) (348) Utilized deferred tax assets or expired loss (144) (438) Other (155) (391) Income tax recovery (expense) $ 3,747 $ (4,563) The applicable federal and provincial tax rate in Canada for the year ended December 31, 2015 was 26%, which reflects the current legislated tax rates. The significant components of the Company's deferred income tax assets and liabilities as at December 31, 2015 and 2014 are as follows: Net deferred income tax assets Year ended December 31, 2015 Year ended December 31, 2014 Non-capital losses $ 3,888 $ Other items (990) Net deferred income tax liabilities 2,898 Non-capital losses 16,370 19,663 Embedded derivatives 13,142 8,813 Investment in partnerships and associates (24,280) (25,200) Plant and equipment and energy properties (25,798) (25,712) Other 7,226 6,756 (13,340) (15,680) Net deferred tax liability $ (10,442) $ (15,680)

114 35) INCOME TAXES (Continued) A summary of the movement of deferred tax assets (liabilities) recognized in profit and loss is as follows: Opening balance Recognized in net income Recognized in equity Foreign exchange translation Closing balance Non-capital losses $ 19,663 $ 2,465 $ $ (1,870) $ 20,258 Embedded derivatives 8,813 5,167 (838) 13,142 Investment in partnerships and associates (25,200) (1,476) 2,397 (24,279) Plant and equipment and energy properties (25,712) (2,532) 2,445 (25,799) Other items 6, (643) 6,236 Deferred tax asset (liability) $ (15,680) $ 3,747 $ $ 1,491 $ (10,442) Of the total deferred income tax assets recognized as at December 31, 2015, $1.3 million is expected to be recovered within the next 12 months (December 31, $nil) and $40.1 million is expected to be recovered after more than 12 months (December 31, $38.9 million). Of the total deferred income tax liabilities recognized as at December 31, 2015, all of the $51.8 million (December 31, $54.6 million) is expected to be discharged after more than 12 months. Deferred tax assets are recognized to the extent that the realization of the related tax benefit through future taxable profits is probable. The ability to realize the tax benefits is dependent upon numerous factors, including the future profitability of operations in the jurisdictions in which the tax benefits arose. The Company did not recognize deferred tax assets for the following deductible temporary differences: December 31, 2015 December 31, 2014 Capital losses $ 52,024 $ 31,055 Non-capital losses 189, ,862 Other deductible temporary differences 40,771 62,706 $ 282,124 $ 263,623 As at December 31, 2015, the Company had non-capital losses for income tax purposes of approximately $263.6 million (December 31, $247.8 million), expiring in various years to 2035 and available to offset future taxable income in Canada, as well as losses and certain expenditures available to offset future taxable income in the USA, Chile, Sweden, Iceland, Italy, and Peru. The tax losses expire as follows:

115 35) INCOME TAXES (Continued) Canada US Chile Sweden Iceland Italy Peru Total 2016 $ $ $ $ $ $ $ 143 $ , , , , ,159 5, ,316 3, ,096 5, ,948 6, ,898 1, ,509 12, ,953 2,343 18, ,210 7,208 29, ,794 4,595 20, ,054 4,511 11, ,643 7,063 10, ,977 2,261 37, ,351 12, ,126 26,767 35,893 Without expiry 4,173 42, ,135 Total $142,463 $ 54,748 $ 4,173 $ 42,119 $ 18,131 $ 843 $ 1,096 $263,573 The Company also has capital losses of $52.0 million ( $31.1 million), which do not expire. 36) SEGMENTED DISCLOSURES The Company has four operating segments: a) The development of hydro, wind, solar and geothermal properties; b) Geothermal operations; c) Hydro operations; and d) Wind operations. Consolidated revenues during the years ended December 31, 2015 and 2014 were generated from HS Orka (including the Svartsengi and Reykjanes plants) in Iceland and the Soda Lake plant in the USA (until it was sold on January 30, 2015). Revenues and results from hydro operations (Toba Montrose GP), wind operations (Dokie GP and Shannon Group LLC), Blue Lagoon, Jimmie Creek LP and the geothermal investment properties are included in share of results of equity investments

116 36) SEGMENTED DISCLOSURES (Continued) Construction and development December 31, 2015 Assets Geothermal Hydro Wind Total CANADA Current assets $ 5,516 $ $ $ $ 5,516 Plant and equipment Equity investments 34,034 21,961 8,020 64,015 Hydro development costs Wind development costs Other assets 4,099 4,099 44,368 21,961 8,020 74,349 USA Current assets Equity investments 62,392 62,392 Wind development costs Other assets 1,026 1,026 1,086 1,026 62,392 64,504 CHILE Current assets 1 1 Equity investments 18,579 18,579 18,580 18,580 ITALY Equity investments PERU Equity investments 2,007 2,007 ICELAND Current assets ,444 39,164 Plant and equipment 288, ,795 Geothermal development costs 55,093 55,093 Equity investments 26,661 26,661 Hydro development costs 2,347 2,347 Other assets 20,711 20,711 58, , ,771 Total Assets $ 125,004 $ 375,637 $ 21,961 $ 70,412 $ 593,

117 36) SEGMENTED DISCLOSURES (Continued) Construction and development December 31, 2014 Assets Geothermal Hydro Wind Total CANADA Current assets $ 45,731 $ $ $ $ 45,731 Plant and equipment Equity investments 40,809 26,977 8,269 76,055 Hydro development costs Wind development costs Other assets 2,003 2,003 89,344 26,977 8, ,590 USA Current assets Plant and equipment Wind development costs 15,439 15,439 Other assets 10,412 10,412 Assets held for sale 11,566 11,566 26,420 11,566 37,986 CHILE Current assets 5 5 Equity investments 22,525 22,525 Other assets ,532 22,532 ITALY Equity investments PERU Equity investments 2,395 2,395 ICELAND Current assets 94 46,724 46,818 Plant and equipment 286, ,468 Geothermal development costs 56,961 56,961 Equity investments 23,421 23,421 Other assets 21,046 21,046 57, , ,714 Total Assets $ 198,741 $ 389,225 $ 26,977 $ 8,269 $ 623,

118 36) SEGMENTED DISCLOSURES (Continued) Year ended December 31, 2015 Construction Operating results and development Geothermal Hydro Wind Total Revenues $ $ 57,835 $ $ $ 57,835 Cost of sales (41,704) (41,704) Gross profit 16,131 16,131 Other income (expenses) General and administrative (5,426) (4,469) (9,895) General development expenses (1,417) (1,417) Share of results of equity investments (597) 7,099 5,931 9,692 22,125 Finance income 167 1,641 1,808 Finance costs (6,331) (6,312) (12,643) Change in the fair value of bonds payable 1,655 1,655 Change in the fair value of derivatives (22,285) (22,285) Foreign exchange gain (loss) (20,141) 1,682 (18,459) Other income 1,927 1,927 (31,818) (20,989) 5,931 9,692 (37,184) Income (loss) before income tax (31,818) (4,858) 5,931 9,692 (21,053) Income tax recovery 44 3,703 3,747 Income (loss) for the year $ (31,774) $ (1,155) $ 5,931 $ 9,692 $ (17,306)

119 36) SEGMENTED DISCLOSURES (Continued) Year ended December 31, 2014 Construction Operating results and development Geothermal Hydro Wind Total Revenues $ $ 70,952 $ $ $ 70,952 Cost of sales (53,860) $ (53,860) Gross profit 17,092 17,092 Other income (expenses) General and administrative (6,504) (3,861) (10,365) General development expenses (315) (315) Share of results of equity investments (376) 4,742 7, ,200 Finance income 196 2,542 2,738 Finance costs (1,286) (7,316) (8,602) Change in the fair value of bonds payable (2,601) (2,601) Change in the fair value of derivatives (11,846) (11,846) Foreign exchange gain (loss) (4,748) 182 (4,566) Write-down of development costs and plant and equipment (20,993) (1,446) (22,439) Write-off of goodwill (2,018) (2,018) Other income (35,533) (19,604) 7, (47,303) Income (loss) before income tax (35,533) (2,512) 7, (30,211) Income tax expense (4,563) (4,563) Income (loss) for the year $ (35,533) $ (7,075) $ 7,298 $ 536 $ (34,774) 37) COST OF SALES The following is a breakdown of the Company s cost of sales by nature of expense: Year ended December 31, 2015 Year ended December 31, 2014 Employee benefit expense $ 3,884 $ 11,243 Depreciation, amortization and accretion 11,039 13,092 Cost of production 26,781 29,525 $ 41,704 $ 53,

120 38) GENERAL AND ADMINISTRATIVE The following is a breakdown of the Company s general and administrative expenses by nature of expense: Year ended December 31, 2015 Year ended December 31, 2014 Employee benefit expense $ 4,032 $ 4,901 Investor relations Professional fees 937 1,395 Depreciation and amortization Other expenses 4,743 3,833 $ 9,895 $ 10,365 39) SUPPLEMENTARY CASH INFORMATION Change in non-cash working capital items December 31, 2015 December 31, 2014 Trade and other receivables $ (2,332) (2,609) Inventories (389) (146) Prepaid expenses (178) (331) Accounts payable and accrued liabilities (2,526) 954 $ (5,425) $ (2,132) Allocation of cash and cash equivalents December 31, 2015 December 31, 2014 Corporate and other $ 3,896 $ 38,158 HS Orka 6,449 25,058 $ 10,345 $ 63,

121 GEOTHERMAL PHOTO GALLERY Jimmie Creek Construction - BC Jimmie Creek- BC Shannon - TX Svartsengi - Iceland Dokie - BC Toba Montrose - BC Reykjanes - Iceland 2015 Annual Report Alterra Power Corp

122 TSX: AXY Producing Renewable Energy for a Brighter Future