Pattern Energy Group Inc Annual Report 2017

Plain-text annual report

PATTERN ENERGY GROUP INC. FORM 10-K (Annual Report) Filed 03/01/18 for the Period Ending 12/31/17 Address Telephone CIK Symbol SIC Code Industry PIER 1 BAY 3 SAN FRANCISCO, CA, 94111 (415) 283-4000 0001561660 PEGI 4911 - Electric Services Independent Power Producers Sector Utilities Fiscal Year 12/31 http://www.edgar-online.com © Copyright 2018, EDGAR Online, a division of Donnelley Financial Solutions. All Rights Reserved. Distribution and use of this document restricted under EDGAR Online, a division of Donnelley Financial Solutions, Terms of Use. UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549 FORM 10-K (Mark One)xANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the Fiscal Year Ended December 31, 2017.-OR-¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Commission File Number 001-36087 PATTERN ENERGY GROUP INC.(Exact name of Registrant as specified in its charter) Delaware 90-0893251(State or other jurisdiction ofincorporation or organization) (I.R.S. EmployerIdentification No.)Pier 1, Bay 3, San Francisco, CA 94111(Address of principal executive offices) (Zip Code)Registrant’s telephone number, including area code: (415) 283-4000Securities registered pursuant to Section 12(b) of the Act:Title of Each Class Name of Each Exchange on Which RegisteredClass A Common Stock, par value $0.01 per share NASDAQ Global Select MarketToronto Stock ExchangeSecurities registered pursuant to Section 12 (g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No ¨Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ýIndicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted andposted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submitand post such files). Yes ý No ¨Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, tothe best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company.See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,”and "emerging growth company" in Rule 12b-2 of the Exchange Act.Large accelerated filerx Accelerated filer¨Non-accelerated filer¨ Smaller reporting company¨ Emerging growth company¨If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financialaccounting standards provided pursuant to Section 13(a) of the Exchange Act.Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes ¨ No ýThe aggregate market value of the voting stock and non-voting stock held by non-affiliates of the registrant based upon the last trading price of the registrant’s Class A commonstock as reported on the NASDAQ Global Select Market on June 30, 2017 was approximately $1,656,909,633 . This excludes 18,136,573 shares of Class A common stock heldby directors, officers, Pattern Renewables LP and certain of its affiliates, and Public Sector Pension Investment Board. Exclusion of shares does not reflect a determination thatpersons are affiliates for any other purpose.The registrant’s Class A common stock is listed on the NASDAQ Global Select Market and on the Toronto Stock Exchange under the symbol "PEGI".On February 23, 2018 , the registrant had 97,865,865 shares of Class A common stock, $0.01 par value per share, outstanding.DOCUMENTS INCORPORATED BY REFERENCEPortions of the registrant’s definitive proxy statement relating to its 2018 annual meeting of stockholders (the "2018 Proxy Statement") are incorporated by reference into Part IIIof this Form 10-K where indicated. The 2018 Proxy Statement will be filed with the U.S. Securities and Exchange Commission within 120 days after the end of the fiscal year towhich this report relates. TABLE OF CONTENTS PART I Item 1.Business.6Item 1A.Risk Factors.22Item 1B.Unresolved Staff Comments.49Item 2.Properties.49Item 3.Legal Proceedings.49Item 4.Mine Safety Disclosures.49 PART II Item 5.Market for Registrant’s Common Equity and Related Stockholder Matters.50Item 6.Selected Financial Data.54Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations.55Item 7A.Quantitative and Qualitative Disclosures about Market Risk.79Item 8.Financial Statements and Supplementary Data.80Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.80Item 9A.Controls and Procedures.80Item 9B.Other Information.84 PART III Item 10.Directors, Executive Officers and Corporate Governance.85Item 11.Executive Compensation.85Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.85Item 13.Certain Relationships and Related Transactions, and Director Independence.85Item 14.Principal Accounting Fees and Services.85 PART IV Item 15.Exhibits and Financial Statement Schedules.86Item 16.Form 10-K SummaryS- 1012CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTSThis Annual Report on Form 10-K ("Form 10-K") contains statements that may constitute forward-looking statements. You can identify these statements byforward-looking words such as "anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan," "potential," "should," "will," "would," or similarwords. You should read statements that contain these words carefully because they discuss our current plans, strategies, prospects, and expectations concerningour business, operating results, financial condition, and other similar matters. While we believe that these forward-looking statements are reasonable as and whenmade, there may be events in the future that we are not able to predict accurately or control, and there can be no assurance that future developments affecting ourbusiness will be those that we anticipate. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) andassumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors thatcould cause our actual results to differ from those in the forward-looking statements, include but are not limited to, those summarized below and further describedin Part I, Item 1A "Risk Factors:"•our ability to complete acquisitions of power projects;•our ability to complete construction of construction projects and transition them into financially successful operating projects;•fluctuations in supply, demand, prices and other conditions for electricity, other commodities and renewable energy credits (RECs);•our electricity generation, our projections thereof and factors affecting production, including wind and other conditions, other weather conditions,availability and curtailment;•changes in law, including applicable tax laws;•public response to and changes in the local, state, provincial and federal regulatory framework affecting renewable energy projects, including those relatedto taxation, the U.S. federal production tax credit (PTC), investment tax credit (ITC) and potential reductions in Renewable Portfolio Standards (RPS)requirements;•the ability of our counterparties to satisfy their financial commitments or business obligations;•the availability of financing, including tax equity financing, for our power projects;•an increase in interest rates;•our substantial short-term and long-term indebtedness, including additional debt in the future;•competition from other power project developers;•development constraints, including the availability of interconnection and transmission;•potential environmental liabilities and the cost and conditions of compliance with applicable environmental laws and regulations;•our ability to operate our business efficiently, manage capital expenditures and costs effectively and generate cash flow;•our ability to retain and attract executive officers and key employees;•our ability to keep pace with and take advantage of new technologies;•the effects of litigation, including administrative and other proceedings or investigations, relating to our wind power projects under construction and thosein operation;•conditions in energy markets as well as financial markets generally, which will be affected by interest rates, foreign currency exchange rate fluctuationsand general economic conditions;•the effectiveness of our currency risk management program;•the effective life and cost of maintenance of our wind turbines and other equipment;•the increased costs of, and tariffs on, spare parts;•scarcity of necessary equipment;•negative public or community response to wind power projects;•the value of collateral in the event of liquidation; and•other factors discussed under "Risk Factors."3Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publiclyupdate or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.Statistical DataThe statistical data used throughout this Form 10-K, other than data relating specifically solely to us, are based upon independent industry publications,government publications, reports by market research firms or other published independent sources. We did not commission any of these publications orreports. These publications generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy orcompleteness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and makeno representation as to the accuracy of such information.Currency InformationIn this Form 10-K, reference to "C$" and "Canadian dollars" are to the lawful currency of Canada, references to "JPY" and Japanese Yen are to the lawful currencyof Japan and references to "$", "US$" and "U.S. dollars" are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars, unlessotherwise noted.MEANING OF CERTAIN REFERENCESUnless the context provides otherwise, references herein to "we," "our," "us," "our company" and "Pattern" refer to Pattern Energy Group Inc., a Delawarecorporation, together with its consolidated subsidiaries. In addition, unless the context requires otherwise, any reference in this Form 10-K to:•"FERC" refers to the U.S. Federal Energy Regulatory Commission;•"FIT" refers to feed-in-tariff regime;•"FPA" refers to the Federal Power Act;•"GPI" refers to Green Power Investment Corporation;•"Identified ROFO Projects" refers to projects that we have identified as development projects, owned by either of the Pattern DevelopmentCompanies and subject to our Project Purchase Rights. See Identified ROFO Projects list in Item 1. Business ;•"IPPs" refers to independent power producers;•"ISOs" refers to independent system organizations, which are organizations that administer wholesale electricity markets;•"ITCs" refers to investment tax credits;•"kWh" refers to kilowatt hour•"Multilateral Management Services Agreement" (MSA) refers to the amended and restated multilateral services agreement between us and eachof the Pattern Development Companies;•"MW" refers to megawatts;•"MWh" refers to megawatt hours;•"Non-Competition Agreement" refers to the second amended and restated non-competition agreement between us and each of the PatternDevelopment Companies in which we and each of the Pattern Development Companies have agreed to various arrangements with respect to howwe may and may not compete with each other;•"Pattern Development Companies" refers collectively to Pattern Development 1.0 and Pattern Development 2.0 and their respective subsidiaries;•"Pattern Development Purchase Rights" refer collectively to our right to acquire Pattern Development 1.0 or substantially all of its assets, ascontemplated by the Amended and Restated Purchase Rights Agreement between us and Pattern Development 1.0 (Pattern Development 1.0Purchase Right) and to our right to acquire Pattern Development 2.0 or4substantially all of its assets, as contemplated by the Amended and Restated Purchase Rights Agreement between us and Pattern Development2.0 (Pattern Development 2.0 Purchase Right);•“Pattern Development 1.0” refers to Pattern Energy Group LP, a Delaware limited partnership, and, where the context so requires, itssubsidiaries (excluding us);•“Pattern Development 2.0” refers to Pattern Energy Group 2 LP, a Delaware limited partnership, and, where the context so requires, itssubsidiaries. We hold an approximate 21% ownership interest in Pattern Development 2.0;•"PSAs" or "power sale agreements" refer to PPAs and/or hedging arrangements, as applicable;•"PPAs" refer to power purchase agreements;•"Project Purchase Rights" refers collectively to our right of first offer with respect to power projects that Pattern Development 1.0 decides to sell,as contemplated by the Amended and Restated Purchase Rights Agreement between us and Pattern Development 1.0, and our right of first offerwith respect to power projects that Pattern Development 2.0 decides to sell, as contemplated by the Amended and Restated Purchase RightsAgreement between us and Pattern Development 2.0 (in each case including any Identified ROFO Projects);•"PSP Investments" refers to the Public Sector Pension Investment Board;•"Purchase Rights" refers collectively to the Project Purchase Rights, and the Pattern Development Purchase Rights, as contemplated by theAmended and Restated Purchase Rights Agreement between us and Pattern Development 1.0 and the Amended and Restated Purchase RightsAgreement between us and Pattern Development 2.0;•"RECs" refers to renewable energy credits;•"Riverstone" refers to Riverstone Holdings LLC;•"ROFO" refers to right of first offer;•"RPS" refers to Renewable Portfolio Standards; and•"Sarbanes-Oxley Act" refers to the Sarbanes-Oxley Act of 2002.5PART IItem 1. BusinessOverviewWe are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential forcontinued growth of our business.We hold interests in 25 wind and solar power projects, including projects we have committed to acquire, with a total owned capacity of 2,942 MW in the UnitedStates, Canada, Japan and Chile that use proven and best-in-class technology. Each of our projects has contracted to sell all or a majority of its output pursuant tolong-term, fixed-price power sale agreements (PSAs), some of which are subject to price escalation. Ninety-two percent of the electricity to be generated by ourprojects will be sold under our PSAs which have a weighted average remaining contract life of approximately 14 years as of December 31, 2017.We were organized in the state of Delaware in October 2012. We issued 100 shares in October 2012 to Pattern Renewables LP, a 100% owned subsidiary ofPattern Development 1.0 and subsequently in October 2013 conducted an initial public offering.Our Relationship with the Pattern Development CompaniesPursuant to the MSA, certain of our executive officers, including our Chief Executive Officer, also are shared executives of the Pattern Development Companiesand devote their time to both us and the Pattern Development Companies as is prudent in carrying out their executive responsibilities and fiduciary duties. InDecember 2016, certain investment funds managed by Riverstone Holdings LLC, which own interests in Pattern Development 1.0, engaged in a transaction inwhich (a) certain assets of Pattern Development 1.0 consisting principally of early and mid-stage U.S. development assets (including the Grady, Stillwater Big Sky,Crazy Mountain and Ishikari projects which are Identified ROFO Projects) were transferred to a newly formed entity, Pattern Development 2.0, and (b) PatternDevelopment 1.0 retained the remainder of its assets consisting principally of the other Identified ROFO Projects, non-U.S. development assets, and its ownershipinterest in our Class A common stock. The purpose of the transaction was to facilitate additional long-term capital raises by Pattern Development 2.0 to support thegrowth in the development pipeline. We also entered into other agreements with Pattern Development 2.0 which were amended and restated in June 2017 andrelate to the relationships among us and the Pattern Development Companies, including relating to purchase rights, service agreements and competition.In 2017, we acquired approximately 21% ownership of Pattern Development 2.0. In February 2018, we made an additional contribution of $35.2 million pursuantto a Pattern Development 2.0 capital call, of which approximately $27 million was used toward Pattern Development 2.0's purchase of GPI. We have alsocommitted to contribute up to an additional $197.5 million to Pattern Development 2.0 in one or more subsequent rounds of financing, which could result in ourownership interest in Pattern Development 2.0 increasing up to 29%. If we do not participate in such subsequent rounds of financing, our ownership interest inPattern Development 2.0 may be diluted on a pro rata basis based on fair market value.As of December 31, 2017, Pattern Development 1.0 owned approximately 7.5% of our outstanding Class A common stock. Our continuing relationship with thePattern Development Companies provides us with access to a pipeline of acquisition opportunities. We believe the Pattern Development Companies’ focus onproject development combined with our Project Purchase Rights will complement our acquisition strategy, which focuses on the identification and acquisition ofoperational and construction-ready power projects and investment in development companies.Our Relationship with PSP InvestmentsIn June 2017, we entered into a strategic joint venture agreement with PSP Investments. The joint venture agreement provides that PSP Investments has the right toco-invest alongside us, up to an aggregate amount of approximately $500 million, in energy projects we may acquire from the Pattern Development Companies,cooperate with us to complete third-party acquisitions (including possibly arranging for or providing bridge loans and construction financing), and we may add aperson that has been designated by PSP Investments to our board of directors. In 2017, we, together with PSP Investments, acquired the Meikle Wind EnergyProject from Pattern Development 1.0. In addition, in 2017, we sold a portion of our interest in the Panhandle 2 wind project to PSP Investments. This relationshipprovides us the ability to increase our portfolio with limited capital investment. In 2018, we expect to acquire Mont Sainte-Marguerite (MSM), together with PSPInvestments from Pattern Development 1.0. PSP Investments is also an investor in Pattern Development 2.0. Additionally, i n June 2017, PSP Investments acquired8.7 million shares, or approximately 9.9%, of our outstanding Class A common6stock from Pattern Development 1.0 and an additional 0.6 million shares from the Company's public offering that occurred on October 23, 2017.7Structure of Our CompanyIndustryWind and solar power have been two of the fastest growing sources of electricity generation in North America and globally over the past decade. In 2016, growthin solar photovoltaic (PV) capacity was larger than any other form of generation with 75 gigawatts (GW) of solar installed, bringing the installed PV capacity to303 GW worldwide and representing 1.8% of global electricity demand. In 2017,8global installed wind capacity grew by nearly 11%, bringing the global total to 540 GW. Projections by the International Energy Agency indicate renewable energywill continue to grow at a faster rate than fossil fuels over the next two decades.Growth in the industry is largely attributable to the increasing cost competitiveness of wind and solar energy relative to other power generation technologies andpublic support for renewable energy driven by energy security and environmental concerns. The 11th annual report by Lazard on the levelized cost of energy(LCOE) for electricity-generating technologies shows renewables are the cheapest available sources of electricity even without government incentives. Globally,the LCOE for both utility-scale solar PV and onshore wind technologies are down approximately 6% from 2016. This is a trend confirmed by similar analyses ofwind and solar costs by the Lawrence Berkeley National Laboratory.Given increased demand, falling costs, and the inherent stability of the cost of renewable energy sources, we believe that our markets present substantial growthopportunities. We require a relatively small share of a very large market to meet our growth objectives, and we believe we will achieve growth through theacquisition of operational and construction-ready projects from the Pattern Development Companies and other third parties.Our Current MarketsThe United States remains the second largest growth market for renewables in the world. In 2016, total wind power capacity in the United States reached 82,634MW, representing 8% of installed capacity and approximately 6% of total electricity demand. Solar energy capacity reached 41,825 MW, representing 4% ofinstalled capacity and 1% of total electricity demand. Government incentives contribute to the competitiveness of renewable energy by providing accelerateddepreciation, tax credits for a portion of the development costs, decreasing the costs associated with developing, and creating demand for renewable energy assetsthrough state renewable portfolio standard (RPS) programs. Additionally, demand has been increasing from commercial and industrial customers, such as majorconsumer brands and universities, and from the voluntary utility market. Nearly half of Fortune 500 companies and 63% of Fortune 100 companies have at leastone climate or clean energy target. The Energy Information Administration expects these demand drivers to push renewable energy to 18% of electricity sales by2030. State RPSs, specifically, are expected to drive an annual average increase of 4 GW of installed renewables capacity, with 18 GW added by 2020 and 55 GWby 2030.The Canadian wind power industry has experienced dramatic growth in recent years, with installed capacity growing by an average of 15% per year during the lastfive years. According to Bloomberg New Energy Finance, installed wind power was 12,108 MW at the end of 2016, representing 9% of installed capacity in thecountry and 3% of energy generation. Clean energy policy occurs mostly at the provincial level. Alberta’s new Renewable Electricity Program is expected to drivedevelopment of at least 4,000 MW of new wind energy capacity by 2030, contributing to the expectation that demand met by renewable sources will triple from9% today to 30% during this timeframe. Saskatchewan aims to have wind energy meet 30% of its electricity generating capacity by 2030, adding about 1,600 MWof new wind capacity.In February 2018, we entered the Japan renewable energy market by committing to the acquisition of three wind projects, two of which are under construction, andtwo solar projects for a total owned capacity of 206 MW in Japan. In addition, we increased our investment in Pattern Development 2.0 in connection with itsacquisition of a controlling interest in Green Power Investments (GPI), a well-established operating and development management team in Japan. Roughly 15% ofJapan’s power needs were met by renewable energy in 2016. Wind and solar energy accounted for 6% of total generation and 18% of installed capacity, with 3,230MW of wind power and 45,596 MW of solar power. Following the nuclear meltdown at the Fukushima Daiichi plant in 2011, the Japanese government has placeda greater emphasis on the development of renewable resources, aiming to have 22 to 24% of Japan's power generated by renewable energy by 2030. This effort wassupported by the introduction of a Feed-in-Tariff (FIT) program in 2012 that offered fixed-term, fixed-price contracts for up to 20 years to renewable powerprojects. Recently, the fixed-price for large solar projects has been replaced with a reverse auction system that has a bid floor set at Japanese Yen (JPY) 21 perkWh. The tariff prices for wind power remain fixed until March 2020, with an onshore wind tariff of JPY21 per kWh and an offshore wind tariff of JPY36 perkWh. As such, there remains a strong incentive for continued investment in the Japanese renewables market.At the end of 2016, renewables represented 12% of all generation, with wind and solar representing 6% of generation in Chile. There was a total of 1,159 MW ofwind power and 1,612 MW of solar power, totaling 12% of Chile’s installed capacity. Chile introduced a time sub-block system for power auctions in 2014, whichcreates opportunities for wind and solar to take advantage of the times of the day when available natural resources match the country’s energy needs. Miningoperations in the country are energy-intensive and represent a large source of demand. The copper industry alone accounted for 29% of total energy generated in2015. Relief from curtailment of renewables that has occurred since 2015 is expected in 2018 from the interconnection of Chile’s largest two system operators.9Our Developing MarketsThe Pattern Development Companies are actively working in Mexico, and we expect to add Mexican projects to the Identified ROFO Projects list in the future.Mexico’s Congress has enacted sweeping reforms to its electric generation industry in recent years, opening new opportunities for private investment in generationand creating a mandate to obtain at least 35% of its generation from clean sources by 2024. The Ministry of Energy estimates an additional 13.41 GW of wind andsolar during this period, representing an average annual addition of 871 MW per year for wind power and 804 MW per year for solar. The government expectsenergy demand to increase 2.9% annually over the next fifteen years. In this period, wind is expected to grow by 13 GW and solar by 8 GW. At the end of 2016,wind and solar energy accounted for 3% of total generation and 5% of installed capacity, with 3,468 MW of wind power and 349 MW of solar power.The map below provides a depiction of our projects and Identified ROFO Projects geographically:Our Core Values and Financial ObjectivesWe intend to maximize long-term value for our stockholders in an environmentally responsible manner and with respect for the communities in which we operate.Our business is built around three core values of creative energy and spirit, pride of ownership and follow-through, and a team first attitude, which guide us in: •creating a safe and high-integrity work environment for our employees;•applying rigorous analysis to all aspects of our business in a timely, disciplined and functionally integrated manner to understand patterns in windregimes, technology developments, market trends and regulatory, financial and legal constraints; and•working proactively with our stakeholders to address environmental and community concerns, which we believe is a socially responsible approach thatalso benefits our business by reducing operating risks at our projects.10Our financial objectives, which we believe will maximize long-term value for our stockholders, are to: •produce stable and sustainable cash available for distribution;•selectively grow our project portfolio and our dividend per Class A share of common stock; and•maintain a strong balance sheet and flexible capital structure.Our Business StrategyTo achieve our financial objectives while adhering to our core values, we intend to execute the following business strategies:Maintaining and Increasing the Value of Our ProjectsWe intend to efficiently operate our projects to meet projected revenue and cash available for distribution. We expect to maximize the long-term value of ourprojects by focusing on value-oriented project availability (by ensuring our projects are operational when the wind is strong and power sale agreement prices are attheir highest) and by regularly scheduled and preventative maintenance. We believe that good operating performance begins with a long-term maintenanceprogram for our equipment. We also seek to improve performance or lower operating costs by working closely with our equipment vendors and consideringcontracting with third parties for maintenance, when appropriate.We believe it is important to employ our own personnel in aspects of our business that we deem critical to the value of our projects. We have entered into revisedlong-term turbine manufacturer service arrangements at certain of our projects pursuant to which the turbine manufacturer will continue to provide routine andcorrective maintenance service, but we would become responsible for a portion of the maintenance and repairs, including on major component parts. We expect tocontinue entering into similar arrangements at other projects in the future. We employ on-site personnel, maintain a 24/7 operations control center to monitor ourprojects and control all critical aspects of commercial asset management.Selectively Growing Our BusinessOur strategy for growth is focused on the acquisition of operational and construction-ready power projects from the Pattern Development Companies and otherthird parties that, together such measured investments into the development business, we believe will contribute to the growth of our business and enable us toincrease our dividend per share of Class A common stock over time. We expect that projects we may acquire in the future will represent a logical extension of ourexisting business and be consistent with our risk profile, and that any incremental assumption of risk will require commensurate expectations of higher returns. Asa result, our near-term growth strategy will remain focused on largely contracted cash flows with creditworthy counterparties and operating or in-constructionprojects.We expect that opportunities will continue to arise from our relationship with the Pattern Development Companies, which provide us with the opportunity toacquire projects as they develop, construct and achieve commercial operations at these projects. Additionally, the investment in Pattern Development 2.0 supportsgrowth in Pattern Development 2.0's development pipeline.From time to time, we may also consider the disposal of a project, particularly if we believe we can utilize funds realized from such a disposal in a more productivemanner or generate a higher return on investment.Maintaining a Prudent Capital Structure and Financial FlexibilityWe intend to maintain a conservative approach to our capital structure to protect our ability to meet our financial obligations, pay our regular dividends and to fundinvestments for future growth. Power projects by their nature require significant capital investment, and as a result, we seek to protect our business through carefulmanagement of our capital structure.The foundation of our capital structure is built on project finance arrangements intended to ensure risk segmentation across our large project portfolio, and ourpractice has been to structure our project finance arrangements comprised of a mix of debt, tax equity and equity to conform to investment grade-like creditstandards. Specifically, we seek to structure our project finance arrangements to:•match assets with liabilities based on a project’s off-take tenor and currency denomination;•fix or hedge project debt on a long-term basis;•amortize our third party project finance capital within the tenor of the off-take arrangement; and•apply conservative debt service coverage or tax equity structuring standards.11Our project capital structure is supplemented with a corporate capital layer that primarily relies on equity capital. Our corporate indebtedness, which includesunsecured senior notes with an aggregate principal amount of $350.0 million which we issued in January 2017 (the 2024 Unsecured Senior Notes), is modest, andintended to ensure broad capital access. In addition, our strategic partnership with PSP Investments is intended to expand capital access and improve flexibility inmanaging capital requirements.We seek to ensure financial flexibility and stability through our corporate revolving credit facility, maturity staging, minimization of interest rate exposure, andmaintenance of our credit ratings. Our foreign currency denominated project dividends are further managed through a short-to-medium term foreign exchangeprogram. We believe this approach, together with a strategic consideration of project-level financial restructuring and recapitalization opportunities, will contributeto our ability to maintain and, over time, increase our cash available for distribution. Working Closely with Our StakeholdersWe believe that close working relationships with our various stakeholders, including suppliers, power sales agreement counterparties, regulators, the localcommunities where we are located and environmental organizations and with the Pattern Development Companies and other developers enable us to best supportour existing projects and will help us access attractive, construction-ready projects.CompetitionWe compete with other wind and solar power, infrastructure funds and renewable energy companies, as well as conventional power companies, to acquireprofitable construction-ready and operating projects. In addition, competitive conditions may be substantially affected by various forms of energy legislation andregulation considered from time to time by federal, state, provincial and local legislatures and administrative agencies.Competitive StrengthsWe believe we compete with other industry participants by having high quality projects which are positioned to generate stable long-term cash flows which in turngive us access to low-cost project-level debt and strong stakeholder relationships. Some of the key attributes of our projects include long-term fixed priced powersale agreements, a geographically diverse market with varying wind and solar regimes and regulatory environment; and state-of-the-art wind turbines and solarpanels. Further contributing to our competitive strength is our approach to project selection which focuses on the acquisition of projects that are operational andhave long term power sales agreements with creditworthy counterparties. We believe our relationship with the Pattern Development Companies provides us withaccess to a pipeline of acquisition opportunities that also supplements our competitive strengths. Pattern Development 1.0's ownership interest in us is 7.5% .Our ProjectsWe hold interests in 25 wind and solar power projects, including projects which we have committed to acquire, with a total owned capacity of 2,942 MW in theUnited States, Canada, Japan and Chile that use proven and best-in-class technology. Each of our projects has contracted to sell all or a majority of its outputpursuant to long-term, fixed-price PSAs, some of which are subject to price escalation. Each of our projects has gone through a rigorous vetting process to meetour investment and our lenders’ financing criteria. As a result, our projects generally have the following characteristics: •multi-year on-site wind and solar data analysis tied to one or more long-term wind and solar energy reference sources;•long-term PSAs designed to ensure a predictable revenue stream;•contractually secured real estate property and easement rights for a period well in excess of the project’s expected useful life and contractualobligations;•a firm right to interconnect to the electricity grid through interconnection agreements, which define the cost allocation and schedule for interconnection,as well as any upgrades required to connect the project to the transmission system;•long-term, limited-recourse, amortizing project financing designed to match the long-lived nature of our power projects and the related power salesagreements;•secured construction and operating permits and other requisite federal, state or provincial and local permits, and regulatory approvals;•fixed-price turbine supply and construction contracts with guaranteed completion dates;12•an operations and maintenance service program based on our own on-site personnel and central operations management as well as equipmentwarranties (for at least the first two years of operation) and service arrangements with qualified providers experienced in wind and solar projectmaintenance (including in some instances our internal operations group); and•safety, environmental and community programs to support our existing projects and relationships in the communities in which we operate.13The following table provides an overview of our wind and solar projects:OperatingProject Location Commencement ofCommercialOperations RatedCapacity inMW (1) Our OwnedCapacity (2) Type ContractedVolume (3) Counterparty CounterpartyCredit Rating (4) ContractExpirationHatchet Ridge California 2010 101 101 PPA 100% Pacific Gas &Electric A-/A2 2025Ocotillo California 2012 (5) 265 265 PPA 100% San Diego Gas &Electric A/A1 2033Spring Valley Nevada 2012 152 152 PPA 100% NV Energy A/Baa2 2032Gulf Wind Texas 2009 283 283 Hedge 58% Morgan Stanley BBB+/A3 2019Panhandle 1 Texas 2014 218 172 Hedge 80% Citigroup Energy Inc. BBB+/Baa1 2027Panhandle 2 Texas 2014 182 75 Hedge 80% Morgan Stanley BBB+/A3 2027Logan's Gap Texas 2015 200 164 PPA 58% Wal-Mart Stores, Inc. AA/Aa2 2025Logan's Gap Hedge 17% Merrill LynchCommodities, Inc. A-/A3 2028Post Rock Kansas 2012 201 120 PPA 100% Westar Energy, Inc. BBB+/Baa1 2032Lost Creek Missouri 2010 150 150 PPA 100% Associated ElectricCooperative, Inc. AA/A1 2030Amazon Wind Indiana 2015 150 116 PPA 100% Amazon.com, Inc. AA-/Baa1 2028St. Joseph Manitoba 2011 138 138 PPA 100% Manitoba Hydro A+/Aa2 2039Santa Isabel Puerto Rico 2012 101 101 PPA 100% Puerto Rico ElectricPower Authority D/Ca 2037El Arrayán Chile 2014 115 81 Hedge 74% Minera LosPelambres NA 2034Grand Ontario 2014 149 67 PPA 100% IndependentElectricity SystemOperator (7) NA/Aa2 2034South Kent Ontario 2014 270 135 PPA 100% IndependentElectricity SystemOperator (7) NA/Aa2 2034K2 Ontario 2015 270 90 PPA 100% IndependentElectricity SystemOperator (7) NA/Aa2 2035Armow Ontario 2015 180 90 PPA 100% IndependentElectricity SystemOperator (7) NA/Aa2 2035Broadview NewMexico 2017 324 272 PPA 100% Southern CaliforniaEdison BBB+/A2 2037Meikle BritishColumbia 2017 179 91 PPA 100% BC Hydro NA/Aaa 2042Mont Sainte-Marguerite (6) Quebec 2018 143 73 PPA 100% Hydro-Quebec NA/Aa2 2043Futtsu Solar (8) Japan 2016 29 29 PPA 100% TEPCO EnergyPartner Ba2 2036Kanagi Solar(8) Japan 2016 10 10 PPA 100% Chugoku ElectricPower Company A3 2036Otsuki (8) Japan 2006 12 12 PPA 100% Shikoku ElectricPower Company A- 2026Ohorayama (8) Japan 2018 33 33 PPA 100% Shikoku ElectricPower Company A- 2038Tsugaru (8) Japan 2020 122 122 PPA 100% Tohoku ElectricPower Company Unrated 2040 3,977 2,942 14(1) Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of weather and other conditions, a project will not operate at its rated capacity atall times and the amount of electricity generated may be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors.(2) Owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW multiplied by our percentage ownership interest in the distributable cash flow ofthe project.(3) Represents the approximate percentage of a project’s total estimated average annual MWh of electricity generation contracted under power purchase agreements or hedgearrangements.(4) Reflects the counterparty’s or counterparty guarantor's corporate credit ratings issued by either Standard and Poor's (S&P) or Moody’s, or both S&P and Moody's, as of December 31,2017 .(5) In 2013, 42 MW of owned capacity was added to our owned capacity.(6) In June 2017, we committed to acquire from Pattern Development 1.0 a 51% interest in MSM, a 143MW wind power project.(7) Independent Electricity System Operator (IESO) acts as the settlement agent under the respective PPA(8) In February 2018, we committed to acquire 206 MW of owned capacity in wind and solar power projects in Japan from Pattern Development 1.0 and GPI.Identified Right of First Offer ProjectsOur continuing relationship with the Pattern Development Companies provides us with access to a pipeline of acquisition opportunities. Currently, the PatternDevelopment Companies have a more than a 10 GW pipeline of development projects, which are subject to our right of first offer. We target achieving a totalowned or managed capacity of 5,000 MW by year end 2020 through a combination of acquisitions from the Pattern Development Companies and other thirdparties capitalizing on the large and fragmented global renewable energy market. Our business is primarily focused in the U.S., Canada, Japan, and Chile; however,we expect opportunities in Mexico will form part of our growth strategy.Below is a summary of the Identified ROFO Projects that we expect to acquire from Pattern Development 1.0 and Pattern Development 2.0 in connection with ourProject Purchase Rights: Capacity (MW)Identified ROFO Projects Status Location Construction Start (1) Commercial Operations (2) Contract Type Rated (3) Pattern Development Companies Owned (4)Pattern Development 1.0 Projects Conejo Solar (5) Operational Chile 2015 2016 PPA 104 104Belle River Operational Ontario 2016 2017 PPA 100 43El Cabo Operational New Mexico 2016 2017 PPA 298 125North Kent Operational Ontario 2017 2018 PPA 100 35Henvey Inlet In construction Ontario 2017 2019 PPA 300 150Pattern Development 2.0 Projects Stillwater Big Sky Late stagedevelopment Montana 2017 2018 PPA 79 67Crazy Mountain Late stagedevelopment Montana 2017 2019 PPA 80 68Grady Late stagedevelopment New Mexico 2018 2019 PPA 220 188Sumita Late stagedevelopment Japan 2019 2021 PPA 100 55Ishikari Late stagedevelopment Japan 2019 2022 PPA 100 100 1,481 935(1) Represents year of actual or anticipated commencement of construction.(2) Represents year of actual or anticipated commencement of commercial operations.(3) Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of weather and other conditions, a project will not operate at its rated capacity atall times and the amount of electricity generated may be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors.(4) Pattern Development Companies-Owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW multiplied by Pattern Development 1.0's orPattern Development 2.0's percentage ownership interest in the distributable cash flow of the project.(5) From time to time, we conduct strategic reviews of our markets. We have been conducting a strategic review of the market, growth, and opportunities in Chile. In the event we believewe can utilize funds that have already been invested in Chile or funds that might otherwise be invested in Chile in a more productive manner elsewhere that could generate a higherreturn on investment, we may decide to exit Chile for other opportunities with greater potential. In addition, Pattern Development 1.0 is also concurrently exploring strategicalternatives for its assets in Chile.Government Incentives and Tax CreditsRenewable energy sources in the United States have benefited from various federal and state governmental incentives, such as production tax credits andinvestment tax credits. Production tax credits and investment tax credits for wind energy on the federal level were extended in December of 2015, under theConsolidated Appropriations Act which extended the expiration date for tax credits for wind facilities commencing construction, with a five-year phase-downbeginning for wind projects commencing construction after December 31, 2014.Hedging ActivityMost of our revenue is subject to long-term PPAs. To the extent that PPAs are not available in a given market, but market prices allow for acceptable projecteconomics, we will enter into hedging agreements to obtain a fixed price for the energy output of our projects, typically by hedging volumes that are expected to beexceeded 99.0% of the time. Those hedging agreements are executed for a monthly or hourly production profile that matches the forecasted production profile ofthe project.Most of our interest rate exposure is hedged either through fixed-rate debt arrangements or hedging of floating rate loans. We enter into interest rate hedgingagreements to convert floating-rate debt to fixed-rate debt for some of our projects, usually at the time we close15construction or term financing of a project. We also monitor our corporate-level interest rate exposure and may, from time to time, enter into interest rate hedges tomitigate our exposure.We have a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flowsthat have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in our cash flow, which may have an adverseimpact to our short-term liquidity or financial condition.Geographic informationThe table below provides information about our consolidated operations by country. Revenue is recorded in the country in which it is earned and assets arerecorded in the country in which they are located (in thousands): Revenue Property, Plant and Equipment, net Year ended December 31, December 31, 2017 2016 2015 2017 2016 2015United States $315,642 $285,187 $258,542 $3,121,387 $2,652,122 $2,791,259Canada 62,063 39,207 39,178 550,183 177,093 184,115Chile 33,639 29,658 32,111 293,551 305,947 319,246Total $411,344 $354,052 $329,831 $3,965,121 $3,135,162 $3,294,620CustomersWe sell our electricity and RECs primarily to local utilities under long-term, fixed-price PPAs or, in limited instances, local liquid ISO markets. For the year endedDecember 31, 2017, San Diego Gas & Electric was our only significant customer representing 13.4% of our total revenue.16SuppliersThere are a limited number of renewable equipment suppliers; however, we believe that current manufacturing capacity is adequate. Our equipment supply strategyis largely based on maintaining strong relationships with leading equipment suppliers to secure our supply needs.Project Supplier Number of Turbines/Panels Equipment TypeHatchet Ridge Siemens-Gamesa 44 SWT-2.3-93Ocotillo Siemens-Gamesa 112 SWT-2.3-108Spring Valley Siemens-Gamesa 66 SWT-2.3-101Gulf Wind Mitsubishi 118 MWT 95/2.4Panhandle 1 General Electric 118 1.85 - 87Panhandle 2 Siemens-Gamesa 79 SWT-2.3-108Logan’s Gap Siemens-Gamesa 87 SWT-2.3-108Post Rock General Electric 134 1.5-82.5Lost Creek General Electric 100 1.5-82.5Amazon Wind Siemens-Gamesa 65 SWT-2.3-108St. Joseph Siemens-Gamesa 60 SWT-2.3-101Santa Isabel Siemens-Gamesa 44 SWT-2.3-108El Arrayán Siemens-Gamesa 50 SWT-2.3-101Grand Siemens-Gamesa 67 SWT-2.3-101South Kent Siemens-Gamesa 124 SWT-2.3-101K2 Siemens-Gamesa 140 SWT-2.3-101Armow Siemens-Gamesa 91 SWT-2.3-101Broadview Siemens-Gamesa 141 SWT-2.3-108Meikle General Electric 61 GE 2.75-120 & GE 3.2-103Mont Sainte-Marguerite (1) Siemens-Gamesa 46 SWT-3.2-113Futtsu Solar (2) Kyocera 168,840 KK250P-3CF-3CGKanagi Solar (2) Kyocera 54,720 KK250P-3CF-3CGOtsuki (2) Mitsubishi 12 MWT 1000 AOhorayama (2) General Electric 11 GE 3.0MW-103Tsugaru General Electric 38 GE 3.2MW-103(1) We have committed to acquire the MSM project and expect to close in early to mid 2018.(2) We have also committed to acquire in Japan the Futtsu Solar, Kanagi Solar, Otsuki, Ohorayama and Tsugaru projects which we expect to close in early to mid 2018.Other important suppliers include engineering and construction companies, such as M. A. Mortenson Company, RES-Americas and Blattner Energy, Inc., withwhom we contract to perform civil engineering, electrical work and other infrastructure construction for our projects.While we do self-perform some turbine service and maintenance activities, the majority of our service work is currently performed by the original equipmentmanufacturers, primarily Siemens-Gamesa and General Electric. Both of these providers are industry leaders in the renewable service business. As describedelsewhere, while we expect over time to increase self-perform activities, we do expect to continue to utilize both original equipment manufacturers and qualifiedindependent service companies for a substantial amount of our service and maintenance needs.Regulatory MattersOur operations are subject to regulation by various federal and state government agencies, including, but, not limited to, the following:17U.S. Federal Energy Regulatory Commission (FERC)Our current projects in operation in the United States are operating as Exempt Wholesale Generators (EWGs) as defined under the Public Utility Holding CompanyAct of 2005, as amended, (PUHCA) and therefore are exempt from certain regulation under PUHCA. Other than Gulf Wind, Panhandle 1, Panhandle 2, andLogan’s Gap, our operating projects in the United States are, however, public utilities under the Federal Power Act subject to rate regulation by FERC. Our futureprojects in the United States will also likely be subject to such rate regulation once they are placed into service. Our projects in the United States that are subject toFERC rate regulation are required to obtain acceptance of their rate schedules for wholesale sales of energy (i.e., not retail sales to consumers), capacity andancillary services, including their ability to charge “market-based rates.”Independent System Operators (ISOs)Most of our North American projects are located in regions in which the wholesale electric markets are administered by ISOs and Regional TransmissionOrganizations (RTOs).North American Electric Reliability CorporationAll of our current operating projects located in North America are also subject to the reliability standards of the North American Electric Reliability Corporation(NERC). If we fail to comply with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.Regulatory Matters - CanadaAll of our current operating projects in Canada are subject to exclusive provincial regulatory authority with respect to the generation and production of electricity,which varies across provincial jurisdictions. In Canada, activities related to owning and operating wind projects and participating in wholesale and retail energymarkets are regulated at the provincial level. In Ontario, for example, electricity generation facilities must be licensed by the Ontario Energy Board and may alsobe required to complete registrations and maintain market participant status with the IESO, in which case they must agree to be bound by and comply with theprovisions of the market rules for the Ontario electricity market as well as the mandatory reliability standards of the NERC.Environmental RegulationOur operations are required to comply with various environmental, health and safety laws and regulations in each of the jurisdictions in which we operate. Theseexisting and future laws and regulations may impact existing and new projects, require us to obtain and maintain permits and approvals, comply with allenvironmental laws and regulations applicable within each jurisdiction and implement environmental, health and safety programs and procedures to monitor andcontrol risks associated with the construction, operation and decommissioning of regulated or permitted energy assets, all of which involve a significant investmentof time and resources. Existing initiatives and rules, some of which could potentially have a material effect (either positive or negative) on us, are as follows:Avian/Bat Regulations and Wind Turbine Siting GuidelinesWe are subject to numerous environmental regulations and guidelines related to threatened and endangered species and their habitats, as well as avian and batspecies, for the ongoing operations of our facilities. Environmental laws in the U.S., including the Endangered Species Act, the Migratory Bird Treaty Act, and theBald and Golden Eagle Protection Act as well as similar environmental laws in Canada (such as the Species at Risk Act, the Migratory Birds Convention Act andthe Endangered Species Act of 2007), among others, provide for the protection of migratory birds, eagles and bats and endangered species of birds and bats andtheir habitats. In addition to regulations, voluntary wind turbine siting guidelines established by the U.S. Fish and Wildlife Service set forth siting, monitoring andcoordination protocols that are designed to support wind development in the U.S. while also protecting both birds and bats and their habitats.Regulation of Greenhouse Gas (GHG) EmissionsThe U.S. Congress and certain states and regions, as well as the Government of Canada and its provinces, have taken and continue to take certain actions, such asfinalizing regulation or setting targets and goals, regarding the reduction of GHG emissions and the increase of renewable energy generation.18Environmental Matters— DomesticWe are required to obtain a range of environmental permits and other approvals to build and operate our projects, including, but not limited to, those describedbelow from U.S. federal, state and local governmental authorities. In addition to being subject to these regulatory requirements, we could experience and haveexperienced significant opposition from third parties when we initially apply for permits or when there is an appeal proceeding after permits are issued. The delayor denial of a permit or the imposition of conditions that are costly or difficult to comply with can impair or even prevent the development of a project or canincrease the cost so substantially that the project is no longer attractive to us.Federal Clean Water ActFrequently, our U.S. projects are located near wetlands, and we are required to obtain permits under the Clean Water Act for the discharge of dredged or fillmaterial into waters of the United States, including wetlands and streams. The Clean Water Act also requires that we mitigate any loss of wetland functions andvalues that accompanies our activities, obtain permits under the Clean Water Act for water discharges, such as storm water runoff associated with constructionactivities, and to follow a variety of best management practices to ensure that water quality is protected and impacts are minimized.Federal Bureau of Land Management PermitsAs some of our U.S. projects are located on lands administered by the Bureau of Land Management, we are required to obtain rights-of-way from the Bureau ofLand Management. The Bureau of Land Management encourages the development of wind power within acceptable areas, consistent with Environmental PolicyAct of 2005 and the Bureau of Land Management’s energy and mineral policy.National Environmental Policy ActOur U.S. projects may also be subject to environmental review under the U.S. National Environmental Policy Act (NEPA) which requires federal agencies toevaluate the environmental impact of all "major federal actions" significantly affecting the quality of the human environment. The granting of a land lease, afederal permit or similar authorization for a major development project, or the interconnection of a significant private project into a federal project generally isconsidered a "major federal action" that requires review under NEPA. As part of the NEPA review, the federal agency considers a broad array of environmentalimpacts, including impacts on air quality, water quality, wildlife, historical and archaeological resources, geology, socioeconomics and aesthetics and alternativesto the project. A federal agency may decide to deny a permit based on its environmental review under NEPA, though in most cases a project would be redesignedto reduce impacts or agree to provide some form of mitigation to offset impacts before a denial is issued.National Historic Preservation ActU.S. federal agencies consider a project’s impact on historical or archeological resources under the U.S. National Historic Preservation Act and may require us toconduct archeological surveys or take other measures to protect these resources. The National Historic Preservation Act requires federal agencies to evaluate theimpact of all federally funded or permitted projects on historic properties (buildings, archaeological sites, etc.)Other State and Local ProgramsIn addition to federal requirements, our U.S. projects, and any future U.S. projects we may acquire, are subject to a variety of state environmental review andpermitting requirements. Many states where our projects are located, or may in the future be located, have laws that require state agencies to evaluate a broad arrayof environmental impacts before granting state permits. The state environmental review process often resembles the federal NEPA process and may be morestringent than the federal review. Our projects also often require state law based permits in addition to federal permits.Our projects also are subject to local environmental and regulatory requirements, including county and municipal land use, zoning, building and transportationrequirements. Local or state regulatory agencies may require modeling and measurement of permissible sound levels in connection with the permitting andapproval of our projects. Local or state agencies also may require us to develop decommissioning plans for dismantling the project at the end of its functional lifeand establish financial assurances for carrying out the decommissioning plan.19Environmental Matters—CanadaWe are required to obtain a range of environmental permits and other approvals to build and operate our Canadian projects, including, but not limited to, thosedescribed below from Canadian federal, provincial and local governmental authorities. In addition to being subject to these regulatory requirements, we couldexperience and have experienced significant opposition from third parties, including, but not limited to, environmental non-governmental organizations,neighborhood groups, municipalities and First Nations when the permits were initially applied for or when there is an appeal proceeding after permits are issued.The delay or denial of a permit or the imposition of conditions that are costly or difficult to comply with can impair or even prevent the development of a project orcan increase the cost so substantially that the project is no longer attractive to us.Ontario Renewable Energy ApprovalsOur projects in Ontario are subject to Ontario’s Environmental Protection Act , which requires proponents of significant renewable energy projects to obtain aRenewable Energy Approval (REA). The REA application requires a variety of studies on environmental, archeological and heritage issues. Significant publicconsultation, as well as consultation with indigenous communities, is also required. Before issuing a REA, the Ontario Ministry of the Environment evaluates abroad range of potential impacts, including on wildlife, wetlands and water resources, communities, scenic areas, species and heritage resources, as well as impactson people. This review can be time consuming and expensive, and an approval can be rejected or approved with conditions that are costly or difficult to complywith. REAs are also subject to appeal by third parties and can result and have resulted in lengthy appeal tribunal hearings.Quebec Environmental Impact AssessmentQuebec`s Environmental Impact Assessment (EIA) is a required permit for wind energy projects with a nameplate capacity above 10 MW. The EIA requires avariety of studies related to environmental, archeological and heritage issues. Significant public consultation, as well as consultation with indigenous communities,is also required. The culmination of this permitting process is the issuing of a project specific decree by the provincial council of ministers. Before issuing thedecree, the Quebec Ministry of Environment evaluates a broad range of potential impacts, including on wildlife, wetlands and water resources, communities, scenicareas, species and heritage resources, as well as impacts on people.Quebec Commission for the Protection of Agricultural LandIn addition to the EIA process, the other major permit in Quebec is granted by the Quebec Commission for the Protection of Agricultural Land. This permit is onlyrequired on land that is zoned agricultural. This permitting body will push proponents to minimize footprints during both the construction phase and the operationsphase.Manitoba Environment ActThe Manitoba Environment Act requires proponents of significant projects to submit a proposal with the Manitoba Conservation Environmental Assessment &Licensing Branch, and to comply with Manitoba’s environmental assessment process under the Environment Act . This process will consider a similar range ofimpacts on the environment, the heritage and scenic values of an area and on people, communities and wildlife as the Ontario process, and brings with it similarrisks.Endangered Species LegislationOur Canadian renewable energy projects may be subject to endangered species legislation, either federally or provincially, which prohibits and imposes stringentpenalties for harming endangered or threatened species and their habitats. Our projects may also be subject to the Migratory Birds Convention Act , which protectsthe habitat of migratory species, and which may also trigger federal "Species at Risk" requirements. Because the operation of wind turbines may result in injury orfatalities to birds and bats, avian and bat risk assessments are generally required both prior to permits being issued for projects and after commercial operations. InOntario, if any of the affected species are listed as endangered or threatened, permits under the Endangered Species Act may also be required.Other ApprovalsOur Canadian projects, and any future projects we may acquire, are subject to a variety of other federal, provincial and municipal permitting and zoningrequirements. Most provinces where our projects are located or may be located have laws that require provincial agencies to evaluate a broad array ofenvironmental impacts before granting permits and approvals. These agencies evaluate similar issues as the permitting regimes above, including impact onwildlife, historic sites, aesthetics, wetlands and water resources, scenic areas, endangered and threatened species and communities. In addition, federal governmentapprovals dealing with, among other things, aeronautics,20fisheries, navigation or species protection may be required and could in some cases trigger additional environmental assessment requirements. Additionalrequirements related to the permitting of transmission lands may be applicable in some cases. Our projects are also subject to certain municipal requirements,including land use and zoning requirements except where superseded by Ontario’s Green Energy and Green Economy Act, 2009 , as well as requirements forbuilding permits and other municipal approvals that can be difficult or costly to comply with and impair or prevent the development of a project.Environmental Matters – ChileWe are required to obtain a range of environmental permits and other approvals from various governmental agencies in Chile to build and operate our projects,including, but not limited to, items described below.Ministry of EnvironmentThe Ministry of the Environment is responsible for the formulation and implementation of environmental policies, including those affecting the wind industry,plans and programs, as well as for the formulation of environmental quality and emission standards, the protection and conservation of biological diversity,renewable natural resources and water resources, and for promoting sustainable development and the integrity of environmental policy and regulations.Environmental Assessment ServiceThe Environmental Assessment Service is responsible for assessing whether projects that might have an adverse effect on the environment, including windprojects, comply with Chilean environmental laws and regulations.Superintendency of EnvironmentThe Superintendency of the Environment’s primary responsibilities are monitoring compliance with the terms of the corresponding environmental licenses, as wellas monitoring compliance with government plans to prevent environmental damage or to clean or restore contaminated geographical areas. The Superintendency ofthe Environment has the power to suspend activities that it deems to have an adverse environmental impact, even if such activities comply with a previouslyapproved environmental impact assessment. In case of noncompliance with environmental regulations, it is enabled to apply fines, revoke the environmentallicense of a project or determine its closure.The Environmental Courts, and Health and SafetyThe Environmental Courts are principally responsible for hearing appeals of determinations made by the Superintendency of the Environment and for adjudicatingclaims for environmental damage.Companies in the wind energy sector, like all companies, must comply with the general principles concerning employee health and safety contained in the ChileanSanitary Code, Labor Code and other labor and health regulations. The Chilean Health Ministry and the Department of Labor are responsible for the enforcementof those standards, with the authority to impose fines among other sanctions. In addition, the Superintendence of Electricity and Fuels has the responsibility tomonitor compliance and also the authority to impose fines and stop operations of violators.Management, Disposal and Remediation of Hazardous SubstancesWe own and lease real property and may be subject to requirements regarding the storage, use and disposal of petroleum products and hazardous substances,including spill prevention, control and counter-measure requirements. If our owned or leased properties are contaminated, whether during or prior to our ownershipor operation, we could be responsible for the costs of investigation and cleanup and for any related liabilities, including claims for damage to property, persons ornatural resources. That responsibility may arise even if we were not at fault and did not cause or were not aware of the contamination. In addition, waste wegenerate is at times sent to third-party disposal facilities. If those facilities become contaminated, we and any other persons who arranged for the disposal ortreatment of hazardous substances at those sites may be jointly and severally responsible for the costs of investigation and remediation, as well as for any claimsfor damage to third parties, their property or natural resources.EmployeesAs of December 31, 2017, we had 210 full-time employees. None of our employees are represented by a labor union or covered by any collective bargainingagreement.21Available InformationWe make our United States Securities and Exchange Commission (SEC) filings, including our annual report on Form 10-K, quarterly reports on Form 10-Q,current reports on Form 8-K, and any amendments to those reports, available free of charge on our website, www.patternenergy.com, as soon as reasonablypracticable after those documents are electronically filed with or furnished to the SEC. The information and materials available on our website are not incorporatedby reference into this Form 10-K. The SEC maintains a website that contains reports, proxy and information statements, and other information regarding registrantsthat file electronically with the SEC at www.sec.gov.Item 1A.Risk Factors.RISK FACTORSYou should carefully consider the following risks, together with other information provided to you in this Form 10-K. If any of the following risks were to occur,our business prospects, financial condition, results of operations and liquidity could be materially adversely affected. In that case, we might have to decrease, ormay not be able to pay, dividends on our Class A shares, the trading price of our Class A shares could decline and you could lose all or part of your investment.The risks described below are not the only risks facing our company. Risks and uncertainties not currently known to us or that we currently deem to be immaterialalso may materially adversely affect our business prospects, financial condition and results of operations and liquidity.Risks Related to Our ProjectsElectricity generated from wind energy depends heavily on suitable wind conditions and wind turbines being available for operation. If wind conditions areunfavorable or below our expectations, or our wind turbines are not available for operation, our projects’ electricity generation and the revenue generatedfrom our projects may be substantially below our expectations.The revenue generated by our projects is principally dependent on the number of MWh generated in a given time period. The quantity of electricity generationfrom a wind power project depends heavily on wind conditions, which are variable. Variability in wind conditions can cause our project revenues to varysignificantly from period to period. We base our decisions about which projects to acquire as well as our electricity generation estimates, in part, on the findings oflong-term wind and other meteorological studies conducted on the project site and its region, which measure the wind’s speed, prevailing direction and seasonalvariations. Projections of wind resources also rely upon assumptions about turbine placement, wind turbine power curves, interference between turbines and theeffects of vegetation, land use and terrain, which involve uncertainty and require us to exercise considerable judgment. We may make incorrect assumptions inconducting these wind and other meteorological studies. Any of these factors could cause our projects to generate less electricity than we expect and reduce ourrevenue from electricity sales, which could have a material adverse effect on our business prospects, financial condition and results of operations.Even if an operating project’s historical wind resources are consistent with our long-term estimates, the unpredictable nature of wind conditions often results indaily, monthly and yearly material deviations from the average wind resources we may anticipate during a particular period. If the wind resources at a project arematerially below the average levels we expect for a particular period, our revenue from electricity sales from the project could correspondingly be less thanexpected. A diversified portfolio of projects located in different geographical areas tends to reduce the magnitude of the deviation, but material deviations may stilloccur. Our cash available for distribution is most directly affected by the volume of electricity generated and sold by our projects. However, for a static portfolio ofprojects, our consolidated expenses, including operating expenses and interest payments on indebtedness, have less variability than the volume of electricitygenerated and sold. Accordingly, decreases in the volume of electricity generated and sold by our projects typically result in a proportionately greater decrease inour cash available for distribution. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operation-Factors that SignificantlyAffect our Business-Factors Affecting our Operational Results-Electricity Sales and Energy Derivative Settlements of Our Operating Projects.”A reduction in electricity generation and sales, whether due to the inaccuracy of wind energy assessments or otherwise, could lead to a number of material adverseconsequences for our business, including:•our projects’ failure to produce sufficient electricity to meet our commitments under our PPAs, hedge arrangements or contracts for sale of RECs, whichcould result in our having to purchase electricity or RECs on the open market to cover our obligations or result in the payment of damages or thetermination of a PPA;22•our projects not generating sufficient cash flow to make payments of principal and interest as they become due on project-related debt, or distributingsufficient cash flow to pay dividends to holders of our Class A shares. For example, certain of our projects have experienced lower than expectedproduction and merchant power prices resulting in those projects failing to pass financial tests that measure cumulative cash distributions to the members.This has in the past, and may in the future, result in a temporary change of the cash percentage to be directed to the tax equity members until the shortfall isremedied. See “-Risks Related to Ownership of our Class A Shares - Our cash available for distribution to holders of our Class A shares may be reduced asa result of restrictions on our subsidiaries’ cash distributions to us under the terms of their indebtedness;” and•our projects’ hedging arrangements being ineffective or more costly.Our projects rely on a limited number of key power purchasers.There are a limited number of possible power purchasers for electricity and RECs produced in a given geographic location. Because our projects depend on sales ofelectricity and RECs to certain key power purchasers, our projects are highly dependent upon these power purchasers fulfilling their contractual obligations undertheir respective PPAs. Our projects’ power purchasers may not comply with their contractual payment obligations or may become subject to insolvency orliquidation proceedings during the term of the relevant contracts and, in such event, we may not be able to find another purchaser on similar or favorable terms orat all. In addition, we are exposed to the creditworthiness of our power purchasers and there is no guarantee that any power purchaser will maintain its credit rating,if any. For example, the power purchaser at our Santa Isabel project in Puerto Rico has been experiencing difficulties as further described in the following riskfactor. To the extent that any of our projects’ power purchasers are, or are controlled by, governmental entities, our projects may also be subject to legislative orother political action that impairs their contractual performance. In addition to the failure by any key power purchasers to meet their contractual commitments orthe insolvency or liquidation of one or more of our power purchasers, we note that our key power purchasers may seek to renegotiate or terminate PPAs that werecontracted for at a time when the prices for power were higher than they may currently be in the relevant markets by asserting that we have not performed ourobligations under our contractual commitments under a PPA. Each such situation could have a material adverse effect on our business prospects, financialcondition and results of operations.The power purchaser at our Santa Isabel project in Puerto Rico has been experiencing difficulties that have affected our Santa Isabel project.Our 101 MW Santa Isabel project located on the south coast of Puerto Rico sells 100% of its electricity generation including environmental attributes to PuertoRico Electric Power Authority (PREPA) under a 20-year PPA. On July 2, 2017, the Financial Oversight and Management Board (or Oversight Board) establishedpursuant to the Puerto Rico Oversight, Management, and Economic Stability Act (or PROMESA) with oversight authority over the Commonwealth of Puerto Ricoand its agencies, including PREPA, filed a voluntary petition for relief for PREPA in the U.S. District Court for the District of Puerto Rico. The petition was filedpursuant to PROMESA thereby commencing a case under Title III thereof which is a specific statutory vehicle that allows the Commonwealth of Puerto Rico andits instrumentalities, such as PREPA, to adjust their debt (similar to a bankruptcy proceeding). While PREPA has previously made payments of amounts due underthe PPA for production, including full payment for all pre-petition receivables, no assurances can be given that PREPA will pay future receivables. Furthermore,under the Title III proceeding, PREPA and the Oversight Board will eventually need to determine whether to assume the PPA or reject the PPA, subject to courtapproval. A rejection of the PPA would likely have a material adverse effect on our business prospects, financial condition and results of operations. The fact ofPREPA’s insolvency and its filing under Title III each constituted an event of default under the project’s financing agreement. However, in August 2017, thelender issued a letter withdrawing the event of default associated with the PREPA insolvency. Pursuant to our agreement with the lender, the Santa Isabel projectmay not make distributions to us until such time as lender consents (which will not be unreasonably withheld if PREPA assumes the PPA). Despite suchagreement, no assurances can be given that PREPA will determine to assume the PPA, will not take actions that separately constitute an event of default under ourfinancing agreement, or that Santa Isabel will be able to remain current with respect to its payments under the financing agreement. In any such event, anotherevent of default under the financing agreement would occur and no assurances can be given that the lender would agree to a further withdrawal, waiver or otherstandstill of any such other event of default, or the lender would not otherwise decide in such circumstance to accelerate and declare the entire amount of debtunder the financing agreement immediately due and payable. Even though the Santa Isabel financing agreement is non-recourse to us, it is secured by the SantaIsabel project and any exercise of remedies by the lender could have a material adverse effect on our business prospects, financial condition and results ofoperations. In addition, on September 20, 2017, Hurricane Maria, a category 4 hurricane, made direct landfall on Puerto Rico and caused substantial damage toPREPA’s electricity transmission and distribution assets. PREPA asserted a force majeure event under the PPA with respect to its assets, claiming relief of itsobligations to perform substantially all of its obligations under the PPA, except its obligation to make payments thereunder. While our project equipment did notsuffer significant damage, Santa Isabel was not authorized to return to service by PREPA due to system reliability issues until mid-February 2018 and, even afterreturning to service, remains heavily curtailed. No assurances can be given as to if or when Santa Isabel may begin to operate at its full capacity.23In connection with the asserted force majeure event, PREPA stated that immediately after Hurricane Maria, PREPA believed approximately 80% of its energytransmission and distribution infrastructure had been damaged, resulting in PREPA being unable to provide electrical power to the majority of its customers. Highdisaster recovery costs coupled with negligible utility billings of its customers due to interruption of service have contributed to a short term liquidity constraintthat PREPA has acknowledged and which is limiting its ability to pay suppliers timely. Further, given the current condition of PREPA’s transmission anddistribution assets and the logistical complexity associated with remediating the damage, no assurances can be given as to when the asserted force majeure underthe PPA might abate and PREPA’s timely performance might resume under the PPA, or how the disruption will affect PREPA’s bankruptcy-like proceedingsunder Title III of the PROMESA (including any decision by PREPA whether to assume the Santa Isabel PPA).A prolonged environment of low prices for natural gas, other conventional fuel sources, or competing renewable resources could have a material adverse effecton our long-term business prospects, financial condition and results of operations.Historically low prices for traditional fossil fuels, particularly natural gas, could cause demand for wind power and solar power to decrease and adversely affect theprice of the electricity we generate for sale on a spot-market basis. In addition, excessive building of competing renewable resources in a limited geographic arearesulting in congestion and potential curtailment could also adversely affect pricing available on the spot-market. See Item 7A "Quantitative and QualitativeDisclosures about Market Risk-Commodity Price Risk." Low spot-market power prices, if combined with other factors, could have a material adverse effect on ourresults of operations and cash available for distribution. Additionally, cheaper conventional fuel sources or competing renewable resources could also have anegative impact on the power prices we are able to negotiate upon the expiration of our current power sale agreements or upon entering into a power saleagreement for a subsequently acquired power project. As a result, the price of our electricity or RECs subject to the open market could be materially and adverselyaffected, which could, in turn, have a material adverse effect on our results of operations and cash available for distribution.Operation and maintenance problems at our renewable energy projects including natural events may cause our electricity generation to fall below ourexpectations.Our electricity generation levels depend upon our ability to maintain the working order of our wind turbines and balance of the plant. A natural disaster, severeweather, accident, failure of major equipment, shortage of or inability to acquire critical replacement or spare parts, failure in the operation of any futuretransmission facilities that we may acquire, including the failure of interconnection to available electricity transmission or distribution networks, could damage orrequire us to shut down our turbines or related equipment and facilities, impeding our ability to maintain and operate our facilities and decreasing electricitygeneration levels and our revenues. For example, Hurricane Maria resulted in damage to PREPA’s transmission and distribution assets that caused our Santa Isabelproject in Puerto Rico to be shut-in until mid-February 2018. The power purchaser at our Santa Isabel project in Puerto Rico has been experiencing difficulties thathave affected our Santa Isabel project. In addition, several of our projects had previously experienced blade failures, and no assurances can be given that potentialequipment deficiencies will not in fact continue to occur, that we will always have warranty coverage for any such defects, that the warranty provider would fulfillits obligations under such warranty coverage (including any liquidated damages compensation provisions), or that any such effects will not have a material adverseeffect on our business prospects, financial condition and results of operation.We typically enter into warranty agreements with the turbine manufacturer for two to ten-year terms, however, such agreements are typically subject to anaggregate maximum liability cap and there can be no assurance that the manufacturer or third-party service provider will be able to fulfill its contractualobligations. In addition, such agreements can vary as to what equipment maintenance risks are fully assumed by the service provider and what equipment failurerisks will be repaired at the owner’s cost.As warranty terms with the manufacturer expire, we have entered and intend to continue entering into revised long-term turbine manufacturer service arrangementsat certain of our projects pursuant to which the turbine manufacturer continues to provide routine and corrective maintenance service, but we are responsible for aportion of the maintenance and repairs, including on major component parts. While the revised service arrangements reduce fixed contract costs, in the event ofunexpectedly high turbine component failures for which we as owner have assumed responsibility, we may face decreased revenues of a project and increasedproject expense which could have a material adverse effect on our business prospects, financial condition, results of operations and ability to make cashdistributions to our investors. We expect over time in the future to continue taking on additional risks as an owner, including increased self-performance ofmaintenance and service work with our own technicians instead of utilizing service providers, which will have expected cost benefits, but will similarly come withadditional increased risks and reduced third party warranty and guarantee protections.Replacement and spare parts for wind turbines and key pieces of electrical equipment may be difficult or costly to acquire or may be unavailable. Sources for somesignificant spare parts and other equipment are often located outside of the jurisdictions in which our power projects operate. Additionally, our operating projectsgenerally do not hold spare substation main transformers. These transformers are designed specifically for each wind power project, and order lead times can belengthy. If one of our projects had to replace any of its24substation main transformers, it would be unable to sell all of its power until a replacement is installed. To the extent we experience a prolonged interruption at oneof our operating projects due to natural events or operational problems and such events are not fully covered by insurance, our electricity generation levels andrevenues could materially decrease, which could have a material adverse effect on our business prospects, financial condition and results of operation.Climate change may have the long-term effect of changing wind patterns at our projects which could have a material adverse effect on our business prospects,financial condition, results of operations and ability to make cash distributions to our investorsClimate change may have the long-term effect of changing wind patterns at our projects. Changing wind patterns could cause changes in expected electricitygeneration. These events could also degrade equipment or components and the interconnection and transmission facilities’ lives or maintenance costs. We may facedecreased revenues of a project and increased project expense which could have a material adverse effect on our business prospects, financial condition, results ofoperations and ability to make cash distributions to our investors.Many of our projects have limited operating history and our growth may make it difficult for us to manage our project expansion efficiently.We have a relatively new portfolio of assets, including several projects that have only recently commenced commercial operations. Stockholders should considerour prospects in light of the risks and uncertainties growing companies encounter in rapidly evolving industries such as ours. Also, our anticipated near-termgrowth could make it difficult for us to manage our project expansion efficiently due to an inability to employ a sufficient number of skilled personnel or otherwiseto effectively manage our capital expenditures and control our costs, including the requisite general and administrative costs necessary to achieve our anticipatedgrowth. These challenges could adversely affect our ability to manage our current or future operating projects in an efficient manner and complete construction ofany construction projects in a timely manner, either of which could have a material adverse effect on our business prospects, financial condition and results ofoperation.Our operations are subject to numerous environmental, health and safety laws and regulations.Our projects are subject to numerous environmental, health and safety laws and regulations in each of the jurisdictions in which our projects operate or willoperate. These laws and regulations require our projects to obtain and maintain permits and approvals, undergo environmental impact assessments and reviewprocesses and implement environmental, health and safety programs and procedures to control risks associated with the siting, construction, operation anddecommissioning of power projects. For example, to obtain permits some projects are, in certain cases, required to undertake programs to protect and maintainlocal endangered or threatened species. If such programs are not successful, our projects could be subject to increased levels of mitigation, penalties or revocationof our permits.Violations of environmental and other laws, regulations and permit requirements, including certain violations of laws protecting wetlands, migratory birds, baldand golden eagles and threatened or endangered species, may also result in criminal sanctions or injunctions. In addition, if our projects do not comply withapplicable laws, regulations or permit requirements, or if there are endangered or threatened species fatalities at our projects, we may be required to pay penaltiesor fines or curtail or cease operations of the affected projects. For example, in connection with a permit we obtained at our Spring Valley wind facility, we had toadopt a mitigation plan with respect to injuries and fatalities to golden eagles, and were required to establish a process in the event of incidents, including reportingto the U.S. Fish and Wildlife Service. We have followed such required processes in connection with three golden eagle incidents since January 1, 2013, and, inaddition, we have filed an application for an eagle take permit which is under consideration by the U.S. Fish and Wildlife Service. While we have entered into anagreement with U.S. Fish and Wildlife to fund additional research into mitigation measures and incurred nominal fines with respect to the prior eagle incidents, noassurances can be given that we will not be required to implement further increased levels of mitigation, or face additional penalties, fines, or other measures as aresult of golden eagle incidents at our Spring Valley facility or any of our other wind facilities. In addition, no assurances can be given that our eagle take permitwill be approved.Certain environmental laws impose liability on current and previous owners and operators of real property for the cost of removal or remediation of hazardoussubstances, even if the owner or operator did not know of, or was not responsible for, the release of such hazardous substances. In addition to actions brought bygovernmental agencies, private plaintiffs may also bring claims arising from the presence of hazardous substances on a property or exposure to such substances.Our projects’ liabilities at properties we own or operate arising from past releases of, or exposure to, hazardous substances could have a material adverse effect onour business prospects, financial condition and results of operations.Environmental, health and safety laws, regulations and permit requirements may change and become more stringent. Any such changes could require our projectsto incur additional material costs or cause our projects to suffer adverse consequences. For example, the Ministry25of Environment in Ontario has established regulatory requirements governing noise restrictions for wind farms which are an integral part of the permittingframework for our projects in certain jurisdictions. In the event of changes in either the regulatory requirements or permitting framework, there is risk that ourprojects that were designed for compliance within the existing framework and requirements for noise could still be evaluated by regulators as noncompliant. Theserisks are enhanced because testing for compliance with noise requirements is technically complex, carries some degree of uncertainty, and does not have significantprecedent in that market. In the event of a determination of noncompliance, there is risk that the necessary mitigation, which would likely need to occur duringperiods of higher wind speeds, could require curtailment of energy production at the facility, with a resulting reduction in revenues.Our projects’ costs of complying with current and future environmental, health and safety laws, regulations and permit requirements (including any change in noiseregulations), and any liabilities, fines or other sanctions resulting from violations of them, could have a material adverse effect on our business prospects, financialcondition and results of operations.We may be unable to complete any future construction projects on time, and our construction costs could increase to levels that make a project too expensive tocomplete or make the return on our investment in that project less than expected.While we have agreements to acquire projects in construction, including Mont Sainte-Marguerite, Ohorayama and Tsugaru, which is in construction, we currentlydo not own any projects in construction. There may be delays or unexpected developments in completing any of our own future construction projects, which couldcause the construction costs of these projects to exceed our expectations. Our construction projects would typically be designed and constructed under fixed-priceand schedule engineering, procurement, and construction contracts with reputable construction and equipment suppliers, and would typically have liquidateddamages provisions for non-performance by the contractors subject to specified limitations on the amount of damages we can recover from the contractor. We maysuffer significant construction delays or construction cost increases as a result of underperformance of these contractors and equipment suppliers, as well as othersuppliers, to our projects. No assurances can be given that disputes with project construction providers will not arise in the future. While we will attempt to reach asettlement if disputes do arise, no assurances can be given that we would actually reach a settlement or that any such settlement amount would be covered by theremaining budgeted project contingencies. If an equitable settlement cannot be reached, arbitration or legal action could be commenced, and any final judgment ordecision could result in increased costs which could make the return on our investment in the project less than expected.Additionally, various other factors could contribute to construction-cost overruns and construction delays, including:•inclement weather conditions;•failure to receive generating equipment or other critical components and equipment necessary to maintain the operating capacity of our projects, in a timelymanner or at all;•failure to complete interconnection to transmission networks, which relies on several third parties, including interconnection facilities provided by localutilities;•failure to maintain all necessary rights to land access and use;•failure to receive quality and timely performance of third-party services;•failure to maintain environmental and other permits or approvals;•failure to meet domestic content requirements;•appeals of environmental and other permits or approvals that we hold;•lawful or unlawful protests by or work stoppages resulting from local community objections to a project;•shortage of skilled labor on the part of our contractors;•adverse environmental and geological conditions; and•force majeure or other events out of our control.Any of these factors could give rise to construction delays and construction costs in excess of our expectations. These circumstances could prevent our constructionprojects from commencing operations or from meeting our original expectations about how much electricity26they will generate or the returns they will achieve. In addition, substantial delays could cause defaults under our financing agreements or under PPAs that requirecompletion of project construction by a certain date at specified performance levels or could result in the loss or reduction of expected tax benefits. Our inability totransition construction projects into financially successful operating projects would have a material adverse effect on our business prospects, financial conditionand results of operations and our ability to pay dividends.Our projects rely on interconnections to transmission lines and other transmission facilities that are owned and operated by third parties which exposes us torisks. Our projects are also exposed to interconnection and transmission facility development and curtailment risks, which may delay the completion of anyconstruction projects or reduce the return to us on those investments.Our projects depend upon interconnection to electric transmission lines owned and operated by regulated utilities to deliver the electricity we generate. A failure ordelay in the operation or development of these interconnection or transmission facilities could result in our losing revenues because such a failure or delay couldlimit the amount of power our operating projects deliver or delay the completion of any construction projects. For example, we have experienced situations wherethe substation to which a project was required to deliver power under its PPA had been shut down for maintenance and we needed to then take steps to mitigate thetransmission outage at the delivery substation, including making alternative transmission arrangements to deliver power at an alternative substation throughalternative short term transmission and revenue arrangements and selling environmental attributes to a third party. If similar circumstances occurred in the future,there could be no assurances that we would be able to make alternative transmission arrangements or the revenues produced from any alternative arrangementswould be equivalent to the revenues that would have been generated had such transmission outage not occurred. Furthermore, individual alternative arrangementsmade to mitigate the transmission outage may present their own risks, such as possible curtailment risks on the alternative transmission arrangements or pricingrisks in the merchant power market, which could adversely affect the overall efficacy of any mitigation efforts. If we were unable to mitigate potential losses, otherfuture sustained transmission outages at a delivery substation could have a material adverse effect on our business prospects, financial condition and results ofoperations.In addition, certain of our operating projects’ generation of electricity may be curtailed without compensation (or, in some cases, choose to continue operating butaccept negative power prices) due to transmission limitations or limitations on the electricity grid’s ability to accommodate intermittent electricity generatingsources, reducing our revenues and impairing our ability to capitalize fully on a particular project’s potential. Such a failure or curtailment at levels above ourexpectations could have a material adverse effect on our business prospects, financial condition and results of operations. For example, in certain geographic areasin the Electric Reliability Council of Texas (ERCOT) market in Texas, construction of renewable energy projects has exceeded the available capacity of theexisting transmission infrastructure resulting in localized congestion on transmission facilities utilized by certain of our projects. While these projects havefinancial hedges that partially protect revenues against movement in broader power markets, these instruments generally do not provide protection against localizedcongestion impacts, which are borne by the projects. In addition, planned or forced outages of transmission circuits in such strained areas of the grid can, and has,compounded the adverse impact on our operations. While efforts to construct additional transmission facilities are underway, there is no assurance that suchadditional facilities will be sufficient to relieve congestion, or that construction of new generation facilities will not continue to exceed the capacity of any addedtransmission in the future.In addition to the risks described above regarding the broader electric grid, many of our projects also own private transmission lines to deliver our power toavailable electricity transmission or distribution networks. In some cases, these facilities may span significant distances. A failure in our operation of thesefacilities that causes the facilities to be temporarily out of service, or subject to reduced service, could result in lost revenues because it could limit the amount ofelectricity our operating projects are able to deliver. In addition, in many of the markets in which we operate or are looking to expand operations, should there beany excess capacity available in those generator lead facilities, and should a third party request access to such capacity, the relevant regulatory authority in suchjurisdiction, such as FERC in the United States, or other authorities might, require our projects to provide service over such facilities for that excess capacity to therequesting third party at regulated rates. Should this occur in markets with such regulations, the projects could be subject to additional regulatory risks and costlycompliance burdens associated with being considered the owner and operator of a transmission facility.The loss of one or more of our executive officers or key employees may adversely affect our ability to effectively manage our operating projects and completeany construction projects on schedule.We depend on our experienced management team and the loss of one or more key executives could have a negative impact on our business. We also depend on ourability to retain and motivate key employees and attract qualified new employees. Because the wind power industry is relatively new, there is a scarcity ofexperienced employees in the wind power industry. We may not be able to replace departing members of our management team or key employees. Integrating newexecutives into our management team and training new employees with no prior experience in the power industry could prove disruptive to our projects, require adisproportionate amount of resources and management attention and ultimately prove unsuccessful. An inability to attract and retain sufficient technical andmanagerial personnel27could limit our ability to effectively manage our operating projects and complete any construction projects on schedule and within budget, which could have amaterial adverse effect on our business prospects, financial condition and results of operations.The employee transfer may adversely affect our costs.Under the Amended and Restated Multilateral Management Services Agreement (“A&R Multilateral Services Agreement”) we entered into with both PatternDevelopment 1.0 and Pattern Development 2.0 in June 2017, we continue to have the option to cause the employees of Pattern Development 1.0 to become ouremployees. We refer to this event as the Pattern Development 1.0 employee transfer, and we may effect such employee transfer after the earliest to occur of noticefrom Pattern Development 1.0 that it will be completing a wind-down, June 16, 2020, and the failure of Pattern Development 1.0 to provide the resources andservices called for under the A&R Multilateral Services Agreement after notice and opportunities to cure. In addition, while Pattern Development 2.0 currentlydoes not have any employees, the A&R Multilateral Services Agreement provides for certain circumstances pursuant to which we can require Pattern Development2.0 to cause its employees (if any) to become our employees. We refer to this event as the Pattern Development 2.0 employee transfer. Following the occurrence ofeither a Pattern Development 1.0 employee transfer event or (in the event Pattern Development 2.0 has employees) a Pattern Development 2.0 employee transferevent, we will be faced with increased costs associated with employing a larger number of employees. If either Pattern Development 1.0 or Pattern Development2.0 reduce the scope of their development activities and are therefore not paying us for the services of the transferred employees pursuant to the terms of the A&RMultilateral Services Agreement and our development activities remain insignificant, we may not immediately require the services of all such employees. Suchevents could have a material adverse effect on our business prospects, financial condition and results of operation.Our use and enjoyment of real property rights for our projects may be adversely affected by the rights of lienholders and leaseholders that are superior to thoseof the grantors of those real property rights to our projects.Our projects generally are, and any of our future projects are likely to be, located on land occupied pursuant to long-term easements, leases and rights-of-way. Theownership interests in the land subject to these easements, leases and rights-of-way may be subject to mortgages securing loans or other liens (such as tax liens)and other easement, lease rights and rights-of-way of third parties (such as leases of oil or mineral rights) that were created prior to our projects’ easements, leasesand rights-of-way. As a result, certain of our projects’ rights under these easements, leases or rights-of-way may be subject, and subordinate, to the rights of thosethird parties. We perform title searches, obtain title insurance and enter into non-disturbance agreements to protect ourselves against these risks. Such efforts may,however, be inadequate to protect our operating projects against all risk of loss of our rights to use the land on which our projects are located, which could have amaterial adverse effect on our business prospects, financial condition and results of operations. In addition, certain lands, such as lands under the jurisdiction of theUnited States Department of Interior's Bureau of Land Management (BLM), are subject to contractual rights that permit the BLM to periodically adjust rent due onproperties and other obligations, such as the amount of required reclamation security, to market terms. Any such loss or curtailment of our rights to use the land onwhich our projects are located, any increase in rent due, or any increase in other obligations with respect to such lands could have a material adverse effect on ourbusiness prospects, financial condition and results of operations.Our operating projects are, and other future projects may be, subject to various governmental regulations, approvals, and compliance requirements thatregulate the sale of electricity, which could have a material adverse effect on our business prospects, financial condition and results of operations.Our current projects in operation in the United States are operating as EWGs as defined under PUHCA and therefore are exempt from certain regulation underPUHCA. Other than Gulf Wind, Panhandle 1, Panhandle 2, and Logan’s Gap, our operating projects in the United States are, however, public utilities under theFederal Power Act subject to rate regulation by FERC. Our future projects in the United States will also likely be subject to such rate regulation once they areplaced into service. Our projects in the United States that are subject to FERC rate regulation are required to obtain acceptance of their rate schedules for wholesalesales of energy ( i.e. , not retail sales to consumers), capacity and ancillary services, including their ability to charge “market-based rates.” FERC may revoke orrevise an entity’s authorization to make wholesale sales at market-based rates if FERC subsequently determines that such entity and its affiliates can exercisehorizontal or vertical market power, create barriers to entry or engage in abusive affiliate transactions or market manipulation. In addition, public utilities in theUnited States are subject to FERC reporting requirements that impose administrative burdens and that, if violated, can expose the company to criminal and civilpenalties or other risks.Most of our North American projects are located in regions in which the wholesale electric markets are administered by ISOs and RTOs. Several of our currentoperating projects are subject to CAISO which is the ISO that prescribes rules for the terms of participation in the California energy market; the ERCOT, which isthe ISO that prescribes the rules for and terms of participation in the Texas energy market; and IESO, which is the ISO that administers the wholesale electricitymarket in Ontario. The Southwest Power Pool is the RTO and regional market administrator for our Post Rock project. Lost Creek is in the Associated ElectricCooperative, Inc. a subregion of the SERC Reliability Corporation. Amazon Wind is in the PJM RTO. Many of these entities can impose rules, restrictions andterms of service28that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, ISOs and RTOs have developed bid-based locationalpricing rules for the energy markets that they administer. In addition, most ISOs and RTOs have also developed bidding, scheduling and market behavior rules,both to curb the potential exercise of market power by electricity generating companies and to ensure certain market functions and system reliability. These actionscould materially adversely affect our ability to sell, and the price we receive for, our energy, capacity and ancillary services.All of our current operating projects located in North America are also subject to the reliability standards of the NERC. If we fail to comply with the mandatoryreliability standards, we could be subject to sanctions, including substantial monetary penalties. Although our U.S. projects are not subject to state utility regulationbecause our projects sell power exclusively on a wholesale basis, we are subject to certain state regulations that may affect the sale of electricity from our projects,the operations of our projects, as well as the potential for state electricity taxes. All of our current operating projects in Canada are subject to exclusive provincialregulatory authority with respect to the generation and production of electricity, which varies across provincial jurisdictions. Changes in regulatory treatment at thestate and provincial level are difficult to predict and could have a significant impact on our ability to operate and on our financial condition and results ofoperations.Our industry could be subject to increased regulatory oversight.Our industry could be subject to increased regulatory oversight. Changing regulatory policies and other actions by governments and third parties with respect tocurtailment of electricity generation, electricity grid management restrictions, interconnection rules and transmission may all have the effect of limiting therevenues from, and increasing the operating costs of, our projects which could have a material adverse effect on our business, financial condition and results ofoperations.Due to regulatory restructuring initiatives at the federal, provincial and state levels, the electricity industry has undergone changes over the past several years.Future government initiatives will further change the electricity industry. Some of these initiatives may delay or reverse the movement towards competitivemarkets. We cannot predict the future design of wholesale power markets or the ultimate effect that on-going regulatory changes will have on our businessprospects, financial condition and results of operations.Our projects are not able to insure against all potential risks and may become subject to higher insurance premiums.Our projects are exposed to the risks inherent in the construction and operation of wind, solar and transmission power projects, such as breakdowns, manufacturingdefects, natural disasters, terrorist attacks and sabotage. We are also exposed to environmental risks. We have insurance policies covering certain risks associatedwith our business. Our insurance policies do not, however, cover losses as a result of certain force majeure events or terrorism. In addition, our insurance policiesfor our projects may cover losses as a result of certain types of natural disasters or sabotage, among other things, but such coverage is not always available in theinsurance market on commercially reasonable terms and is often capped at predetermined limits that may not be adequate. Our insurance policies are subject toannual review by our insurers and may not be renewed on similar or favorable terms or at all. A serious uninsured loss or a loss significantly exceeding the limitsof our insurance policies could have a material adverse effect on our business prospects, financial condition and results of operations.Currency exchange rate fluctuations may have an impact on our financial results and condition.We have exposures to currency exchange rate fluctuations, primarily the Canadian dollar and (commencing in 2018) Japanese yen, related to owning and operatingpart of our business outside of the United States. A portion of our revenue for the years ended December 31, 2017, 2016 and 2015 was denominated in currenciesother than the U.S. dollar, and we expect net revenue from non-U.S. dollar markets to continue to represent a portion of our net revenue. We manage our currencyexposure through a variety of methods, including efforts to match our asset and liabilities in the same currencies, mainly by raising local currency debt. In addition,we have implemented a currency hedging program to, in part, manage short and medium term fluctuations in our dividends from our wind facilities located outsidethe United States. However, any measures that we have implemented or may implement in the future to reduce the effect of currency exchange rate fluctuationsand other risks of our global operations may not be effective or may be expensive. We cannot provide assurance that currency exchange rate fluctuations will nototherwise have a material adverse effect on our financial condition or results of operations or cause significant fluctuations in quarterly and annual results ofoperations.Foreign currency translation risk arises upon the translation of balance sheet and statement of operations items of our non-U.S. dollar denominated subsidiarieswhose functional currency is a currency other than the U.S. dollar into the functional currency and reporting currency of us (which is the U.S. dollar) for purposesof preparing the consolidated financial statements included elsewhere in this Form 10-K presented in U.S. dollars. The assets and liabilities of our non-U.S. dollardenominated subsidiaries are translated at the closing rate at the date of reporting and statement of operations items are translated at the average rate for the period.All resulting exchange differences are recognized in a separate component of equity, “Foreign currency translation, net of tax,” and are recorded in “Othercomprehensive29income (loss), net of tax.” These foreign currency translation differences may have significant negative or positive impacts. Our foreign currency translation riskmainly relates to our operations in Canada and Japan, commencing in 2018.In addition, foreign currency transaction risk arises when we or our subsidiaries enter into transactions where the settlement occurs in a currency other than thefunctional currency of us or our subsidiary. Exchange differences (gains and losses) arising on the settlement of monetary items or on translation of monetary itemsat rates different from those at which they were translated on initial recognition during the period or in previous financial statements are recognized theconsolidated statement of operations in the period in which they arise. In order to reduce significant foreign currency transaction risk from our operating activities,we may use forward currency derivative instruments to hedge forecasted cash inflows and outflows. Furthermore, most non-U.S. dollar denominated debts are heldby non-U.S. dollar denominated subsidiaries in the same functional currency of those subsidiary operations.Our cross-border operations require us to comply with anti-corruption laws and regulations of the U.S. government and various non-U.S. jurisdictions.Doing business in multiple countries requires us and our subsidiaries to comply with the laws and regulations of the U.S. government and various non-U.S.jurisdictions. Our failure to comply with these rules and regulations may expose us to liabilities. These laws and regulations may apply to our companies,individual directors, officers, employees and agents and may restrict our operations, trade practices, investment decisions and partnering activities. In particular,our non-U.S. operations are subject to U.S. and foreign anti-corruption laws and regulations, such as the Foreign Corrupt Practices Act of 1977 (FCPA). The FCPAprohibits U.S. companies and their officers, directors, employees and agents acting on their behalf from corruptly offering, promising, authorizing or providinganything of value to foreign officials for the purposes of influencing official decisions or obtaining or retaining business or otherwise obtaining favorabletreatment. The FCPA also requires companies to make and keep books, records and accounts that accurately and fairly reflect transactions and dispositions ofassets and to maintain a system of adequate internal accounting controls. As part of our business, we deal with state-owned business enterprises, the employees andrepresentatives of which may be considered foreign officials for purposes of the FCPA. As a result, business dealings between our employees or our agents and anysuch foreign official could expose our company to the risk of violating anti-corruption laws even if such business practices may be customary or are not otherwiseprohibited between our company and a private third-party. Violations of these legal requirements are punishable by criminal fines and imprisonment, civilpenalties, disgorgement of profits, injunctions, debarment from government contracts as well as other remedial measures. We have established policies andprocedures designed to assist us and our personnel in complying with applicable U.S. and non-U.S. laws and regulations; however, we cannot assure stockholdersthat these policies and procedures will completely eliminate the risk of a violation of these legal requirements, and any such violation (inadvertent or otherwise)could have a material adverse effect on our business prospects, financial condition and results of operations.We own, and in the future may acquire, certain projects in joint ventures, and our joint venture partners’ interests may conflict with our and our stockholders’interests.We own certain projects in joint ventures, including South Kent, Armow, Grand and K2, in which we have a 50%, 50%, 45% and 33% interest, respectively, andEl Arrayán, in which we have a 70% interest. In addition, in connection with our strategic partnership with PSP Investments, we have joint venture arrangementswith PSP Investments in Meikle in which we have a 51% interest. In December 2017, we also entered into a joint venture arrangement with PSP Investments inconnection with the sale to PSP Investments of 49% of our Class B interests in Panhandle 2. In the future, we may acquire or invest in other projects with a jointventure partner, including certain projects which may be owned by one of the Pattern Development Companies. In addition, our arrangements with PSPInvestments include arrangements in which PSP Investments may co-invest in ROFO projects based on a process that is controlled by us, and we can elect thepercentage interest to offer to PSP Investments in each project, which is expected to range from 30% to 49.9%. Joint ventures inherently involve a lesser degree ofcontrol over business operations, which could result in an increase in the financial, legal, operational or compliance risks associated with a project, including, butnot limited to, variances in accounting and internal control requirements. To the extent we do not have a controlling interest in a project, our joint venture partnerscould take actions that decrease the value of our investment and lower our overall return. In addition, conflicts of interest may arise in the future between ourcompany and our stockholders, on the one hand, and our joint venture partners, on the other hand, where our joint venture partners’ business interests areinconsistent with our and our stockholders’ interests. Further, disagreements or disputes between us and our joint venture partners may arise which could result inlitigation, increase our expenses and potentially limit the time and effort our officers and directors are able to devote to our business, all of which could have amaterial adverse effect on our business prospects, financial condition and results of operations.30Security breaches, including cybersecurity breaches, and other disruptions could compromise our business operations and critical and proprietary informationand expose us to liability, which could adversely affect our business prospects, financial condition and reputation.In the ordinary course of our business, we store sensitive data and proprietary information regarding our business, employees, shareholders, offtakers, serviceproviders, business partners and other individuals in our data center and on our network. Additionally, we use and are dependent upon information technologysystems that utilize sophisticated operational systems and network infrastructure to run our wind farms. Through our 24/7 operations control center, we can, amongother things, monitor and control each wind turbine, monitor regional and local climate, track real time market prices and, for some of our projects, monitor certainenvironmental activities. The secure maintenance of information and information technology systems is critical to our operations. Despite security measures wehave employed, including certain measures implemented pursuant to mandatory NERC Critical Infrastructure Protection standards, our infrastructure may beincreasingly vulnerable to attacks by hackers or terrorists as a result of the rise in the sophistication and volume of cyberattacks. Also, our information andinformation technology systems may be breached due to viruses, human error, malfeasance or other malfunctions and disruptions. Any such attack or breach could:(i) compromise our turbines and wind farms thereby adversely affecting generation and transmission to the grid; (ii) adversely affect our operations; (iii) corruptdata; or (iv) result in unauthorized access to the information stored on our networks, including, company proprietary information and employee data causing theinformation to be publicly disclosed, lost or stolen or result in incidents that could result in harmful effects on the environment and human health, including loss oflife. Any such attack, breach, access, disclosure or other loss of information could result in lost revenue, the inability to conduct critical business functions, legalclaims or proceedings, regulatory penalties, increased regulation, increased protection costs for enhanced cyber security systems or personnel, damage to ourreputation and/or the rendering of our disclosure controls and procedures ineffective, all of which could adversely affect our business prospects, financial conditionand reputation.Risks Related to Future Growth and AcquisitionsThe growth of our business depends on locating and acquiring interests in additional attractive independent power and transmission projects.Our business strategy includes acquiring power projects that are either operational, construction-ready, or in limited circumstances outside of activities conductedby Pattern Development 2.0, under development. We intend to pursue opportunities to acquire projects from third-party owners where we may submit bids fromtime to time, and from each of the Pattern Development Companies pursuant to our respective Purchase Rights. To enhance alignment and allow us to benefit fromdevelopment, we have to date made investments of $102.5 million in Pattern Development 2.0 resulting in an ownership of approximately 21%. We have the right,but not the obligation, to participate in subsequent capital calls for a total commitment of up to $300 million, and if this right is exercised for all future capital calls,this would increase our ownership to approximately 29%.Various factors could affect the availability of attractive projects to grow our business, including:•competing bids for a project, including a project subject to our respective Purchase Rights, from other owners, including companies that may havesubstantially greater capital and other resources than we do;•fewer third-party acquisition opportunities than we expect, which could result from, among other things, available projects having less desirable economicreturns or higher risk profiles than we believe suitable for our business plan and investment strategy;•failure by either of the Pattern Development Companies to complete the development of (i) an Identified ROFO Project, which could result from, amongother things, permitting challenges, failure to procure the requisite financing, equipment or interconnection, local opposition to the project which mayentail litigation, or an inability to satisfy the conditions to effectiveness of project agreements such as PPAs and (ii) any of the other projects in itsrespective development pipeline, in a timely manner, or at all, in either case, which could limit our acquisition opportunities under our respective PurchaseRights and/or the value of our investment in Pattern Development 2.0;•our failure to exercise our respective Purchase Rights or acquire assets from Pattern Development 1.0 or Pattern Development 2.0;•our failure to successfully develop and finance projects, to the extent that we decide to pursue development activities with respect to new power projectsoutside of activities conducted by Pattern Development 2.0. See also “- Our growth strategy is dependent upon the acquisition of attractive power projectsdeveloped by third-parties, including Pattern Development 1.0 and Pattern Development 2.0, and an inability of such development companies to obtain therequisite financing to develop and construct projects could have a material adverse effect on our ability to grow our business." In addition, we also mustalso potentially31anticipate obtaining funds from equity or debt financings to complete an acquisition or construction of an acquired project which exposes us to similarfinancing risks;•local opposition to wind turbine installations is growing in certain markets due to concerns about noise, health and other alleged impacts of wind powerprojects. In addition, indigenous communities in the United States and Canada, including Native Americans and First Nations, are becoming moreinvolved in the development of wind power projects and have certain treaty rights that can negatively affect the viability of power projects. As a result, forthese and other reasons, litigation and challenges to wind power projects has increased; and•limited access to capital, or an increase in the cost of our capital, may impair our ability to buy certain projects or buy them at the time we had expected.Any of these factors could prevent us from executing our growth strategy or otherwise have a material adverse effect on our business prospects, financial conditionand results of operations. See also “We have invested in Pattern Development 2.0 which exposes us directly to project development risks.”Additionally, even if we consummate acquisitions that we believe will be accretive to cash available for distribution per share, those acquisitions may in fact resultin a decrease in cash available for distribution per Class A share as a result of incorrect assumptions in our evaluation of such acquisitions, unforeseenconsequences or other external events beyond our control. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations maychange significantly, and stockholders will not generally have the opportunity to evaluate the economic, financial and other relevant information that we willconsider in determining the application of these funds and other resources.Capital market conditions can have an effect on both our timing and ability to consummate future acquisitions. We must also potentially anticipate obtainingfunds from equity or debt financings to complete construction or pay capital costs of an acquired project which exposes us to financing risks.Since we often finance acquisitions of projects partially or wholly through the issuance of additional Class A shares or the issuance of notes or other debtinstruments, we may need to be able to access the capital markets on commercially reasonable terms when acquisition opportunities arise. For example, we issuedsenior notes in January 2017 to help finance the acquisition of the Broadview project and to repay other debt previously incurred to finance acquisitionopportunities. In addition, we utilized in part proceeds from an underwritten public offering of our Class A shares in October 2017 and at-the-market offeringsunder an equity distribution agreement we entered into in May 2016 for investment in acquisition opportunities and to repay other debt previously incurred tofinance acquisition opportunities. Our ability to access the equity and debt capital markets is dependent on, among other factors, the overall state of the capitalmarkets and investor appetite for investment in clean energy projects in general and our Class A shares and our debt securities in particular. Volatility in the marketprice of our Class A shares or our credit rating may prevent or limit our ability to utilize our equity or debt securities as a source of capital to help fund acquisitionopportunities.During 2017, the prices for our Class A shares traded on the NASDAQ Global Select Market ranged from a high of $26.56 to a low of $18.83 . On February 23,2018 , the last reported sale price of our Class A shares on such market was $18.91 . In connection with the issuance of senior notes in January 2017, we obtained aBB-/Ba3 credit rating from Standard & Poor’s and Moody’s, respectively. An inability to obtain equity or debt financing on commercially reasonable terms couldsignificantly limit our timing and ability to consummate future acquisitions, and to effectuate our growth strategy. In addition, the issuance of additional Class Ashares in connection with acquisitions, particularly if consummated at depressed price levels or consummated at price levels that declined significantly between thesigning and closing of an acquisition, could cause significant shareholder dilution, expose us to risks of being unable to consummate an acquisition we had agreedto due to an inability to obtain financing, and reduce the cash distribution per share if the acquisitions are not sufficiently accretive.We must also potentially anticipate obtaining funds from equity or debt financings, including tax equity transactions, or from other sources in order to fund anyrequired construction and other capital costs of the acquired projects. The availability of tax equity financing with respect to any future acquisitions by us willlikely be narrowed as a result of impacts of the recent comprehensive U.S. federal tax reform passed in late 2017 and Base Erosion Anti-Abuse Tax, or BEAT,provisions. In addition, management believes there may be potential delays in tax equity financings as tax equity investors analyze the impact of the BEAT on theircurrent and future tax position. While uncertainty remains, no assurances can be given that there will not be a material adverse effect on the willingness ofinvestors to provide tax equity financing, an ability by us to obtain alternative financings which would be as attractive as was available from tax equity investorsprior to tax reform, or that the terms of any tax equity financing that may be obtained would be as favorable as those currently in place at certain of our existingprojects.32We currently intend to acquire power projects that are at least at the stage of being construction-ready, which is generally the point in time when the project is ableto procure construction financing and secure tax equity investor commitments.In the event we determine it is not economical to utilize, or we are unable to utilize our equity or debt securities as a source of capital to fund acquisitionopportunities, or as a source of capital to complete any construction outstanding or pay capital costs of acquired projects, we may need to consider utilizing othersources of capital, such as cash on hand, borrowings under our existing credit facilities, or arranging additional credit facilities, none of which may be available ormay not be available at attractive terms. Our inability to effectively consummate future acquisitions, or to finance construction or other capital costs cost-effectively, could have a material adverse effect on our ability to grow our business and make cash distributions to our shareholders.Acquisition and disposal of power projects involves numerous risks.Our strategy includes acquiring power projects. The acquisition of power projects involves numerous risks, many of which may not be able to be discoveredthrough our due diligence process, including exposure to previously existing liabilities and unanticipated costs associated with the pre-acquisition period; difficultyin integrating the acquired projects into our existing business; and, if the projects are in new markets, the risks of entering markets where we have limitedexperience. We are entering new markets, such as Japan and Mexico, with different languages and cultures which may further enhance risks relating to assimilatingnew operations and personnel in these markets, becoming familiar with applicable local laws and regulations, providing effective control over operations in remotelocations, and diverting time and attention of management to address integration issues. In addition, while we will perform our due diligence on prospectiveacquisitions, we may not be able to discover all potential operational deficiencies in such projects or problematic wind characteristics. A failure to achieve thefinancial returns we expect when we acquire power projects could have a material adverse effect on our ability to implement our growth strategy and, ultimately,our business prospects, financial condition and results of operations.Furthermore, from time to time, we may believe it in the best interests of ourselves and our stockholders to dispose of power projects. Reasons for a disposal mayinclude limited opportunities in a market, changes in business environment or law which reduces the attractiveness of a market, excessive competition in themarket, changes in business strategy, or a belief we can utilize funds realized from such a disposal in a more productive manner or generate a higher return oninvestment. The disposal of power projects involves numerous risks, many of which are outside of our control, including the ability to locate an attractive buyer ofa power project, the management attention required to devote to the disposal, the ability to obtain a favorable price for a power project, the length of time requiredto complete the disposal process, and the potential difficulty of re-entering a market in the future after exiting a market. In the event we decide to dispose of apower project, no assurances can be given that we would be successful in consummating the disposal in a timely manner (or at all), that we would achieve anattractive (or positive) financial return from the disposal, or that we would be successful in re-deploying funds generated from any disposal in a manner that wouldgenerate higher returns.Our growth strategy is dependent upon the acquisition of attractive power projects developed by others, including Pattern Development 1.0 and PatternDevelopment 2.0 (in which we hold a minority interest), and an inability of such development companies to obtain the requisite financing to develop andconstruct projects could have a material adverse effect on our ability to grow our business.Power project development is a capital intensive, high-risk business that relies heavily on and, therefore, is subject to the availability of debt and equity financingsources to fund projected construction and other projected capital expenditures. As a result, in order to successfully develop a power project, developmentcompanies, including Pattern Development 1.0 and Pattern Development 2.0, from which we may seek to acquire power projects, must obtain at-risk fundssufficient to complete the development phase of their projects. Any significant disruption in the credit and capital markets, or a significant increase in interest rates,could make it difficult for development companies to successfully develop attractive projects. If development companies from which we seek to acquire projectsare unable to raise funds when needed, the ability to grow our project portfolio may be limited, which could have a material adverse effect on our ability toimplement our growth strategy and, ultimately, our business prospects, financial condition and results of operations.We have invested in Pattern Development 2.0 which exposes us directly to project development risks.Pattern Development 2.0 was structured to allow us to potentially invest in Pattern Development 2.0, and in July 2017 we consummated a transaction in which wemade an initial capital contribution to Pattern Development 2.0 of approximately $60 million for an approximately 20% ownership interest in Pattern Development2.0. In December 2017, we funded an additional $7.3 million and $35.2 million in 2018. As a result of such fundings, we hold an approximate 21% ownershipinterest in Pattern Development 2.0. In addition, we have the right to contribute up to an additional approximately $197.5 million to Pattern Development 2.0 inone or more subsequent rounds of financing, which could result in our ownership interest in Pattern Development 2.0 increasing up to approximately 29%. If we donot participate in such subsequent rounds of financing, our ownership interest in Pattern Development 2.0 may be diluted.33As a result of our investment in Pattern Development 2.0, we are exposed directly to, and in the event we elected to further increase our investment in PatternDevelopment 2.0 by participating in additional capital calls or otherwise decided to invest in other project development opportunities, we would further exposeourselves directly to project development risks, including permitting challenges, failure to secure PPAs, failure to procure the requisite financing, equipment orinterconnection, or an inability to satisfy the conditions to effectiveness of project agreements such as PPAs. Generally, project development may entail risks ofmaking investments in assets that are not profitable, and we are, and if we invested further could be further, exposed to significant investment activities that requirecapital prior to having certainty that a project can move forward. We may lose money invested without generating returns. No assurances can be given that wewould be successful in project development activities we undertake, whether through the investment in Pattern Development 2.0 or otherwise, which can diminishour capital available for investment in operating power projects and adversely impact our business prospects, financial condition and results of operations.Our ability to grow our cash available for distribution is substantially dependent on our ability to make acquisitions from the Pattern Development Companiesor third parties on economically favorable terms.Our goal of growing our cash available for distribution and increasing dividends to our Class A stockholders is substantially dependent on our ability to make andfinance acquisitions on terms that result in an increase in cash available for distribution per Class A share. To grow our cash available for distribution per Class Ashare through acquisitions, we must be able to acquire new generation assets, such as the Identified ROFO Projects, on economically favorable terms. If we areunable to make accretive acquisitions from the Pattern Development Companies or third parties because we are unable to identify attractive acquisitionopportunities, negotiate acceptable purchase contracts, obtain financing on economically acceptable terms (as a result of the then current market value of our ClassA shares or otherwise) or are outbid by competitors, we may not be able to realize our targeted growth in cash available for distribution per Class A share.The energy industry in the markets in which we operate, as well as the markets we are looking to expand into, benefit from governmental support that issubject to change. With respect to the U.S. market, legislators and the current U.S. administration have proposed environmental and tax policies that havecreated regulatory uncertainty in the clean energy sector.The energy industry in the markets in which we operate and are looking to expand into, including both fossil fuel and renewable energy sources, in general benefitsfrom various forms of governmental support. Renewable energy sources in Canada benefit from federal and provincial incentives, such as RPS programs,accelerated cost recovery deductions, the availability of off-take contracts through RFP and standard offer programs including the Hydro-Quebec call for tenders,the Ontario feed-in tariff and large renewable procurement programs, and other commercially oriented incentives. Renewable energy sources in the United Stateshave benefited from various federal and state governmental incentives, such as PTCs, ITCs, ITC cash grants, loan guarantees, RPS programs and accelerated taxdepreciation. PTCs and ITCs for wind energy on the federal level were extended in December 2015. The extension extended the expiration date for tax credits forwind facilities with a five year phase-down for wind projects commencing construction after December 31, 2014. Renewable energy sources in Chile benefit fromthe Renewable and Non-Conventional Energy Law, which stipulates that by 2025 a portion of the total energy withdrawn from the grid, starting with 5% in 2015and progressively increasing up to 20% by 2025, shall be produced with renewable and non-conventional technologies. Such obligations translate into “greenattributes” which can be freely traded. In 2012, Japan introduced a feed-in-tariff program that offered fixed term, fixed price contracts of up to 20 years torenewable power projects. The Mexican congress has established a mandate that at least 35% of its energy consumption be supplied by clean sources by 2024.While such developments extending various forms of governmental support provide general benefits to the wind power industry in which we operate, to the extentthat these governmental incentive programs may be amended or changed in the future, particularly if amendments or changes are unexpected or unfavorable andafter we have developed long-term business plans and strategies based upon them, it could adversely affect the price of electricity sold to power purchasersgenerated by developed or planned wind power projects, decrease demand for wind power, or reduce the number of projects available to us for acquisition, any ofwhich could have a material adverse effect on our ability to implement our growth strategy and, ultimately, our business prospects, financial condition and resultsof operations. For example, the U.S. Environmental Protection Agency (EPA) under the current U.S. administration has announced that it is taking measures torepeal the Clean Power Plan, a regulation issued by the EPA under the prior U.S. administration aimed at reducing use of existing coal fired electricity generationfacilities and increasing renewable generation in order to reduce greenhouse gas emissions. The current U.S. administration has also proposed other environmentalpolicies that have created regulatory uncertainty in the clean energy sector, including the sectors in which we operate, and may lead to a reduction or removal ofvarious clean energy programs and initiatives designed to curtail climate change. Such a reduction or removal of incentives may diminish the markets in which weoperate. As a part of recent comprehensive income tax reform, the corporate tax rate was reduced, and while such reductions may have certain positive impacts onour financial results as applied to our own corporate taxes, a reduction in the corporate tax rate could also have adverse consequences, such as diminishing thecapacity of potential investors in our projects to benefit from incentives and reduce the value of accelerated depreciation deductions. As a part of comprehensivetax reform in late 2017, there were proposed amendments in Congress that would have adversely affected the value and ability to preserve benefits of PTCs forwind energy on the federal level. While these amendments34were in large part not adopted, no assurances can be given that there will not be future efforts to make amendments that could adversely affect the value andbenefits of the PTC. The current administration also made public statements regarding overturning or modifying policies of or regulations enacted by the prioradministration that placed limitations on coal and gas electric generation, mining and/or exploration. Efforts to overturn federal and state laws, regulations orpolicies that are supportive of wind energy generation or that remove costs or other limitations on other types of generation that compete with wind energy projectscould materially and adversely affect our business prospects, financial condition or results of operations.Wind power procurement in Canada is a provincial matter, with relatively irregular, infrequent and competitive procurement windows.Each province in Canada has its own regulatory framework and renewable energy policy, with few material federal policies to drive the growth of renewableenergy. Renewable energy developers must anticipate the future policy direction in each of the provinces, and secure viable projects before they can bid to procurea PPA through highly competitive PPA auctions. Most markets are relatively small. Energy policy in our key market of Ontario is subject to a political process,including with respect to its FIT program, and renewable energy procurement may change dramatically as a result of changes in the provincial government orpolitical climate.We face competition primarily from other renewable energy IPPs and, in particular, other wind power companies.We believe our primary competitors are infrastructure funds and some wind power companies or IPPs focused on renewable energy generation. We compete withthese companies to acquire well-developed projects with projected stable cash flows that can be built in a cost-effective manner. We also compete with other windpower developers and operators for the limited pool of personnel with requisite industry knowledge and experience. Furthermore, in past years, there have beentimes of increased demand for wind turbines and their related components, causing turbine suppliers to have difficulty meeting the demand. If these conditionsreturn in the future, turbine and other component manufacturers may give priority to other market participants, including our competitors, who may have resourcesgreater than ours.We compete with other renewable energy companies (and power companies in general) for the lowest cost financing, which provides the highest returns for ourprojects. Once we have acquired a construction project and put it into operation, we may compete on price if we sell electricity into power markets at wholesalemarket prices. Depending on the regulatory framework and market dynamics of a region, we may also compete with other wind power companies and otherrenewable energy generators, when our projects bid on or negotiate for long-term power sale agreements or sell electricity or RECs into the spot-market. Ourability to compete on price with other wind power companies and other renewable energy IPPs may be negatively impacted if the regulatory framework of a regionfavors other sources of renewable energy over wind power.We have no control over where our competitors may erect wind power projects. Our competitors may erect wind power projects adjacent to our wind projects thatmay cause upwind array losses to occur at our wind projects. Upwind array losses reflect the diminished wind resource available at a project resulting frominterference with available wind caused by adjacent wind turbines. An adjacent wind power project that causes upwind array losses could have a material adverseeffect on our revenues and results of operations.Any change in power consumption levels could have a material adverse effect on our business prospects, financial condition and results of operations.The amount of wind power consumed by the electric utility industry is affected primarily by the overall demand for electricity, environmental and othergovernmental regulations and the price and availability of fuels such as nuclear, coal, natural gas and oil as well as other sources of renewable energy. A decline inprices for these fuels could cause demand for wind power to decrease and adversely affect the demand for renewable energy. For example, low natural gas priceshave led, in some instances, to increased natural gas consumption by electricity-generating utilities in lieu of other power sources. To the extent renewable energyand wind power, in particular, becomes less cost-competitive on an overall basis as a result of a lack of governmental incentives, cheaper alternatives or otherwise,demand for wind power and other forms of renewable energy could decrease. Slow growth in overall demand for electricity or a long-term reduction in the demandfor renewable energy could have a material adverse effect on our plan to grow our business and could, in turn, have a material adverse effect on our businessprospects, financial condition and results of operations.Some states and provinces with renewable energy targets have met their targets, or will meet them in the near future, which could cause demand for new windand solar power capacity to decrease.Renewable Portfolio Standard programs in the United States represent sixty percent of the growth in non-hydro renewable energy generation since 2000.Enactment of new RPS policies has waned but states continue to hone existing policies. Roughly half of all RPS states have raised their overall RPS targets orcarve-outs since initial RPS adoption. Recent legislation in California, Hawaii, Oregon and Vermont extended targets to 2030 and beyond. However, other statesare starting to approach their final targets. Five states reached the35final year of their RPS in 2015. Most others will do so in 2020 or 2025. Many bills have also been proposed to repeal, reduce, or freeze RPS programs, though onlytwo have been enacted.While some Canadian provinces have increased their renewable energy targets - Saskatchewan 50% by 2030 and Alberta 30% by 2030 - others have reduced theirdemand for renewables, including Ontario, which has halted its Large Renewable Procurement Process. Additionally, hydro power dominates when it comes tomeeting renewable energy targets.As a result of achieving targets, and if such U.S. states and Canadian provinces do not increase non-hydro renewable energy targets in the future, demand foradditional wind and solar power generating capacity could decrease, which could have a material adverse effect on our business prospects, financial condition, andresults of operations.New projects being developed that we may acquire may need governmental approvals and permits, including environmental approvals and permits, forconstruction and operation. Any failure to obtain or maintain in effect necessary permits could adversely affect the amount of our growth.The design, construction and operation of wind power projects are highly regulated, require various governmental approvals and permits, including environmentalapprovals and permits, and may be subject to the imposition of related conditions that vary by jurisdiction. In some cases, these approvals and permits requireperiodic renewal and a subsequently issued permit may not be consistent with the permit initially issued. In other cases, these permits may require compliance withterns that can change over time. We cannot predict whether all permits required for a given project will be granted or whether the conditions associated with thepermits, as such conditions may change over time, will be achievable. The denial or loss of a permit essential to a project, or the imposition of impractical orburdensome conditions upon renewal or over time, could impair our ability to construct and operate a project. In addition, we cannot predict whether seeking thepermits will attract significant opposition or whether the permitting process will be lengthened due to complexities, legal claims or appeals. Delay in the reviewand permitting process for a project can impair or delay our ability to construct or acquire a project or increase the cost such that the project is no longer attractiveto us.In developing certain of our projects, Pattern Development 1.0 experienced delays in obtaining non-appealable permits and we, Pattern Development 1.0, and/orPattern Development 2.0 may experience delays in the future. For example, when we acquired our Ocotillo project, it was then the subject of four active lawsuitsbrought by a variety of project opponents, all of which challenged the prior issuance of Ocotillo’s primary environmental analysis and right-of-way entitlement.We had commenced commercial operations at the Ocotillo project in anticipation of securing favorable rulings on these lawsuits. In Ontario, in prior years anti-wind advocacy groups have opposed the Renewable Energy Approval environmental permit granted to our South Kent, Grand, K2 and Armow wind projects bycommencing proceedings before the Ontario Environmental Review Tribunal. Each of these appeals ultimately was unsuccessful and dismissed by the Tribunal.We are subject to the risk of being unable to complete construction of our projects, or continue operation of our projects, if any of the key permits are revoked orpermit conditions are violated. If this were to occur at any future project, we would likely lose a significant portion of our investment in the project and could incura loss as a result, which would have a material adverse effect on our business prospects, financial condition and results of operations.If we are unable to make an offer, make an attractive offer, or make an acceptable final offer in the event one of the Pattern Development Companies deliverednotice that it is seeking a purchaser for a project on the identified ROFO list, we may be unable to acquire such project from the relevant Pattern DevelopmentCompany pursuant to our respective Project Purchase Right.Generally, we have a Project Purchase Right with each of Pattern Development 1.0 and Pattern Development 2.0, and although Pattern Development 1.0 andPattern Development 2.0 may choose to seek a purchaser of a project at a time of its choosing whether earlier in the project’s development stage or later at a time,we have generally anticipated that Pattern Development 1.0 and Pattern Development 2.0 will seek a purchaser of its development projects upon or afterconstruction-readiness following commencement of its construction. We do not control either Pattern Development 1.0 or Pattern Development 2.0, and PatternDevelopment 1.0 and Pattern Development 2.0 may deem it necessary or desirable to deliver such notice to us that is seeking a purchaser for its projects at anytime for its own capital, liquidity, shareholder, or other requirements. In the event Pattern Development 1.0 or Pattern Development 2.0 delivered notice for aproject on the identified ROFO list, for which we are unable to, or do not, deliver a written first rights project offer, make an attractive offer, or make an acceptablefinal offer to purchase its entire interest in such project, such respective Pattern Development Company may be able to sell the project to a third party (including acompetitor), provided it is at a price not less than 105%, in the case of a project developed by Pattern Development 1.0, and 110%, in the case of a projectdeveloped by Pattern Development 2.0, of our first rights project offer (if any), greater than our final offer price, and on other terms not materially less favorable. Ifthis occurred, we would not acquire such project from Pattern Development 1.0 or Pattern Development 2.0 (as the case may be). An inability to acquire projectson36the identified ROFO list under our respective Project Purchase Right with Pattern Development 1.0 or Pattern Development 2.0 could materially adversely affectour ability to implement our growth strategy.In spite of our Pattern Development 1.0 Purchase Rights and Pattern Development 2.0 Purchase Rights, it is possible that Pattern Development 1.0 and/orPattern Development 2.0, respectively, might be sold to third parties. In addition, each of our respective Project Purchase Rights, Pattern Development 1.0Purchase Rights and Pattern Development 2.0 Purchase Rights may expire, and the Second Amended and Restated Non-Competition Agreement with PatternDevelopment 1.0 and Pattern Development 2.0 might terminate.To the extent we do not exercise our Pattern Development 1.0 Purchase Rights and/or Pattern Development 2.0 Purchase Rights (or upon their expiration), PatternDevelopment 1.0 and /or Pattern Development 2.0, respectively, or substantially all of its respective assets may be sold to third parties, including our competitors.Even if we are interested in exercising the Pattern Development 1.0 Purchase Rights and/or Pattern Development 2.0 Purchase Rights, Pattern Development 1.0and/or Pattern Development 2.0 may seek a purchaser at an inopportune time for us, or we may not be able to reach an agreement on pricing or other terms. If weare unable to reach an agreement with Pattern Development 1.0, Pattern Development 2.0, or its respective equity owners or if we decline to make an offer, PatternDevelopment 1.0, Pattern Development 2.0, or its respective equity owners may seek alternative buyers, which could have a material adverse effect on our abilityto implement our growth strategy and, ultimately, our business prospects, financial condition and results of operations.In addition, our Project Purchase Right with Pattern Development 1.0 and our Pattern Development 1.0 Purchase Rights terminate upon the third occasion onwhich we decline to exercise our respective Project Purchase Right with respect to an operational or construction-ready project for which we did not make a finaloffer for such projects (excluding a failure to make an offer for the Conejo project). Our Project Purchase Right with Pattern Development 2.0 and our PatternDevelopment 2.0 Purchase Rights terminate upon winding-up of Pattern Development 2.0. Following termination of our respective Project Purchase Right, and ourPattern Development 1.0 Purchase Rights and Pattern Development 2.0 Purchase Rights, Pattern Development 1.0 or Pattern Development 2.0, as the case may be,will be under no obligation to offer any of its projects to us, which could have a material adverse effect on our ability to implement our growth strategy andultimately on our business prospects, financial condition and results of operations.Once our respective Purchase Rights with Pattern Development 1.0 and/or Pattern Development 2.0 terminate, the Second Amended and Restated Non-Competition Agreement with respect to Pattern Development 1.0 or Pattern Development 2.0, as the case may be, will also terminate. In addition, we also have theright terminate the Second Amended and Restated Non-Competition Agreement upon the earlier of wind-up of Pattern Development 2.0 or the valid rejection byPattern Development 2.0 of three or more first rights project offers representing a cumulative net capacity of at least 600 MWs. Under the Second Amended andRestated Non-Competition Agreement, (among other things) Pattern Development 2.0 is granted an exclusive right, with certain exceptions, to pursue all powergeneration, storage or transmission development projects in the U.S., Canada and Mexico that have not completed construction, but this does not restrict us fromacquiring any company or business that is principally engaged in the business of owning and operating renewable energy facilities. In addition, at any time thatTokyo, Japan-based Green Power Investment Corporation is majority owned by either us, Pattern Development 1.0 or Pattern Development 2.0, such majorityowner (which is currently Pattern Development 1.0) is granted exclusive development rights, with certain exceptions, over power generation, storage ortransmission projects in Japan.The loss of one or more of Pattern Development 1.0’s or Pattern Development 2.0’s officers, or key employees, may adversely affect our ability to implementour growth strategy.In addition to relying on our management team for managing our projects, our growth strategy relies on Pattern Development 1.0’s and Pattern Development 2.0’sofficers and key employees for their strategic guidance and expertise in the selection of projects that we may acquire in the future. Because the wind powerindustry is relatively new, there is a scarcity of experienced officers and employees in the wind power industry. As a result, if one or more of Pattern Development1.0’s or Pattern Development 2.0’s officers or key employees leaves or retires, and Pattern Development 1.0 or Pattern Development 2.0 are unable to find asuitable replacement, our ability to implement our growth strategy may be diminished, which could have a material adverse effect on our business prospects,financial condition and results of operations. See also “- Risks Related to Our Projects - The loss of one or more of our executive officers or key employees mayadversely affect our ability to effectively manage our operating projects and complete any construction projects on schedule.”37We may decide to further expand our acquisition strategy to include other types of power projects or transmission projects besides wind power. Any futureadditional acquisitions of non-wind power projects or transmission projects may present unforeseen challenges and result in a competitive disadvantagerelative to our more-established competitors.With the consummation of the acquisition of the 35-mile 345 kV Western Interconnect transmission line as a part of the acquisition of the Broadview projectswhich we acquired in April 2017, and assuming the consummation of the acquisitions of the Kanagi Solar and Futtsu Solar projects (representing in aggregate 39MW of owned-capacity in solar) which we have committed to acquire in March 2018, we have expanded our operations into other types of projects besides windpower. In the future, we may further expand our acquisition strategy into other types of power projects or transmission projects besides wind power. There can beno assurance that we will be able to identify other attractive non-wind or transmission acquisition opportunities or acquire such projects at a price and on terms thatare attractive or that, once acquired, such projects will operate profitably. Additionally, these acquisitions could expose us further to increased operating costs,unforeseen liabilities or risks, and regulatory and environmental concerns associated with entering new sectors of the power industry, including requiring adisproportionate amount of our management’s attention and resources, which could have an adverse impact on our business, as well as place us at a competitivedisadvantage relative to more established non-wind energy market participants. A failure to successfully integrate such acquisitions into our existing projectportfolio as a result of unforeseen operational difficulties or otherwise, could have a material adverse effect on our business prospects, financial condition andresults of operations.We are subject to risks associated with litigation or administrative proceedings that could materially impact our operations, including proceedings in the futurerelated to power projects we subsequently acquire.We are subject to risks and costs, including potential negative publicity, associated with lawsuits, in particular, with respect to environmental claims and lawsuits,claims contesting the construction or operation of our projects, or shareholder suits. See Item 3 "Legal Proceedings.” The result of, and costs associated with,defending any such lawsuit, regardless of the merits and eventual outcome, may be material and could have a material adverse effect on our operations. In thefuture, we may be involved in legal proceedings, disputes, administrative proceedings, claims and other litigation that arise in the ordinary course of businessrelated to a power project that we subsequently acquire. For example, individuals and interest groups may sue to challenge the issuance of a permit for a powerproject or seek to enjoin construction or operation of a power project. We may also become subject to claims from individuals who live in the proximity of ourpower projects based on alleged negative health effects related to acoustics caused by wind turbines or alleged contamination of groundwater. In addition, we havebeen and may subsequently become subject to legal proceedings or claims contesting the construction or operation of our power projects. Any such legalproceedings or disputes could delay our ability to complete construction of a power project in a timely manner, or at all, or materially increase the costs associatedwith commencing or continuing commercial operations at a power project. Settlement of claims and unfavorable outcomes or developments relating to theseproceedings or disputes, such as judgments for monetary damages, injunctions or denial or revocation of permits, could have a material adverse effect on ourability to implement our growth strategy and, ultimately, our business prospects, financial condition and results of operations.Risks Related to Our Financial ActivitiesOur substantial amount of indebtedness may adversely affect our ability to operate our business and impair our ability to pay dividends.Our consolidated indebtedness not including financing costs as of December 31, 2017 was approximately $2.0 billion . Despite our current consolidated debtlevels, we or our subsidiaries may still incur substantially more debt or take other actions which would intensify the risks discussed below.Our substantial indebtedness could have important consequences, including, for example:•failure to comply with the covenants in the agreements governing these obligations could result in an event of default under those agreements, or, undercertain circumstances, cross-default to other debt instruments, which could be difficult to cure, or result in our bankruptcy;•in the event a project is unable to meet its debt service obligations through its own project cash flows, excess cash flow from other projects may berequired to help service such obligations, thereby reducing funds available to pay dividends;•in the event a project is unable to meet its debt service obligations, it may result in a foreclosure on the project collateral and loss of the project;•our limited financial flexibility could reduce our ability to plan for and react to unexpected opportunities; and38•our substantial debt service obligations make us vulnerable to adverse changes in general economic, credit and capital markets, industry and competitiveconditions and adverse changes in government regulation, and place us at a disadvantage compared with competitors with less debt.Any of these consequences could have a material adverse effect on our business prospects, financial condition and results of operations. If we do not comply withour obligations under our debt instruments, we may be required to refinance all or part of our existing debt, borrow additional amounts or sell securities, which wemay not be able to do on favorable terms or at all. In addition, increases in interest rates and changes in debt covenants may reduce the amounts that we canborrow, reduce our cash flows and increase the equity investment we may be required to make to complete any construction of our projects. These increases couldcause some of our projects to become economically unattractive. If we are unable to raise additional capital or generate sufficient operating cash flow to repay ourindebtedness, we could be in default under our lending agreements and could be required to delay construction of our projects, reduce overhead costs, reduce thescope of our projects or abandon or sell some or all of our projects, all of which could have a material adverse effect on our business prospects, financial conditionand results of operations.Our indebtedness may limit the amount of cash flow available to invest in the ongoing needs of our business which could have a material adverse effect onbusiness prospects, financial condition and results of operations.Subject to the limits contained in our revolving credit facility, we may incur substantial additional debt from time to time to finance working capital, capitalexpenditures, investments or acquisitions, or for other purposes. If we do so, the risks related to our level of indebtedness could intensify. Specifically, a high levelof indebtedness could have important consequences due to the adverse ways in which it affects us, including the following:•requiring us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of ourcash flow to fund working capital, capital expenditures, dividend payments, development activity, acquisitions and other general corporate purposes;•increasing our vulnerability to adverse general economic or industry conditions;•limiting our flexibility in planning for, or reacting to, changes in our business or the industries in which we operate;•making us more vulnerable to increases in interest rates, as borrowings under our revolving credit facility are at variable rates;•limiting our ability to obtain additional financing in the future for working capital or other purposes; and•placing us at a competitive disadvantage compared to our competitors that have less indebtedness.Our ability to comply with restrictions and covenants under the terms of our indebtedness may be affected by events beyond our control, including prevailingeconomic, financial and industry conditions. As a result, there can be no assurance that we will be able to comply with these restrictions and covenants, and anysuch default under our debt agreements could have a material adverse effect on our business by, among other things, limiting our ability to take advantage offinancing, merger and acquisition or other corporate opportunities.Despite our current consolidated debt levels, we and our subsidiaries may be able to incur substantial additional debt in the future, subject to the restrictionscontained in our revolving credit facility and our future debt instruments, some of which may be secured debt. Although our revolving credit facility containsrestrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and could be amended orwaived, and the indebtedness incurred in compliance with these restrictions could be substantial and may also be secured. Accordingly, we may, in compliancewith these restrictions, incur additional debt, secure existing or future debt, recapitalize our debt or take a number of other actions that are not limited by the termsof our existing indebtedness and that could have the effect of intensifying the risks discussed above.We may not have the ability to raise the funds necessary to make payments in cash which may be required under the terms of the notes we have issued uponconversion settlement, repayment at maturity, or upon exercise of a repurchase obligation, and our debt agreements may limit our ability to pay cash uponconversion, repurchase or redemption of these notes.Holders of the convertible notes we issued in July 2015 have the right to require us to repurchase all or a portion of their convertible notes upon the occurrence of afundamental change at a repurchase price equal to 100% of the principal amount of the notes to be repurchased, plus accrued and unpaid interest, if any. Inaddition, upon conversion of the convertible notes, unless we elect to deliver solely our Class A shares to settle such conversion (other than paying cash in lieu ofdelivering any fractional share), we will be required39to make cash payments in respect of the convertible notes being converted. In addition, holders of the senior notes we issued in January 2017 may have the right torequire us to repurchase all or a portion of their notes upon a change of control triggering event at a repurchase price equal to 101% of the principal amount of thenotes to be repurchased, plus accrued and unpaid interest, if any.However, we may not have enough available cash or be able to obtain financing at the time we are required to make repurchases of notes surrendered therefor, paycash at their maturity, or (with respect to convertible notes) pay cash upon conversion settlement. In addition, our ability to repurchase the notes or to pay cashupon conversions of the convertible notes may be limited by law, regulatory authority or agreements governing our indebtedness. Our failure to repurchase notes ata time when the repurchase is required by the indenture or (with respect to the convertible notes) to pay any cash payable on future conversions of the convertiblenotes pursuant to the indenture would constitute a default under the indenture governing the issuance of the respective notes. A fundamental change, change ofcontrol triggering event, or a default under the indenture could also lead to a default under agreements governing our or our subsidiaries’ indebtedness. If therepayment of the related indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay theindebtedness and repurchase the notes or make cash payments upon redemptions thereof.The conditional conversion feature of the convertible notes we have issued, if triggered, may adversely affect our financial condition and operating results.The convertible notes we issued in July 2015 have a conditional conversion feature. In the event the conditional conversion feature of the convertible notes istriggered, holders of convertible notes will be entitled to convert such notes at any time during specified periods at their option. If one or more holders elect toconvert their convertible notes, unless we elect to satisfy our conversion obligation by delivering solely our Class A shares (other than paying cash in lieu ofdelivering any fractional share), we would be required to settle a portion or all of our conversion obligation through the payment of cash, which could adverselyaffect our liquidity. In addition, even if holders do not elect to convert their convertible notes, we could be required under applicable accounting rules to reclassifyall or a portion of the outstanding principal of the convertible notes as a current rather than long-term liability, which would result in a material reduction of our networking capital.Provisions in the indentures governing our outstanding notes may deter or prevent a business combination that may be favorable to investors.If a fundamental change occurs prior to the maturity date of the convertible notes we issued in July 2015 or a change of control triggering event occurs prior to thematurity date of the senior notes we issued in January 2017, holders of such notes may have the right, at their option, to require us to repurchase all or a portion oftheir respective notes. In addition, if a make-whole fundamental change occurs prior to the maturity date of the convertible notes, we will in some cases be requiredto increase the conversion rate for a holder that elects to convert its convertible notes in connection with such make-whole fundamental change. Furthermore, ourindentures prohibit us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity assumes our obligations thereunder. Theseand other provisions in our indentures could deter or prevent a third party from acquiring us even when the acquisition may be favorable to investors.If our subsidiaries default on their obligations under their project-level debt, we may decide to make payments to lenders to prevent foreclosure on thecollateral securing the project-level debt, which would, without such payments, cause us to lose certain of our projects.Our subsidiaries incur various types of debt. Non-recourse debt is repayable solely from the applicable project’s revenues and is secured by the project’s physicalassets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. Limited recourse debt is debt where we have provided alimited guarantee, and recourse debt is debt where we have provided a full guarantee, which means if our subsidiaries default on these obligations, we will be liabledirectly to those lenders, although in the case of limited recourse debt only to the extent of our limited recourse obligations. To satisfy these obligations, we may berequired to use amounts distributed by our other subsidiaries as well as other sources of available cash, reducing our cash available to execute our business planand pay dividends to holders of our Class A shares. In addition, if our subsidiaries default on their obligations under non-recourse financing agreements, we maydecide to make payments to prevent the lenders of these subsidiaries from foreclosing on the relevant collateral. Such a foreclosure would result in our losing ourownership interest in the subsidiary or in some or all of its assets. The loss of our ownership interest in one or more of our subsidiaries or some or all of their assetscould have a material adverse effect on our business prospects, financial condition and results of operations and, in turn, on our cash available for distribution.We are subject to indemnity and guarantee obligations.We provide a variety of indemnities in the ordinary course of business to contractual counterparties and to our lenders and other financial partners. For example,the Hatchet Ridge indemnity indemnifies MetLife Capital, Limited Partnership, the owner participant, under the40Hatchet Ridge Wind Lease Financing against certain tax losses. In addition, we have entered into tax equity partnership agreements in connection with six of ourprojects which also provide for specific allocations in certain circumstances.In addition, although we primarily rely on limited recourse or non-recourse financing at our project-level entities, we sometimes provide specific indemnities tosupport such financings. For example, some of our subsidiaries in the United States had obtained construction bridge loans to finance a portion of projectconstruction costs, and in certain cases, such loans were secured by the ITC cash grant proceeds received from the U.S. Treasury. We have assumed certainindemnities that were originally provided by Pattern Development 1.0 to certain of these bridge lenders and other on-going term lenders in the event that the ITCcash grant is recaptured by the U.S. Treasury, in whole or in part. The cash grant indemnities are in effect for five years from the date the relevant projectcommences commercial operations. If, for any of those subsidiaries which received the ITC cash grant, the ITC cash grant is recaptured, in whole or in part, wemay be required to make payments under the indemnities to prevent the lenders of those subsidiaries from foreclosing on the relevant project collateral. Paymentby us under a cash grant indemnity could have a material adverse effect on our business prospects, financial condition and results of operations and, in turn, on ourcash available for distribution.Our failure to pay any of these indemnities would enable the applicable project lenders to foreclose on the project collateral. The payments we may be obligated tomake pursuant to these indemnities could have a material adverse effect on our business prospects, financial condition and results of operations and, in turn, on ourcash available for distribution.Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.Certain borrowings under our revolving credit facility are subject to variable rates of interest, primarily based on the International Continental Exchange LondonInterbank Offered Rate (LIBOR) or Canadian Dollar Offered Rate (CDOR), and expose us to interest rate risk. Such rates tend to fluctuate based on generaleconomic conditions, general interest rates, Federal Reserve rates and the supply of and demand for credit in the relevant interbanking market. Increases in theinterest rate generally, and particularly when coupled with any significant variable rate indebtedness, could materially adversely impact our interest expenses. Ifinterest rates were to increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same,and our net income and cash flows, including cash available for servicing our indebtedness, will correspondingly decrease. A hypothetical increase or decrease ininterest rates by 1% would have increased or decreased interest expense related to our revolving credit facility by $0 million, $2.6 million and $1.6 million, for theyears ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017, no amounts were outstanding under our revolving credit facility. To theextent we borrow under our revolving credit facility, we are not required to enter into interest rate swaps to hedge such indebtedness. If we decide not to enter intohedges on such indebtedness, our interest expense on such indebtedness will fluctuate based on LIBOR, CDOR or other variable interest rates. Consequently, wemay have difficulties servicing such unhedged indebtedness and funding our other fixed costs, and our available cash flow for general corporate requirements maybe materially adversely affected. In the future, we may enter into interest rate swaps that involve the exchange of floating for fixed rate interest payments in orderto reduce interest rate volatility. However, we may not maintain interest rate swaps with respect to all of our variable rate indebtedness, and any swaps we enterinto may not fully mitigate our interest rate risk.Our hedging activities may not adequately manage our exposure to commodity and financial risk, which could result in significant losses or require us to usecash collateral to meet margin requirements, each of which could have a material adverse effect on our business prospects, financial condition, results ofoperations and liquidity, which could impair our ability to execute favorable financial hedges in the future.Certain of the electricity we generate is sold on the open market at spot-market prices. In order to stabilize all or a portion of the revenue from such sales, we haveentered, and may in the future enter, into financial swaps, day-ahead sales transaction or other hedging arrangements. We may acquire additional assets in thefuture with similar hedging agreements. In an effort to stabilize our revenue from electricity sales from these projects, we evaluate the electricity sale options foreach of our projects, including the appropriateness of entering into a PPA, a physical sale, a financial swap, or combination of these arrangements. If we sell ourelectricity into an ISO market without a PPA, we may enter into a physical sale or financial swap to stabilize all or a portion of our estimated revenue stream.Under the term of our existing physical sales, we are obligated to physically deliver electricity to a common delivery point. Under these arrangements, we sell theelectricity produced at our facility to the ISO at the project node and buy electricity at the common delivery point to meet the delivery obligations under thephysical sale. The delivery obligations under the physical sale are for specified volumes in each hour for an overall quantity that we estimate we are highly likely toproduce. Under the terms of our existing financial swaps, we are not obligated to physically deliver or purchase electricity. Instead, we receive payments forspecified quantities of electricity based on a fixed price and are obligated to pay our counterparty the real time market price for the same quantities of electricity.These financial swaps cover quantities of electricity that we estimate we are highly likely to produce. Gains or losses under the physical sales and financial swapsare designed to be offset by decreases or increases in our revenues from real time market sales of electricity in liquid ISO markets. However, the actual amount ofelectricity we generate from operations may be materially different from our estimates for a variety of reasons, including variable wind conditions and wind turbineavailability. If a project does not generate the volume of electricity covered41by the associated physical sale or financial swap contract, we could incur significant losses if electricity prices in the market rise substantially above the fixed priceprovided for in the physical sale or financial swap. If a project generates more electricity than is contracted in the physical sale or financial swap, the excessproduction will not be hedged and the related revenues will be exposed to market price fluctuations.We would also incur financial losses as a result of adverse changes in the mark-to-market values of the financial swaps or if the counterparties to our hedgingcontracts fail to make payments when due. We could also experience a reduction in cash flow if we are required to post margin in the form of cash collateral tosecure our delivery or payment obligations under these hedging agreements. We are not currently required to post cash collateral or issue letters of credit tobackstop our obligations under our hedging arrangements after commercial operation has been achieved, but we may be required to do so in the future. If we wererequired to do so, our available cash or available borrowing capacity under the credit facilities under which these letters of credit are issued would becorrespondingly reduced.We enter into PPAs when we sell our electricity into markets other than deregulated ISO markets or where we believe it is otherwise advisable. Under a PPA, wecontract to sell all or a fixed proportion of the electricity generated by one of our projects, sometimes bundled with RECs and capacity or other environmentalattributes, to a power purchaser which is often a utility or large commercial entity. We do this to stabilize our revenues from that project. We are exposed to therisk that the power purchaser will fail to perform under a PPA, with the result that we will have to sell our electricity at the market price sometime in the future,which could be substantially lower than the price provided in the applicable PPA. In most instances, we also commit to sell minimum levels of generation on anannual basis to the power purchaser. If the project generates less than the committed minimum volumes, we may be required to buy the shortfall of electricity (orRECs and other environmental attributes) on the open market or make payments of liquidated damages or be in default under a PPA, which could result in itstermination.We sometimes seek to sell forward a portion of our RECs or other environmental attributes to fix the revenues from those attributes and hedge against futuredeclines in prices of RECs or other environmental attributes. If our projects do not generate the amount of electricity required to earn the RECs or otherenvironmental attributes sold forward or if for any reason the electricity we generate does not produce RECs or other environmental attributes for a particular state,we may be required to make up the shortfall of RECs or other environmental attributes through purchases on the open market or make payments of liquidateddamages. Further, current market conditions may limit our ability to hedge sufficient volumes of our anticipated RECs or other environmental attributes, leaving usexposed to the risk of falling prices for RECs or other environmental attributes. Future prices for RECs or other environmental attributes are also subject to the riskthat regulatory changes will adversely affect prices.Risks Related to Ownership of our Class A SharesWe are a holding company with no operations of our own, and we depend on our power projects for cash to fund all of our operations and expenses, includingto make dividend payments.Our operations are conducted almost entirely through our power projects and our ability to generate cash to meet our debt service obligations or to pay dividends isdependent on the earnings and the receipt of funds from our project subsidiaries through distributions or intercompany loans. Our power projects’ ability togenerate adequate cash depends on a number of factors, including wind conditions, timely completion of any construction projects, the price of electricity,payments by key power purchasers, increased competition, foreign currency exchange rates, compliance with all applicable laws and regulations and other factors.See Item 1A "Risk Factors-Risks Related to Our Projects.” Our ability to declare and pay regular quarterly cash dividends is subject to our obtaining sufficient cashdistributions from our project subsidiaries after the payment of operating costs, debt service and other expenses. See Item 5 “Market for Registrant’s CommonEquity and Related Stockholder Matters-Cash Dividend to Investors.” We may lack sufficient available cash to pay dividends to holders of our Class A shares dueto shortfalls attributable to a number of operational, commercial or other factors, including insufficient cash flow generation by our projects, as well as unknownliabilities, the cost associated with governmental regulation, increases in our operating or general and administrative expenses, principal and interest payments onour and our subsidiaries’ outstanding debt, tax expenses, working capital requirements and anticipated cash needs.Our cash available for distribution to holders of our Class A shares may be reduced as a result of restrictions on our subsidiaries’ cash distributions to usunder the terms of their indebtedness, or in the event certain specified events occurred under our tax equity arrangements that change the percentage of cashdistributions to be made to the tax equity investors.We intend to declare and pay regular quarterly cash dividends on all of our outstanding Class A shares. However, in any period, our ability to pay dividends toholders of our Class A shares depends on the performance of our subsidiaries and their ability to distribute cash to us, as well as all of the other factors discussedunder Item 5 “Market for Registrant’s Common Equity and Related Stockholder Matters-Cash Dividend to Investors.” The ability of our subsidiaries to makedistributions to us may be restricted by, among other things, the provisions of existing and future indebtedness and the provisions existing and future tax equityarrangements.42Restrictions on distributions to us by our subsidiaries under our revolving credit facility and the agreements governing their respective project-level debt couldlimit our ability to pay anticipated dividends to holders of our Class A shares. These agreements contain financial tests and covenants that our subsidiaries mustsatisfy prior to making distributions. We may agree to similar restrictions on distributions under future debt instruments we may enter into in connection withfuture note or bond offerings. If any of our subsidiaries is unable to satisfy these restrictions or is otherwise in default under such agreements, it would beprohibited from making distributions to us that could, in turn, limit our ability to pay dividends to holders of our Class A shares. For example, low wind conditionscontributed to one of our projects not satisfying financial tests required to permit distributions to us during certain quarters of 2017 and also resulted in arequirement that such trapped cash be utilized to prepay certain debt at the project level. The terms of our project indebtedness typically require commencement ofcommercial operations prior to our ability to receive cash distributions from a project. The terms of any such indebtedness also typically include cash managementor similar provisions, pursuant to which revenues generated by projects subject to such indebtedness are immediately, or upon the occurrence of certain events,swept into an account for the benefit of the lenders under such debt agreements. As a result, project revenues typically only become available to us after thefunding of reserve accounts for, among other things, operations and maintenance expenses, debt service, taxes and insurance at the project level. In some instances,projects may be required to sweep cash to reserve funds intended to mitigate the results of pending litigation or other potentially adverse events.In addition, the terms of operating agreements for our wind facilities with tax equity investors, which include Panhandle 1, Panhandle 2, Post Rock, Logan’s Gap,Amazon Wind and Broadview, generally provide for specified allocations of distributions between the tax equity investors and ourselves which change at aspecified point when the tax equity investor has realized a target after tax internal rate of return. In the event this change has not occurred by a targeted date, the taxequity investor begins to receive a greater allocation of distributions until the targeted rate of return has been achieved. In addition, the operating agreements alsoprovide for earlier increases in the percentage of distributable cash to be allocated to the tax equity investors if the project fails to achieve certain defined minimumperformance levels that are likely to cause the tax equity investors to not achieve the targeted after tax return by the targeted date and for increases under certaincircumstances to match allocations of taxable income that are made to mitigate a negative capital account balance for such tax equity investors. As a result, in theevent our share of distributable cash from these projects is changed as a result of one of these events, our distributions from such wind facilities may be less thanexpected that could, in turn, limit our ability to pay dividends to holders of our Class A shares.Some of our wind facilities with tax equity investors have experienced lower than expected production and merchant power prices resulting in each of thoseprojects failing to pass financial tests that measure cumulative cash distributions to the members. This resulted in 2017, and could additionally result in 2018, in achange of the cash percentage allocated to the tax equity members which will continue until the shortfall is remedied.If our projects do not generate sufficient cash available for distribution, we may be required to reduce or eliminate our dividend, or fund dividends from workingcapital or other sources of liquidity, which may not be available, any of which could have a material adverse effect on the price of our Class A shares and on ourability to pay dividends at anticipated levels or at all.Our ability to pay regular dividends on our Class A shares is subject to the discretion of our Board of Directors.Our Class A stockholders have no contractual or other legal right to dividends. The payment of future dividends on our Class A shares is at the discretion of ourBoard of Directors and depends on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractualrestrictions applying to the payment of dividends, consideration of factors such as our payout ratio, and other considerations that our Board of Directors deemsrelevant. Our Board of Directors has the authority to establish cash reserves for the prudent conduct of our business, and the establishment of or increase in thosereserves could result in a reduction in cash available for distribution to pay dividends on our Class A shares at anticipated levels. Accordingly, we may not be ableto make, or may have to reduce or eliminate, the payment of dividends on our Class A shares, which could adversely affect the market price of our Class A shares.If we fail to maintain proper and effective internal controls, our ability to produce accurate and timely financial statements could be impaired and investors’views of us could be harmed.U.S. securities laws require, among other things, that we maintain effective internal control over financial reporting and disclosure controls and procedures. Wemust perform system and process evaluation and testing of our internal control over financial reporting to allow management to report on the effectiveness of ourinternal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act.If we identify deficiencies in our internal control over financial reporting that are deemed to be material weaknesses (even if such material weaknesses do not resultin a misstatement of our financial statements), it could adversely affect investor perceptions of our company. Furthermore, if there was a failure in theeffectiveness of our internal controls over financial reporting which results in misstatements in43our financial statements, it could cause us to fail to meet our reporting obligations, could cause the market price of our shares to decline, and we could be subject tosanctions or investigations by the stock exchanges on which we list, the SEC, the Canadian Securities Administrators or other regulatory authorities, and couldadversely affect our ability to access the capital markets.Risks Regarding Our Cash Dividend PolicyWhile we believe that we will have sufficient available cash to enable us to pay the aggregate dividend on our Class A shares for the year ending December 31,2018, we may be unable to pay the quarterly dividend or any amount on our Class A shares during these periods or any subsequent period. Holders of our Class Ashares have no contractual or other legal right to receive cash dividends from us on a quarterly or other basis and, while we currently intend to at least maintain ourcurrent dividend and to grow our business and continue to increase our dividend per Class A share over time, our cash dividend policy is subject to all the risksinherent in our business and may be changed at any time. Some of the reasons for such uncertainties in our stated cash dividend policy include the followingfactors:•Our revolving credit facility includes customary affirmative and negative covenants that will subject certain of our project subsidiaries to restrictions onmaking distributions to us. Our subsidiaries are also subject to restrictions on distributions under the agreements governing their respective project-leveldebt. Additionally, we may incur debt in the future to acquire new power projects, the terms of which will likely require commencement of commercialoperations prior to our ability to receive cash distributions from such acquired projects. These agreements also likely will contain financial tests andcovenants that our subsidiaries must satisfy prior to making distributions. In the future, we may also enter into debt instruments in connection with note orbond offerings which may also contain restrictions on making distributions. If any of our subsidiaries is unable to satisfy applicable financial tests andcovenants or are otherwise in default under our financing agreements, it would be prohibited from making distributions to us, which could, in turn, limit ourability to pay dividends to holders of our Class A shares at our intended level or at all. See "-Risks Related to our Financial Activities-Our substantialamount of indebtedness may adversely affect our ability to operate our business and impair our ability to pay dividends."•Under the terms of operating agreements for our wind facilities with tax equity investors, the share of distributable cash we may receive from these projectsmay change under certain circumstances, and if these circumstances occurred and were adverse, our distributions from such wind facilities may be less thanexpected. For example, two of our wind facilities with tax equity investors have experienced lower than expected production and merchant power pricesresulting in each of those projects failing to pass financial tests that measure cumulative cash distributions to the members. This resulted in 2017 in achange of the cash percentage allocated to the tax equity members which will continue until the shortfall is remedied. See "-Our cash available fordistribution to holders of our Class A shares may be reduced as a result of restrictions on our subsidiaries' cash distributions to us under the terms of theirindebtedness, or in the event certain specified events occurred under our tax equity arrangements that change the percentage of cash distributions to bemade to the tax equity investors."•Our Board of Directors will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of or increase inthose reserves would reduce the cash available to pay our dividends.•We may lack sufficient cash available for distribution to pay our dividends due to operational, commercial or other factors, some of which are outside ofour control, including insufficient cash flow generation by our projects, as well as unexpected operating interruptions, insufficient wind resources, legalliabilities, the cost associated with governmental regulation, changes in governmental subsidies or regulations, increases in our operating or selling, generaland administrative expenses, principal and interest payments on our and our subsidiaries’ outstanding debt, tax expenses, working capital requirements andanticipated cash reserve needs.We are an SEC foreign issuer under Canadian securities laws and, therefore, are exempt from certain requirements of Canadian securities laws applicable toother Canadian reporting issuers.Although we are a reporting issuer in Canada, we are an SEC foreign issuer under Canadian securities laws and are exempt from certain Canadian securities lawsrelating to continuous disclosure obligations and proxy solicitation if we comply with certain reporting requirements applicable in the United States, provided thatthe relevant documents filed with the SEC are filed in Canada and sent to our Class A stockholders in Canada to the extent and in the manner and within the timerequired by applicable U.S. requirements. In some cases, the disclosure obligations applicable in the United States are different or less onerous than the comparabledisclosure requirements applicable in Canada for a Canadian reporting issuer that is not exempt from Canadian disclosure obligations. Therefore, there may be lessor different publicly available information about us than would be available if we were a Canadian reporting issuer that is not exempt from such Canadiandisclosure obligations.44Pattern Development 1.0’s and Pattern Development 2.0’s general partners and their officers and directors have fiduciary or other obligations to act in the bestinterests of the owners of such entities, which could result in a conflict of interest with us and our stockholders.Pattern Development 1.0 holds approximately 7.5% of our outstanding Class A shares, representing in the aggregate an approximate 7.5% voting interest in ourcompany. We are party to the Multilateral Management Services Agreement, pursuant to which each of our executive officers (including our Chief ExecutiveOfficer) is a shared executive and devotes time to each of our company, Pattern Development 1.0, and Pattern Development 2.0 as needed to conduct the respectivebusinesses. As a result, these shared executives have fiduciary and other duties to these Pattern Development Companies. Conflicts of interest may arise in thefuture between our company (including our stockholders other than Pattern Development 1.0), and Pattern Development 1.0 and Pattern Development 2.0 (andtheir respective owners and affiliates). Our directors and executive officers owe fiduciary duties to the holders of our shares. However, Pattern Development 1.0’sand Pattern Development 2.0’s general partners and their officers and directors also have a fiduciary duty to act in the best interest of Pattern Development 1.0’sand Pattern Development 2.0’s limited partners, respectively, which interest may differ from or conflict with that of our company and our other stockholders.The share ownership of certain significant stockholders may limit other stockholders’ ability to influence corporate matters.Public Sector Pension Investment Board and Pattern Development 1.0 (and its affiliates) hold approximately 9.5% and 7.5%, respectively, of the combined votingpower of our shares. The voting power of each of these stockholders may limit other stockholders’ ability to influence corporate matters, and as a result, actionsmay be taken that other stockholders may not view as beneficial. As a result of their ownership in our company, each of these entities have significant influenceover all matters that require approval by our stockholders, including the election of directors. The interests of these significant stockholders may differ from orconflict with the interests of our other stockholders.In addition, under the Joint Venture Agreement we have entered into with PSP Investments, we may add a person that has been designated by PSP Investments toour Board of Directors.Certain of our executive officers will continue to have an economic interest in, and all of our executive officers will continue to provide services to, PatternDevelopment 1.0 and Pattern Development 2.0, which could result in conflicts of interest.All of our executive officers provide services to Pattern Development 1.0 and Pattern Development 2.0 pursuant to the terms of the Multilateral ManagementServices Agreement between our company, Pattern Development 1.0, and Pattern Development 2.0, and, as a result, in some instances, have fiduciary or otherobligations to such Pattern Development Companies. However, neither our Chief Financial Officer, or Chief Investment Officer, receives compensation from, orhas an economic interest in, either Pattern Development 1.0 or Pattern Development 2.0. Additionally, while none of our Chief Executive Officer, Executive VicePresident, Business Development, and Executive Vice President and General Counsel, receive compensation from either Pattern Development 1.0 or PatternDevelopment 2.0, such officers have economic interests in such Pattern Development Companies and, accordingly, the benefit to such Pattern DevelopmentCompanies from a transaction between such Pattern Development Company and our company will proportionately inure to their benefit as holders of economicinterests in such Pattern Development Company. Each of Pattern Development 1.0 and Pattern Development 2.0 are related parties under the applicable securitieslaws governing related party transactions and, as a result, any material transaction between our company and Pattern Development 1.0 or Pattern Development 2.0is subject to our corporate governance guidelines, which require prior approval of any such transaction by the conflicts committee, which is comprised solely ofindependent members of our Board of Directors. Those of our executive officers who have economic interests in Pattern Development 1.0 or Pattern Development2.0 may be conflicted when advising the conflicts committee or otherwise participating in the negotiation or approval of such transactions. These executive officershave significant project- and industry-specific expertise that could prove beneficial to the conflicts committee’s decision-making process and the absence of suchstrategic guidance could have a material adverse effect on our company’s ability to evaluate any such transaction and, in turn, on our business prospects, financialcondition and results of operations.Riverstone is under no obligation to offer us an opportunity to participate in any business opportunities that it may consider from time to time, including thosein the energy industry, and, as a result, Riverstone’s existing and future portfolio companies may compete with us for investment or business opportunities.Conflicts of interest could arise in the future between us, on the one hand, and Riverstone, including its portfolio companies, on the other hand, concerning amongother things, potential competitive business activities or business opportunities. Riverstone is a private equity firm in the business of making investments in entitiesprimarily in the energy industry. As a result, Riverstone’s existing and future portfolio companies (other than Pattern Development 1.0 and Pattern Development2.0, which are subject to the Second Amended and Restated Non-Competition Agreement) may compete with us for investment or business opportunities. Theseconflicts of interest may not be resolved in our favor.45Subject to the terms of the Second Amended and Restated Non-Competition Agreement with, and our respective Purchase Rights granted to us by, each of PatternDevelopment 1.0 and Pattern Development 2.0, we have expressly renounced any interest or expectancy in, or in being offered an opportunity to participate in, anybusiness opportunity that may be from time to time presented to Riverstone or any of its officers, directors, agents, stockholders, members or partners or businessopportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability ordesire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of any fiduciary or other duty, as a director or officer orcontrolling stockholder or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such businessopportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case ofany such person who is our director or officer, any such business opportunity is expressly offered to such director or officer solely in his or her capacity as ourdirector or officer. In view of Riverstone’s policies and practices with respect to the apportionment of business opportunities presented to the investment fundsmanaged or advised by it and their respective portfolio companies, a business opportunity presented to such fund or portfolio company may generally be pursuedby such fund (or other Riverstone funds, as applicable) or directed to any such portfolio company.As a result, Riverstone may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct suchopportunities to other businesses in which it has invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunities.Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any businessopportunity that may be from time to time presented to Riverstone could adversely impact our business or prospects if attractive business opportunities areprocured by such parties for their own benefit rather than for ours.Our actual or perceived failure to deal appropriately with conflicts of interest with the Pattern Development Companies could damage our reputation, increaseour exposure to potential litigation and have a material adverse effect on our business prospects, financial condition and results of operations.Our conflicts committee is required to review, and make recommendations to the full Board of Directors regarding, any future transactions involving theacquisition of an asset or investment in an opportunity offered to us by Pattern Development 1.0 or Pattern Development 2.0 to determine whether the offer is fairand reasonable (including any acquisitions by us of assets of Pattern Development 1.0 or Pattern Development 2.0 pursuant to our respective Purchase Rights).Furthermore, during 2017 and through February 2018 we have made an aggregate investment of $102.5 million in Pattern Development 2.0 resulting in anownership of approximately 21%. We have established certain governance procedures between ourselves and Pattern Development 2.0 to manage conflicts issueswhich may arise between ourselves and Pattern Development 2.0, which include having the chair of the conflicts committee, or his designee, attend regularlyscheduled meetings of the Pattern Development 2.0 board at which the development pipeline will be reviewed and anticipated funding needs will be discussed, andregular reporting of reasonably expected potential conflicts between us and Pattern Development 2.0 to the conflicts committee.However, our establishment of a conflicts committee and governance procedures for our Pattern Development 2.0 investment may not prevent holders of ourshares from filing derivative claims against us related to these conflicts of interest and related party transactions. Regardless of the merits of their claims, we maybe required to expend significant management time and financial resources on the defense of such claims. Additionally, to the extent we fail to appropriately dealwith any such conflicts, it could negatively impact our reputation and ability to raise additional funds and the willingness of counterparties to do business with us,all of which could have a material adverse effect on our business prospects, financial condition and results of operations.Market interest and foreign exchange rates may have an effect on the value of our Class A shares.One of the factors that influences the price of our Class A shares will be the effective dividend yield of our Class A shares ( i.e ., the yield as a percentage of thethen market price of our Class A shares) relative to market interest rates. An increase in market interest rates, which are currently at low levels relative to historicalrates, may lead prospective purchasers of our Class A shares to expect a higher dividend yield and, our inability to increase our dividend as a result of an increasein borrowing costs, insufficient cash available for distribution or otherwise, could result in selling pressure on, and a decrease in the market price of, our Class Ashares as investors seek alternative investments with higher yield. Additionally, we intend to pay a regular quarterly dividend in U.S. dollars and, as a result, to theextent the value of the U.S. dollar dividend decreases relative to Canadian dollars, the market price of our Class A shares in Canada could decrease.46The price of our Class A shares may fluctuate significantly, and stockholders could lose all or part of their investment.Volatility in the market price of our shares may prevent stockholders from being able to sell their Class A shares at or above the price stockholders paid for theirshares. The market price of our Class A shares could fluctuate significantly for various reasons, including:•our operating and financial performance and prospects;•our quarterly or annual results of operations or those of other companies in our industry;•a change in interest rates or changes in currency exchange rates;•the public’s reaction to our press releases, our other public announcements and our filings with the Canadian securities regulators and the SEC;•changes in, or failure to meet, earnings estimates or recommendations by research analysts who track our Class A shares or the stock of other companiesin our industry;•the failure of research analysts to cover our Class A shares;•strategic actions by us, our power purchasers or our competitors, such as acquisitions or restructurings;•new laws or regulations or new interpretations of existing laws or regulations applicable to our business;•changes in accounting standards, policies, guidance, interpretations or principles;•material litigation or government investigations;•changes in applicable tax laws;•changes in general conditions in the United States, Canadian and global economies or financial markets, including those resulting from war, incidents ofterrorism or responses to such events;•changes in key personnel;•sales of Class A shares by us or members of our management team;•termination of lock-up agreements with our management team and principal stockholders;•the granting or exercise of employee stock options;•volume of trading in our Class A shares; and•the realization of any risks described under “Risk Factors.”Volatility in the stock markets has had a significant impact on the market price of securities issued by many companies, including companies in our industry andyieldcos. The changes frequently appear to occur without regard to the operating performance of the affected companies. Hence, the price of our Class A sharescould fluctuate based upon factors that have little or nothing to do with our company, and these fluctuations could materially reduce the share price of our Class Ashares and cause stockholders to lose all or part of their investment. Further, in the past, market fluctuations and price declines in a company’s stock have led tosecurities class action litigation. If such a suit were to arise, it could have a substantial cost and divert our resources regardless of the outcome.We incur increased costs and demands upon management as a result of complying with the laws and regulations affecting public companies, which couldharm our operating results.As a public company, we incur significant legal, accounting, investor relations and other expenses that we did not incur as a private company, including costsassociated with public company reporting requirements. We also have incurred and will incur costs associated with current corporate governance requirements,Section 404 and other provisions of the Sarbanes-Oxley Act and the Dodd-Frank Wall47Street Reform and Consumer Protection Act of 2010, as well as rules implemented by the SEC, the Canadian Securities Administrators and the stock exchanges onwhich our Class A shares are traded.The expenses incurred by public companies for reporting and corporate governance purposes have increased dramatically over the past several years. Greaterexpenditures may be necessary in the future with the advent of new laws and regulations pertaining to public companies. If we are not able to comply with theserequirements in a timely manner, the market price of our Class A shares could decline and we could be subject to sanctions or investigations by the SEC, theCanadian Securities Administrators, the applicable stock exchanges or other regulatory authorities, which would require additional financial and managementresources.As a result of the FPA and FERC’s regulations in respect of transfers of control, absent prior authorization by FERC, neither we nor Pattern Development 1.0can convey, nor will an investor in our company generally be permitted to obtain, a direct and/or indirect voting interest in 10% or more of our issued andoutstanding voting securities, and a violation of this limitation could result in civil or criminal penalties under the FPA and possible further sanctions imposedby FERC under the FPA.We are a holding company with U.S. operating subsidiaries that are “public utilities” (as defined in the FPA) and, therefore, subject to FERC’s jurisdiction underthe FPA. As a result, the FPA requires us or Pattern Development 1.0, as the case may be, either to (i) obtain prior authorization from FERC to transfer an amountof our voting securities sufficient to convey direct or indirect control over any of our public utility subsidiaries or (ii) qualify for a blanket authorization grantedunder or an exemption from FERC’s regulations in respect of transfers of control. Similar restrictions apply to purchasers of our voting securities who are a“holding company” under the PUHCA, in a holding company system that includes a transmitting utility or an electric utility, or an “electric holding company,”regardless of whether our voting securities were purchased in our initial public offering, subsequent offerings by us or Pattern Development 1.0, in open markettransactions or otherwise. A purchaser of our voting securities would be a “holding company” under the PUHCA and an electric holding company if the purchaseracquired direct or indirect control over 10% or more of our voting securities or if FERC otherwise determined that the purchaser could directly or indirectlyexercise control over our management or policies (e.g., as a result of contractual board or approval rights). Under the PUHCA, a “public-utility company” isdefined to include an “electric utility company,” which is any company that owns or operates facilities used for the generation, transmission or distribution ofelectric energy for sale, and which includes EWGs such as our U.S. operating subsidiaries. Accordingly, absent prior authorization by FERC or an increase to theapplicable percentage ownership under a blanket authorization, for the purposes of sell-side transactions by us or Pattern Development 1.0 and buy-sidetransactions involving purchasers of our securities that are electric holding companies, no purchaser can acquire 10% or more of our issued and outstanding votingsecurities. A violation of these regulations by us or Pattern Development 1.0, as sellers, or an investor, as a purchaser of our securities, could subject the party inviolation to civil or criminal penalties under the FPA, including civil penalties of up to approximately $1.25 million per day per violation (which amount isadjusted annually to account for inflation) and other possible sanctions imposed by FERC under the FPA.As a result of the FPA and FERC’s regulations in respect of transfers of control, and consistent with the requirements for blanket authorizations granted thereunderor exemptions therefrom, absent prior authorization by FERC, no purchaser of our Class A common stock in the open market, or in subsequent offerings of ourvoting securities, will be permitted to purchase an amount of our securities that would cause such purchaser and its affiliate and associate companies to collectivelyhold 10% or more of our voting securities outstanding. Additionally, investors should manage their investment in us in a manner consistent with FERC’sregulations in respect of obtaining direct or indirect “control” of our company. Accordingly, absent prior authorization by FERC, investors in our Class A commonstock are advised not to acquire a direct and/or indirect voting interest in 10% or more of our issued and outstanding voting securities, whether in connection withan offering by us or Pattern Development 1.0 or in open market purchases or otherwise.Provisions of our organizational documents and Delaware law might discourage, delay or prevent a change of control of our company or changes in ourmanagement and, as a result, depress the trading price of our Class A shares.Our amended and restated certificate of incorporation and amended and restated bylaws contain provisions that could discourage, delay or prevent a change incontrol of our company or changes in our management that the stockholders of our company may deem advantageous. These provisions:•authorize the issuance of blank check preferred stock that our Board of Directors could issue to increase the number of outstanding shares and to discouragea takeover attempt;•prohibit our stockholders from calling a special meeting of stockholders;•prohibit stockholder action by written consent, which requires all stockholder actions to be taken at a meeting of our stockholders;48•provide that the Board of Directors is expressly authorized to adopt, or to alter or repeal our bylaws; and•establish advance notice requirements for nominations for election to our Board of Directors or for proposing matters that can be acted upon bystockholders at stockholder meetings.These anti-takeover defenses could discourage, delay or prevent a transaction involving a change in control of our company. These provisions could alsodiscourage proxy contests and make it more difficult for stockholders to elect directors of their choosing and cause us to take corporate actions other than thosedesired.Future sales of our shares in the public market could lower our Class A share price, and any additional capital raised by us through the sale of equity orconvertible debt securities may dilute stockholders’ ownership in us and may adversely affect the market price of our Class A shares.In addition to follow-on offerings of our Class A shares in each of 2014, 2015 and 2016, in October 2017 we completed a follow-on offering in which a total of9,200,000 Class A shares were sold. We also established an “at-the-market” equity distribution program in May 2016 under which we sold approximately 1.2million and 1.1 million shares in 2016 and 2017, respectively. In addition, previously in July 2015, we issued $225.0 million aggregate principal amount of 4.00%Convertible Senior Notes due 2020. If we sell, or if Pattern Development 1.0 or other significant stockholders sell, additional large numbers of our Class A shares,or if we issue a large number of shares of our Class A common stock in connection with future acquisitions, financings, or other circumstances, the market price ofour Class A shares could decline significantly. Moreover, the perception in the public market that we, Pattern Development 1.0 or another significant stockholdermight sell Class A shares could depress the market price of those shares.In addition, in May 2014, Pattern Development 1.0 entered into a loan agreement pursuant to which it may pledge our Class A shares owned by it to secure suchloan. As of December 31, 2017, substantially all of our Class A shares owned by Pattern Development 1.0, approximating 7.4 million Class A shares, have beenpledged as security for such loan. If Pattern Development 1.0 were to default on its obligations under the loan, the lenders would have the right to sell shares tosatisfy Pattern Development 1.0’s obligation. Such an event could cause our stock price to decline. In addition, in August 2017, Pattern Development 1.0 enteredinto a trading plan pursuant to Rule 10b5-1 under the Securities Exchange Act of 1934, as amended, pursuant to which periodic sales of up to an aggregate of 6.0million Class A shares may be made, subject to the terms of the trading plan. We cannot predict the size of future issuances of our Class A shares, sales of ourClass A shares, or sales of securities convertible into our Class A shares, or the effect, if any, that any such future issuances or sales will have on the market priceof our shares. Sales of substantial amounts of our shares (including sales pursuant to either Pattern Development 1.0’s or PSP Investments's registration rights andshares issued in connection with an acquisition) or securities convertible into our shares, or the perception that such sales could occur, may adversely affectprevailing market prices for our Class A shares.Item 1B.Unresolved Staff Comments . None. Item 2.Properties.Leased FacilitiesOur corporate headquarters and executive offices are located in San Francisco, California and we additionally lease office space in Houston, Texas.Our ProjectsWe hold interests in 25 wind and solar power projects, including projects which we have committed to acquire. Our projects are located in the United States,Canada, Japan and Chile and have a total owned capacity of 2,942 MW. We typically finance our wind and solar projects through project entity specific debtsecured by each project's assets with no recourse to us. For details on our operating wind and solar power projects, please see Item 1 "Business - Our Projects" inthis Form 10-K.Item 3.Legal Proceedings.During the third quarter of 2015, rights to appeal prior decisions granting the Renewable Energy Approval (REA) under Ontario's Environmental Protection Actfor our K2 facility were exhausted without further appeal. As a result, a stay of a previously filed civil suit against the K2 facility pending final determination of theREA was lifted, allowing such suit to move forward if the claimants so chose to continue such suit. K2 has been awarded their legal fees in connection with theportion of the claim that was stricken, and has reached a settlement agreement under which K2 will waive entitlement to the legal fees and in return claimants haveagreed to full dismissal of all pending claims.We are also subject, from time to time, to various other routine legal proceedings and claims arising out of the normal course of business. These proceedingsprimarily involve claims from landowners related to calculation of land royalties and warranty claims we initiate against equipment suppliers. The outcome ofthese legal proceedings and claims cannot be predicted with certainty. Nevertheless, we believe the outcome of any of such currently existing proceedings, even ifdetermined adversely, would not have a material adverse effect on our financial condition or results of operations. Item 4.Mine Safety Disclosures.Not applicable.49PART II Item 5.Market for Registrant’s Common Equity and Related Stockholder Matters.Our Class A common stock is traded on the National Association of Securities Dealers Automated Quotations (NASDAQ) Global Select Market and on theToronto Stock Exchange (TSX) under the trading symbol “PEGI.” On February 23, 2018 , the last reported sale price of our Class A common stock on theNASDAQ Global Select Market was $18.91 per share and on the TSX was C $23.93 per share.The following table sets forth, for the periods indicated, the high and low sales prices for our Class A common stock on the NASDAQ Global Select Market: 2017 2016 High Low High LowFourth Quarter $24.94 $20.58 $23.01 $18.68Third Quarter $26.56 $22.87 $25.13 $22.27Second Quarter $25.42 $19.82 $23.02 $17.70First Quarter $21.28 $18.83 $21.01 $14.56The following table sets forth, for the periods indicated, the range of high and low sales prices for our Class A common stock on the TSX: 2017 2016 High Low High LowFourth Quarter C$30.82 C$26.50 C$30.65 C$25.01Third Quarter C$32.57 C$29.66 C$33.00 C$29.01Second Quarter C$33.35 C$26.65 C$29.74 C$23.24First Quarter C$27.74 C$25.35 C$29.20 C$20.50On October 23, 2017, we completed an underwritten public offering of our Class A common stock. In total, 9,200,000 shares of our Class A common stock weresold at a public offering price of $23.40 per share. This includes 1,200,000 shares purchased by the underwriters to cover over-allotments. Aggregate net proceedsof the equity offering, including the proceeds of the over-allotment option, were approximately $211.9 million after deduction of underwriting discounts,commissions, and transaction expenses.On May 9, 2016, we entered into an Equity Distribution Agreement. Pursuant to the terms of the Equity Distribution Agreement, we may offer and sell shares ofour Class A common stock, par value $0.01 per share, from time to time through the Agents, as our sales agents for the offer and sale of the shares, up to anaggregate sales price of $200.0 million. For the year ended December 31, 2017, we sold 1,068,261 shares under the Equity Distribution Agreement and netproceeds under the issuances were $25.3 million .Holders of RecordBecause many of our shares of Class A common stock are held by brokers and other institutions on behalf of stockholders, we are unable to estimate the totalnumber of stockholders represented by these record holders. As of February 23, 2018 , there were approximately 15 stockholders of record of our Class A commonstock.50Stock performance chartThis performance graph shall not be deemed “soliciting material” or to be “filed” with the SEC for purposes of Section 18 of the Securities Exchange Act of 1934,as amended, or the "Exchange Act," or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into anyfiling of Pattern Energy Group Inc. under the Securities Act of 1933, as amended, or the "Securities Act."The following graph shows a comparison from September 27, 2013 (the date our Class A common stock commenced trading on the NASDAQ) throughDecember 31, 2017 of the cumulative total stockholder return for our Class A common stock, the NASDAQ Composite Index (NASDAQ Composite) and thePhiladelphia Utility Sector Index. The graph assumes that $100 was invested at the market close on September 27, 2013 in the Class A common stock of PatternEnergy Group Inc., the NASDAQ Composite and the Philadelphia Utility Sector Index and also assumes reinvestments of dividends. The stock price performanceof the following graph is not necessarily indicative of future stock price performance.51Cash Dividend to InvestorsWe intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A stock. The following table sets forth the dividends declared on shares ofClass A common stock for the periods indicated. On February 22, 2018 , we maintained our dividend at $ 0.4220 per share of Class A common stock, or $ 1.688per share of Class A common stock on an annualized basis, commencing with respect to dividends paid on April 30, 2018 to holders of record on March 30, 2018 . Dividends Declared2018 First Quarter$0.42202017Fourth Quarter$0.4220Third Quarter$0.4200Second Quarter$0.4180First Quarter$0.41382016Fourth Quarter$0.4080Third Quarter$0.4000Second Quarter$0.3900First Quarter$0.3810We have established our quarterly dividend level based on a targeted cash available for distribution payout ratio, after considering the annual cash available fordistribution that we expect our projects will be able to generate and with due regard to retaining a portion of the cash available for distribution to grow ourbusiness. We intend to grow our business primarily through the acquisition of operational and construction ready power projects, which, we believe, will facilitatethe growth of our cash available for distribution and enable us to increase our dividend per share of Class A common stock over time. We may in the future raisecapital and make investments in new power projects upon or near the commencement of construction of such projects and therefore prior to the expectedcommencement of operations of the new projects, which could result in a passage of time of twelve or more months before we begin to receive any cash flowcontributions from such projects to our cash available for distribution. In connection with these investments, we may increase our dividends prior to the receipt ofsuch cash flow contributions, which would likely cause our payout ratio to temporarily exceed our targeted run-rate payout ratio. However, the determination of theamount of cash dividends to be paid to holders of our Class A common stock will be made by our Board of Directors and will depend upon our financial condition,results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant. See Item 1A “ Risk Factors —Risks Relatedto Ownership of our Class A Shares—Risks Regarding our Cash Dividend Policy.”We expect to pay a quarterly dividend on or about the 30th day following each fiscal quarter to holders of record of our Class A common stock on the last day ofsuch quarter.Our cash available for distribution is likely to fluctuate from quarter to quarter, perhaps significantly, as a result of variability in wind conditions and other factors.Accordingly, during quarters in which we generate cash available for distribution in excess of the amount required to pay our stated quarterly dividend, we mayreserve a portion of the excess to fund dividends in future quarters. In addition, we may use sources of cash not included in our calculation of cash available fordistribution, such as certain net cash provided by financing and investing activities, to pay dividends to holders of our Class A common stock in quarters in whichwe do not generate sufficient cash available for distribution to fund our stated quarterly dividend. Although these other sources of cash may be substantial andavailable to fund a dividend payment in a particular period, we exclude these items from our calculation of cash available for distribution because we considerthem non-recurring or otherwise not representative of the operating cash flows we typically expect to generate. See Item 7 “Management's Discussion andAnalysis of Financial Condition and Results of Operations—Key Metrics—Cash Available for Distribution."52Repurchase of Equity SecuritiesThe table below provides information with respect to repurchases of our Class A common stock during the fourth quarter ended December 31, 2017 . All shareswere tendered to us in satisfaction of employee tax withholding obligations upon the vesting of restricted stock grants under our 2013 Equity Incentive AwardPlan. We currently do not have a stock repurchase plan in place. Period Total Number of Shares Purchased Average Price Paid Per Share10/1/17-10/31/17 — $—11/1/17-11/30/17 — $—12/1/17-12/31/17 42,666 $21.41 42,666 $21.41For information on the equity compensation plans see Item 12 "Security Ownership of Certain Beneficial Owners and Management and Related StockholderMatters."53Item 6.Selected Financial Data.Set forth below is our summary historical consolidated financial data. This information may not be indicative of our future results of operations, financial positionand cash flows and should be read in conjunction with the consolidated financial statements and notes thereto and Item 7 “ Management’s Discussion and Analysisof Financial Condition and Results of Operations ” presented elsewhere in this Form 10-K. We believe that the assumptions underlying the preparation of ourhistorical consolidated financial statements are reasonable. Year Ended December 31, 2017 2016 2015 2014 2013 (in thousands, except per share data)Statement of operations data: Total revenue (1) $411,344 $354,052 $329,831 $265,493 $201,573Operating income (expense) 10,259 5,311 37,105 57,593 48,393Net income (loss) (82,410) (52,299) (55,607) (39,999) 10,072Net loss attributable to noncontrolling interest (64,505) (35,188) (23,074) (8,709) (6,887)Net income (loss) attributable to Pattern Energy $(17,905) $(17,111) $(32,533) $(31,290) $16,959Less: Net income attributable to Pattern Energy prior to the initial publicoffering on October 2, 2013 (30,295)Net loss attributable to Pattern Energy subsequent to the initial public offering $(13,336)Loss per share data: Class A common stock: basic and diluted loss per share $(0.20) $(0.22) $(0.46) $(0.56) $(0.17)Class B common stock: basic and diluted loss per share N/A N/A N/A (0.49) (0.48)Dividends: Dividends declared per Class A common share $1.67 $1.58 $1.43 $1.30 $0.31Deemed dividends per Class B common share N/A N/A N/A $1.41 —Balance sheet data: Total assets (1)(2) $4,741,531 $3,752,767 $3,829,592 $2,795,287 $1,872,233Revolving credit facility $— $180,000 $355,000 $50,000 $—Long-term debt including current portion, net of financing costs (2) $1,930,731 $1,383,672 $1,415,886 $1,413,858 $1,217,820Total liabilities $2,393,389 $1,874,023 $2,053,830 $1,630,553 $1,304,229(1)Total revenues and total assets increased during the years ended and as of December 31, 2017, December 31, 2015 and 2014 compared to the years ended and as of December 31, 2016,December 31, 2014 and 2013, respectively, primarily due to acquisitions and the commencement of operations at various project wind farms. For further details of acquisitions, see Note 3, Acquisitions , in the notes to consolidated financial statements.(2)In 2015, we early adopted ASU 2015-03, “Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs." As a result, we reclassified deferred financing costs fromother assets to long-term debt. In the table above, prior year presentation of long-term debt reflects the reclassification of deferred financing costs.54Item 7.Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and relatednotes included elsewhere in this Form 10-K. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs andexpected performance. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of anumber of factors, including those we discuss under Item 1A "Risk Factors" elsewhere in this Form 10-K. We caution that assumptions, expectations, projections,intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See "Cautionary Notice RegardingForward-Looking Statements."OverviewWe are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential forcontinued growth of our business. We hold interests in 25 wind and solar power projects, including projects that we have committed to acquire with a total ownedcapacity of 2,942 MW in the United States, Canada, Japan and Chile that use proven and best-in-class technology. Each of our projects has contracted to sell all ora majority of its output pursuant to a long-term, fixed-price PSAs, some of which are subject to price escalation. Ninety-two percent of the electricity to begenerated by our projects will be sold under our PSAs which have a weighted average remaining contract life of approximately 14 years as of December 31, 2017 .We intend to maximize long-term value for our stockholders in an environmentally responsible manner and with respect for the communities in which we operate.Our business is built around three core values of creative energy and spirit, pride of ownership and follow-through and a team first attitude, which guide us increating a safe, high-integrity work environment, applying rigorous analysis to all aspects of our business and proactively working with our stakeholders to addressenvironmental and community concerns. Our financial objectives, which we believe will maximize long-term value for our stockholders, are to produce stable andsustainable cash available for distribution, selectively grow our project portfolio and our dividend per Class A share and maintain a strong balance sheet andflexible capital structure.Our growth strategy is focused on the acquisition of operational and construction-ready power projects from the Pattern Development Companies and other thirdparties that, together with measured investments into the development business, we believe will contribute to the growth of our business and enable us to increaseour dividend per share of Class A common stock over time. The Pattern Development Companies (Pattern Energy Group LP (Pattern Development 1.0), PatternEnergy Group 2 LP (Pattern Development 2.0) and their respective subsidiaries) are leading developers of renewable energy and transmission projects. Ourcontinuing relationship with the Pattern Development Companies, including a 21% interest in Pattern Development 2.0, provides us with access to a pipeline ofacquisition opportunities. Currently, the Pattern Development Companies have a more than 10 GW pipeline of development projects, all of which are subject to ourright of first offer. We target achieving a total owned or managed capacity of 5,000 MW by year end 2020 through a combination of acquisitions from the PatternDevelopment Companies and other third parties capitalizing on the large and fragmented global renewable energy market. Our business is primarily focused in theU.S., Canada, Japan and Chile; however, we expect Mexico will form part of our growth strategy.The discussion and analysis below has been organized as follows:•Recent Developments•Factors that Significantly Affect our Business◦Trends Affecting our Industry◦Factors Affecting our Operational Results•Key Metrics•Results of Operations•Liquidity and Capital Resources◦Sources of Liquidity◦Uses of Liquidity◦Covenants, Distribution Conditions and Events of Default•Critical Accounting Policies and Estimates55Recent DevelopmentsOn February 26, 2018 , we entered into a series of purchase and sale agreements with Pattern Development 1.0 and Green Power Investments (GPI) to purchase206 MW of renewable energy projects, consisting of Futtsu Solar, Kanagi Solar, Otsuki, Ohorayama and Tsugaru. The acquisition price for the 84 MW projectportfolio (Futtsu Solar, Kanagi Solar, Otsuki and Ohorayama) is approximately $131.5 million , subject to certain closing price adjustments. The acquisition priceof Tsugaru for the 122 MW wind project is approximately $194.0 million , consisting of an initial payment of approximately $79.7 million to be funded at closingand approximately JPY12.567 billion payable to Pattern Development 1.0 upon the term conversion of the construction loan and to the extent such term conversiondoes not occur, such second consideration payment will be made upon the commencement of commercial operations at Tsugaru which is expected in 2020. Weexpect to close on these transactions in early to mid 2018.On October 23, 2017, we completed an underwritten public offering of our Class A common stock. In total, 9,200,000 shares of our Class A common stock weresold at a public offering price of $23.40 per share. This includes 1,200,000 shares purchased by the underwriters to cover over-allotments. Aggregate net proceedsof the equity offering, including the proceeds of the over-allotment option, were approximately $211.9 million after deduction of underwriting discounts,commissions and transaction expenses.On August 10, 2017, pursuant to a Purchase and Sale Agreement with Pattern Development 1.0, we acquired 50.99% of the limited partner interests in MeikleWind Energy Limited Partnership (Meikle) and 70% of the issued and outstanding shares of Meikle Wind Energy Corp. (Meikle Corp) for a purchase price ofapproximately $67.4 million, paid at closing, in addition to $1.1 million of capitalized transaction-related expenses. Meikle operates the approximately 179 MWwind farm located in the Peace River Regional District of British Columbia, Canada, which achieved commercial operations in the first quarter of 2017. On June 16, 2017, we entered into several agreements with the Pattern Development Companies and the Public Sector Pension Investment Board (PSPInvestments) which resulted in the following transactions:•On July 27, 2017, we funded an initial investment of $60 million in Pattern Development 2.0 for an approximately 20% initial ownership, with a right, butnot the obligation, to participate in subsequent capital calls for a total commitment of up to $300 million. If this right is exercised for all future capitalcalls, this would increase our ownership to approximately 29%. On December 26, 2017, we funded an additional capital call for $7.3 million. In February2018, we also funded approximately $35.2 million into Pattern Development 2.0 of which approximately $27 million will be used by PatternDevelopment 2.0 to fund the purchase of GPI.•We entered into a Joint Venture Agreement with PSP Investments pursuant to which PSP Investments will have the right to co-invest up to an aggregateamount of approximately $500 million in projects acquired by us under our Project Purchase Rights with the Pattern Development Companies, includinginvestments in Meikle, MSM and Panhandle 2.•In August 2017, we acquired a 51% interest in Meikle as discussed above.•We committed to acquire from Pattern Development 1.0 a 51% interest in MSM, a 143MW wind power project, for approximately $40 million.•On December 22, 2017, we sold 49% of the Class B membership interest in the 182 MW Panhandle 2 project to PSP Investments for $58.6 million .On April 21, 2017, we acquired an 84% initial distributable cash flow interest in Broadview and a 99% ownership interest in Western Interconnect from PatternDevelopment 1.0. Consideration consisted of $214.7 million of cash, a $2.4 million assumed liability and a post-closing payment of approximately $21.3 millioncontingent upon the commercial operation of the Grady Project. As part of the acquisition, we also assumed $51.2 million of construction debt and accrued interestoutstanding at Western Interconnect which was immediately extinguished, and concurrently, we entered into a variable rate term loan for $54.4 million. The GradyProject is a wind project on the Identified ROFO Projects list being separately developed by Pattern Development 2.0 which is expected to begin full constructionin 2018, and which intends to interconnect through Western Interconnect. Following the commencement of commercial operations of the Grady Project, at whichtime the Grady Project will begin making transmission service payments to Western Interconnect, the Company will make the aforementioned contingent post-closing payment.In March 2017, we entered into revised Long-term Service Agreements (LTSAs) at certain of our projects pursuant to which the turbine manufacturer will continueto provide routine and corrective maintenance service, but we have become responsible for a portion of the maintenance and repairs, including on majorcomponent parts.56Factors that Significantly Affect our BusinessOur results of operations in the near-term, as well as our ability to grow our business and revenue from electricity sales over time, could be impacted by a numberof factors, including trends affecting our industry and factors affecting our operating results as discussed below:Trends Affecting our IndustryThe growth in the industry is largely attributable to renewable energy’s increasing cost competitiveness with other power generation technologies, the advantagesof wind and solar power over other renewable energy sources and growing public support for renewable energy driven by energy security and environmentalconcerns.We believe that the key drivers for the long-term growth of renewable power include:•increased demand for renewable energy resulting from regulatory or policy initiatives. Notable initiatives include country, state or provincial RPS programs;•governmental incentives for renewable energy including feed-in-tariff regimes, carbon credits and the U.S. federal based production or investment tax credits,which were extended through December 2019 (wind) and December 2022 (solar), that improve the cost competitiveness of renewable energy compared totraditional sources;•new demand created by corporate and industrial buyers directly procuring renewable electricity on a large scale;•efficiency and capital cost improvements in wind, solar and other renewable energy technologies, enabling wind and other forms of renewable energy tocompete successfully in more markets;•environmental and social factors supporting increasing levels of wind, solar and other renewable technologies in the generation mix;•regulatory barriers, market pressure and public acceptance challenges increase the time, cost and difficulty of permitting new fossil fuel-fired facilities, notablycoal, and nuclear facilities;•decommissioning of aging coal-fired and nuclear facilities is expected to leave a gap in electricity supply; and•policy initiatives to include such externalities as the cost of carbon pollution, methane leakage and water usage in conventional fossil fuel-fired electricitygeneration over time will increase costs of conventional generation.In general, we continue to believe that there will be additional acquisition opportunities in the United States in the short term and that the longer-term growth trendwill continue.Our OutlookOur projects are generally unaffected by short-term trends given that 92% of the electricity to be generated by our projects is to be sold under our fixed-price powersale agreements, which have a weighted average remaining life of approximately 14 years as of December 31, 2017.Our near-term growth strategy will focus on wind and solar power projects. We expect that most of our short-term growth will come from opportunities to acquirethe Identified ROFO Projects, but we will evaluate unaffiliated third-party asset acquisition opportunities as well. In addition, we will continue to evaluate furtherinvestment in Pattern Development 2.0 as discussed below.Factors Affecting our Operational ResultsThe primary factors that will affect our financial results are (i) electricity sales and energy derivative settlements of our operating projects, (ii) project operations,(iii) debt financing, (iv) congestion in the Texas market, (v) general and administrative costs, (vi) acquisitions and (vii) investment in Pattern Development 2.0.Electricity Sales and Energy Derivative Settlements of our Operating ProjectsOur electricity sales and energy derivative settlements are primarily determined by the price of electricity and any environmental attributes we sell under our powersale agreements and the amount of electricity that we produce, which is in turn principally the result of the wind conditions at our project sites and the performanceof our equipment. We base our estimates of each project’s capacity to generate electricity on the findings of our internal and external experts’ long-termmeteorological studies, which include on-site data collected from equipment on the property and relevant reference wind data from other sources, as well asspecific equipment power curves and estimates for the57performance of our equipment over time. Ninety-two percent of the electricity to be generated across our projects is currently committed under long-term, fixed-price power sale agreements which have a weighted average remaining contract life of approximately 14 years as of December 31, 2017.Our wind analysis evaluates the wind’s speed and prevailing direction, atmospheric conditions, and wake and seasonal variations for each project. The result of ourmeteorological analysis is a probabilistic assessment of a project’s likely output. A P50 level of production indicates we believe a 50% probability exists that theelectricity generated from a project will exceed a specified aggregate amount of electricity generation during a given period. While we plan for variability aroundthis P50 production level, it generally provides the foundation for our base case expectation. The variability is measured in a spectrum of possible output levelssuch as a P75 output level, which indicates that over a specified period of time, such as one or ten years, the P75 output level would be exceeded 75% of the time.Similarly, the P25 output level would be exceeded 25% of the time. We often use P95, P90 and P75 production levels to plan ahead for low-wind years, whilerecognizing that we should also have corresponding high-wind years.In addition to annual P50 variability, we also expect seasonal variability to occur. Variability increases as the period of review shortens, so it is likely that we willexperience more variability in monthly or quarterly production than we do for annual production. Therefore, our periodic cash flow and payout ratios will alsoreflect more variability during periods shorter than a year. As a result, we use cash reserves to help manage short term production and cash flow variability.When analyzed together, a portfolio’s probability of exceeding a specific output level changes when all the projects are considered as a portfolio instead of on astand-alone basis. Due to the geographical separation between our projects, the uncertainty variables and wind speed correlations are diverse enough across theportfolio to provide reduction in the overall uncertainty, which we refer to as the portfolio effect. For example, the sum of our individual projects’ P75 outputlevels is approximately 93% of the aggregate P50 output level (which is unaffected by the portfolio effect), while the P75 output level, when taking into accountthe portfolio effect, is approximately 96% of our aggregate P50 output level. On a portfolio basis, our P90 and P95 production estimates for the annual electricitygeneration of our twenty operating projects (excluding projects in Japan we have agreed to acquire) are approximately 91% and 89%, respectively, of our estimatedP50 output levels. The portfolio effect results in an improvement in the production stability across the portfolio. A greater diversity of projects in the portfolio hasthe effect of increasing the frequency of occurrences aggregated around the expected result (probability level).Our electricity generation is also dependent on the equipment that we use. We have selected high-quality equipment with a goal of having a concentration ofturbines from top manufacturers. With a combination of high-quality equipment and scale and in-house operating capability, we have structured our projects suchthat we may expect high availability and long-term production from the equipment, develop operating expertise and experience, which can be shared among ouroperators, obtain a high level of attention and focus from the manufacturers and common operating practices. Given our manufacturers’ global fleet sizes andstrong balance sheets, the warranties that we secure for our turbines and our operating approach described below, we are confident in our expectations for reliablelong-term turbine operation.Impact of Derivative InstrumentsWhere possible, we have sought to protect ourselves against electricity and interest rate exposures with a relatively longer term hedging strategy. We expect tohedge exposure to foreign currency exchange rates in the future over shorter periods of time. Accordingly, we have experienced in the past, and expect to record inthe future, substantial volatility in the components of our net income that relate to the mark-to-market adjustments on our undesignated energy and interest ratederivatives.We believe that mark-to-market adjustments that we make to the fair value of our derivative assets and liabilities are generally mirrored by changes in theeconomic value of the related operating or financial assets, such as our wind projects and our project loans, for which the application of accounting principlesgenerally accepted in the United States (U.S. GAAP) does not permit us to record such economic gains and losses. For this reason, and because one of ourprincipal financial objectives is to produce stable and sustainable cash available for distribution, we believe that the economic value to our shareholders reflected inthese derivative instruments, outweighs the risk of volatility in net income that we expect to report. Accordingly, we believe it is useful to investors to considersupplemental financial measures that we report, such as Adjusted Earnings Before Interest, Taxes, Depreciation, Amortization and Accretion (Adjusted EBITDA),where we have subtracted and added back, as applicable, the unrealized gains and losses arising from mark-to-market adjustments on our derivative instruments,and cash available for distribution.58Project OperationsTurbine AvailabilityOur ability to generate electricity in an efficient and cost-effective manner is impacted by our ability to maintain the operating capacity of our projects. We usereliable and proven wind turbines and other equipment for each of our projects. For the years ended December 31, 2017 and 2016, our turbine availability acrossour projects was 97.4% and 96.8% respectively, which is in line with industry standards for original investment projections reviewed by independent engineeringfirms.Operations and maintenance - self-performIn early 2017, we revised long-term turbine manufacturer service arrangements at certain of our projects pursuant to which the turbine manufacturer continues toprovide routine and corrective maintenance service, but we are responsible for a portion of the maintenance and repairs, including on major component parts.These revised service arrangements have reduced our fixed contract costs. Over time we are generally taking on more operational responsibility and risks as anowner, including self-performing maintenance and service work with our own technicians instead of utilizing service providers, which will have continuingexpected cost benefits, but will similarly come with increased risks and reduced third party warranty and guarantee protections. We completed this transition toself-perform at five of our projects by the end of 2017 and expect to make a similar transition at additional projects in the future.Debt FinancingWe intend to use a portion of our revenue from electricity sales to cover our subsidiaries’ interest expense and principal payments on borrowings under theirrespective project financing facilities. Our interest expense primarily reflects (i) imputed interest on the lease financing of our Hatchet Ridge project, (ii) periodicinterest on the term loan financing arrangements, including the effects of interest rate swaps, at our other operating projects, (iii) interest on our convertible seniornotes issued in 2015 and the Unsecured Senior Notes issued in 2017 and (iv) interest on short-term loan facilities, including any borrowings under our revolvingcredit facility.We believe that our projects have been financed on average with stronger coverage ratios than is typical in our industry. A debt service coverage ratio is generallydefined as a project’s operating cash flows divided by scheduled payments of principal and interest for a period. While we believe that the commercial bank marketgenerally seeks a minimum average annual debt service coverage ratio for wind power projects, based on P50 output levels, of between 1.4 and 1.5 to 1.0, ourprojects, on a portfolio basis, have an expected average annual debt service coverage ratio over the remaining scheduled loan amortization periods ofapproximately 2.0 to 1.0.Congestion in the Texas marketIn addition to the risks we face in broad commodity markets, many of our projects, especially in ERCOT, also face project-specific risks related to transmissionsystem limitations which can result in local prices that are lower than the broader market prices (congestion). In the case of adverse congestion, our revenues arenegatively impacted, and our PSAs do not protect us from these impacts, since under those contracts, this risk is fully allocated to our projects and not to thecounterparty (e.g. we sell our power at the lower local price, but still have to buy power for the counterparty at the higher broad market or hub price). In the pastthese impacts have been material to our economic results, and we expect that congestion will continue to be a material risk, in the future.General and Administrative CostIn addition to reducing our project expense through restructuring service agreements and a transition to self-perform, we are also focused on measures to reduceour general and administrative expenses, including our net related party charges to and from Pattern Development 1.0. We are investing in a number of efficiencyinitiatives (principally automation and other process improvements) in accounting, procurement, human resources, loan administration, and asset management,among others, that we believe will also result in a lower administrative cost structure. In 2017, these initiatives along with measures we took to remediate ourmaterial weaknesses in internal controls in 2017 resulted in higher audit, consulting and staffing expenses; however, we anticipate that the consequent changes wemake to our control environment together with the efficiency initiatives will reduce certain general and administrative costs starting in 2018.AcquisitionsOur ability to grow our cash available for distribution is substantially dependent on our ability to make acquisitions. During 2017, our acquisitions of Broadviewand Meikle increased our operating capacity by 363 MW or 14%. In addition, the Broadview acquisition included the acquisition of Western Interconnect. Ourinvestment in 2017 and our additional commitment to fund capital calls in Pattern Development 2.0 facilitates additional long-term capital for Pattern Development2.0 to support the growth in the development pipeline.59In 2018, we committed to acquire several entities in Japan which when consummated will increase our project portfolio capacity by 206 MW including 39 MW ofsolar renewable energy projects. Additionally, we expect to complete the acquisition of MSM, of which our proportionate interest will be 51%, in 2018.Potential DispositionsAs discussed below, we have been conducting a strategic review of the market, growth and opportunities in Chile. To that end, we began a process to solicit bidsfor the potential sale of El Arrayan. In early 2018, we received a range of initial non-binding bids for the purchase of El Arrayan, and we elected to continue thestrategic review with certain bidders, a process we expect to conclude in early to mid 2018. No assurances can be given that we will accept any bid and that if wedid accept a bid, it would be above the current carrying value of El Arrayan. During the time we are evaluating our opportunities in Chile, we will continue toreport the assets and liabilities as held and used on our consolidated balance sheets until such time as the strategic review of Chile advances to a point where itmight meet (if ever) the assets held for sale requirements specified in ASC 360.Our aggregate owned capacity is 2,942 MW. We expect that the acquisition of operational power projects from the Pattern Development Companies and otherthird parties will continue to contribute to our operational results.Below is a summary of the Identified ROFO Projects that we expect to acquire from the Pattern Development Companies in connection with our Project PurchaseRights: Capacity (MW)Identified ROFO Projects Status Location Construction Start (1) Commercial Operations (2) Contract Type Rated (3) Pattern Development Companies Owned (4)Pattern Development 1.0 Projects Conejo Solar (5) Operational Chile 2015 2016 PPA 104 104Belle River Operational Ontario 2016 2017 PPA 100 43El Cabo Operational New Mexico 2016 2017 PPA 298 125North Kent Operational Ontario 2017 2018 PPA 100 35Henvey Inlet In construction Ontario 2017 2019 PPA 300 150Pattern Development 2.0 Projects Stillwater Big Sky Late stage development Montana 2017 2018 PPA 79 67Crazy Mountain Late stage development Montana 2017 2019 PPA 80 68Grady Late stage development New Mexico 2018 2019 PPA 220 188Sumita Late stage development Japan 2019 2021 PPA 100 55Ishikari Late stage development Japan 2019 2022 PPA 100 100 1,481 935(1) Represents year of actual or anticipated commencement of construction.(2) Represents year of actual or anticipated commencement of commercial operations.(3) Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of weather and other conditions, a project will not operate at its rated capacity atall times and the amount of electricity generated may be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors.(4) Pattern Development Companies-Owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW multiplied by Pattern Development 1.0's orPattern Development 2.0's percentage ownership interest in the distributable cash flow of the project.(5) From time to time, we conduct strategic reviews of our markets. We have been conducting a strategic review of the market, growth, and opportunities in Chile. In the event we believewe can utilize funds that have already been invested in Chile or funds that might otherwise be invested in Chile in a more productive manner elsewhere that could generate a higherreturn on investment, we may decide to exit Chile for other opportunities with greater potential. In addition, Pattern Development 1.0 is also concurrently exploring strategicalternatives for its assets in Chile.Investment in Pattern Development 2.0In December 2016, certain investment funds managed by Riverstone Holdings LLC, which own interests in Pattern Development 1.0, engaged in a transaction inwhich (a) certain assets of Pattern Development 1.0 consisting principally of early and mid-stage U.S. development assets (including the Grady project which is anIdentified ROFO Project) were transferred to a newly formed entity, Pattern Development 2.0, and (b) Pattern Development 1.0 retained the remainder of its assetsconsisting principally of the other Identified ROFO Projects, non-U.S. development assets, and its ownership interest in our Class A common stock. Subsequently,in June 2017, concurrently60with the entry into the strategic relationship with PSP Investments, we entered into a series of new arrangements and amendments to existing arrangements witheach of Pattern Development 1.0 and Pattern Development 2.0, the purpose of which was to increase opportunities for growth with improved alignment with ourcore business strategy.During 2017, we invested $67.3 million in Pattern Development 2.0 and in February 2018, we also funded approximately $35.2 million into Pattern Development2.0 of which approximately $27 million will be used by Pattern Development 2.0 to fund the purchase of GPI. During the remainder of 2018, we will continue toevaluate the potential benefits and risks of an investment in Pattern Development 2.0. Strategic benefits include a strengthened link to Pattern Development 2.0'sdevelopment pipeline and increased return on investment expectations commensurate with increased development risk. To the extent we invest in PatternDevelopment 2.0, we will be initially exposed to capital requirements prior to having certainty that a project can move forward. As projects are successfullycompleted, we anticipate that our return on our capital investment will increase. However, there are risks in project development that we have not yet been exposedto including, but not limited to, permitting challenges, failure to secure PPAs, failure to procure the requisite financing, equipment or interconnection, or aninability to satisfy the conditions to effectiveness of project agreements such as PPAs.Key MetricsWe regularly review a number of financial measurements and operating metrics to evaluate our performance, measure our growth and make strategic decisions. Inaddition to traditional U.S. GAAP performance and liquidity measures, such as total revenue, cost of revenue, net loss and net cash provided by operatingactivities, we also consider cash available for distribution as a supplemental liquidity measure and Adjusted EBITDA, MWh sold and average realized electricityprice in evaluating our operating performance. We disclose cash available for distribution, which is a non-U.S. GAAP measure, because management recognizesthat it will be used as a supplemental measure by investors and analysts to evaluate our liquidity. We disclose Adjusted EBITDA, which is a non-U.S. GAAPmeasure, because management believes this metric assists investors and analysts in comparing our operating performance across reporting periods on a consistentbasis by excluding items that our management believes are not indicative of our core operating performance. Each of these key metrics is discussed below.Limitations to Key MetricsWe disclose cash available for distribution, which is a non-U.S. GAAP measure, because management recognizes that it will be used as a supplemental measure byinvestors and analysts to evaluate our liquidity. However, cash available for distribution has limitations as an analytical tool because it:•excludes depreciation, amortization and accretion;•does not capture the level of capital expenditures necessary to maintain the operating performance of our projects;•is not reduced for principal payments on our project indebtedness except to the extent they are paid from operating cash flows during a period; and•excludes the effect of certain other cash flow items, all of which could have a material effect on our financial condition and results from operations.Because of these limitations, cash available for distribution should not be considered an alternative to net cash provided by operating activities or any otherliquidity measure determined in accordance with U.S. GAAP, nor is it indicative of funds available to fund our cash needs. In addition, our calculation of cashavailable for distribution is not necessarily comparable to cash available for distribution as calculated by other companies.We disclose Adjusted EBITDA, which is a non-U.S. GAAP measure, because management believes this metric assists investors and analysts in comparing ouroperating performance across reporting periods on a consistent basis by excluding items that our management believes are not indicative of our core operatingperformance. We use Adjusted EBITDA to evaluate our operating performance. You should not consider Adjusted EBITDA as an alternative to net income (loss),as determined in accordance with U.S. GAAP.Adjusted EBITDA has limitations as an analytical tool. Some of these limitations include:•Adjusted EBITDA•does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;•does not reflect changes in, or cash requirements for, our working capital needs;61•does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our debt, or ourproportional interest in the interest expense of our unconsolidated investments or the cash requirements necessary to service interest or principalpayments on the debt borne by our unconsolidated investments;•does not reflect our income taxes or the cash requirement to pay our taxes; or our proportional interest in income taxes of our unconsolidatedinvestments or the cash requirements necessary to pay the taxes of our unconsolidated investments;•does not reflect depreciation, amortization and accretion which are non-cash charges; or our proportional interest in depreciation, amortizationand accretion of our unconsolidated investments. The assets being depreciated, amortized and accreted will often have to be replaced in thefuture, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and•does not reflect the effect of certain mark-to-market adjustments and non-recurring items or our proportional interest in the mark-to-marketadjustments at our unconsolidated investments.•We do not have control, nor have any legal claim to the portion of the unconsolidated investees' revenues and expenses allocable to our joint venturepartners. As we do not control, but do exercise significant influence, we account for the unconsolidated investments in accordance with the equity methodof accounting. Net earnings from these investments are reflected within our consolidated statements of operations in "Earnings in unconsolidatedinvestments, net." Adjustments related to our proportionate share from unconsolidated investments include only our proportionate amounts of interestexpense, income taxes, depreciation, amortization and accretion, and mark-to-market adjustments included in "Earnings in unconsolidated investments,net;" and•Other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure.Because of these limitations, Adjusted EBITDA should not be considered in isolation or as a substitute for performance measures calculated in accordance withU.S. GAAP.Cash Available for DistributionWe define cash available for distribution as net cash provided by operating activities as adjusted for certain other cash flow items that we associate with ouroperations. It is a non-U.S. GAAP measure of our ability to generate cash to service our dividends.Cash available for distribution represents cash provided by operating activities as adjusted to:(i) add or subtract changes in operating assets and liabilities;(ii) subtract net deposits into restricted cash accounts, which are required pursuant to the cash reserve requirements of financing agreements, to the extent they arepaid from operating cash flows during a period;(iii) subtract cash distributions paid to noncontrolling interests;(iv) subtract scheduled project-level debt repayments in accordance with the related loan amortization schedule, to the extent they are paid from operating cashflows during a period;(v) subtract non-expansionary capital expenditures, to the extent they are paid from operating cash flows during a period;(vi) add cash distributions received from unconsolidated investments (as reported in net cash used in investing activities), to the extent such distributions werederived from operating cash flows; and(vii) add or subtract other items as necessary to present the cash flows we deem representative of our core business operations.62The most directly comparable U.S. GAAP measure to cash available for distribution is net cash provided by operating activities. The following table is areconciliation of our net cash provided by operating activities to cash available for distribution for the periods presented (unaudited and in thousands): Year ended December 31, 2017 2016 2015Net cash provided by operating activities (1) $217,613 $163,664 $117,849Changes in operating assets and liabilities (31,568) (11,000) (6,880)Network upgrade reimbursement 9,282 4,821 2,472Release of restricted cash to fund project and general and administrative costs 7,239 640 1,611Operations and maintenance capital expenditures (783) (1,017) (779)Distributions from unconsolidated investments 13,358 41,698 34,216Reduction of other asset - Gulf Wind energy derivative deposit — — 6,205Other 2,182 (302) (323)Less: Distributions to noncontrolling interests (20,250) (17,896) (7,882)Principal payments paid from operating cash flows (51,278) $(47,634) $(54,041)Cash available for distribution $145,795 $132,974 $92,448(1) Included in net cash provided by operating activities is the portion of distributions from unconsolidated investments paid from cumulative earnings representing the return oninvestment.Cash available for distribution was $145.8 million for the year ended December 31, 2017 as compared to $133.0 million in the prior year. This $12.8 millionincrease in cash available for distribution was primarily due to:•a $49.0 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs) driven by projects acquired during 2017;•a $10.6 million increase in total distributions from unconsolidated investments;•a $6.6 million increase in release of restricted cash to fund project costs; and•a $4.5 million increase in network upgrade reimbursement primarily related to Broadview.These increases were partially offset by:•a $23.0 million increase in interest expense (excluding amortization of financing costs and debt discount/premium) primarily due to the issuance of theUnsecured Senior Notes in January 2017 and debt associated with our acquisitions;•a $21.2 million increase in transmission cost and project expense;•a $7.0 million increase in operating expenses;•a $3.6 million increase in principal payments of project-level debt; and•a $2.4 million increase in distributions to noncontrolling interests.Cash available for distribution was $133.0 million for the year ended December 31, 2016 as compared to $92.4 million in the prior year. This $40.5 millionincrease in cash available for distribution was due to:•additional revenues of $47.3 million (excluding unrealized loss on energy derivative and amortization of PPAs) primarily from projects which wereacquired or commenced commercial operations during 2015;•an increase of $22.5 million in cash distributions from our unconsolidated investments when compared to the same period in the prior year which was dueto full year operations at K2 and the acquisition of Armow in the fourth quarter of 2016;•reduced principal payments of project-level debt by $6.4 million; and•decreased net losses on transactions of $3.1 million.63These increases were partially offset by:•increased transmission cost and project expense of $14.2 million ;•increased operating expenses of $10.7 million ;•increased distributions to noncontrolling interests of $10.0 million; and•the $6.2 million cash distribution from the partial refund of a deposit associated with the Gulf Wind energy derivative in 2015.Adjusted EBITDAWe define Adjusted EBITDA as net income (loss) before net interest expense, income taxes, and depreciation, amortization and accretion, including ourproportionate share of net interest expense, income taxes, and depreciation, amortization and accretion of unconsolidated investments. Adjusted EBITDA alsoexcludes the effect of certain mark-to-market adjustments and infrequent items not related to normal or ongoing operations, such as early payment of debt, realizedderivative gain or loss from refinancing transactions, gain or loss related to acquisitions or divestitures, and adjustments from unconsolidated investments. Incalculating Adjusted EBITDA, we exclude mark-to-market adjustments to the value of our derivatives because we believe that it is useful for investors tounderstand, as a supplement to net income (loss) and other traditional measures of operating results, the results of our operations without regard to periodic, andsometimes material, fluctuations in the market value of such assets or liabilities.Adjustments from unconsolidated investments represent distributions received in excess of the carrying amount of our investment and suspended equity earnings,during periods of suspension of recognition of equity method earnings. We may suspend the recognition of equity method earnings when we receive distributionsin excess of the carrying value of our investment. As we are not liable for the obligations of the investee nor otherwise committed to provide financial support, werecord gains resulting from such excess distributions in the period the distributions occur. Additionally, when our carrying value in an unconsolidated investment iszero and we are not liable for the obligations of the investee nor otherwise committed to provide financial support, we will not recognize equity in earnings (losses)in other comprehensive income of unconsolidated investments.The most directly comparable U.S. GAAP measure to Adjusted EBITDA is net income (loss). The following table reconciles net income (loss) to AdjustedEBITDA for the periods presented (unaudited and in thousands): Year ended December 31, 2017 2016 2015Net loss $(82,410) $(52,299) $(55,607)Plus: Interest expense, net of interest income 100,687 76,598 75,309Tax provision 11,734 8,679 4,943Depreciation, amortization and accretion 215,492 184,002 145,322EBITDA $245,503 $216,980 $169,967Unrealized loss on energy derivative (1) 14,045 22,767 791(Gain) loss on derivatives 9,787 3,324 16,711Early extinguishment of debt 8,643 — 4,941Other — 326 3,400Adjustments from unconsolidated investments (2) — (659) —Plus, proportionate share from unconsolidated investments: Interest expense, net of interest income 39,240 32,103 23,537Depreciation, amortization and accretion 35,311 27,763 22,680(Gain) loss on derivatives (8,829) 1,552 8,514Adjusted EBITDA $343,700 $304,156 $250,541(1) Amount is included in electricity sales on the consolidated statements of operations.(2) Adjustments for the year ended December 31, 2016, consists of $19.9 million gains on distributions from unconsolidated investments and ($19.2) million of suspended equity earnings.See Note 7 . Unconsolidated Investments in the Notes to Consolidated Financial Statements in this Form 10-K, for further discussion.64Adjusted EBITDA for the year ended December 31, 2017 was $343.7 million compared to $304.2 million in the prior year, an increase of $39.5 million , orapproximately 13.0% . The increase in Adjusted EBITDA during 2017 as compared to 2016 was primarily due to:•a $49.0 million increase in revenue (excluding unrealized loss on energy derivative and amortization of PPAs) primarily attributable to projects whichwere acquired or commenced commercial operations in 2017; and•a $20.9 million increase in our proportionate share of Adjusted EBITDA from unconsolidated investments.These increases were partially offset by:•a $21.2 million increase in transmission cost and project expense;•a $7.0 million increase in operating expenses; and•a $1.0 million increase in transaction cost.Adjusted EBITDA for the year ended December 31, 2016 was $304.2 million compared to $250.5 million in the prior year, an increase of $53.6 million , orapproximately 21.4% . The increase in Adjusted EBITDA during 2016 as compared to 2015 was primarily due to:•a $47.3 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs) driven by projects which were acquired orcommenced commercial operations in 2015;•a $26.6 million increase in our proportionate share of Adjusted EBITDA from unconsolidated investments; and•a $3.5 million increase in other income, net primarily due to gains on foreign currency transaction.These increases were partially offset by:•a $14.2 million increase in project expense and transmission cost; and•a $10.7 million increase in operating expenses.MWh Sold and Average Realized Electricity PriceThe number of consolidated MWh, unconsolidated investments proportional MWh and proportional MWh sold, as well as consolidated average realized price perMWh and the proportional average realized price per MWh sold, are the operating metrics that help explain trends in our revenue, earnings from ourunconsolidated investments and net income (loss) attributable to us.•Consolidated MWh sold for any period presented, represents 100% of MWh sold by wholly-owned and partially-owned subsidiaries in which we have acontrolling interest and are consolidated in our consolidated financial statements;•Noncontrolling interest MWh represents that portion of partially-owned subsidiaries not attributable to us;•Controlling interest in consolidated MWh is the difference between the consolidated MWh sold and the noncontrolling interest MWh;•Unconsolidated investments proportional MWh is our proportion in MWh sold from our equity method investments;•Proportional MWh sold for any period presented, represents the sum of the controlling interest and our percentage interest in our unconsolidatedinvestments; and•Average realized electricity price for each of consolidated MWh sold, unconsolidated investments proportional MWh sold and proportional MWh soldrepresents (i) total revenue from electricity sales for each of the respective MWh sold, discussed above, excluding unrealized gains and losses on ourenergy derivative and the amortization of finite-lived intangible assets and liabilities, divided by (ii) the respective MWh sold.65The following table presents selected operating performance metrics for the periods presented (unaudited): Year ended December 31, MWh sold 2017 2016 Change % ChangeConsolidated MWh sold 7,700,853 6,745,525 955,328 14.2 %Less: noncontrolling MWh (1,147,409) (940,358) (207,051) 22.0 %Controlling interest in consolidated MWh 6,553,444 5,805,167 748,277 12.9 %Unconsolidated investments proportional MWh 1,233,967 1,001,105 232,862 23.3 %Proportional MWh sold 7,787,411 6,806,272 981,139 14.4 % Average realized electricity price per MWh Consolidated average realized electricity price per MWh $54 $55 $(1) (1.8)%Unconsolidated investments proportional average realizedelectricity price per MWh $112 $112 $— — %Proportional average realized electricity price per MWh $65 $66 $(1) (1.5)%Our consolidated MWh sold for the year ended December 31, 2017 was 7,700,853 MWh, as compared to 6,745,525 MWh for the year ended December 31, 2016 ,an increase of 955,328 MWh, or 14.2% . The change in consolidated MWh sold was primarily attributable to:•an increase in volume of 917,166 MWh as a result of acquisitions in 2017; and•an increase in volume of 254,443 MWh from projects that existed in 2016 primarily due to favorable wind conditions.This increase was partially offset by:•a decrease in volume of 216,146 MWh from projects that existed in 2016 due to lower availability and curtailment.Our proportional MWh sold for the year ended December 31, 2017 was 7,787,411 MWh, as compared to 6,806,272 MWh for the year ended December 31, 2016 ,an increase of 981,139 MWh, or 14.4% . The change in proportional MWh sold was primarily attributable to:•an increase in volume of 748,277 MWh from controlling interest in consolidated MWh primarily due to acquisitions in 2017 and favorable windconditions partially offset by lower availability; and•an increase in volume of 232,862 MWh from unconsolidated investments primarily due to the acquisition of Armow in the fourth quarter of 2016 andfavorable wind conditions partially offset by lower availability.Our consolidated average realized electricity price was $54 per MWh for the year ended December 31, 2017 as compared to $55 per MWh for the year endedDecember 31, 2016 . The decrease of $1 per MWh was primarily due to an increase in volume of lower priced PPAs coupled with lower spot market pricing as aresult of congestion in the Texas market.Proportional average realized electricity price was $65 per MWh for the year ended December 31, 2017 as compared to $66 per MWh for the year endedDecember 31, 2016 . The decrease of $1 per MWh in the proportional average realized electricity price was primarily due to an increase in volume of lower pricedPPAs coupled with the presence of ERCOT market congestion.66The following table presents selected operating performance metrics for the periods presented (unaudited): Year ended December 31, MWh sold 2016 2015 Change % ChangeConsolidated MWh sold 6,745,525 5,257,976 1,487,549 28.3 %Less: noncontrolling MWh (940,358) (877,847) (62,511) 7.1 %Controlling interest in consolidated MWh 5,805,167 4,380,129 1,425,038 32.5 %Unconsolidated investments proportional MWh 1,001,105 756,546 244,559 32.3 %Proportional MWh sold 6,806,272 5,136,675 1,669,597 32.5 % Average realized electricity price per MWh Consolidated average realized electricity price per MWh $55 $62 $(7) (11.3)%Unconsolidated investments proportional average realizedelectricity price per MWh $112 $118 $(6) (5.1)%Proportional average realized electricity price per MWh $66 $73 $(7) (9.6)%Our consolidated MWh sold for the year ended December 31, 2016 was 6,745,525 MWh, as compared to 5,257,976 MWh for the year ended December 31, 2015 ,an increase of 1,487,549 MWh, or 28.3% . The change in consolidated MWh sold was primarily attributable to:•an increase in volume of 153,835 MWh from projects which commenced commercial operations prior to 2015;•an increase in volume of 460,159 MWh from projects acquired in 2015; and•an increase in volume of 873,556 MWh from projects which completed construction during 2015.Our proportional MWh sold in the year ended December 31, 2016 was 6,806,272 MWh, as compared to 5,136,675 MWh for the year ended December 31, 2015 ,representing an increase of 1,669,597 MWh or 32.5% . This change in proportional MWh sold was primarily attributable to:•an increase in volume of 1,425,038 MWh from controlling interest in consolidated MWh; and•an increase in volume of 244,559 MWh from unconsolidated investments due to the acquisition of Armow in October 2016 and K2 in June 2015.Our consolidated average realized electricity price was $55 per MWh for the year ended December 31, 2016 as compared to $62 per MWh for the year endedDecember 31, 2015 . The decrease of $7 per MWh was primarily due to an increase in volume of lower priced PPAs coupled with lower spot market pricing as aresult of increased supply at certain electric hubs.Proportional average realized electricity price was $66 per MWh for the year ended December 31, 2016 as compared to $73 per MWh for the year endedDecember 31, 2015 . The $7 per MWh decrease in the proportional average realized electricity price was primarily due to an increase in volume of lower pricedPPAs coupled with lower spot market pricing as a result of increased supply of energy at certain electric hubs partially offset by an increase in volume of higherpriced contracts at our unconsolidated investments primarily due to Armow which was acquired in October 2016 and K2 which was acquired in June 2015.67Results of OperationsThe following table provides selected financial information for the periods presented (in thousands, except percentages): Year ended December 31, 2017 vs. 2016 2016 vs. 2015 2017 2016 2015 $ Change % Change $ Change % ChangeTotal revenue $411,344 $354,052 $329,831 $57,292 16.2% $24,221 7.3 %Total cost of revenue 348,677 303,342 257,995 45,335 14.9 45,347 17.6Total operating expenses 52,408 45,399 34,731 7,009 15.4 10,668 30.7Operating income 10,259 5,311 37,105 4,948 93.2 (31,794) (85.7)Total other expense 80,935 48,931 87,769 32,004 65.4 (38,838) (44.3)Net loss before income tax (70,676) (43,620) (50,664) (27,056) 62.0 7,044 (13.9)Tax provision 11,734 8,679 4,943 3,055 35.2 3,736 75.6Net loss (82,410) (52,299) (55,607) (30,111) 57.6 3,308 (5.9)Net loss attributable to noncontrolling interest (64,505) (35,188) (23,074) (29,317) 83.3 (12,114) 52.5Net loss attributable to Pattern Energy $(17,905) $(17,111) $(32,533) $(794) 4.6% $15,422 (47.4)%Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 andYear Ended December 31, 2016 Compared to Year Ended December 31, 2015Total RevenueTotal revenue for the year ended December 31, 2017 was $411.3 million compared to $354.1 million for the year ended December 31, 2016 , an increase of $57.3million , or approximately 16.2% . The increase in total revenue for the year ended December 31, 2017 as compared to the prior year was primarily attributable to:•a $54.1 million increase in electricity sales driven by projects acquired in 2017;•an $18.0 million increase in electricity sales due to favorable wind availability and an increase in PPA contractual volumes for Amazon Wind; and•an $8.7 million decrease in unrealized loss on our energy derivative primary due to lower forward natural gas price curves when compared to the priorperiod.The increase in electricity sales was partially offset by:•a $4.5 million decrease related to an interruption caused principally by a hurricane in Puerto Rico; and•a $16.4 million decrease driven by presence of ERCOT market congestion.Total revenue for the year ended December 31, 2016 was $354.1 million compared to $329.8 million for the year ended December 31, 2015 , an increase of $24.2million , or approximately 7.3% . The change in total revenue for the year ended December 31, 2016 as compared to the prior year was primarily attributable to:•a $48.9 million in additional electricity sales from projects which were acquired or commenced commercial operations during 2015;•a $2.2 million increase from related party revenue related to management fees.The increase in total revenues was partially offset by:•$22.0 million in higher unrealized losses due to higher forward electricity price curves when compared to the prior period; and•a $5.2 million decrease in electricity sales from projects which were in operation prior to 2015.68Cost of revenueCost of revenue for the year ended December 31, 2017 was $348.7 million compared to $303.3 million for the year ended December 31, 2016 , an increase of$45.3 million , or approximately 14.9% . The increase in cost of revenue during 2017 as compared to 2016 was primarily attributable to:•a $19.0 million and a $12.4 million increase in transmission costs and project expense, respectively for costs associated with projects acquired in 2017;and•a $ 24.2 million increase in depreciation, primarily due to projects acquired in 2017.The increase in cost of revenue was partially offset by a $10.2 million decrease primarily due to the turbine maintenance expense.Cost of revenue for the year ended December 31, 2016 was $303.3 million compared to $258.0 million for the year ended December 31, 2015 , an increase of$45.3 million , or approximately 17.6% . The increase in cost of revenue during 2016 as compared to 2015 was primarily attributable to:•an $11.9 million increase in expenses associated with turbine operations and maintenance for new projects which were acquired or became commerciallyoperable during 2015 as discussed above; and•a $31.1 million increase in depreciation for projects which became commercially operable during 2015.Operating expensesOperating expenses for the year ended December 31, 2017 were $52.4 million compared to $45.4 million for the year ended December 31, 2016 , an increase of$7.0 million , or approximately 15.4% . The increase in operating expenses during 2016 as compared to 2016 was primarily attributable to:•a $5.1 million increase in employee related costs primarily to support growth in employee headcount;•a $4.6 million net increase in professional fees and other general administrative; and•a $3.9 million increase in related party general and administrative expense.The increase in operating expense was partially offset by a $6.6 million increase in related party reimbursement.Operating expenses for the year ended December 31, 2016 were $45.4 million compared to $34.7 million for the year ended December 31, 2015 , an increase of$10.7 million , or approximately 30.7% . The increase in operating expenses during 2016 as compared to 2015 was primarily attributable to:•a $5.0 million increase in employee related costs primarily to support growth in employee headcount;•a $5.6 million net increase in professional fees, office related lease expenses, travel and entertainment; and•a $2.3 increase in related party general and administrative expense.The increase in operating expense was partially offset by a $2.4 million increase in related party reimbursement.Other expenseOther expense for the year ended December 31, 2017 was $80.9 million compared to $48.9 million for the year ended December 31, 2016 , an increase of$32.0 million , or approximately 65.4% . The increase was primarily attributable to:•a $24.2 million increase in interest expense primarily due to the issuance of the Unsecured Senior Notes in January 2017 and debt associated with ouracquisitions in 2017;•an $8.6 million increase in early extinguishment loss associated with Ocotillo debt;•a $6.5 million increase in loss on derivatives primarily as a result of an unfavorable impact from foreign currency exchange rates and a realized loss dueto the termination of the interest rate swaps; and•a $2.8 million increase in net losses on transactions and accretion expense primarily related to the acquisition of the Broadview Project.The increase in other expense was partially offset by an $ 11.1 million increase in equity in earnings in unconsolidated investments, net.69Other expense for the year ended December 31, 2016 was $48.9 million compared to $87.8 million for the year ended December 31, 2015 , a decrease of $38.8million , or approximately 44.3% . The change in other expense during 2016 as compared to 2015 was primarily attributable to:•a $14.1 million increase in equity in earnings in unconsolidated investments, net primarily due to increased recognition of gains on distributions fromunconsolidated investments as a result of the 2016 suspension of equity method accounting for certain of our unconsolidated investments and increasedproject income from investments acquired in 2015 and late 2016;•an $11.2 million realized loss on designated derivatives, net for the July 2015 termination of a designated interest rate swap;•a $4.9 million early extinguishment of debt occurring in July and November of 2015;•a $3.5 million increase in other income primarily from foreign currency transactions;•a $3.1 million decrease in net losses on transactions; and•a $2.2 million net increase in earnings from undesignated derivatives primarily due to increases in the interest rate curves compared to the interest ratecurves in the prior year offset by decreases in foreign currency price curves compared to foreign currency price curves in the prior year.Tax provisionWe are subject to taxation in the United States, Chile, Canada and Puerto Rico.The tax provision was $11.7 million for the year ended December 31, 2017 compared to $8.7 million for the year ended December 31, 2016 . Generally, theamount of tax expense or benefit allocated to continuing operations is determined without regard to the tax effects of other categories of income or loss, such asother comprehensive income (loss). However, an exception to the general rule is provided within the intraperiod tax allocation rules when there is a pre-tax lossfrom continuing operations and pre-tax income from other categories in the current year. This exception resulted in a tax benefit for the year ended December 31,2017. The expense of $11.7 million is principally related to our Canadian operations partially offset by a tax benefit earned from the intraperiod tax allocation rulesthat are applied when there is a pre-tax loss from continuing operations and pre-tax income from other categories in the year such as other comprehensive income(loss) and benefits earned in our Chilean operations.The tax provision was $8.7 million for the year ended December 31, 2016 compared to $4.9 million for the same period in the prior year. The expense of $8.7million is principally related to our Canadian operations offset against tax benefits earned in our Chilean operations.Effective tax rateOn December 22, 2017, the U.S. government enacted comprehensive tax legislation (the Tax Act), which significantly revises the ongoing U.S. corporate incometax law by lowering the U.S federal corporate income tax rate from 35% to 21%, implementing a territorial tax system, imposing one-time tax on foreignunremitted earnings and setting limitations on deductibility of certain costs, among other things.On December 22, 2017, Staff Accounting Bulletin No. 118 (SAB 118) was issued due to the complexities involved in accounting for the recently enacted Tax Act.SAB 118 requires a company to include in its financial statements, a reasonable estimate of the impact of the Tax Act on earnings to the extent such estimate hasbeen determined. Accordingly, the U.S. provision for income tax for 2017 is based on the reasonable estimate guidance provided by SAB 118. We are continuingto assess the impact from the Tax Act and will record adjustments in 2018, as necessary. The final impact on us from the Tax Act's transition tax legislation maydiffer from the reasonable estimate due to the complexity of calculating and supporting with primary evidence U.S. tax attributes such as accumulated foreignearnings and profits, foreign tax paid, and other tax components involved in foreign tax credit calculations for prior years back to 2013. Such differences could bematerial, due to, among other things, changes in interpretations of the Tax Act, future legislative action to address questions that arise because of the Tax Act,changes in accounting standards for income taxes, related interpretations in response to the Tax Act, or any updates or changes to estimates we have utilized tocalculate the transition tax's reasonable estimate.Our effective tax rate was (16.6)% in 2017 compared to (19.8)% in 2016. Our effective tax rate differs from the statutory tax rates primarily due to adjustments forincome in non-taxable entities allocable to noncontrolling interest, consideration of the change in the U.S. federal corporate income tax rate from 35% to 21% inapplying the exception to the general intra-period tax allocation rule, and foreign tax rate differential on pre-tax book income.70Net lossNet loss was $82.4 million for the year ended December 31, 2017 , compared to $52.3 million for the prior year; an increase in net loss of $30.1 million or 57.6% .The increase in net loss was primarily attributed to:•a $45.3 million increase in cost of revenues due primarily to acquisitions in 2017;•a $32.0 million increase in other expense primarily related to increases in interest expense, early extinguishment loss, losses on derivatives due tounfavorable impacts from foreign currency exchange rates and the termination of the interest rate swaps;•a $7.0 million increase in operating expense, as discussed above; and•a $3.1 million increase in the tax provision.The increase in net loss was partially offset by a $57.3 million increase in total revenue, as discussed above.Net loss was $52.3 million for the year ended December 31, 2016 , compared to $55.6 million for the prior year; a decrease in loss of $3.3 million or 5.9% . Thedecrease in loss was primarily attributed to:•a $24.2 million increase in total revenue, as discussed above; and•a $38.8 million decrease in other expense primarily related to an increase in earnings in unconsolidated investments, decreased net losses on transactions,expenses in 2015 for the early extinguishment of debt, and the termination of designated interest rate derivatives.The decrease in net loss was partially offset by:•a $45.3 million increase in cost of revenue associated with project related expense and increased depreciation expense primarily for projects that wereacquired or became commercially operable during 2015 and 2016;•a $10.7 million increase in operating expenses, as discussed above; and•a $3.7 million increase in the tax provision.Noncontrolling interestThe net loss attributable to noncontrolling interest was $64.5 million for the year ended December 31, 2017 compared to a $35.2 million net loss attributable tononcontrolling interest for the year ended December 31, 2016 . The increased loss of $29.3 million , or approximately 83.3% , was primarily attributable toallocations of losses for tax equity projects, including allocations related to projects acquired in 2017.The net loss attributable to noncontrolling interest was $35.2 million for the year ended December 31, 2016 compared to a $23.1 million net loss attributable tononcontrolling interest for the year ended December 31, 2015 . The increased loss of $12.1 million , or approximately 52.5% , was primarily attributable toallocations of losses for tax equity projects which commenced commercial operations or were acquired during 2015 and 2016.Liquidity and Capital ResourcesOur business requires substantial liquidity to fund (i) equity investments in our construction projects, (ii) current operational costs, (iii) debt service payments,(iv) dividends to our stockholders, (v) potential investments in new acquisitions, (vi) modifications to our projects, (vii) unforeseen events and (viii) other businessexpenses. As a part of our liquidity strategy, we plan to retain a portion of our cash flows in above-average wind years in order to have additional liquidity inbelow-average wind years.Sources of LiquidityOur sources of liquidity include cash generated by our operations, cash reserves, borrowings under our corporate and project-level credit agreements and furtherissuances of equity and debt securities.71The principal indicators of our liquidity are our unrestricted and restricted cash balances and availability under our Revolving Credit Facility and project levelfacilities. Our available liquidity is as follows (in millions): December 31, 2017Unrestricted cash$116.8Restricted cash21.2Revolving Credit Facility availability (1)392.5Project facilities: Post construction use135.9Total available liquidity$666.4(1) As of February 26, 2018, the amount available on the Revolving Credit Facility is $339.8 million.We believe that throughout 2018, we will have sufficient liquid assets, cash flows from operations, and borrowings available under our revolving credit facility tomeet our financial commitments debt service obligations, contingencies and anticipated required capital expenditures for at least the next 24 months, not includingcapital required for additional project acquisitions or capital call from Pattern Development 2.0. However, we are subject to business and operational risks thatcould adversely affect our cash flow. A material decrease in our cash flows would likely produce a corresponding adverse effect on our borrowing capacity.In connection with our future capital expenditures and other investments, including any project acquisitions that we may make, or capital call on PatternDevelopment 2.0 we elect to participate in, we may, from time to time, issue debt or equity securities. Our ability to access the debt and equity markets isdependent on, among other factors, the overall state of the debt and equity markets and investor appetite for investment in clean energy projects in general and ourClass A shares in particular. Volatility in the market price of our Class A shares may prevent or limit our ability to utilize our equity securities as a source of capitalto help fund acquisitions. An inability to obtain debt or equity financing on commercially reasonable terms could significantly limit our timing and ability toconsummate future acquisitions, and to effectuate our growth strategy.Financing DevelopmentsOn November 21, 2017, certain of our subsidiaries entered into a Second Amended and Restated Credit and Guaranty Agreement (the Revolving Credit Facility).The Revolving Credit Facility provides for a revolving credit facility of $440 million, decreased from the previous limit of $500 million. The Revolving CreditFacility permits the borrower to request increases to the facility up to the greater of $600 million and 250% of Borrower Cash Flow (as defined in the RevolvingCredit Facility), subject to receipt of commitments and other customary conditions. The facility has a five-year term and is comprised of a revolving loan facility, aletter of credit facility and a swingline facility. The facility is secured by pledges of the capital stock and ownership interests in certain of our holding companysubsidiaries, in addition to other customary collateral.On October 23, 2017, we completed an underwritten public offering of our Class A common stock. In total, 9,200,000 shares of our Class A common stock weresold at a public offering price of $23.40 per share. This includes 1,200,000 shares purchased by the underwriters to cover over-allotments. Aggregate net proceedsof the equity offering, including the proceeds of the over-allotment option, were approximately $211.9 million after deduction of underwriting discounts,commissions, and transaction expenses.In January 2017, we issued the Unsecured Senior Notes with an aggregate principal amount of $350.0 million. Net proceeds to us were approximately $345.0million, after deducting the initial purchasers’ discount, commissions and transaction expenses. We used approximately $215 million of the net proceeds topartially fund our acquisition of the Broadview projects, as described above and used $128 million of proceeds to repay borrowings incurred under the RevolvingCredit Facility to finance the 2016 purchase of the Armow project. The Unsecured Senior Notes bear interest at a rate of 5.875% per year, payable semiannually inarrears on February 1 and August 1, beginning on August 1, 2017 and maturing on February 1, 2024, unless repurchased or redeemed at an earlier date. TheUnsecured Senior Notes are guaranteed on a senior unsecured basis by Pattern US Finance Company, one of our subsidiaries.On May 9, 2016, we entered into an Equity Distribution Agreement. Pursuant to the terms of the Equity Distribution Agreement, we may offer and sell shares ofour Class A common stock, par value $0.01 per share, from time to time through the Agents, as our sales agents for the offer and sale of the shares, up to anaggregate sales price of $200.0 million . We intend to use the net proceeds from the sale of the shares for general corporate purposes, which may include therepayment of indebtedness and the funding of acquisitions and investments. For the year ended December 31, 2017 we sold 1,068,261 shares under the EquityDistribution Agreement and net proceeds under the issuance were $25.3 million .72Subject to market conditions, we will continue to consider various forms of repricings, refinancings, and/or repayments of our project level finance facilities. Noassurances, however, can be given that we will be able to consummate any such transactions, the transactions can be consummated on terms that are financiallyfavorable to us, or that such transactions will have the intended financial effects of improving the consolidated statements of operations, net cash provided byoperating activities, or cash available for distribution.Cash FlowsWe use traditional measures of cash flow, including net cash provided by operating activities, net cash used in investing activities and net cash provided byfinancing activities, as well as cash available for distribution discussed earlier, to evaluate our periodic cash flow results. Below is a summary of our cash flows foreach period (in millions): Year ended December 31, 2017 2016 2015Net cash provided by operating activities$217.6 $163.7 $117.8Net cash used in investing activities(319.1) (124.3) (759.1)Net cash provided by (used in) financing activities124.7 (76.7) 643.7Effect of exchange rate changes on cash, cash equivalents and restricted cash5.4 0.3 (5.5)Net change in cash, cash equivalents and restricted cash$28.6 $(36.9) $(3.1)Net cash provided by operating activitiesNet cash provided by operating activities was $217.6 million for the year ended December 31, 2017 as compared to $163.7 million in the prior year, an increase of$53.9 million , or approximately 33.0% . The increase in cash provided by operating activities was primarily due to higher revenues of $49.0 million (excludingunrealized loss on energy derivative and amortization of PPAs) primarily from projects which were acquired in 2017 and increase of $38.9 million in distributionsfrom unconsolidated investments. These increases were partially offset by an increase of $21.2 million in transmission and project expense, an increase of $16.3million in interest payments, an increase of $7.0 million in operating expense and other changes in working capital as a result of the timing of receipts of paymentsand disbursements.Net cash provided by operating activities was $163.7 million for the year ended December 31, 2016 as compared to $117.8 million in the prior year, an increase of$45.8 million , or approximately 38.9% . The increase in cash provided by operating activities was primarily due to higher revenues of $47.3 million (excludingunrealized loss on energy derivative and amortization of PPAs) from projects which were acquired since May 2015 or which commenced commercial operationssince September 2015, increased distributions from unconsolidated investments of $15.0 million, increase in working capital of $4.1 million, and a decrease intransaction costs of $3.1 million. These increases were partially offset by increased project and transmission expense of $14.2 million and operating expenses of$10.7 million .Net cash used in investing activitiesNet cash used in investing activities was $319.1 million for the year ended December 31, 2017 , which consisted primarily of $227.8 million in cash paid, net ofcash and restricted cash acquired for acquisitions completed in 2017, $68.8 million in cash invested in Pattern Development 2.0, $43.8 million for capitalexpenditures, which primarily relates to payments for construction liabilities assumed with our acquisitions completed in 2017, partially offset by $13.4 million indistributions from unconsolidated investments and $8.0 million in reimbursement of interconnection costs.Net cash used in investing activities was $124.3 million for the year ended December 31, 2016 , which consisted primarily of $135.8 million for the acquisition ofa 50% interest in Armow, net of cash and restricted cash acquired, $32.9 million for capital expenditures primarily related to payments made in 2016 for projectsthat became commercially operable in 2015 and capital expenditures incurred in 2015 and leasehold improvements and furniture and fixtures, partially offset by$41.7 million in distributions from unconsolidated investments.Net cash used in investing activities was $759.1 million for the year ended December 31, 2015 , which consisted primarily of $422.4 million for acquisitions, net ofcash and restricted cash acquired, which primarily includes $222.1 million for both Lost Creek and Post Rock, $65.2 million for Amazon Wind and $128.4 millionfor an unconsolidated investment in K2, in addition to $380.5 million for capital expenditures primarily related to the construction at Logan’s Gap and AmazonWind. These increases were partially offset by $38.2 million of distributions from unconsolidated investments.73Net cash provided by (used in) financing activitiesNet cash provided by financing activities for the year ended December 31, 2017 was $124.7 million . Net cash provided by financing activities consisted primarilyof the following:•$693.7 million in net proceeds from the issuance of long-term debt;•$237.1 million in net proceeds from equity issuances, net of expenses;•$333.0 million in draws on the Revolving Credit Facility; and•$57.8 million in proceeds from the partial sale of Panhandle 2.Net cash provided by financing activities were partially offset by:•$513.0 million in repayments of the Revolving Credit Facility;•$145.2 million in dividend payments;•$483.0 million in repayment of long-term debt;•$20.3 million in distributions to noncontrolling interests; and•$15.9 million in financing fee payments; and•$14.1 million in termination of designated derivatives payment.Net cash used in financing activities for the year ended December 31, 2016 was $76.7 million . Net cash used in financing activities consisted primarily of thefollowing:•$286.3 million in net proceeds from equity issuances, net of expenses; and•$175.0 million in draws on the Revolving Credit Facility.Net cash used in financing activities were partially offset by:•$350.0 million in repayments of the Revolving Credit Facility;•$120.2 million in dividend payments;•$47.6 million in repayment of long-term debt; and•$17.9 million in distributions to noncontrolling interests.Net cash provided by financing activities for the year ended December 31, 2015 was $643.7 million. Net cash provided by financing activities consisted primarilyof the following:•$317.4 million in net proceeds from our February 2015 equity offering, net of expense;•$405.0 million in draws on the Revolving Credit Facility;•$329.1 million in proceeds from construction debt related to our construction projects;•$165.0 million in proceeds from issuance of long term debt;•$218.9 million from the July 2015 issuance of convertible debt, net of issuance costs; and•$336.0 million in capital contributions from noncontrolling interests.Net cash provided by financing activities were partially offset by:•$785.9 million in repayments of debt;•$121.2 million in payments for the purchase of the noncontrolling interest at Gulf Wind and Lost Creek;•$100.0 million in repayments of the Revolving Credit Facility;•$90.6 million in dividend payments;•$13.7 million in payments for deferred financing costs; and•$11.1 million in payments for interest rate derivatives.74Uses of LiquidityCash Dividends to InvestorsWe intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A common stock. On February 22, 2018 , we maintained our dividend at $0.4220 per Class A share, or $1.688 per Class A share on an annualized basis, commencing with respect to dividends to be paid on April 30, 2018 to holders ofrecord on March 30, 2018 . Cash paid for dividends for the year ended December 31, 2017 was $145.2 million .We expect to pay a quarterly dividend on or about the 30th day following each fiscal quarter to holders of record of our Class A common stock on the last day ofsuch quarter.Capital Expenditures and InvestmentsIn 2017 , total cash used for capital expenditures was $43.8 million . We do not include capital expenditures at our projects held at our unconsolidated equityinvestments. Cash paid for acquisitions was $227.8 million .We expect to make investments in additional projects in 2018 and provide further capital to Pattern Development 2.0. We have committed to acquire MSM fromPattern Development 1.0 for a purchase price of approximately CAD $53.0 million , which is currently expected to occur by the second quarter of 2018. We havealso committed to acquire the 84 MW project portfolio (Futtsu Solar, Kanagi Solar, Otsuki and Ohorayama) for approximately $131.5 million , subject certainclosing price adjustments and Tsugaru for approximately $194.0 million , consisting of an initial payment of approximately $79.7 million to be funded at closingand approximately JPY12.567 billion payable to Pattern Development 1.0 upon the term conversion of the construction loan and to the extent such term conversiondoes not occur, such second consideration payment will be made upon the commencement of commercial operations at Tsugaru which is expected in 2020. Weexpect to close on these transactions in early to mid 2018. In February 2018, we also funded approximately $35.2 million into Pattern Development 2.0 of whichapproximately $27 million will be used by Pattern Development 2.0 to fund the purchase of GPI.We also evaluate, from time to time, third-party acquisition opportunities. We believe that we will have sufficient cash and Revolving Credit Facility capacity tocomplete the funding of future commitments, but this may be affected by any other acquisitions or investments that we make. To the extent that we make any suchinvestments or acquisitions, we will evaluate capital markets and other corporate financing sources available to us at the time. In addition, we will makeinvestments, from time to time, at our operating projects. Operational capital expenditures are those capital expenditures required to maintain our long-termoperating capacity. Capital expenditures for the projects are generally made at the project level using project cash flows and project reserves, although funding formajor capital expenditures may be provided by additional project debt or equity. Therefore, the distributions that we receive from the projects may be made net ofcertain capital expenditures needed at the projects.For the year ending December 31, 2018 , we have budgeted $ 2.3 million for operational capital expenditures and $ 17.3 million for expansion capital expenditures.Contractual ObligationsWe have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to our capital expenditureprograms. See also Note 8 , Debt , and Note 17 , Commitments and Contingencies , in the notes to consolidated financial statements for additional discussion ofcontractual obligations.75The following table summarizes estimates of future commitments related to the various agreements that we have entered into as of December 31, 2017 (inthousands):Contractual Obligations (1) Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years TotalRevolving credit facility $— $— $— $— $—Corporate-level debt principal payments — 225,000 — 350,000 575,000Corporate-level interest payments on debt instruments 30,284 60,539 42,536 34,142 167,501Project-level debt principal payments 53,704 132,937 147,584 1,058,402 1,392,627Project-level interest payments on debt instruments 60,806 116,194 106,200 242,092 525,292Transmission service agreements 23,600 47,200 47,200 520,465 638,465Operating leases 15,822 31,815 33,086 320,718 401,441Service and maintenance agreements 39,817 51,526 44,288 54,562 190,193Acquisition and other commitments 46,576 7,546 4,240 16,270 74,632Asset retirement obligations — — — 56,620 56,620Total $270,609 $672,757 $425,134 $2,653,271 $4,021,771(1) The table above does not include our commitment to purchase the Futtsu Solar, Kanagi Solar, Otsuki, Ohorayama and Tsugaru projects discussed earlier, or thecommitments we will assume in connection with the purchase.Credit Agreements for Equity Method InvestmentsBelow is a summary of our proportion of debt in unconsolidated investments, as of December 31, 2017 (in thousands): Total Project Debt Percentage of Ownership Our Portion of Unconsolidated Project DebtSouth Kent $489,858 50.0% $244,929Grand 282,153 45.0% 126,969K2 599,821 33.3% 199,920Armow 405,709 50.0% 202,855Pattern Development 2.0 $103,443 20.9% $21,620Unconsolidated investments - debt $1,880,984 $796,293Off-Balance Sheet ArrangementsAs of December 31, 2017, we did not have any significant off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K.Covenants, Distribution Conditions and Events of DefaultCorporate-Level DebtRevolving Credit FacilityOur Revolving Credit Facility has customary covenants, prepayment provisions and events of default. The most restrictive of such provisions is the maintenancecoverage ratio that requires the subsidiary borrowers to maintain a leverage ratio (the ratio of borrower debt to borrower cash flow) that does not exceed 5.50:1.00and an interest coverage ratio (the ratio of borrower cash flow to borrower interest expense) that is not less than 1.75:1.00.In addition, certain of our subsidiaries are subject to usual and customary affirmative and negative covenants under our Revolving Credit Facility. Specifically,with limited exceptions, such subsidiaries are prohibited from distributing funds to us unless the following conditions are met: (i) no event of default under thecorporate credit facility has occurred and is continuing or would be caused by such distribution and (ii) the corporate credit facility borrowers are in compliancewith the leverage ratio test and the interest coverage ratio test, both before and after giving effect to such distribution.76Convertible NotesThe indenture for the convertible notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either thetrustee or the holders of not less than 25% in aggregate principal amount of the convertible notes then outstanding may declare the unpaid principal of theconvertible notes and accrued and unpaid interest, if any, thereon immediately due and payable. In the case of certain events of bankruptcy, insolvency orreorganization relating to us, the principal amount of the convertible notes together with accrued and unpaid interest, if any, thereon will automatically become andbe immediately due and payable.Unsecured Senior NotesUnder the Unsecured Senior Notes issued in January 2017, we have agreed to certain restrictions on our or the subsidiary guarantor's ability to incur secured debtand our ability to consolidate, merge or sell all or substantially all of our assets. These covenants are subject to a number of important limitations and exceptions.Consolidated Project-Level Debt and Unconsolidated Investments Project-Level DebtUnder the respective credit agreements for each of Hatchet Ridge, St. Joseph, Spring Valley, Santa Isabel, Ocotillo, El Arrayán, and Lost Creek, WesternInterconnect and Meikle, our projects are subject to certain covenants, events of default and distribution conditions. In addition, the respective credit agreementsfor each of our unconsolidated investments South Kent, Grand, K2 and Armow contain certain covenants, events of default and distribution conditions. Whileterms may vary between the individual credit agreements, the most significant and restrictive include the following:•restrict the project’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business.In general, the distribution conditions included in the credit agreements are as follows:•to the extent the project has letter of credit facilities under the project debt, there are no letter of credit loans outstanding;•to the extent the project has reserve requirements, accounts are fully funded;•any mandatory prepayment required has been made;•no default has occurred and such distribution will not result in an event of default; and•the applicable project has met its debt service coverage ratio.Distributions from Unconsolidated InvestmentsIn general, distributions result from excess cash flows from our unconsolidated investments, which represent revenues received from the sale of electricity, asreduced by operating expenses, interest and principal payments on project level debt provided that specified distribution requirements are met under the projectloan agreement. Project financing arrangements typically limit the timing of such distributions from the project entity to the same frequency as the scheduledprincipal and interest payments made by such project entity, which is usually on a quarterly basis although some financing arrangements instead call for monthly orsemiannual payments. Distributions from our unconsolidated investments may be affected by the underlying performance of the windfarm for each project entity,significant underperformance of the windfarm could result in distributions not being made for some period of time. Overall, however, we expect that we willreceive distributions throughout the term of the project's PPA.Tax Equity PartnershipGenerally, tax equity partnerships have specific commercial terms that dictate distributions of cash and allocation of tax items among the partners, who are dividedinto one of two categories: tax equity and cash investor. A disproportionate share of income and cash is given to tax equity in order for them to achieve a targetafter-tax yield or “flip” near year 10 of project operations. The target yield and flip term vary by agreement and are dependent on project performance. Prior to theflip, tax items (income, PTCs) are commonly allocated 99% to the tax equity. On the other hand, distributable cash is divided among the partners in percentagesthat do not match the tax items. Cash distribution percentages can be temporarily increased for tax equity in the event that certain cumulative distributionthresholds are not achieved. This has occurred for certain projects in 2017 and may occur for additional projects in 2018. Once tax equity reaches their target yield,the allocations and distributions “flip” to different amounts. After the flip, income and cash are77typically allocated 5% to the tax equity and 95% to the cash investor. REC sales are often specially addressed in each agreement with most of the cash and incomedirected to the cash investor both pre and post-flip.Tax equity partnership imposes a range of affirmative and negative covenants that are similar to what a term lender would require, such as, financial reporting,insurance maintenance and prudent operator standards. Most of these restrictions end once the flip point occurs and any deficit restoration obligation of the taxequity has been eliminated. There are also covenants that specifically seek to preserve the tax attributes of the project that are not customary for project termlenders.If tax equity suffers any losses or damages as the result of a breach of representation, covenant, or other obligation by the cash investor in its capacity as managingmember, tax equity may provide notice to the cash investor and require that any distributions otherwise required to be paid to the cash investor shall, instead, bepaid to tax equity to cover any damages.Critical Accounting Policies and EstimatesOur discussion and analysis of our financial condition and results of operations are based on our consolidated historical financial statements that are includedelsewhere in this Form 10-K, which have been prepared in accordance with U.S. GAAP. In applying the critical accounting policies set forth below, ourmanagement uses its judgment to determine the appropriate assumptions to be used in making certain estimates. These estimates are based on management’sexperience, the terms of existing contracts, management’s observance of trends in the wind power industry, information provided by our power purchasers andinformation available to management from other outside sources, as appropriate. These estimates are subject to an inherent degree of uncertainty.We use estimates, assumptions and judgments for certain items, including the calculation of our acquisitions, noncontrolling interest balances, and derivatives.These estimates, assumptions and judgments are derived and continually evaluated based on available information, experience and various assumptions we believeto be reasonable under the circumstances. To the extent these estimates are materially incorrect and need to be revised, our operating results may be materiallyadversely affected.AcquisitionsWe adopted Accounting Standards Update (ASU) 2017-01, Clarifying the Definition of a Business (ASU 2017-01) which provides a screen to determine when aset of assets and activities should not be considered a business. Under ASU 2017-01, we will set up an initial screening test that, if met, results in the conclusionthat the set is not a business. If the initial screening test is not met, we will evaluate whether the set is a business based on whether there are inputs and asubstantive process in place. The definition of a business impacts whether we consolidate an acquisition under business combination guidance or asset acquisitionguidance. When the acquisition is recognized as an equity method investment, the definition of a business impacts whether equity method goodwill can berecognized.Business Combinations, Asset Acquisitions, and Equity Method InvestmentsWhen we acquire a controlling interest in an entity deemed to be a business, the purchase is accounted for using the acquisition method, and the fair value of thepurchase consideration is allocated to the tangible and intangible assets acquired and the liabilities assumed based on their estimated fair values. Contingentconsideration is also recognized and measured at fair value as of the acquisition date. The excess, if any, of the fair value of the purchase consideration over the fairvalues of the identifiable net assets is recorded as goodwill. Conversely, the excess, if any, of the net fair value of the identifiable net assets over the fair value ofthe purchase consideration is recorded as a gain. Transaction costs associated with business combinations are expensed as incurred.When we acquire assets and liabilities that do not constitute a business, the fair value of the purchase consideration, including transaction costs of the assetacquisition, is assumed to be equal to the fair value of the net assets acquired. The purchase consideration, including the transaction costs, is allocated to theindividual assets and liabilities assumed based on their relative fair values. Contingent consideration associated with the acquisition is generally recognized whenthe contingency is resolved and the consideration is paid or becomes payable. An asset acquisition does not result in the recognition of goodwill, and transactioncosts are capitalized as part of the cost of the asset or group of assets acquired.When we acquire a noncontrolling interest in an entity where it is not the primary beneficiary, does not control any of the ongoing activities of the entity, and doesnot meet consolidation requirements of Accounting Standards Codification (ASC) 810, Consolidation , and ASU 2015-02, Consolidation (Topic 810):Amendments to the Consolidation Analysis , the investment is initially recognized as an equity method investment at cost. Any difference between the cost of aninvestment and the amount of underlying equity in net assets of an investee are considered basis differences. Basis difference related to the property, plant andequipment will be amortized over the estimated economic useful life of the underlying long-lived assets, while basis difference related to the PPA will beamortized over the remaining term of the PPA. Transaction costs associated with equity method investments are included in the investment.Additionally, if the projects in which we hold these investments recognize an impairment under the provisions of ASC 360, Property, Plant and Equipment , wewould record our impairment loss and would evaluate our investment for an other than temporary decline in value under ASC 323, Investments—Equity Methodand Joint Ventures .Significant judgment is required in determining the acquisition date fair value of the assets acquired and liabilities assumed using either an income, market, or cost-based valuation method. The valuations require management to make significant estimates and assumptions. These estimates and assumptions are inherentlyuncertain, and as a result, actual results may differ from estimates. Significant estimates include, but are not limited to, revenue and operating expense growth,future expected cash flows, and discount rates.For business combinations, during the measurement period, which is one year from the acquisition date, we may record adjustments to the assets acquired andliabilities assumed. Upon the conclusion of the measurement period, any subsequent adjustments are recorded to earnings.The allocation of the purchase price directly affects the following items in our consolidated financial statements:•The amount of purchase price allocated to the various tangible and intangible assets, liabilities and noncontrolling interests on our consolidated balancesheets;•The amounts of purchase price allocated to the value of above-market and below-market power purchase agreement, which is subsequently amortized toelectricity sales over the remaining terms of each respective arrangement; and•The period of time over which tangible and intangible assets are depreciated or amortized varies, and thus, changes in the amounts allocated to theseassets will have a direct impact on our results of operations.Noncontrolling InterestsNoncontrolling interests represent the portion of our net income (loss), net assets and comprehensive income (loss) that is not allocable to us and is calculatedbased on our ownership percentage, for certain projects.For those projects where economic benefits are not allocated based on pro rata ownership percentage, we have determined that the appropriate methodology forcalculating the noncontrolling interest balances that reflects the substantive economic arrangements in the operating agreements is a balance sheet approach usingthe hypothetical liquidation at book value (HLBV) method.Under the HLBV method, the amounts reported as noncontrolling interests in the consolidated balance sheets represent the amounts third-party investors wouldhypothetically receive at each balance sheet reporting date under the liquidation provisions of the operating partnership agreements, assuming the net assets of ourprojects were liquidated at amounts determined in accordance with U.S. GAAP and distributed to the investors. Therefore, the noncontrolling interest balances inthese projects are reported as a component of equity in the consolidated balance sheets.The third-party interests in the results of operations for those projects using HLBV is determined as the difference in noncontrolling interests in the consolidatedbalance sheets at the start and end of each reporting period, after taking into account any capital transactions between our projects and the third-party investors.Factors used in the HLBV calculation include U.S. GAAP income, taxable income, capital contributions, production tax credits, and distributions, and thestipulated targeted equity investor return specified in the projects' operating agreements.Changes in these factors could have a significant impact on the amounts that investors would receive upon a hypothetical liquidation. The use of the HLBVmethodology to allocate income to the noncontrolling interest holders may create volatility in our consolidated statements of operations as the application of HLBVcan drive changes in net income or loss attributable to noncontrolling interests from quarter to quarter.DerivativesWe enter into derivative transactions primarily for the purpose of reducing exposure to fluctuations in interest rates, foreign currency exchange rates and electricityprices. We have entered into interest rate swap agreements and have designated certain of these derivatives as cash flow hedges of expected interest payments onvariable rate debt. We also enter into foreign exchange currency transactions to hedge the distributions in Canadian dollars from our operational Canadian projectentities. These foreign exchange currency derivatives currently do not qualify for hedge accounting. We may also enter into interest rate caps and energy derivativeagreements. Currently, we do not hold interest rate cap arrangements. Furthermore, the energy derivative agreements do not qualify for hedge accounting.We recognize our derivative instruments at fair value in the consolidated balance sheets, unless the derivative instruments qualify for the normal purchase normalsale (NPNS) scope exception to derivative accounting. Accounting for changes in the fair value of a derivative78instrument depends on whether the derivative instrument has been designated as part of a hedging relationship and on the type of hedging relationship.For derivative instruments that are designated as cash flow hedges, the effective portion of change in fair value of the derivative is reported as a component of othercomprehensive income (loss). Changes in the fair value of these derivatives are subsequently reclassified into earnings in the period that the hedged transactionaffects earnings. The ineffective portion of change, if any, in fair value is recorded as a component of net income (loss) on the consolidated statements ofoperations. The change in fair value for undesignated derivative instruments is reported as a component of net income (loss) on the consolidated statements ofoperations. Certain of our energy derivative agreements qualify for the NPNS scope exception and therefore are not accounted for as derivatives.Energy prices are subject to wide swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generatingfacility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists primarily on variable-rate debt for which thecash flows vary based upon fluctuations in interest rates. Also, foreign currency exchange rates are subject to fluctuations in market movements and can beimpacted by, among other factors, economic conditions, inflation rate, political stability and public debt. We do not hedge all of our commodity price, foreigncurrency exchange rate and interest rate risks, thereby exposing the unhedged portion to changes in market prices.Market price quotations for certain electricity and natural gas trading hubs related to energy derivative agreements are not as readily obtainable due to the lengthsof the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, we use forward price curvesderived from third-party models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value ofenergy derivative agreements is a function of underlying forward energy prices, related volatility, counterparty creditworthiness, and duration of the contracts. Theassumptions used in the valuation models are critical and any changes in assumptions could have a significant impact on the estimated fair value of the contract.Item 7A.Quantitative and Qualitative Disclosures about Market Risk.We have significant exposure to commodity prices, interest rates and foreign currency exchange rates, as described below. To mitigate these market risks, we haveentered into multiple derivatives. We have not applied hedge accounting treatment to all of our derivatives, therefore we are required to mark some of ourderivatives to market through earnings on a periodic basis, which will result in non-cash adjustments to our earnings and may result in volatility in our earnings, inaddition to potential cash settlements for any losses.Commodity Price RiskWe manage our commodity price risk for electricity sales primarily through the use of fixed price long-term power purchase agreements with creditworthycounterparties. Our financial results reflect approximately 618,103 MWh of electricity sales in the year ended December 31, 2017 that were subject to spot marketpricing. A hypothetical increase or decrease of 10% or $ 1.69 per MWh in the merchant market prices would have increased or decreased revenue by $ 1.0 millionfor the year ended December 31, 2017 .In addition to the risks we face in broad commodity markets, many of our projects, especially in ERCOT, also face project-specific risks related to transmissionsystem limitations which can result in local prices that are lower than the broader market prices (congestion). In the case of adverse congestion, our revenues arenegatively impacted, and our PSAs do not protect us from these impacts, since under those contracts, this risk is fully allocated to our projects and not to thecounterparty (e.g. we sell our power at the lower local price, but still have to buy power for the counterparty at the higher broad market or hub price). In the pastthese impacts have been material to our economic results, and we expect that congestion will continue to be a material risk, in the future.Interest Rate RiskAs of December 31, 2017 , our long-term debt includes both fixed and variable rate debt. As long-term debt is not carried at fair value on the consolidated balancesheets, changes in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments prior to their maturity. The fairmarket value of our outstanding convertible senior notes, or "debentures," is subject to interest rate risk, market price risk and other factors due to the convertiblefeature of the debentures. The fair market value of the debentures will generally increase as interest rates fall and decrease as interest rates rise. In addition, the fairmarket value of the debentures will generally increase as the market price of our Class A common stock increases and decrease as the market price of our Class Acommon stock falls. The interest and market value changes affect the fair market value of the debentures, but do not impact our financial position, cash flows orresults of operations due to the fixed nature of the debt obligations, except to the extent that changes in the fair value of the debentures or value of Class A commonstock permit the holders of the debentures to convert into shares. As of December 31, 2017 , the estimated fair value of our debt was $1.9 billion and the carryingvalue of our debt was $1.9 billion . The fair value of variable interest79rate long-term debt is approximated by its carrying cost. A hypothetical increase or decrease in market interest rates by 1% would have resulted in a $48.0 milliondecrease or $52.0 million increase in the fair value of our fixed rate debt.We are exposed to fluctuations in interest rate risk as a result of our variable rate debt and outstanding amounts due under our Revolving Credit Facility. As ofDecember 31, 2017 , no amounts were outstanding under the Revolving Credit Facility.We may use a variety of derivative instruments, with respect to our variable rate debt, to manage our exposure to fluctuations in interest rates, including interestrate swaps and interest rate caps. As a result, our interest rate risk is limited to the unhedged portion of the variable rate debt. As of December 31, 2017 , theunhedged portion of our variable rate debt was $310.8 million . A hypothetical increase or decrease in interest rates by 1% would have a $ 3.1 million impact tointerest expense for the year ended December 31, 2017 .Foreign Currency Exchange Rate RiskOur wind power projects are located in the United States, Canada and Chile. As a result, our financial results could be significantly affected by factors such aschanges in foreign currency exchange rates or weak economic conditions in the foreign markets in which we operate. When the U.S. dollar strengthens againstforeign currencies, the relative value in revenue earned in the respective foreign currency decreases. When the U.S. dollar weakens against foreign currencies, therelative value in revenue earned in the respective foreign currency increases. A majority of our power sale agreements and operating expenditures are transacted inU.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. For the year ended December 31, 2017 , ourfinancial results included C$72.8 million , or $55.7 million calculated based on the monthly average exchange rate, in Canadian dollar denominated net income,from our Canadian operations. A hypothetical increase or decrease of 10% in exchange rates between the Canadian and U.S. dollar would have increased ordecreased net earnings of our Canadian operations by $ 5.6 million and $ 3.1 million for the years ended December 31, 2017 and 2016 , respectively.In January 2015, we established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising fromtransactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in our cash flow, whichmay have an adverse impact to our short-term liquidity or financial condition. For the year ended December 31, 2017 , we recognized an unrealized loss on foreigncurrency forward contracts of $4.8 million in loss on derivatives, net in the consolidated statements of operations. We also recognized a realized loss of $2.0million in loss on derivatives, net in the consolidated statements of operations related to foreign currency forward contracts that matured during the year endedDecember 31, 2017 .As of December 31, 2017 , a 10% devaluation in the Canadian dollar to the United States dollar would result in our consolidated balance sheets being negativelyimpacted by a $36.9 million cumulative translation adjustment in accumulated other comprehensive loss.Item 8.Financial Statements and Supplementary Data.The financial statements and schedules are listed in Part IV, Item 15 of this Form 10-K, beginning at page F-1, Index to Consolidated Financial Statements, and areincorporated by reference herein.Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.None. Item 9A.Controls and Procedures .Evaluation of Disclosure Controls and ProceduresOur management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls andprocedures pursuant to Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act), as of the end of the period coveredby this Form 10-K.80Based on this evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2017, our disclosure controls and procedures aredesigned at a reasonable assurance level and are effective to provide reasonable assurance that information we are required to disclose in reports that we file orsubmit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that suchinformation is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timelydecisions regarding required disclosure.Inherent Limitations Over Internal ControlsIn designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed andoperated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures mustreflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls andprocedures relative to their costs.Management’s Annual Report on Internal Control over Financial ReportingOur management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under theExchange Act. Management conducted an assessment of the effectiveness of our internal control over financial reporting based on the criteria set forth in InternalControl - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework).Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2017. Our independentregistered public accounting firm, Ernst & Young LLP, has issued an audit report on our internal control over financial reporting, which appears below.Remediation of Prior Material WeaknessesAs previously discussed in Item 9A “Controls and Procedures” of our Annual Report for the period ended December 31, 2016 and Item 4 “Controls andProcedures” of our 2017 Form 10-Q’s, management identified material weaknesses in five areas of its internal controls : inadequate training of personnel,inadequate documentation of and ineffective accounting policies, ineffective management review and monitoring controls, ineffective contract review proceduresand ineffective procure-to-pay procedures.During the fourth quarter of 2016 and throughout 2017, management conducted an extensive remediation plan to address its material weaknesses. The remediationplan involved extensive redesign of our overall system of internal controls, implementation of a number of newly designed controls and improved documentationof our system of internal controls specific to the five identified material weaknesses. Management took the following actions in remediating the materialweaknesses.•Inadequate training of personnel - general Sarbanes Oxley (SOX) awareness training was conducted with a broad base of employees and management. Inaddition, SOX workshops and mock walkthroughs were conducted with narrative and control owners. Additional areas of training were conducted foraccounting policies, journal entry preparation and review, account reconciliations, accruals, mergers and acquisitions, treasury, debt, tax, HLBV, and whatcould go wrong risk analysis. Additionally, management hired a number of key personnel with public company experience across its accounting, internalaudit and SOX compliance office functions.•Inadequate documentation of and ineffective accounting policies - Management formally documented 33 accounting policies and established a process fortheir periodic updates as well as a review and approval process over each policy. Protocols were established for the maintenance and availability of suchpolicies to accounting personnel.•Ineffective management review and monitoring controls - Management documented, redesigned and implemented numerous monitoring and reviewcontrols, including controls over budget versus actual, account reconciliations, cashflow, journal entry review, technical accounting review, footnotedisclosures and financial statement tie-out, disclosure committee, period-over-period fluctuation analysis, HLBV, tax, and fixed assets.•Ineffective contract review procedures - Management conducted a risk-based retrospective contract review process to ensure that all existing contracts areaccounted for appropriately. For all new contracts, a formal contract review process was designed and implemented to ensure all contracts are reviewedand appropriate accounting conclusions are documented.•Ineffective procure-to-pay procedures - Management updated and implemented three new policies related to procure-to-pay; Sub-delegation of AuthorityPolicy, Procurement Policy and Invoice Approval Policy. These policies are maintained on our internal website and an update, review and approvalprocess was documented and implemented for each policy. In addition, we81made a number of system enhancements to automate controls within the procure-to-pay cycle and redesigned and implemented additional controls.Implementation of management's remediation plans described above have strengthened our internal control over financial reporting and addressed the materialweaknesses that were identified in 2016. Based on its assessment, management concluded that the material weaknesses have been remediated as of December 31,2017.Change in Internal Control Over Financial ReportingManagement continuously reviews disclosure controls and procedures, and internal control over financial reporting, and accordingly may, from time to time, makechanges aimed at enhancing their effectiveness to ensure that its systems evolve with its business. Except as noted above with respect to the remediationprocedures for the previously identified material weaknesses, there were no other changes in our internal control over financial reporting during the year endedDecember 31, 2017 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.82Report of Independent Registered Public Accounting FirmTo the Shareholders and the Board of Directors of Pattern Energy Group Inc.Opinion on Internal Control over Financial ReportingWe have audited Pattern Energy Group Inc.’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion,Pattern Energy Group Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based onthe COSO criteria.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balancesheets of Pattern Energy Group Inc. as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income (loss),stockholders' equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and financial statement Schedule Ilisted in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”) and our report dated March 1, 2018 expressed an unqualifiedopinion thereon.Basis for OpinionThe Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is toexpress an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB andare required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of theSecurities and Exchange Commission and the PCAOB.We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assuranceabout whether effective internal control over financial reporting was maintained in all material respects.Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluatingthe design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in thecircumstances. We believe that our audit provides a reasonable basis for our opinion.Definition and Limitations of Internal Control Over Financial ReportingA company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect thetransactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation offinancial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only inaccordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection ofunauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance withthe policies or procedures may deteriorate./s/ Ernst & Young LLPSan Francisco, CaliforniaMarch 1, 201883Item 9B.Other Information .None84PART IIICertain information required by Part III is omitted from this Form 10-K because the registrant will file with the U.S. Securities and Exchange Commission adefinitive proxy statement pursuant to Regulation 14A in connection with the solicitation of proxies for the Company’s Annual Meeting of Stockholders, or the2018 Proxy Statement, within 120 days after the end of the fiscal year covered by this Form 10-K, and certain information included therein is incorporated hereinby reference.Item 10.Directors, Executive Officers and Corporate Governance .The information required under this Item 10 is incorporated by reference to our 2018 Proxy Statement.Item 11.Executive Compensation .The information required under this Item 11 is incorporated by reference to our 2018 Proxy Statement.Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.The information required under this Item 12 is incorporated by reference to our 2018 Proxy Statement.Item 13.Certain Relationships and Related Transactions, and Director Independence.The information required under this Item 13 is incorporated by reference to our 2018 Proxy Statement.Item 14.Principal Accounting Fees and Services.The information required under this Item 14 is incorporated by reference to our 2018 Proxy Statement.85PART IV Item 15.Exhibits and Financial Statement Schedules.(a) Documents filed as part of this report (1) Consolidated financial statements—Pattern Energy Group Inc. Report of Independent Registered Public Accounting Firm F-2 Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016 F-3 Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015 F-4 Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 2015 F-5 Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2017, 2016 and 2015 F-6 Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015 F-7 Notes to Consolidated Financial Statements F-9 Financial statements—Pattern Energy Group Inc. Parent and Equity Method Investments a) Condensed Parent-Company Financial Statements S- 1 b) South Kent Wind LP Financial Statements S- 7 c) Grand Renewables Wind LP Financial Statements S- 25 d) SP Armow Wind Ontario LP Financial Statements S- 44 e) K2 Wind Ontario LP Financial Statements S- 62 f) Pattern Energy Group 2 LP Financial Statements S- 79 (2) Financial Statement Schedules - All financial statement schedules have been omitted, since the required information is either included in theConsolidated Financial Statements or the notes thereto, is not applicable or is not required. (3) Exhibits 86The following documents are filed or furnished as part of this Form 10-K. The Company will furnish a copy of any exhibit listed to requesting stockholdersupon payment of the Company’s reasonable expenses in furnishing those materials. Exhibit No. Description Of Exhibits 3.1 Amended and Restated Certificate of Incorporation of Pattern Energy Group Inc. (Incorporated by reference to Exhibit 3.1 to the Company'sRegistration Statement on Form S-1/A dated September 20, 2013 (Registration No. 333-190538)). 3.2 Amended and Restated Bylaws of Pattern Energy Group Inc. (Incorporated by reference to Exhibit 3.2 to the Company's Registration Statementon Form S-1/A dated September 3, 2013 (Registration No. 333-190538)). 4.1 Form of Class A Stock Certificate (Incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-1/A datedSeptember 3, 2013 (Registration No. 333-190538)). 4.2 Form of Senior Indenture (Incorporated by reference to Exhibit 4.3 to the Company's Registration Statement on Form S-3 dated August 14, 2017(Registration No. 333-219970). 4.3 Form of Subordinated Indenture (Incorporated by reference to Exhibit 4.5 to the Company's Registration Statement on Form S-3 dated August14, 2017 (Registration No. 333-219970). 4.4 Indenture, dated July 28, 2015, among Pattern Energy Group Inc., as issuer, Pattern US Finance Company LLC, as subsidiary guarantor, andDeutsche Bank Trust Company Americas, as trustee, related to 4.00% Convertible Senior Notes due 2020 (Incorporated by reference to Exhibit4.1 to the Company’s Current Report on Form 8-K dated July 28, 2015). 4.5 Indenture, dated as of January 25, 2017, among Pattern Energy Group Inc., Pattern US Finance Company LLC, as guarantor, and Deutsche BankTrust Company Americas, as trustee, related to 5.875% Senior Notes due 2024 (Incorporated by reference to Exhibit 4.1 to the Company'sCurrent Report on Form 8-K dated January 20, 2017). 10.1 Second Amended and Restated Credit and Guaranty Agreement, among Pattern US Finance Company LLC, Pattern Canada Finance CompanyULC, as borrowers, certain subsidiaries of the borrowers, the lenders party thereto from time to time, Royal Bank of Canada, as SwinglineLender, Administrative Agent and Collateral Agent, Bank of Montreal, as Syndication Agent, Royal Bank of Canada, Bank of Montreal, MorganStanley Bank, N.A., Citibank N.A. and Bank of America, N.A. each as LC Issuing Bank, and Citibank, N.A. as Documentation Agent, dated asof November 21, 2017 (the “Amended and Restated Credit and Guaranty Agreement) (Incorporated by reference to Exhibit 10.1 to theCompany's Current Report on Form 8-K dated November 22, 2017). 10.2 Pattern Energy Group Inc. Amended and Restated 2013 Equity Incentive Award Plan (Incorporated by reference to Exhibit B to the Company'sDefinitive Proxy Statement on Schedule 14A dated April 14, 2017. 10.3 Form of Pattern Energy Group Inc. 2013 Incentive Bonus Plan. (Incorporated by reference to Exhibit 10.3 to the Company's RegistrationStatement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)). 10.4 Form of Stock Option Agreement under 2013 Equity Incentive Award Plan (Incorporated by reference to Exhibit 10.4 to the Company'sRegistration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)). 10.5 Form of Restricted Stock Agreement under 2013 Equity Incentive Award Plan. (Incorporated by reference to Exhibit 10.5 to the Company'sRegistration Statement on Form S-1/A dated September 20, 2013 (Registration No. 333-190538)). 10.6 Form of Restricted Stock Unit Agreement under 2013 Equity Incentive Award Plan. (Incorporated by reference to Exhibit 10.6 to the Company'sRegistration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)). 10.7 Form of Deferred Restricted Stock Unit Agreement under 2013 Equity Incentive Award Plan. (Incorporated by reference to Exhibit 10.2 to theCompany's Current Report on Form 8-K dated November 22, 2017). 10.8 Form of Indemnification Agreement between the Registrant and each of its Executive Officers and Directors. (Incorporated by reference toExhibit 10.7 to the Company's Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)). 10.9 Registration Rights Agreement between the Company and Pattern Energy Group LP, dated as of October 2, 2013. (Incorporated by reference toExhibit 10.1 to the Company's Current Report on Form 8-K dated September 26, 2013). 10.10 Contribution Agreement among the Company, Pattern Renewables LP, Pattern Energy Group LP, and Pattern Renewable Holdings Canada ULC,dated as of October 2, 2013. (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K dated September 26,2013). 10.11 Purchase Rights Agreement among the Company, Pattern Energy Group LP, Pattern Energy Group Holdings LP and Pattern Energy GP LLC,dated as of October 2, 2013. (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K dated September 26,2013). 10.12 Purchase and Sale Agreement, dated as of December 20, 2013, by and between Pattern Canada Operations Holdings ULC and Pattern EnergyGroup LP (Grand PSA). (Incorporated by reference to Exhibit 12 to the Company's Current Report on Form 8-K dated December 20, 2013). 87Exhibit No. Description Of Exhibits10.13 Purchase and Sale Agreement, dated as of December 20, 2013, by and among Pattern Energy Group Inc., Panhandle B Holdco 2 LLC and PatternEnergy Group LP (PH2 PSA) (Incorporated by reference to Exhibit 13 to the Company's Current Report on Form 8-K dated December 20, 2013). 10.14 Management, Operation and Maintenance Agreement, dated as of December 20, 2013, by and between Pattern Panhandle Wind 2 LLC andPattern Operators LP (PH2 MOMA) (Incorporated by reference to Exhibit 14 to the Company's Current Report on Form 8-K dated December 20,2013). 10.15 Project Administration Agreement, dated as of December 20, 2013, by and between Pattern Panhandle Wind 2 LLC and Pattern Operators LP(PH2 PAA) (Incorporated by reference to Exhibit 15 to the Company's Current Report on Form 8-K dated December 20, 2013). 10.16 Purchase and Sale Agreement, dated as of May 1, 2014, by and among Pattern Energy Group Inc., Pattern Renewables LP and Pattern EnergyGroup LP (PH1 PSA) (Incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K dated May 2, 2014). 10.17 Purchase and Sale Agreement by and among Pattern Energy Group Inc., as Purchaser, Pattern Renewables LP, as Seller, and (solely for purposesof Section 7.1) Pattern Energy Group LP, as Guarantor, dated as of December 19, 2014 (Logan’s Gap PSA) (Incorporated by reference to Exhibit2.1 to the Company's Current Report on Form 8-K dated December 19, 2014). 10.18 Purchase and Sale Agreement, by and between Pattern Energy Group Inc., Pattern Renewables Development Company LLC, and (as guarantorfor certain obligations) Pattern Energy Group LP dated April 29, 2015 (Amazon Wind Farm Fowler Ridge PSA) (Incorporated by reference toExhibit 2.1 to the Company’s Current Report on Form 8-K dated April 29, 2015). 10.19 Purchase and Sale Agreement, by and between Wind Capital Group, LLC, Lincoln County Wind Project Finco, LLC and Pattern Energy GroupInc., dated April 1, 2015 (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K dated May 15, 2015). 10.20 Purchase and Sale Agreement between Pattern Canada Finance Company ULC and Pattern Energy Group LP dated April 4, 2015 (K2 PSA)(Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K dated June 17, 2015). 10.21 Purchase Agreement between Pattern Gulf Wind Equity 2 LLC, as seller, and Pattern Gulf Wind Equity LLC, as buyer, dated July 20, 2015(Incorporated by reference to the Exhibit 10.1 to the Company’s Current Report on Form 8-K dated July 20, 2015). 10.22 Employment Agreement between Pattern Energy Group Inc. and Michael M. Garland dated October 2, 2013 (Incorporated by reference toExhibit 10.19 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2013). 10.23 Employment Agreement between Pattern Energy Group Inc. and Hunter H. Armistead dated October 2, 2013 (Incorporated by reference toExhibit 10.20 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2013). 10.24 Employment Agreement between Pattern Energy Group Inc. and Daniel M. Elkort dated October 2, 2013 (Incorporated by reference to Exhibit10.21 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2013). 10.25 Employment Agreement between Pattern Energy Group Inc. and Esben Pedersen dated October 2, 2013 (Incorporated by reference to Exhibit10.16 to the Company's Registration Statement on Form S-1 dated April 25, 2014 (Registration No. 333-195488)). 10.26 Purchase and Sale Agreement, dated as of June 30, 2016, by and between Pattern Energy Group Inc., Pattern Renewables LP, and Pattern EnergyGroup LP (Incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed July 1, 2016). 10.27 Purchase and Sale Agreement, dated September 21, 2016, by and between Pattern Canada Finance Company ULC, a Nova Scotia unlimitedliability company, and Pattern Energy Group LP, a Delaware limited partnership (Incorporated by reference to Exhibit 2.1 to the Company'sCurrent Report on Form 8-K filed September 23, 2016). 10.28 Employment Agreement between Pattern Energy Group Inc. and Michael J. Lyon dated October 2, 2013 (Incorporated by reference to Exhibit10.1 to the Company’s Quarterly Report on Form 10-Q dated May 7, 2015). 10.29 Assignment and Assumption of Lease and Consent of Landlord Agreement, effective as of January 1, 2016, by and between Pattern EnergyGroup LP, Pattern Energy Group Inc., and AMB Pier One, LLC (Incorporated by reference to Exhibit 10.1 to the Company's Current Report onForm 8-K dated January 25, 2016).88Exhibit No. Description Of Exhibits 10.30 Purchase Rights Agreement among Pattern Energy Group Inc., Pattern Energy Group 2 LP, and (solely with respect to Article III thereto) PatternEnergy Group Holdings 2 LP and Pattern Energy Group Holdings 2 GP LLC, dated as of December 8, 2016 (Incorporated by reference toExhibit 10.1 to the Company's Current Report on Form 8-K dated December 8, 2016). 10.31 Service Mark License Agreement between Pattern Energy Group Inc. and Pattern Energy Group 2 LP, dated as of December 8, 2016(Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K dated December 8, 2016). 10.32 Amended and Restated Purchase Rights Agreement by and among Pattern Energy Group LP, Pattern Energy Group Inc., Pattern Energy GroupHoldings LP (solely with respect to Article IV therein) and Pattern Energy GP LLC, dated as of June 16, 2017 (Incorporated by reference toExhibit 10.1 to the Company's Current Report on Form 8-K filed June 19, 2017). 10.33 Amended and Restated Purchase Rights Agreement by and among Pattern Energy Group 2 LP, Pattern Energy Group Inc., Pattern Energy GroupHoldings 2 LP (solely with respect to Article III therein) and Pattern Energy Group Holdings 2 GP LLC, dated as of June 16, 2017 (Incorporatedby reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed June 19, 2017). 10.34 Second Amended and Restated Non-Competition Agreement by and among Pattern Energy Group LP, Pattern Energy Group Inc. and PatternEnergy Group 2 LP, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filedJune 19, 2017). 10.35 Amended and Restated Multilateral Management Services Agreement by and among Pattern Energy Group Inc., Pattern Energy Group LP andPattern Energy Group 2 LP, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-Kfiled June 19, 2017). 10.36 Second Amended and Restated Limited Partnership Agreement of Pattern Energy Group Holdings 2 LP, dated as of June 16, 2017 (Incorporatedby reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed June 19, 2017). 10.37 Joint Venture Agreement between PSP Investments and Pattern Energy Group Inc., dated as of June 16, 2017 (Incorporated by reference toExhibit 10.6 to the Company's Current Report on Form 8-K filed June 19, 2017). 10.38 Sponsor Services Agreement between Pattern Energy Group Inc. and PSP Investments, dated as of June 16, 2017 (Incorporated by reference toExhibit 10.7 to the Company's Current Report on Form 8-K filed June 19, 2017). 10.39 Purchase and Sale Agreement by and among Pattern Energy Group Inc., Vertuous Energy Canada Inc. and Pattern Energy Group LP, dated as ofJune 16, 2017 (Meikle PSA) (Incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K filed June 19, 2017). 10.40 Purchase and Sale Agreement by and among Pattern Energy Group Inc., Vertuous Energy Canada Inc. and Pattern Energy Group LP, dated as ofJune 16, 2017 (MSM PSA) (Incorporated by reference to Exhibit 10.9 to the Company's Current Report on Form 8-K filed June 19, 2017). 10.41 Purchase and Sale Agreement by and among Vertuous Energy LLC and Pattern Energy Group Inc., dated as of June 16, 2017 (Panhandle 2 PSA)(Incorporated by reference to Exhibit 10.10 to the Company's Current Report on Form 8-K filed June 19, 2017). 10.42 Amended and Restated Limited Partnership Agreement among Pattern Canada Finance Company ULC, Vertuous Energy Canada Inc. andMeikle Wind Energy Corp. dated as of August 10, 2017 (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed August 14, 2017). 10.43 Shareholders Agreement among Pattern Canada Finance Company ULC, Vertuous Energy Canada Inc. and Meikle Wind Energy Corp. dated asof August 10, 2017 (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed August 14, 2017). 10.44 Amended and Restated Limited Liability Company Agreement of PAN2 B2, LLC, a Delaware limited liability company, dated as of December22, 2017 (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated December 28, 2017). 10.45 Voting Agreement between Panhandle B Member 2 LLC and Vertuous Energy LLC made as of December 22, 2017 (Incorporated by referenceto Exhibit 10.2 to the Company's Current Report on Form 8-K dated December 28, 2017). 10.46 Letter Agreement between Pattern Energy Group Inc. and Public Sector Pension Investment Board, dated as of December 22, 2017 (Incorporatedby reference to Exhibit 10.3 to the Company's Current Report on Form 8-K dated December 28, 2017).89Exhibit No. Description Of Exhibits 10.47 Reimbursement Agreement between Pattern Energy Group Inc. and Public Sector Pension Investment Board, dated as of December 22, 2017(Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K dated December 28, 2017). 10.48 Registration Rights Agreement (Side Letter) among PSP Investments and the Pattern Energy Group, Inc. dated as of October 27, 2017(Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated October 30, 2017). 10.49 Purchase and Sale Agreement by and between Pattern Energy Group Inc. and Pattern Energy Group LP dated as of February 26, 2018 related toindirect interests in Green Power Tsugaru GK (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K datedFebruary 27, 2018). 10.50 Purchase and Sale Agreement by and between Pattern Energy Group Inc. and Green Power Investment Corporation dated as of February 26,2018 related to indirect interests in Green Power Tsugaru GK (Incorporated by reference to Exhibit 10.2 to the Company's Current Report onForm 8-K dated February 27, 2018). 10.51 Purchase and Sale Agreement by and between Pattern Energy Group Inc. and Pattern Energy Group LP dated as of February 26, 2018 related toindirect interests in GK Green Power Kanagi, GK Green Power Otsuki and GK Green Power Futtsu (Incorporated by reference to Exhibit 10.3 tothe Company's Current Report on Form 8-K dated February 27, 2018). 10.52 Purchase and Sale Agreement by and between Pattern Energy Group Inc. and Green Power Investment Corporation dated as of February 26,2018 related to indirect interests in GK Green Power Kanagi, GK Green Power Otsuki and Otsuki Wind Power Corporation (Incorporated byreference to Exhibit 10.4 to the Company's Current Report on Form 8-K dated February 27, 2018). 10.53 Deferred Payment Agreement by and between Pattern Energy Group Inc. and Pattern Energy Group LP dated as of February 26, 2018(Incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K dated February 27, 2018). 21.1** Subsidiaries of the Company 23.1** Consent of Independent Registered Public Accounting Firm 23.2** Consent of PricewaterhouseCoopers LLP 24.1 Powers of Attorney (included in the signature pages to this filing). 31.1** Certifications of the Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and15d-14(a), as adopted pursuant to Section 302 of theSarbanes-Oxley Act of 2002 31.2** Certifications of the Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and15d-14(a), as adopted pursuant to Section 302 of theSarbanes-Oxley Act of 2002 32* Certifications of the Company’s Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant toSection 906 of the Sarbanes-Oxley Act of 2002. 101.INS** XBRL Instance Document 101.SCH** XBRL Taxonomy Extension Schema Document 101.CAL** XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF** XBRL Taxonomy Extension Definition Linkbase Document 101.LAB** XBRL Taxonomy Extension Label Linkbase Document 101.PRE** XBRL Taxonomy Extension Presentation Linkbase Document*These certifications accompany this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed “filed” by the Company forpurposes of Section 18 of the Exchange Act.** Filed herewith.90SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf bythe undersigned, thereunto duly authorized. Date: March 1, 2018Pattern Energy Group Inc. By/s/ Michael M. Garland Michael M. Garland President and Chief Executive OfficerPOWER OF ATTORNEYKNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Dyann Blaine and Michael Lyon, andeach of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him or her and in his or her name,place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, andother documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, fullpower and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposesas he or she might or could do in person, hereby ratifying and confirming that all said attorneys-in-fact and agents, or any of them or their or his or her substitute orsubstitutes, may lawfully do or cause to be done by virtue hereof.Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed by the following persons on behalf of theregistrant and in the capacities and on the dates indicated: 91Signature Title Date /s/ MICHAEL M. GARLAND President, Chief Executive Officerand Director ofPattern Energy Group Inc.(Principal Executive Officer) March 1, 2018Michael M. Garland /s/ ALAN R. BATKIN Director and Chairman ofPattern Energy Group Inc. March 1, 2018Alan R. Batkin /s/ PATRICIA S. BELLINGER Director of Pattern Energy Group Inc. March 1, 2018Patricia S. Bellinger /s/ THE LORD BROWNE OF MADINGLEY Director of Pattern Energy Group Inc. March 1, 2018The Lord Browne of Madingley /s/ DOUGLAS G. HALL Director of Pattern Energy Group Inc. March 1, 2018Douglas G. Hall /s/ MICHAEL B. HOFFMAN Director of Pattern Energy Group Inc. March 1, 2018Michael B. Hoffman /s/ PATRICIA M. NEWSON Director of Pattern Energy Group Inc. March 1, 2018Patricia M. Newson /s/ MICHAEL J. LYON Chief Financial Officer of Pattern Energy Group Inc. (Principal Financial Officer) March 1, 2018Michael J. Lyon /s/ RICHARD A. OSTBERG Senior Vice President, ControllerPattern Energy Group Inc.(Principal Accounting Officer) March 1, 2018Richard A. Ostberg 92INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm F-2Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016 F-3Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015 F-4Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 2015 F-5Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2017, 2016 and 2015 F-6Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015 F-7Notes to Consolidated Financial Statements F-9F-1Report of Independent Registered Public Accounting FirmTo the Shareholders and the Board of Directors of Pattern Energy Group Inc.Opinion on the Financial StatementsWe have audited the accompanying consolidated balance sheets of Pattern Energy Group Inc. (the Company) as of December 31, 2017 and 2016, and the relatedconsolidated statements of operations, comprehensive income (loss), stockholders' equity and cash flows for each of the three years in the period ended December31, 2017, and the related notes and financial statement Schedule I listed in the Index at Item 15(a) (collectively referred to as the “consolidated financialstatements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Pattern EnergyGroup Inc. at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,in conformity with U.S. generally accepted accounting principles.We did not audit the financial statements of SP Armow Wind Ontario LP, South Kent Wind LP and Grand Renewable Wind LP partnerships in which theCompany has a 50%, 50% and 45% interest, respectively. In the consolidated financial statements, the Company’s investment in SP Armow Wind Ontario LP,South Kent Wind LP and Grand Renewable Wind LP is stated at $145,652,000 and $136,243,000 at December 31, 2017 and 2016, respectively, and theCompany’s equity in the net earnings (losses) of SP Armow Wind Ontario LP, South Kent Wind LP and Grand Renewable Wind LP is stated at $46,000,000,$24,704,000 and $12,233,000 for the years ended December 31, 2017, 2016 and 2015, respectively. The statements for SP Armow Wind Ontario LP, South KentWind LP and Grand Renewable Wind LP were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to theamounts included for SP Armow Wind Ontario LP, South Kent Wind LP and Grand Renewable Wind LP, is based solely on the reports of the other auditors.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internalcontrol over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission (2013 framework) , and our report dated March 1, 2018 expressed an unmodified opinion thereon.Basis for OpinionThese financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statementsbased on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordancewith the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures toassess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Suchprocedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating theaccounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believethat our audits provide a reasonable basis for our opinion./s/ Ernst & Young LLPWe have served as the Company’s auditor since 2012.San Francisco, CaliforniaMarch 1, 2018F-2Pattern Energy Group Inc.Consolidated Balance Sheets(In thousands of U.S. dollars, except share and par value data) December 31, 20172016AssetsCurrent assets:Cash and cash equivalents (Note 6)$116,753$83,932Restricted cash (Note 6)9,06511,793Funds deposited by counterparty29,780 43,635Trade receivables (Note 6)54,90037,510Derivative assets, current19,44517,578Prepaid expenses (Note 6)17,84713,803Other current assets (Note 6)21,1057,350Deferred financing costs, current, net of accumulated amortization of $2,580 and $9,350 as of December31, 2017 and December 31, 2016, respectively1,4152,456Total current assets270,310218,057Restricted cash (Note 6)12,16213,646Property, plant and equipment, net (Note 6)3,965,1213,135,162Unconsolidated investments311,223233,294Derivative assets9,62826,712Deferred financing costs7,7844,052Net deferred tax assets6,3495,559Finite-lived intangible assets, net (Note 6)136,04891,895Other assets (Note 6)22,90624,390Total assets$4,741,531$3,752,767(Continued)Pattern Energy Group Inc.Consolidated Balance Sheets(In thousands of U.S. dollars, except share and par value data) December 31, 2017 2016Liabilities and equityCurrent liabilities:Accounts payable and other accrued liabilities (Note 6)$53,615$31,305Accrued construction costs (Note 6)1,3691,098Counterparty deposit liability29,780 43,635Accrued interest (Note 6)16,4609,545Dividends payable41,38735,960Derivative liabilities, current8,40911,918Revolving credit facility—180,000Current portion of long-term debt, net51,99648,716Other current liabilities (Note 6)14,0184,698Total current liabilities217,034366,875Long-term debt, net1,878,7351,334,956Derivative liabilities20,97224,521Net deferred tax liabilities56,49131,759Finite-lived intangible liability, net51,19454,663Contingent liabilities62,398 576Other long-term liabilities (Note 6)106,56560,673Total liabilities2,393,3891,874,023Commitments and contingencies (Note 17)Equity:Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 97,860,048 and87,410,687 shares outstanding as of December 31, 2017 and December 31, 2016, respectively980875Additional paid-in capital1,234,8461,145,760Accumulated loss(112,175)(94,270)Accumulated other comprehensive loss(25,691)(62,367)Treasury stock, at cost; 157,812 and 110,964 shares of Class A common stock as of December 31, 2017and December 31, 2016, respectively(3,511)(2,500)Total equity before noncontrolling interest1,094,449987,498Noncontrolling interest1,253,693891,246Total equity2,348,1421,878,744Total liabilities and equity$4,741,531$3,752,767(Concluded)See accompanying notes to consolidated financial statements.F-3Pattern Energy Group Inc.Consolidated Statements of Operations(In thousands of U.S. dollars, except share data) Year ended December 31, 2017 2016 2015Revenue: Electricity sales$401,888$346,000 $324,275Other revenue9,4568,052 5,556Total revenue411,344354,052329,831Cost of revenue: Project expense130,561128,428 114,619Transmission costs19,472 424 —Depreciation and accretion198,644174,490 143,376Total cost of revenue348,677303,342257,995Gross profit62,66750,710 71,836Operating expenses: General and administrative38,58335,499 27,142Related party general and administrative13,8259,900 7,589Total operating expenses52,40845,39934,731Operating income10,2595,311 37,105Other income (expense): Interest expense(102,229)(78,004) (77,907)Loss on derivatives(9,787)(3,324) (16,711)Earnings in unconsolidated investments, net41,29930,192 16,119Early extinguishment of debt(8,643)— (4,941)Net loss on transactions(1,322)(326) (3,400)Other income (expense), net(253)2,531 (929)Total other expense(80,935)(48,931)(87,769)Net loss before income tax(70,676)(43,620) (50,664)Tax provision11,7348,6794,943Net loss(82,410)(52,299) (55,607)Net loss attributable to noncontrolling interest(64,505)(35,188)(23,074)Net loss attributable to Pattern Energy$(17,905)$(17,111) $(32,533) Weighted average number of common shares outstanding Basic and diluted89,179,34379,382,38870,535,568Loss per share attributable to Pattern Energy Basic and diluted$(0.20) $(0.22) $(0.46)Dividends declared per Class A common share$1.67 $1.58 $1.43See accompanying notes to consolidated financial statements.F-4Pattern Energy Group Inc.Consolidated Statements of Comprehensive Income (Loss)(In thousands of U.S. Dollars) Year ended December 31, 2017 2016 2015Net loss$(82,410) $(52,299) $(55,607)Other comprehensive income (loss): Foreign currency translation, net of tax provision of $3,569, zero and zero, respectively15,313 4,785 (28,947)Derivative activity: Effective portion of change in fair market value of derivatives, net of tax (provision)benefit of ($758), $833 and $1,860, respectively(2,738) (6,751) (16,163)Reclassifications to net loss due to termination of interest rate derivatives, net of zerotax impact2,207 — 17,139Reclassifications to net loss, net of tax impact of $1,060, $949 and $670, respectively8,935 7,462 12,234Total change in effective portion of change in fair market value of derivatives8,404 711 13,210Proportionate share of equity investee's derivative activity: Effective portion of change in fair market value of derivatives, net of tax (provision)benefit of ($2,094), ($375) and $2,394, respectively5,807 1,039 (6,640)Reclassifications to net loss, net of tax impact of $2,887, $1,656 and $870, respectively8,006 4,594 2,412Total change in effective portion of change in fair market value of derivatives13,813 5,633 (4,228)Total other comprehensive income (loss), net of tax37,530 11,129 (19,965)Comprehensive loss(44,880) (41,170) (75,572)Less comprehensive loss attributable to noncontrolling interest: Net loss attributable to noncontrolling interest(64,505) (35,188) (23,074)Foreign currency translation, net of zero tax impact168 — —Derivative activity: Effective portion of change in fair market value of derivatives, net of tax benefit of $80,$44 and $185, respectively(182) (119) (1,740)Reclassifications to net loss, net of tax impact of $117, $107 and $201, respectively868 290 2,088Total change in effective portion of change in fair market value of derivatives686 171 348Comprehensive loss attributable to noncontrolling interest(63,651) (35,017) (22,726)Comprehensive income (loss) attributable to Pattern Energy$18,771 $(6,153) $(52,846)See accompanying notes to consolidated financial statements.F-5Pattern Energy Group Inc.Consolidated Statement of Stockholders’ Equity(In thousands of U.S. Dollars, except share data) Class A Common Stock Treasury Stock AdditionalPaid-inCapital AccumulatedLoss AccumulatedOtherComprehensiveIncome (Loss) Total NoncontrollingInterest TotalEquity Shares Amount Shares Amount Balances at December 31, 201462,088,306 $621 (25,465) $(717) $723,938 $(44,626) $(45,068) $634,148$530,586 $1,164,734Issuance of Class A commonstock, net of issuance costs12,435,000 124 — — 316,828 — — 316,952 — 316,952Issuance of Class A commonstock under equity incentiveaward plan, net186,136 2 — — (2) — — — — —Repurchase of shares foremployee tax withholding— — (39,836) (860) — — — (860) — (860)Stock-based compensation— — — — 4,462 — — 4,462 — 4,462Dividends declared— — — — (102,893) — — (102,893) — (102,893)Dividend equivalents declaredupon vesting of deferredrestricted stock units— — — — 23 — — 23 — 23Acquisition of Post Rock— — — — — — — — 205,100 205,100Conversion option ofconvertible senior notes, net ofissuance costs— — — — 23,743 — — 23,743 — 23,743Buyout of noncontrollinginterests— — — — 16,715 — (7,944) 8,771 (95,047) (86,276)Contributions fromnoncontrolling interests— — — — — — — — 334,231 334,231Distributions to noncontrollinginterests— — — — — — — — (7,882) (7,882)Net loss— — — — — (32,533) — (32,533) (23,074) (55,607)Other comprehensive income(loss), net of tax— — — — — — (20,313) (20,313) 348 (19,965)Balances at December 31, 201574,709,442 747 (65,301) (1,577) 982,814 (77,159) (73,325) 831,500944,2621,775,762Issuance of Class A commonstock, net of issuance costs12,540,504 125 — — 285,994 — — 286,119 — 286,119Issuance of Class A commonstock under equity incentiveaward plan, net271,705 3 — — (3) — — — — —Repurchase of shares foremployee tax withholding— — (45,663) (923) — — — (923) — (923)Stock-based compensation— — — — 5,391 — — 5,391 — 5,391Dividends declared— — — — (128,502) — — (128,502) — (128,502)Distributions to noncontrollinginterests— — — — — — — — (17,896) (17,896)Other— — — — 66 — — 66 (103) (37)Net loss— — — — — (17,111) — (17,111) (35,188) (52,299)Other comprehensive income,net of tax— — — — — — 10,958 10,958 171 11,129Balances at December 31, 201687,521,651 875 (110,964) (2,500) 1,145,760 (94,270) (62,367) 987,498891,2461,878,744Issuance of Class A commonstock, net of issuance costs10,268,261 103 — — 237,156 — — 237,259 — 237,259Issuance of Class A commonstock under equity incentiveaward plan, net227,948 2 — — (2) — — — — —Repurchase of shares foremployee tax withholding— — (46,848) (1,011) — — — (1,011) — (1,011)Stock-based compensation— — — — 5,322 — — 5,322 — 5,322Dividends declared— — — — (151,503) — — (151,503) — (151,503)Acquisition of Broadview andMeikle— — — — — — — — 390,388 390,388Distributions to noncontrollinginterests— — — — — — — — (20,250) (20,250)Sale of a partial interest inPanhandle 2 to noncontrollinginterests— — — — (2,003) — — (2,003) 56,174 54,171Other— — — — 116 — — 116 (214) (98)Net loss— — — — — (17,905) — (17,905) (64,505) (82,410)Other comprehensive income,net of tax— — — — — — 36,676 36,676 854 37,530Balances at December 31, 201798,017,860 $980 (157,812) $(3,511) $1,234,846 $(112,175) $(25,691) $1,094,449 $1,253,693 $2,348,142See accompanying notes to consolidated financial statements.F-6Pattern Energy Group Inc.Consolidated Statements of Cash Flows(In thousands of U.S. dollars) Year ended December 31, 2017 2016 2015Operating activities Net loss$(82,410)$(52,299) $(55,607)Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation and accretion198,644174,490 143,376Amortization of financing costs7,8716,968 7,435Amortization of debt discount/premium, net4,5834,226 1,660Amortization of power purchase agreements, net3,5093,049 1,946Loss on derivatives16,24322,239 13,440Stock-based compensation5,3225,391 4,462Deferred taxes15,0128,247 4,494Intraperiod tax allocation(3,569) — —Earnings in unconsolidated investments, net(41,299)(30,192) (16,180)Distribution from unconsolidated investments53,93015,015 —Early extinguishment of debt8,643— 4,722Other reconciling items(434) (4,470) 1,221Changes in operating assets and liabilities: Funds deposited by counterparty13,855 (43,635) —Trade receivables(10,342)7,796 (2,254)Prepaid expenses(2,658)709 1,272Other current assets(11,521)(4,300) (2,218)Other assets (non-current)1,9771,379 (2,336)Accounts payable and other accrued liabilities17,643(2,546) 4,716Counterparty deposit liability(13,855)43,635 —Accrued interest5,550 458 4,489Other current liabilities8,570876 515Long-term liabilities21,2226,628 2,696Contingent liabilities822— —Derivatives305——Net cash provided by operating activities217,613163,664 117,849Investing activities Cash paid for acquisitions, net of cash and restricted cash acquired(227,840)(135,778) (422,413)Capital expenditures(43,777)(32,901) (380,458)Distribution from unconsolidated investments13,35841,698 38,240Other assets7,9972,696 5,559Investment in Pattern Development 2.0(68,813)——Other investing activities(3)31 (3)Net cash used in investing activities(319,078)(124,254) (759,075)F-7Pattern Energy Group Inc.Consolidated Statements of Cash Flows(In thousands of U.S. dollars) Year ended December 31, 2017 2016 2015Financing activities Proceeds from public offering, net of issuance costs237,090286,298 317,432Proceeds from issuance of convertible senior notes, net of issuance costs—— 218,929Dividends paid(145,207)(120,207) (90,582)Buyout of noncontrolling interest— — (121,224)Capital contributions - noncontrolling interest—— 336,043Capital distributions - noncontrolling interest(20,250)(17,896) (7,882)Refund of deposit for letters of credit—— 3,425Payment for financing fees(15,886)(542) (13,667)Proceeds from revolving credit facility333,000175,000 405,000Repayment of revolving credit facility(513,000)(350,000) (100,000)Proceeds from construction loans——329,070Proceeds from long-term debt693,735— 164,973Repayment of long-term debt(482,974)(47,634) (785,923)Payment for interest rate derivatives—— Payment for termination of designated derivatives(14,056)—(11,061)Disposition of controlling interest, net57,846——Other financing activities(5,639)(1,682) (860)Net cash provided by (used in) financing activities124,659(76,663) 643,673Effect of exchange rate changes on cash, cash equivalents and restricted cash5,415332 (5,501)Net change in cash, cash equivalents and restricted cash28,609(36,921) (3,054)Cash, cash equivalents and restricted cash at beginning of period109,371146,292 149,346Cash, cash equivalents and restricted cash at end of period$137,980$109,371 $146,292Supplemental disclosures Cash payments for income taxes$335$375 $342Cash payments for interest expense$85,930$69,666 $62,607Schedule of non-cash activities Change in property, plant and equipment$2,071$540 $15,695Change in additional paid-in capital$(2,003)$—$16,715See accompanying notes to consolidated financial statements.F-8Pattern Energy Group Inc.Notes to Consolidated Financial Statements1 . OrganizationPattern Energy Group Inc. (Pattern Energy or the Company) was organized in the state of Delaware on October 2, 2012. Pattern Energy is an independent energygeneration company focused on constructing, owning and operating energy projects with long-term energy sales contracts located in the United States, Canada andChile. Pattern Energy Group LP (Pattern Development 1.0) owns a 7.5% interest in the Company. The Pattern Development Companies (Pattern Development 1.0,Pattern Energy Group 2 LP (Pattern Development 2.0) and their respective subsidiaries) are leading developers of renewable energy and transmission projects.The Company consists of the consolidated operations of certain entities and assets contributed by, or purchased principally from, Pattern Development 1.0, exceptfor purchases of Lost Creek, Post Rock and certain additional interests in El Arrayán (each as defined below, which were purchased from third-parties). Each of theCompany's wind projects and certain assets are consolidated into the Company's subsidiaries which are organized by geographic location as follows:•Pattern US Operations Holdings LLC (which consists primarily of 100% ownership of Hatchet Ridge Wind, LLC (Hatchet Ridge), Spring Valley Wind LLC(Spring Valley), Pattern Santa Isabel LLC (Santa Isabel), Ocotillo Express LLC (Ocotillo), Pattern Gulf Wind LLC (Gulf Wind) and Lost Creek Wind, LLC(Lost Creek), as well as the following consolidated controlling interest in Pattern Panhandle Wind LLC (Panhandle 1), Pattern Panhandle Wind 2 LLC(Panhandle 2), Post Rock Wind Power Project, LLC (Post Rock), Logan's Gap Wind LLC (Logan's Gap), Fowler Ridge IV Wind Farm LLC (Amazon Wind),and Broadview Finco Pledgor LLC ((Broadview Project) (which consists primarily of Broadview Energy KW, LLC and Broadview Energy JN, LLC(together, Broadview) and Western Interconnect LLC, a transmission line (Western Interconnect)));•Pattern Canada Operations Holdings ULC (which consists primarily of 100% ownership of St. Joseph Windfarm Inc. (St. Joseph), a consolidated controllinginterest in Meikle Wind Energy Limited Partnership (Meikle) and noncontrolling interests in South Kent Wind LP (South Kent), Grand Renewable Wind LP(Grand), K2 Wind Ontario Limited Partnership (K2), and SP Armow Wind Ontario LP (Armow) which are accounted for as unconsolidated investments); and•Pattern Chile Holdings LLC (which includes a controlling interest in Parque Eólico El Arrayán SpA (El Arrayán) and a controlling interest in Don GoyoTransmisión S.A. (Don Goyo), a transmission asset of El Arrayán).On July 27, 2017, the Company funded an initial investment of $60 million in Pattern Development 2.0. On December 27, 2017, the Company contributed anadditional $7.3 million to Pattern Development 2.0. As a result of such funding, and the related funding by other investors in Pattern Development 2.0 andconsummation of certain redemptions, the Company holds an approximate 21% ownership interest in Pattern Development 2.0.2 . Summary of Significant Accounting PoliciesBasis of Presentation and Principles of ConsolidationThe accompanying consolidated financial statements have been prepared in accordance with the accounting principles generally accepted in the United States (U.S.GAAP). They include the results of wholly-owned and partially-owned subsidiaries in which the Company has a controlling interest with all significantintercompany accounts and transactions eliminated.Use of EstimatesThe preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amountsof assets and liabilities, disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expensesduring the reporting period. Actual results could differ from those estimates, and such differences may be material to the consolidated financial statements.ReclassificationCertain prior period balances have been reclassified to conform to the current period presentation in the Company’s consolidated financial statements and theaccompanying notes.F-9Cash and Cash EquivalentsCash and cash equivalents consist of cash in banks and highly liquid investments with original maturities of three months or less.Restricted CashRestricted cash consists of cash balances which are restricted as to withdrawal or usage and includes cash to collateralize bank letters of credit related primarily tointerconnection rights, power sale agreements (PSA) and for certain reserves required under the Company’s loan agreements.Reconciliation of Cash and Cash Equivalents and Restricted Cash as presented on the Statements of Cash FlowsThe following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets that sum to the total ofthe same such amounts shown in the consolidated statements of cash flows (in thousands): December 31, 2017 2016 2015 2014Cash and cash equivalents $116,753 $83,932 $94,808 $101,656Restricted cash - current 9,065 11,793 14,609 7,945Restricted cash 12,162 13,646 36,875 39,745Cash, cash equivalents and restricted cash shown in the consolidated statements ofcash flows $137,980 $109,371 $146,292 $149,346Funds Deposited by CounterpartyAs a result of a counterparty's credit rating downgrade, the Company received cash collateral related to an energy derivative agreement, as discussed in Note 10 ,Derivative Instruments . The Company does not have the right to pledge, invest, or use the cash collateral for general corporate purposes. As of December 31, 2017, the Company has recorded a current asset of $29.8 million to funds deposited by counterparty and a current liability of $29.8 million to counterparty depositliability representing the cash collateral received and corresponding obligation to return the cash collateral, respectively. The cash was deposited into a separatecustodial account for which the Company is not entitled to the interest earned on the cash collateral.Trade ReceivablesThe Company’s trade receivables are generated by selling energy and renewable energy credits primarily to creditworthy utilities. The Company believes that allamounts are collectible and an allowance for doubtful accounts is not required as of December 31, 2017 and 2016 .DerivativesThe Company may enter into interest rate swaps, interest rate caps, forwards and other agreements to manage its interest rate, electricity price and foreignexchange rate risk. The Company recognizes its derivative instruments as assets or liabilities at fair value in the consolidated balance sheets, unless the derivativeinstruments qualify for the "normal purchase normal sale" (NPNS) scope exception to derivative accounting.Contracts used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as NPNS. NPNScontracts do not meet the definition of derivatives, and therefore, contracts associated with the sale of energy are recognized as electricity sales and contractsassociated with the production of electricity are recognized as project expense on the consolidated statements of operations.The Company does not have contracts subject to master netting agreements with counterparties, as such assets and liabilities are presented gross on theconsolidated balance sheets. Accounting for changes in the fair value of a derivative instrument depends on whether it has been designated as part of a hedgingrelationship and on the type of hedging relationship. For derivative instruments that qualify and are designated as cash flow hedges, the effective portion of changein fair value of the derivative is reported as a component of other comprehensive income (loss) (OCI), and is reclassified into earnings in the same period orperiods during which the hedged transaction affects earnings. The ineffective portion of change in fair value is recorded as a component of net income (loss) on theconsolidatedF-10statements of operations. The Company discontinues hedge accounting for its cash flow hedges prospectively when it has determined that the hedging relationshiphas materially changed since its inception or when the derivative instrument is no longer considered highly effective at offsetting the hedged risk. If the hedgedtransaction is no longer probable of occurring, any gain or loss previously deferred in OCI will be immediately recognized into earnings. If hedge accounting isdiscontinued for any other reason, any previously deferred gain or loss will remain in OCI and amortized into earnings as the hedged transaction affects futureearnings. For undesignated derivative instruments, the change in fair value is reported as a component of net income (loss) on the consolidated statements ofoperations.Fair Value of Financial InstrumentsAccounting Standards Codification (ASC) 820, Fair Value Measurement , defines fair value as the price at which an asset could be exchanged or a liabilitytransferred in an orderly transaction between knowledgeable, willing parties in the principal or most advantageous market for the asset or liability. Whereavailable, fair value is based on observable market prices or derived from such prices. Where observable prices or inputs are not available, valuation models areapplied which may involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments ormarket and the instruments’ complexity. See Note 12 , Fair Value Measurement .Deferred Financing CostsFinancing costs incurred with securing a construction loan are recorded in the Company’s consolidated balance sheets as an offset to the construction loan andamortized over the contractual life of the loan to construction in progress using the effective interest method. Financing costs incurred with securing a term loan arerecorded in the Company’s consolidated balance sheets as an offset to the term loan and amortized to interest expense in the Company’s consolidated statements ofoperations over the contractual life of the loan using the effective interest method. If the term loan has not been drawn on, financing costs incurred with securingthe term loan are recorded in the Company’s consolidated balance sheets as an asset.Financing costs related to a revolving credit facility or a letter of credit facility are recorded in the Company’s consolidated balance sheets as an asset andamortized to interest expense in the Company’s consolidated statements of operations on a straight-line basis over the contractual term of the arrangement.Construction in ProgressConstruction in-progress represents the accumulation of project development costs and construction costs, including the costs incurred for the purchase of majorequipment such as turbines for which the Company has taken legal title, civil engineering, electrical and other related costs. Other capitalized costs includereclassified deferred development costs, amortization of intangible assets, amortization of deferred financing costs, capitalized interest and other costs required toplace a project into commercial operation. Deferred development costs represent the accumulated costs of initial permitting, environmental reviews, land rights andobligations and preliminary design and engineering work. The Company expenses all project development costs until a project is determined to be technicallyfeasible and likely to achieve commercial success. The Company begins capitalizing deferred development costs as a component of construction in progress on thedate the project commences construction. Once the project achieves commercial operation, the Company reclassifies the amounts recorded in construction inprogress to property, plant and equipment.Property, Plant and EquipmentProperty, plant and equipment represents the costs of completed and operational projects transferred from construction in progress, as well as other costs incurredfor purchasing assets such as land, computer equipment and software, furniture and fixtures, leasehold improvements and other equipment. Property, plant andequipment are stated at cost, less accumulated depreciation. Depreciation is calculated using the straight-line method over the respective assets’ useful lives. Windfarms for which construction began before 2011 are depreciated over 20 years and wind farms for which construction began after 2011 are depreciated over 25years . Transmission assets are depreciated over 50 years . The remaining assets are depreciated over two to five years. Improvements to property, plant andequipment deemed to extend the useful economic life of an asset are capitalized. Repair and maintenance costs are expensed as incurred.Finite-Lived Intangible Assets and Intangible LiabilityFinite-lived intangible assets and intangible liability primarily include power purchase agreements (PPAs), land easements, land options, tax savings and miningrights. PPAs obtained through acquisitions are valued at the time of acquisition and the difference between the contract price and the estimated fair value results inan intangible asset or an intangible liability. If the contract price is higher than the estimated fair value, the Company will recognize an intangible asset. If thecontract price is lower than the estimated fair value, theF-11Company will recognize an intangible liability. Land easements, land options and mining rights are recognized at the carryover basis from the seller as theseamounts approximate fair value.The Company generally amortizes its finite-lived intangible assets and intangible liability using the straight-line method over the remaining term of the relatedPPA. The Company amortizes land easements, land options, tax savings and mining rights using the straight-line method over the term of their estimated usefullives, which represents the term of the land easements, land option, tax savings and mining rights agreements, ranging from approximately 12 - 51 years. TheCompany periodically evaluates whether events or changes in circumstances have occurred that indicate the carrying amount of finite-lived intangible assets maynot be recoverable, or information indicates that impairment may exist.Accounting for Impairment of Long-Lived AssetsThe Company periodically evaluates long-lived assets for potential impairment whenever events or changes in circumstances have occurred that indicate thatimpairment may exist, or the carrying amount of the long-lived asset may not be recoverable. An impairment loss is recognized only if the carrying amount of along-lived asset is not recoverable based on its estimated future undiscounted cash flows. An impairment loss is calculated based on the excess of the carryingvalue of the long-lived asset over the fair value of such long-lived asset, with the fair value determined based on an estimate of discounted future cash flows. Therewas no impairment for the year ended December 31, 2017.Variable Interest EntitiesVariable interest entities (VIEs) are entities that do not qualify for a scope exception from the variable interest model and are therefore subject to consolidationunder the variable interest model. An entity is considered to be a VIE if (1) the entity does not have enough equity to finance its own activities without additionalsupport, (2) the entity’s at-risk equity holders lack the characteristics of a controlling financial interest, or (3) the entity is structured with non-substantive votingrights. ASC 810, Consolidation , defines the criteria for determining the existence of VIEs and provides guidance for consolidation. The Company consolidatesVIEs where the Company is the primary beneficiary. The primary beneficiary of a VIE is the party that has the power to direct the activities that most significantlyimpact the performance of the entity and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the entity.To the extent the entity does not meet the definition of a VIE, the ASC 810 guidance for voting interest entities (VOEs) is applied. The usual condition for acontrolling financial interest, and therefore consolidation by the Company, is ownership of a majority voting interest of a corporation or a majority of kick-outrights for a limited partnership.To the extent the entity is not consolidated under the VIE or VOE models, the Company will use the equity method of accounting. These amounts are included inunconsolidated investments in the consolidated balance sheets.AcquisitionsOn July 1, 2017, the Company adopted Accounting Standards Update (ASU) 2017-01, Clarifying the Definition of a Business (ASU 2017-01) which provides ascreen to determine when a set of assets and activities should not be considered a business. Under ASU 2017-01, the Company will set up an initial screening testthat, if met, results in the conclusion that the set is not a business. If the initial screening test is not met, the Company evaluates whether the set is a business basedon whether there are inputs and a substantive process in place. The definition of a business impacts whether the Company consolidates an acquisition underbusiness combination guidance or asset acquisition guidance. When the Company's acquisition is recognized as an equity method investment, the definition of abusiness impacts whether equity method goodwill can be recognized.Business CombinationsThe Company accounts for its business combinations by recognizing the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in theacquiree at the acquisition date. The purchase is accounted for using the acquisition method, and the fair value of purchase consideration is allocated to the tangibleand intangible assets acquired and the liabilities assumed, based on their estimated fair values. Contingent consideration is also recognized and measured at fairvalue as of the acquisition date. The excess, if any, of the fair value of the purchase consideration over the fair values of the identifiable net assets is recorded asgoodwill. Conversely, the excess, if any, of the net fair values of the identifiable net assets over the fair value of the purchase consideration is recorded as a gain.Such valuations require management to make significant estimates and assumptions, especially with respect to intangible assets. These estimates and assumptionsare inherently uncertain, and as a result, actual results may differ from estimates. Significant estimates include, but are not limited to, future expected cash flows,useful lives and discount rates. During the measurement period, which is oneF-12year from the acquisition date, we may record adjustments to the assets acquired and liabilities assumed, with a corresponding offset to either goodwill or gain,depending on whether the fair value of purchase consideration is in excess of or less than net assets acquired. Upon the conclusion of the measurement period, anysubsequent adjustments are recorded to earnings. Transaction costs associated with business combinations are expensed as incurred.Asset AcquisitionsWhen the Company acquires assets and liabilities that do not constitute a business, the fair value of the purchase consideration, including the transaction costs ofthe asset acquisition, is assumed to be equal to the fair value of the net assets acquired. The purchase consideration, including the transaction costs, is allocated tothe individual assets and liabilities assumed based on their relative fair values. Contingent consideration associated with the acquisition is generally recognizedonly when the contingency is resolved. No goodwill is recognized in an asset acquisition. Transaction costs associated with asset acquisitions are capitalized as partof the costs of the group of assets acquired.Equity Method InvestmentsWhen the Company acquires a noncontrolling interest in an entity where it is not the primary beneficiary, does not control any of the ongoing activities of theentity, and does not meet consolidation requirements of ASC 810 and ASU 2015-02 , the investment is initially recognized as an equity method investment at cost.Any difference between the cost of an investment and the amount of underlying equity in net assets of an investee are considered basis differences. Basisdifferences related to the property, plant and equipment will be amortized over the estimated economic useful life of the underlying long-lived assets while basisdifferences related to the PPA will be amortized over the remaining term of the PPA. Transactions costs associated with equity method investments are included inthe investment.When the Company receives distributions in excess of the carrying value of its investment, and the Company is not liable for the obligations of the investee norotherwise committed to provide financial support, the Company recognizes such excess distributions as equity method earnings in the period the distributionsoccur. Additionally, when the Company's carrying value in an unconsolidated investment is zero and the Company is not liable for the obligations of the investeenor otherwise committed to provide financial support, the Company will not recognize equity in earnings (losses) or equity in other comprehensive income ofunconsolidated investments. When the investee subsequently reports income, the Company does not record its share of such income until it equals the amount ofdistributions in excess of the carrying value that were previously recognized in income and previously unrecognized losses. During the years ended December 31,2017, 2016 and 2015, the Company had no such obligations, commitments or requirements to provide additional funding to its unconsolidated investments.As a result, equity income or loss reported on the Company's income statement for certain unconsolidated investments may differ from a mathematical calculationof net income or loss attributable to the Company's equity interest based upon the factor of its equity interest and the net income or loss attributable to equityowners as shown on investee companies' income statements.To the extent that cumulative comprehensive income exceeds cumulative distributions received, the Company records the distribution as distributions fromunconsolidated investments on the Company's consolidated statements of cash flows within operating cash flows. All other distributions are recorded asdistributions from unconsolidated investments on the Company's consolidated statements of cash flows within investing activities.Noncontrolling InterestsNoncontrolling interests represent the portion of the Company’s net income (loss), net assets and comprehensive income (loss) that is not allocable to the Companyand is calculated based on ownership percentage, for applicable projects.For the noncontrolling interests in the Company’s Panhandle 1, Panhandle 2, Post Rock, Logan's Gap, Amazon Wind, and Broadview Holdings, the Company hasdetermined that the operating partnership agreements do not allocate economic benefits pro rata to its two classes of investors and the appropriate methodology forcalculating the noncontrolling interest balance that reflects the substantive profit sharing arrangement is a balance sheet approach using the hypothetical liquidationat book value (HLBV) method.Under the HLBV method, the amounts reported as noncontrolling interest in the consolidated balance sheets and consolidated statements of operations representthe amounts the third party would hypothetically receive at each balance sheet reporting date under the liquidation provisions of the operating partnershipagreement assuming the net assets of the projects were liquidated at recorded amounts determined in accordance with U.S. GAAP and distributed to the investors.The noncontrolling interest in the results of operations and comprehensive income (loss) is determined as the difference in noncontrolling interests in theconsolidated balance sheets at the start and end of eachF-13reporting period, after taking into account any capital transactions between the projects and the third party. The noncontrolling interest balances in the projects arereported as a component of equity in the consolidated balance sheets.Asset Retirement ObligationThe Company records asset retirement obligations (AROs) for the estimated costs of decommissioning turbines, removing above-ground installations and restoringsites, at the time when a contractual decommissioning obligation is incurred. AROs represent the present value of the expected costs and timing of the relateddecommissioning activities. The ARO assets and liabilities are recorded in property, plant and equipment and other long-term liabilities, respectively, in theconsolidated balance sheets. The Company records accretion expense, which represents the increase in the asset retirement obligations, over the remaining oroperational life of the associated wind project. Accretion expense is recorded as cost of revenue in the consolidated statements of operations using accretion ratesbased on credit adjusted risk-free interest rates. Changes resulting from revisions to the timing or amount of the original estimate of cash flows are recognized as anincrease or a decrease in the asset retirement cost, or income when the asset retirement cost is depleted.Contingent LiabilitiesContingent obligations that are acquired through business combinations are initially recorded at fair value on the date of acquisition while contingent obligationsthat are acquired through asset acquisitions are recorded when the contingency is resolved. Subsequent to the initial recognition of contingent obligationsaccounted for as a business combination, the Company accounts for these contingent obligations in a systematic and rational method in accordance with ASC 450,Contingencies.The Company’s contingent liabilities related to turbine availability warranties with turbine manufacturers and turbine availability guarantees associated with long-term turbine service arrangements are reported at net realizable value. Pursuant to these warranties and guarantees, if a turbine operates at less than minimumavailability during the warranty or guarantee period, the manufacturer or service provider is obligated to pay, as liquidated damages, an amount for each percentthat the turbine operates below the minimum availability threshold at the end of the warranty period. However, the Company does not recognize liquidateddamages that remain contingent until the end of the warranty period. In addition, pursuant to certain of these warranties and guarantees, if a turbine operates atmore than a specified availability during the warranty or guarantee period, the Company has an obligation to pay a bonus to the turbine manufacturer or serviceprovider at the end of the warranty period. The Company records contingent liabilities at each reporting period associated with these bonuses expected to be paid atthe end of the warranty period.Concentrations of Credit RiskFinancial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents, trade receivables,reimbursable interconnection costs and derivative instruments. The Company’s cash and cash equivalents are with high quality institutions. The Company hasexposure to credit risk to the extent cash and cash equivalent balances, including restricted cash, exceed amounts covered by federal deposit insurance; however,the Company believes that its credit risk is immaterial. In addition, reimbursable interconnection costs are with large creditworthy utility companies and theCompany’s derivative instruments are placed with counterparties that are creditworthy institutions. The Company generally does not require collateral.The Company sells electricity and renewable energy credits (RECs) primarily to creditworthy utilities under long-term, fixed-priced PSAs. During the year endedDecember 31, 2017 , Standard & Poor’s Rating Service's credit rating of the Puerto Rico Electric Power Authority (PREPA) remained unchanged at D. ThroughDecember 31, 2017 , Moody’s Investor Service’s credit rating of PREPA changed from Caa3 to Ca.The table below presents significant customers who accounted for greater than 10% of total revenue and PREPA, and the related maximum amount of credit lossbased on their percentages of total trade receivables as of December 31, 2017 , 2016 and 2015 : Year ended December 31, 2017 2016 2015 Revenue TradeReceivables Revenue TradeReceivables Revenue TradeReceivablesSan Diego Gas & Electric13.4% 6.4% 14.6% 5.1% 17.1% 16.6%Morgan Stanley Capital Group Inc.9.1% 3.3% 10.9% 4.4% 5.9% 7.8%PREPA4.2% 4.9% 6.0% 6.1% 8.4% 8.6%F-14Revenue RecognitionThe Company sells electricity and related RECs under the terms of PSAs, PPAs or at market prices. Revenue is recognized based upon the amount of electricitydelivered at rates specified under the contracts, or at market prices for spot market transactions, assuming all other revenue recognition criteria are met. Whenrenewable energy credits are sold as a separate component, revenue is recognized at the time title to the energy credits is transferred to the buyer. Depending on theterms of the PSA, the Company may account for the contracts as operating leases pursuant to ASC 840, Leases (ASC 840), or derivative instruments pursuant toASC 815, Derivatives and Hedging (ASC 815). In considering ASC 840, it was determined that certain of the Company's PPAs are operating leases. ASC 840,requires minimum lease payments to be recognized over the term of the lease and contingent rents to be recorded when the achievement of the contingencybecomes probable. All energy sales under the PPAs, which are considered leases, are contingent rent due to the inherent uncertainty and variability associated witha fuel source (i.e., wind) that is outside the control of the parties to the PPA . None of the operating leases have minimum lease payments; therefore, revenue fromthese contracts and any related renewable energy attributes are recognized as electricity sales when delivered. Contingent rents for the years ending December 31,2017, 2016 and 2015 were $316.5 million , $262.4 million and $252.0 million , respectively. Contracts that meet the NPNS scope exception to derivativeaccounting are accounted for under the accrual method, where revenues are recorded in the period they are earned.Energy derivative instruments that reduce exposure to changes in commodity prices may allow the Company to lock in a fixed price per megawatt hour (MWh) fora specified amount of annual electricity generation over the life of the swap contract. Monthly settlement amounts under energy hedges are accounted for as energyderivative settlements in the consolidated statements of operations. Changes in the fair value of energy hedges are recorded in electricity sales in the consolidatedstatements of operations.The Company recognizes revenue for warranty settlements in other revenue upon resolution of outstanding contingencies. Any cash receipts for amounts subject tofuture adjustment or repayment are deferred in other liabilities until the final settlement amount is considered fixed and determinable.Cost of RevenueThe Company’s cost of revenue is comprised of direct costs of operating and maintaining its wind project facilities, including labor, turbine service arrangements,land lease royalties, depreciation, accretion, property taxes and insurance.Stock-Based CompensationThe Company accounts for stock-based compensation related to stock options granted to employees by estimating the fair value of the stock-based awards usingthe Black-Scholes option-pricing model. The Black-Scholes option pricing model includes assumptions regarding dividend yields, expected volatility, expectedoption term, and risk-free interest rates. Expense is recognized by amortizing the fair value of the stock options granted using a straight-line method over theapplicable vesting period. The Company estimates expected volatility based on the historical volatility of comparable publicly traded companies for a period that isequal to the expected term of the options. The risk-free interest rate is based on the U.S. treasury yield curve in effect at the time of grant for a periodcommensurate with the estimated expected term of the stock option. The expected term of options granted is derived using the "simplified" method as allowedunder the provisions of the ASC 718, Compensation—Stock Compensation, and represents the period of time that options granted are expected to be outstanding.The Company accounts for stock-based compensation related to restricted stock award grants and restricted stock unit grants by amortizing the fair value of therestricted stock award grants, which is the grant date market price, over the applicable vesting period. For certain restricted stock award grants, the Companymeasures the fair value at the grant date using a Monte Carlo simulation model and amortizes the fair value over the longer of the requisite period or performanceperiod. The Monte Carlo simulation model includes assumptions regarding dividend yields, expected volatility, risk-free interest rates and initial total shareholderreturn (TSR) performance.With the adoption of ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), the Company accounts for forfeitures as they occur. Stock-based compensation expense is recorded as a component of general and administrative expenses inthe Company’s consolidated statements of operations.Income TaxesThe Company accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expectedfuture tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined on thebasis of the differences between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differencesare expected to reverse. The effect of a change in taxF-15rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The Company recognizes deferred tax assets to theextent that it believes these assets are more likely than not to be realized. In making such a determination, the Company considers all available positive andnegative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning and results of recentoperations. If the Company determines that it would be able to realize its deferred tax assets in the future in excess of their net recorded amount, it would make anadjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes. The Company records uncertain tax positions inaccordance with ASC 740, Income Taxes, on the basis of a two-step process whereby (1) it determines whether it is more likely than not that the tax positions willbe sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, itrecognizes the largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority. The Company has apolicy to classify interest and penalties associated with uncertain tax positions together with the related liability, and the expenses incurred related to such accruals,if any, are included in the provision for income taxes.Comprehensive Income (Loss)Comprehensive income (loss) consists of net income (loss) and other comprehensive income (loss), net of tax. Other comprehensive income (loss), net of taxincluded in accumulated other comprehensive income (loss) in the consolidated statements of stockholders’ equity, is comprised primarily of changes in foreigncurrency translation adjustments and the effective portion of changes in the fair value of derivatives designated as cash flow hedges.Foreign Currency TranslationThe assets and liabilities of foreign subsidiaries, where the local currency is the functional currency, are translated from their respective functional currencies intoU.S. dollars at the rates in effect at the balance sheet date and revenue and expense amounts are translated at average rates during the period, with resulting foreigncurrency translation adjustments recorded in other comprehensive income (loss), net of tax, in the consolidated statements of stockholders’ equity andcomprehensive income (loss). Where the U.S. dollar is the functional currency, re-measurement adjustments are recorded in other (expense) income, net in theaccompanying consolidated statements of operations.Segment Data and Geographic InformationSegment dataOperating segments are defined as components of a company about which separate financial information is available that is evaluated regularly by the chiefoperating decision maker in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is the chief executiveofficer. Based on the financial information presented to and reviewed by the chief operating decision maker in deciding how to allocate the resources and inassessing the Company’s performance, the Company has determined its wind projects represent individual operating segments with similar economiccharacteristics that meet the criteria for aggregation into a single reporting segment for financial statement purposes.Geographic informationThe table below provides information, by country, about the Company’s consolidated operations. Revenue is recorded in the country in which it is earned andassets are recorded in the country in which they are located (in thousands): Revenue Property, Plant and Equipment, net Year ended December 31, December 31, 2017 2016 2015 2017 2016United States $315,642 $285,187 $258,542 $3,121,387 $2,652,122Canada 62,063 39,207 39,178 550,183 177,093Chile 33,639 29,658 32,111 293,551 305,947Total $411,344 $354,052 $329,831 $3,965,121 $3,135,162Recently Adopted Accounting StandardsIn January 2017, the FASB issued ASU 2017-01, which provides a screen to determine when a set of assets and activities is not a business. The screen requires thatwhen substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a singleF-16identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated.ASU 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those periods, with early application permitted.The Company adopted ASU 2017-01 on July 1, 2017. The adoption of ASU 2017-01 resulted in the acquisition of Meikle being accounted for as an assetacquisition.In March 2016, the FASB issued ASU 2016-09, which simplifies several aspects of the accounting for share-based payment award transactions, including theincome tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 is effective forannual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company adopted ASU 2016-09, effective January 1,2017. The adoption of ASU 2016-09 did not have a material impact on the Company’s consolidated financial statements and related disclosures.Recently Issued Accounting Standards Not Yet AdoptedIn February 2018, the FASB issued ASU 2018-02, Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects fromAccumulated Other Comprehensive Income (ASU 2018-02). ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated other comprehensiveincome (loss) to retained earnings as a result of the U.S. government enacted the Tax Cuts and Jobs Act in December 2017 (Tax Act). ASU 2018-02, is to beapplied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the United States federal corporate incometax rate in the Tax Act is recognized. ASU 2018-02 is effective for annual periods, and interim periods within those annual periods, beginning after December 15,2018. Early adoption is permitted. The Company is currently assessing the future impact of this update on its consolidated financial statements and relateddisclosures.In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), which amends the presentationand disclosure requirements and changes how companies assess effectiveness. The amendments are intended to more closely align hedge accounting withcompanies’ risk management strategies, simplify the application of hedge accounting, and increase transparency as to the scope and results of hedging programs.ASU 2017-12 is effective for annual periods beginning after December 15, 2018, including interim periods within those periods. Early application is permitted.The Company is currently assessing the future impact of this update on its consolidated financial statements and related disclosures.In June 2016, the FASB issued ASU 2016-13, Financial Instruments —Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments(ASU 2016-13), which requires the measurement of all expected credit losses for financial assets including trade receivables held at the reporting date based onhistorical experience, current conditions, and reasonable and supportable forecasts. ASU 2016-13 is effective for fiscal years, and interim periods within thosefiscal years, beginning after December 15, 2019. The adoption of ASU 2016-13 is not expected to have a material impact on its consolidated financial statementsand related disclosures.In February 2016, the FASB issued ASU 2016-02, Leases (ASU 2016-02), which requires lessees to recognize right-of-use assets and lease liabilities, for allleases, with the exception of short-term leases, at the commencement date of each lease. Under the new guidance, lessor accounting is largely unchanged. ASU2016-02 simplifies the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and liabilities. ASU 2016-02 iseffective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. Early adoption is permitted. The amendments ofthis update should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of theearliest period presented. The Company is in the initial stages of evaluating the impact of the new standard on its accounting policies, processes and systemrequirements. The Company is also assessing the accounting impact of the ASU 2016-02 as it applies to its PPAs, land leases, office leases and equipment leases.As the Company progresses further in its analysis, the scope of this assessment could be expanded to review other types of contracts. The Company will adoptASU 2016-02 beginning January 1, 2019.In the first quarter of 2018, the Company will adopt ASC Topic 606 , Revenue from Contracts with Customers, which supersedes ASC Topic 605, RevenueRecognition (ASU 2014-09). The new standard replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. Thecore principle of the new standard is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount thatreflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the new standard requires the entity todisclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as otherinformation about the significant judgments and estimates used in recognizing revenues from contracts with customers.The new standard permits adoption by either using (i) the full retrospective approach for all periods presented in the period of adoption or (ii) a modifiedretrospective approach with the cumulative effect of initially applying the new standard recognized at the date of initial application and providing certain additionaldisclosures. The Company will adopt these updates beginning with the first quarter of its fiscal year 2018 and anticipates doing so using the modified retrospectivemethod. The Company is in the process of finalizing itsF-17evaluation of the impact of the adoption of ASU 2014-09 on historical contracts and other arrangements. The Company’s assessment efforts to date have includedidentification of revenue streams from its contracts with customers, reviewing current accounting policies and drafting revised accounting policies affected by thestandard, assessing the redesign of internal controls, processes, and systems requirements, as well as assigning internal resources and engaging third-partyconsultants to assist in the process. Additionally, the Company has reviewed historical contracts and other arrangements to identify potential differences that couldarise from the adoption of ASU 2014-09 and evaluated the expanded disclosure requirements. As a result of the review of revenue arrangements, the Company isevaluating its current conclusions with respect to the impact of certain pricing structures on the timing of revenue recognition. The Company is also continuing toassess the potential effects that this new standard and its anticipated adoption of ASU 2016-02, as discussed above, may have on its consolidated financialstatements as it relates to PSAs accounted for as leases and its leasing arrangements with landowners.In September 2017, the Financial Accounting Standards Board (FASB) issued ASU 2017-13, Revenue Recognition (Topic 605), Revenue from Contracts withCustomers (Topic 606), Leases (Topic 840), and Leases (Topic 842): Amendments to SEC Paragraphs Pursuant to the Staff Announcement at the July 20, 2017EITF Meeting and Rescission of Prior SEC Staff Announcements and Observer Comments (ASU 2017-13), which amends the early adoption date option for certaincompanies related to the adoption of ASU 2014-09 and ASU 2016-02. The SEC staff stated the SEC would not object to a public business entity that otherwisewould not meet the definition of a public business entity except for a requirement to include or the inclusion of its financial statements or financial information inanother entity’s filing with the SEC adopting Topic 606 and Topic 842 using the adoption dates available for non-public entities. Certain of the Company'sunconsolidated investments, for which the Company may be required to include in its Form 10-K, have elected to utilize the adoption date available for non-publicentities. The Company does not expect their adoption of this update to have a material impact on its consolidated financial statements and related disclosures.3 . AcquisitionsBusiness CombinationsBroadview Project AcquisitionOn April 21, 2017, pursuant to a Purchase and Sale Agreement with Pattern Development 1.0, the Company acquired a 100% ownership interest in BroadviewProject which indirectly owns both 100% of the Class B membership interest in Broadview Energy Holdings LLC (Broadview Holdings) and a 99% ownershipinterest in Western Interconnect, a 35 -mile 345 kV transmission line. Broadview Holdings owns 100% ownership interests that comprise the 324 MW Broadviewwind power projects, which achieved commercial operations in the first quarter of 2017. The acquisition is in alignment with the Company's growth strategy toexpand its portfolio of generating projects. The Company's indirect Class B membership interest in Broadview Holdings represents an 84% interest in initialdistributable cash flow from Broadview. Consideration consisted of $214.7 million of cash, a $2.4 million assumed liability and a post-closing payment ofapproximately $21.3 million contingent upon the commercial operation of the Grady Project (as defined below). As part of the acquisition, the Company alsoassumed $51.2 million of construction debt and related accrued interest outstanding at Western Interconnect which was immediately extinguished, andconcurrently the Company entered into a variable rate term loan for $54.4 million . The Grady Wind Energy Center, LLC (the Grady Project) is a wind powerproject on the identified right of first offer projects (identified ROFO Projects) list being developed by Pattern Development 2.0 separately from Broadview, whichis expected to begin full construction in 2018, and which will be interconnected through Western Interconnect. Following the commencement of commercialoperations of the Grady Project, at which time the Grady Project will begin making transmission service payments to Western Interconnect, the Company willmake the aforementioned contingent post-closing payment.The identifiable assets, operating contracts and liabilities assumed for the Broadview Project were recorded at their fair values, which corresponded to the sum ofthe cash purchase price, contingent consideration payment, and the fair value of the other investors' noncontrolling interests.F-18The fair values are as follows (in thousands):April 21, 2017Cash and cash equivalents$3,022Trade receivables3,259Prepaid expenses187Other current assets9,830Restricted cash44,383Deferred financing costs, net1,890Property, plant and equipment627,502Intangible assets22,346Accounts payable and other accrued liabilities(2,956)Accrued interest(108)Long-term debt, current portion(51,053)Accrued construction costs(38,814)Related party payable(674)Contingent liability(36,205)Asset retirement obligation(6,296)Other long-term liabilities(12,350)Total consideration before non-controlling interest563,963Less: noncontrolling interests(325,600)Total consideration$238,363Current assets, non-current restricted cash, accounts payable, other accrued liabilities, accrued interest, accrued construction costs, related party payable andcurrent portion of long-term debt were recorded at carrying value, which was representative of the fair value on the date of acquisition. Property, plant andequipment, finite-lived intangible assets, contingent liabilities and long-term liabilities were recorded at fair value estimated using the cost and income approach.The fair value of asset retirement obligations was recorded at fair value using a combination of market data, operational data and discounted cash flows and wasadjusted by a discount rate factor reflecting current market conditions at the time of acquisition.Concurrent with the closing, certain tax equity investors made capital contributions to acquire 100% of the Class A membership interests in Broadview Holdingsand have been admitted as noncontrolling members in the entity, with a 16% initial interest in the distributable cash flow from Broadview. The noncontrollinginterest was recorded at fair value estimated using the purchase price from the purchase agreement executed on April 21, 2017 among the Company and the taxequity investors.The Company recorded a $7.2 million contingent obligation, payable to a third party who holds a 1% interest in Western Interconnect, at fair value upon theacquisition of the Broadview Project. These contingent payments are subject to certain conditions, including the actual energy production of Broadview in aproduction year and the continued operation of Broadview. Additionally, the Company recorded a $29.0 million contingent obligation, payable to the samecounterparty, at fair value upon the acquisition of the Broadview Project. These contingent payments are subject to certain conditions, including the commercialoperation of the Grady Project. The contingent payment is calculated as a percentage of additional transmission revenue earned by Western Interconnect upon theGrady Project's commercial operation.The Broadview Project acquisition includes contingent consideration, which requires the Company to make an additional payment upon the commercial operationof the Grady Project. See Note 12, Fair Value Measurement for further discussion on the fair value of the contingent consideration.The Company incurred transaction-related expense of $0.4 million which were recorded in net loss on transactions in the consolidated statements of operations forthe year ended December 31, 2017 .The fair value estimates for the assets acquired and liabilities assumed were based on preliminary calculations and valuations, and the estimates and assumptionsare subject to change as additional information is obtained for the estimates during the measurement period (up to one year from the acquisition date). During theyear ended December 31, 2017, the Company adjusted the initial valuation andF-19decreased property, plant and equipment by $1.0 million , decreased accrued construction costs by $1.3 million and increased asset retirement obligations by $0.3million . These changes are a result of the updated inputs, assumptions and methodologies used in determining the fair value of these assets and liabilities. Theaccounting for this acquisition is final as of December 31, 2017.The Company has determined that the operating partnership agreement does not allocate economic benefits pro rata to its two classes of investors for Broadviewand will use the HLBV method to calculate the noncontrolling interest balance that reflects the substantive profit sharing arrangement.Wind Capital Group AcquisitionOn May 15, 2015, pursuant to a Purchase and Sale Agreement, the Company acquired 100% of the membership interests in Lost Creek Wind Finco, LLC (LostCreek Finco) from Wind Capital Group LLC, an unrelated third party, and 100% of the membership interests in Lincoln County Wind Project Holdco, LLC(Lincoln County Holdco) from Lincoln County Wind Project Finco, LLC, an unrelated third party. Lost Creek Finco owns 100% of the Class B membershipinterests in Lost Creek Wind Holdco, LLC (Lost Creek Wind Holdco), a company which owns a 100% interest in the Lost Creek wind project. Lincoln CountyHoldco owns 100% of the Class B membership interests in Post Rock Wind Power Project, LLC, a company which owns a 100% interest in the Post Rock windproject. The acquisition of 100% of the membership interests in Lost Creek Finco and Lincoln County Holdco was for an aggregate consideration of approximately$242.0 million , paid at closing. The Company also assumed certain project level indebtedness and ordinary course performance guarantees securing projectobligations. Lost Creek is a 150 megawatt (MW) wind project in King City, Missouri, and Post Rock is a 201 MW wind project in Ellsworth and Lincoln Counties,Kansas.The Company acquired assets and operating contracts for Lost Creek and Post Rock, including assumed liabilities. The identifiable assets and liabilities assumedwere recorded at their fair values, which corresponded to the sum of the cash purchase price and the fair value of the other investors’ noncontrolling interests. Theaccounting for the Lost Creek and Post Rock acquisition was completed as of March 31, 2016 at which point the fair values became final. The fair value of theassets acquired and liabilities assumed in connection with the acquisition are as follows (in thousands): May 15, 2015Cash and cash equivalents$3,501Restricted cash, current11,787Trade receivables7,910Prepaid expenses1,232Other current assets444Restricted cash4,592Property, plant and equipment543,347Finite-lived intangible assets97,400Other assets17,632Accounts payable and other accrued liabilities(2,611)Accrued interest(951)Derivative liabilities, current(3,759)Current portion of long-term debt, net of financing costs(7,463)Finite-lived intangible liabilities(60,300)Asset retirement obligations(7,192)Long-term debt, net of financing costs(108,838)Derivative liabilities(14,631)Total consideration before temporary equity and noncontrolling interests482,100Less: temporary equity(35,000)Less: noncontrolling interests(205,100)Total consideration after temporary equity and noncontrolling interests$242,000Current assets, non-current restricted cash, accounts payable and other accrued liabilities and accrued interest were recorded at carrying value, which isrepresentative of the fair value on the date of acquisition. Property, plant and equipment, finite-lived intangible asset, finite-lived intangible liability and debt wererecorded at fair value estimated using the income approach. The fair values of other assets, derivatives and asset retirement obligations were recorded at fair valueusing a combination of market data, operational data and discounted cash flows and were adjusted by a discount rate factor reflecting current market conditions atthe time of acquisition.F-20The noncontrolling interest in Post Rock was recorded at fair value estimated using a projected cash flow stream of distributable cash and tax benefits anticipatedbased on the existing Partnership Agreement, discounted to present value with a discount rate reflecting the estimated return on investment required by participantsin the tax equity market. The noncontrolling interest in Lost Creek was recorded at fair value estimated using the purchase price from a purchase agreementexecuted on May 15, 2015 between the Company and the tax equity investor.The Company incurred transaction-related expenses of $1.7 million which were recorded in net gain (loss) on transactions in the consolidated statements ofoperations for the year ended December 31, 2015.On July 30, 2015, the Company acquired 100% of the Class A membership interests in Lost Creek Wind Holdco for a cash purchase price of approximately $35.2million . As a result, Lost Creek became wholly owned as of July 30, 2015.The Company has determined that the operating partnership agreement does not allocate economic benefits pro rata to its two classes of investors and will use theHLBV method to calculate the noncontrolling interest balance that reflects the substantive profit sharing arrangement.Supplemental pro forma data (unaudited)Broadview reached commercial operations in March 2017 and until approximately three weeks before acquisition, Broadview was still under construction.Therefore, pro forma data for Broadview has not been provided as there is no material difference between pro forma data that give effect to the Broadview Projectacquisition as if it had occurred on January 1, 2016 and actual data reported for the years ended December 31, 2017 and 2016.The unaudited pro forma statement of operations data below gives effect to the Lost Creek and Post Rock acquisitions, as if they had occurred on January 1, 2014.The pro forma net loss for the year ended December 31, 2015 was adjusted to exclude nonrecurring transaction related expenses of $1.7 million . The unauditedpro forma data is presented for illustrative purposes only and is not intended to be indicative of actual results that would have been achieved had these acquisitionsbeen consummated as of January 1, 2014. The unaudited pro forma data should not be considered representative of the Company’s future financial condition orresults of operations. Year endedDecember 31,Unaudited pro forma data (in thousands)2015Pro forma total revenue$351,094Pro forma total expenses411,746Pro forma net loss(60,652)Less: pro forma net loss attributable to noncontrolling interest(29,091)Pro forma net loss attributable to Pattern Energy$(31,561)The following table presents the amounts included in the consolidated statements of operations for Lost Creek and Post Rock from their respective dates ofacquisition through December 31, 2015 and for the Broadview Project from its date of acquisition through December 31, 2017: Year ended December 31,Unaudited data (in thousands)2017 2015Total revenue$33,073 $31,093Total expenses50,225 34,574Net loss(17,152) (3,481)Less: net loss attributable to noncontrolling interest(17,315) (5,114)Net loss attributable to Pattern Energy$163 $1,633Asset AcquisitionMeikleOn August 10, 2017, pursuant to a Purchase and Sale Agreement by and among the Company, Pattern Development 1.0, and Public Sector Pension InvestmentBoard (PSP Investments), the Company acquired 50.99% of the limited partner interests in Meikle and 70% of theF-21issued and outstanding shares of Meikle Wind Energy Corp. (Meikle Corp) for a purchase price of $67.4 million, paid at closing, in addition to $1.1 million ofcapitalized transaction-related expenses. PSP Investments acquired 48.99% of the limited partner interest in Meikle and 30% of the issued and outstanding sharesof Meikle Corp for a purchase price of $64.8 million . Meikle operates the approximately 179 MW wind farm located in the Peace River Regional District ofBritish Columbia, Canada, which achieved commercial operations in the first quarter of 2017.The fair value of the purchase consideration, including transaction-related expenses of the asset acquisition, and fair value of the noncontrolling interest is allocatedto the relative fair value of the individual assets, operating contracts and liabilities assumed. The noncontrolling interest was recorded at fair value estimated usingthe purchase price paid by PSP Investments pursuant to the Purchase and Sale Agreement. The fair value of the assets acquired and liabilities assumed inconnection with the Meikle acquisition are as follows (in thousands): August 10, 2017Cash and cash equivalents$3,865Trade receivables5,432Prepaid expenses1,194Deferred financing costs, current36Other current assets432Restricted cash6,808Deferred financing costs726Property, plant and equipment375,717Finite lived intangible asset29,287Other assets80Accounts payable and other accrued liabilities(4,676)Accrued construction costs(1,762)Related party payable(96)Accrued interest(1,180)Derivative liabilities, current(1,980)Current portion of long-term debt(7,291)Long-term debt, net(258,303)Derivative liabilities, noncurrent(13,198)Other long-term liabilities(1,816)Total consideration before non-controlling interest133,275Less: noncontrolling interests(64,789)Total consideration$68,486F-22Unconsolidated InvestmentsPattern Development 2.0Under the Second Amended and Restated Agreement of Limited Partnership of Pattern Development 2.0 (A&R LPA), the Company has the right to contribute upto $300.0 million to Pattern Development 2.0 in one or more subsequent rounds of financing. On July 27, 2017, the Company funded an initial $60.0 millioncapital call and on December 26, 2017, the Company funded an additional $7.3 million capital call. As a result of such funding, and the related funding by otherinvestors in Pattern Development 2.0 and consummation of certain redemptions, the Company holds an approximate 21% ownership interest in PatternDevelopment 2.0 as of December 31, 2017. The Company is a noncontrolling investor in Pattern Development 2.0, but has significant influence over PatternDevelopment 2.0. Accordingly, the investment is accounted for under the equity method of accounting.The Company capitalized $1.5 million of transaction costs for the year ended December 31, 2017. The Company's initial investment in Pattern Development 2.0 of$60.0 million was $ 40.6 million higher than the Company's underlying equity in the net assets of Pattern Development 2.0 at the time of the initial funding. Thisequity method basis difference was primarily attributable to equity method goodwill.ArmowOn October 17, 2016, the Company acquired from Pattern Development 1.0 a 50% equity interest in Armow for approximately $132.3 million , in addition to $0.3million of capitalized transaction-related expenses, plus assumed estimated proportionate debt, net of deferred financing cost, of approximately $193.6 million .Armow is a joint venture established to develop, construct and operate a wind power project located in Ontario, Canada. The project operates under a 20 -year PPAand commenced commercial operation in December 2015. The Company’s investment in Armow was funded through general corporate funds and borrowingsunder the revolving credit facility. The Company is a noncontrolling investor in Armow, but has significant influence over Armow. Accordingly, the investment isbeing accounted for using the equity method of accounting.The cost of the Company’s investment in Armow was $138.2 million higher than the Company’s underlying equity in the net assets of Armow. This equity methodbasis difference was comprised of $89.8 million related to property, plant and equipment and $48.4 million related to the PPA. The difference between thepurchase price paid, including transaction costs of $132.6 million and the equity method basis differences of $138.2 million was due to the Armow project having anegative equity balance of $5.6 million as of the acquisition date primarily due to losses incurred on its interest rate derivative.4 . Property, Plant and EquipmentThe following presents the categories within property, plant and equipment (in thousands): December 31, 2017 2016Operating wind farms$4,640,718 $3,707,823Transmission line93,849 —Furniture, fixtures and equipment12,643 9,307Land141 141Subtotal4,747,351 3,717,271Less: accumulated depreciation(782,230) (582,109)Property, plant and equipment, net$3,965,121 $3,135,162The Company recorded depreciation expense related to property, plant and equipment of $194.8 million , $171.7 million and $141.2 million for the years endedDecember 31, 2017 , 2016 and 2015 , respectively.F-235 . Finite-Lived Intangible Assets and LiabilityThe following presents the major components of the finite-lived intangible assets and liability (in thousands): December 31, 2017 Weighted AverageRemaining Life Gross AccumulatedAmortization NetIntangible assets Power purchase agreement15$127,084$(17,611) $109,473Industrial revenue bond tax savings24 12,778 (351) 12,427Other intangible assets3415,234(1,086) 14,148Total intangible assets $155,096 $(19,048) $136,048Intangible liability Power purchase agreement15$60,300$(9,106) $51,194 December 31, 2016 Weighted AverageRemaining Life Gross AccumulatedAmortization NetIntangible assets Power purchase agreement13$97,400$(10,632)$86,768Other intangible assets155,666(539)5,127Total intangible assets $103,066 $(11,171) $91,895Intangible liability Power purchase agreement16$60,300$(5,637) $54,663The Company presents amortization of the PPA asset and PPA liability as an offset to electricity sales in the consolidated statements of operations, which resultedin net expense of $3.5 million , $3.0 million and $1.9 million in electricity sales for the years ended December 31, 2017 , 2016 and 2015 , respectively. For theyears ended December 31, 2017 , 2016 and 2015 , the Company recorded amortization expense of $0.5 million , $0.3 million and $0.1 million , respectively,related to other intangible assets in depreciation and accretion in the consolidated statements of operations.The acquisition of the Broadview Project provided for future property tax savings as a result of the issuance of industrial revenue bonds during construction of theBroadview Project. The Company considered the future tax savings an intangible asset and calculated the fair value of the asset at the acquisition date. The taxsavings was calculated by forecasting the difference between the property tax payments that the Broadview Project would be liable for if the industrial revenuebond structure was not in place and the actual payments in lieu of tax. The fair value of the property tax savings was recorded to finite-lived intangible assets, neton the consolidated balance sheets at the acquisition date, and such value will be amortized to depreciation and accretion in the consolidated statements ofoperations over the 25 year exemption period that remains as of the acquisition date. The Company recorded amortization expense of $0.4 million for the yearended December 31, 2017 related to the industrial revenue bond tax savings intangible asset.The following table presents estimated future amortization for the next five years related to the PPA asset and PPA liability and other intangible assets:Year ended December 31, Power PurchaseAgreements, Net Industrial revenuebond tax savings Other IntangibleAssets2018 $4,243 $513$6032019 4,243 5136052020 4,264 5136052021 4,243 5136052022 4,243 513605Thereafter 37,043 9,86211,125F-246 . Variable Interest EntitiesThe Company consolidates VIEs in which it holds a variable interest and is the primary beneficiary. The Company has determined that Logan's Gap, Panhandle 1,Panhandle 2, Post Rock, Amazon Wind and Broadview Holdings are VIEs. The Company determined that as the managing member of the VIEs it is the primarybeneficiary by reference to the power and benefits criterion under ASC 810, Consolidation and therefore, consolidates the VIEs. The Company consideredresponsibilities within the contractual agreements, which grant it the power to direct the activities of the VIE that most significantly impact the VIE's economicperformance. Such activities include management of the wind farms' operations and maintenance, budgeting, policies and procedures. In addition, the Companyhas the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIEs on the basis of the income allocations and cashdistributions.The Company’s equity method investment in Pattern Development 2.0 is considered to be a VIE primarily because the total equity at risk is not sufficient to permitPattern Development 2.0 to finance its activities without additional subordinated financial support by the equity holders. The Company does not hold the power orbenefits to be the primary beneficiary and does not consolidate the VIE. The carrying value of its unconsolidated investment in Pattern Development 2.0 was $62.2million as of December 31, 2017 . The Company's maximum exposure to loss is equal to the carrying value of its investment in PEGH 2. See Note 3, Acquisitions ,for additional information.The following presents the carrying amounts of the consolidated VIEs' assets and liabilities included in the consolidated balance sheets (in thousands). Assetspresented below are restricted for settlement of the consolidated VIEs' obligations and all liabilities presented below can only be settled using the VIE resources. December 31, 2017 2016 (1)Assets Current assets: Cash and cash equivalents$33,273 $12,745Restricted cash4,314 4,291Trade receivables12,769 6,290Prepaid expenses4,965 4,468Other current assets2,597 1,456Total current assets57,918 29,250 Restricted cash3,330 3,203Property, plant and equipment, net1,984,606 1,538,793Finite-lived intangible assets, net12,210 2,070Other assets12,984 13,622Total assets$2,071,048 $1,586,938 Liabilities Current liabilities: Accounts payable and other accrued liabilities$26,826 $12,635Accrued construction costs759 709Accrued interest78 77Other current liabilities4,789 2,090Total current liabilities32,452 15,511 Contingent liabilities87 81Other long-term liabilities47,345 20,081Total liabilities$79,884 $35,673(1) Does not include Broadview Holdings as it was acquired in April 2017.7 . Unconsolidated InvestmentsThe Company's unconsolidated investments consist of the following for the periods presented below (in thousands): December 31, Percentage of Ownership December 31, 2017 2016 2017 2016South Kent$6,151 $1,537 50.0% 50.0%Grand6,611 3,459 45.0% 45.0%K2103,328 97,051 33.3% 33.3%Armow132,890 131,247 50.0% 50.0%Pattern Development 2.062,243 — 20.9% NAUnconsolidated investments$311,223 $233,294 F-25South KentThe Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. Theproject has a 20 -year PPA, and commenced commercial operation in March 2014.GrandThe Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. Theproject has a 20 -year PPA and commenced commercial operation in December 2014.K2The Company is a noncontrolling investor in a joint venture established to develop, construct and own a wind power project located in Ontario, Canada. Theproject has a 20 -year PPA and commenced commercial operation in May 2015.ArmowThe Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. Theproject has a 20 -year PPA, and commenced commercial operation in December 2015. See Note 3 , Acquisitions - Unconsolidated Investments , for disclosure onthe acquisition of the 50% interest in Armow.Pattern Development 2.0The Company is a noncontrolling investor in the long-term development vehicle. The core of Pattern Development 2.0's assets consists of the early and mid-stageU.S. development assets. The investment allows the Company to secure access to an exclusive pipeline of new projects and enhance its alignment with thedevelopment business. See Note 3 , Acquisitions - Unconsolidated Investments , for disclosure on the acquisition of the equity interest in Pattern Development 2.0.Basis Amortization of Unconsolidated InvestmentsThe cost of the Company’s investment in the net assets of unconsolidated investments was higher than the fair value of the Company’s equity interest in theunderlying net assets of its unconsolidated investments. The basis differences were primarily attributable to property, plant and equipment, PPAs, and equitymethod goodwill. The Company amortizes the basis difference attributable to property, plant and equipment, and PPAs over their useful life and contractual life,respectively. The Company does not amortize equity method goodwill. For the years ended December 31, 2017 , 2016 and 2015 , the Company recorded basisdifference amortization for its unconsolidated investments of $11.4 million , $6.5 million and $2.9 million , respectively, in earnings in unconsolidatedinvestments, net on the consolidated statements of operations.Suspension of Equity Method AccountingDuring the year ended December 31, 2016 the Company's equity method balances for South Kent and Grand were zero . In accordance with ASC 323, Investments- Equity Method and Joint Ventures , the Company suspended recognition of South Kent's and Grand's equity method earnings or losses and accumulated othercomprehensive income (loss), until the fourth quarter of 2016 when South Kent's and Grand's cumulative equity method earnings and other comprehensive incomeexceeded cumulative distributions received, cumulative equity method losses and, where applicable, cumulative other comprehensive income (loss) during thesuspension period. As the Company has no explicit or implicit commitment to fund losses at the unconsolidated investments, the Company has recorded gainsresulting from distributions received in excess of the carrying amount of its unconsolidated investments. For the year ended December 31, 2016, earnings (loss) inunconsolidated investments, net as reported on the consolidated statement of operations attributable to South Kent and Grand includes $19.9 million indistributions received in excess of the carrying amount of the Company's investment and equity earnings of $0.6 million . During 2017, there was no suspension ofequity method earnings or losses.During the suspension period, the Company maintains a memo ledger that records the components of the suspended activity. During the year ended December 31,2016, the memo ledger balance was made up of distributions received in excess of the carrying amount of the Company's investment of $19.9 million , suspendedequity losses of $4.6 million and suspended other comprehensive income of $0.7 million which were offset by equity earnings of $23.8 million during the fourthquarter of 2016 when cumulative equity method earnings and other comprehensive income exceeded cumulative distributions received, cumulative equity methodlosses and, where applicable, cumulative other comprehensive income (loss) during the suspension period. As a result, the Company's memo ledger as ofDecember 31, 2016 is $0.0 million .F-268 . DebtThe Company’s debt consists of the following for periods presented below (in thousands): December 31, 2017 December 31, ContractualInterest Rate Effective InterestRate 2017 2016 MaturityCorporate-level Revolving Credit Facility$— $180,000 varies(1 ) —% November 20222020 Notes225,000 225,000 4.00% 6.60% July 20202024 Notes350,000 — 5.88% 5.88% February 2024Project-level Fixed interest rate El Arrayán EKF term loan99,112 103,904 5.56% 5.56% March 2029Santa Isabel term loan103,878 107,090 4.57% 4.57% September 2033Variable interest rate Ocotillo commercial term loan (2)289,339 193,257 6.00% 6.06%(3 ) June 2033Lost Creek term loan (4)— 103,846 —% —% N/AEl Arrayán commercial term loan90,102 94,458 4.25% 5.72%(3 ) March 2029Spring Valley term loan125,678 130,658 3.45% 5.12%(3 ) June 2030Ocotillo development term loan— 102,300 —% —% N/ASt. Joseph term loan (2)171,487 162,356 3.17% 3.91%(3 ) November 2033Western Interconnect term loan (2)54,395 — 3.70% 4.26% April 2027Meikle term loan (2)266,557 — 3.04% 3.90% May 2024Imputed interest rate Hatchet Ridge financing lease obligation192,079 202,593 1.43% 1.43% December 2032 1,967,627 1,605,462 Unamortized premium/discount, net (4)(13,470) (17,019) Unamortized financing costs(23,426) (24,771) Total debt, net$1,930,731 $1,563,672 As reflected on the consolidated balance sheets Revolving credit facility$— $180,000 Current portion of long-term debt, net of financing costs51,996 48,716 Long term debt, net of financing costs1,878,735 1,334,956 Total debt, net$1,930,731 $1,563,672 (1) Refer to Revolving Credit Facility for interest rate details.(2) The amortization for the St. Joseph term loan, the Western Interconnect term loan and the Meikle term loan are through September 2036, March 2036 and December 2038,respectively, which differs from the stated maturity date of such loans due to prepayment requirements.(3) Includes impact of interest rate swaps. See Note 10 , Derivative Instruments , for discussion of interest rate swaps.(4) The discount relates to the 2020 Notes and the premium relates to the Lost Creek term loan as of December 31, 2016. The Lost Creek term loan was terminated in September 2017.F-27The following are principal payments, excluding deferred financing costs, due under the Company's debt as of December 31, 2017 for the following years (inthousands): Amount2018 $53,7042019 64,4262020 293,5112021 71,8212022 75,763Thereafter 1,408,402Total $1,967,627Interest and commitment fees incurred and interest expense for debt consisted of the following (in thousands): Year ended December 31, 2017 2016 2015Corporate-level interest and commitment fees incurred$33,777 $18,171 $9,983Project-level interest and commitment fees incurred55,535 47,994 64,903Capitalized interest, commitment fees, and letter of credit fees— — (6,607)Amortization of debt discount/premium, net4,583 4,226 1,660Amortization of financing costs7,871 6,968 7,435Other interest463 645 533Interest expense$102,229 $78,004 $77,907Corporate Level DebtRevolving Credit FacilityOn November 21, 2017, certain of our subsidiaries entered into a Second Amended and Restated Credit and Guaranty Agreement (the Revolving Credit Facility).The Revolving Credit Facility provides for a revolving credit facility of $440 million , decreased from the previous limit of $500 million . The facility has a five -year term and is comprised of a revolving loan facility, a letter of credit facility and a swingline facility. The facility is secured by pledges of the capital stock andownership interests in certain of our holding company subsidiaries, in addition to other customary collateral.As of December 31, 2017 , $392.5 million was available for borrowing under the $440 million Revolving Credit Facility. The Revolving Credit Facility contains abroad range of covenants that, subject to certain exceptions, restrict the Company’s holding company subsidiaries' ability to incur debt, grant liens, sell or leaseassets, transfer equity interests, dissolve, pay distributions and change its business. As of December 31, 2017 , the Company's holding company subsidiaries are incompliance with covenants contained in the Revolving Credit Facility.The loans under the Revolving Credit Facility are base rate loans, Eurodollar rate loans, Canadian prime rate loans or CDOR rate loans. The base rate loans accrueinterest at the fluctuating rate per annum equal to the greatest of the (i) the U.S. dollar prime rate, (ii) the federal funds rate plus 0.50% and (iii) LIBOR one monthplus 1.0% , plus an applicable margin ranging from 0.625% to 0.875% (corresponding to applicable leverage ratios of the borrowers). The Eurodollar rate loansaccrue interest at a rate per annum equal to LIBOR, as published by Reuters plus an applicable margin ranging from 1.625% to 1.875% (corresponding toapplicable leverage ratios of the borrowers). The Canadian prime rate loans accrue interest at a fluctuating rate per annum equal to the greater of (i) the Canadiandollar prime rate and (ii) the average CDOR rate for a 30 day term plus 0.50% , plus an applicable margin ranging from 0.625% to 0.875% (corresponding toapplicable leverage ratios of the borrowers). The CDOR rate loans accrue interest at a rate per annum equal to CDOR, as published by Reuters plus an applicablemargin ranging from 1.625% to 1.875% (corresponding to applicable leverage ratios of the borrowers). Under the facility, the Company pays a revolvingcommitment fee equal to a percentage per annum determined by reference to the leverage ratio of the borrowers, ranging from 0.30% to 0.50% . Letter of creditfees are also paid.As of December 31, 2017 and 2016 , letters of credit of $47.5 million and $31.7 million , respectively, were available to be issued under the Revolving CreditFacility.F-282024 NotesIn January 2017, the Company issued unsecured senior notes with an aggregate principal amount of $350.0 million (Unsecured Senior Notes or 2024 Notes). Netproceeds to the Company were approximately $345.0 million , after deducting the initial purchasers’ discount, commissions and transaction expenses. The 2024Notes bear interest at a rate of 5.875% per year, payable semiannually in arrears on February 1 and August 1, beginning on August 1, 2017 and maturing onFebruary 1, 2024, unless repurchased or redeemed at an earlier date. The 2024 Notes are guaranteed on a senior unsecured basis by Pattern US Finance Company,one of the Company's subsidiaries.2020 NotesIn July 2015, the Company issued $225.0 million aggregate principal amount of 4.00% convertible senior notes due 2020 (2020 Notes). The 2020 Notes bearinterest at a rate of 4.00% per year, payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2016. The 2020 Notes willmature on July 15, 2020. The 2020 Notes were sold in a private placement. Upon conversion, the Company may, at its discretion, pay cash, shares of theCompany’s Class A common stock, or a combination of cash and stock. The 2020 Notes were set at an initial conversation rate of 35.4925 shares of Class Acommon stock per $1,000 principal amount of 2020 Notes, which is equivalent to an initial conversion price of approximately $28.175 per share of Class Acommon stock. The conversion rate is subject to adjustment in some events (including, but not limited to, certain cash dividends made to holders of the Company'sClass A common stock which exceed the initial dividend threshold of $0.363 per quarter per share). The conversion rate would be adjusted to offset the effect ofthe portion of the dividend in excess of $0.363 , provided that the adjustment would result a change of at least 1% in the then effective conversion rate. During theyear ended December 31, 2017, the conversion rate increased to 35.8997 shares of Class A common stock per $1,000 principal amount of 2020 Notes. Theconversion rate will not be adjusted for any accrued and unpaid interest. The 2020 Notes are not redeemable prior to maturity.The 2020 Notes are guaranteed on a senior unsecured basis by a subsidiary of the Company and are general unsecured obligations of the Company. The obligationsrank senior in rights of payment to the Company’s subordinated debt, equal in right of payment to the Company’s unsubordinated debt and effectively junior inright of payment to any of the Company’s secured indebtedness to the extent of the value of the assets securing such indebtedness.The following table presents a summary of the equity and liability components of the 2020 Notes (in thousands):December 31,2017 2016Principal$225,000 $225,000Less: Unamortized debt discount(13,470) (18,196)Unamortized financing costs(2,794) (3,894)Carrying value of convertible senior notes$208,736 $202,910 Carrying value of the equity component (1)$23,743 $23,743(1) Included in the consolidated balance sheets as additional paid-in capital, net of $0.7 million in equity issuance costs.Project-level Financing ArrangementsThe Company typically finances its wind projects through project entity specific debt secured by each project's assets with no recourse to the Company. Typically,these financing arrangements provide for a construction loan, which upon completion may be converted into a term loan or repaid through capital contributionsfrom the Company and tax equity investors.Collateral for project level facilities typically include each project's tangible assets and contractual rights and cash on deposit with the depository agents. Each loanagreement contains a broad range of covenants that, subject to certain exceptions, restrict each project's ability to incur debt, grant liens, sell or lease certain assets,transfer equity interests, dissolve, make distributions and change their business. As of December 31, 2017 , all projects were in compliance with their financingcovenants.F-29OcotilloIn December 2017, the Company refinanced Ocotillo's commercial term loan of $179.3 million and development term loan of $101.2 million and letters of creditassociated with the loans and entered into a new Commercial term loan for $289.3 million maturing in June 2033 and letters of credits totaling $58.2 million . Therefinancing was treated as an extinguishment of debt; however, as the refinancing included existing lenders, the Company recognized a loss on extinguishment ofdebt of $8.6 million in other income, net on the consolidated statements of operations for the year ended December 31, 2017 . The $8.6 million loss onextinguishment includes the write-off of unamortized debt issuance costs of $4.3 million and new financing fees of $4.3 million. The interest rate on the term loanis LIBOR plus 1.5% .Lost CreekIn September 2017, the Company prepaid 100% of the outstanding balance of the Lost Creek project's term loan of $100.1 million. A $0.1 million loss on the debtextinguishment was recorded in other income, net in the consolidated statements of operations, primarily due to the offsetting impact of writing-off the debtpremium and deferred financing costs. As a result of the early extinguishment of debt, the Company terminated the related interest rate swaps. See Note 10 ,Derivative Instruments , for additional information.MeikleIn August 2017, in connection with the Meikle acquisition, the Company assumed a $265.6 million variable rate term loan maturing on May 12, 2024. The interestrate on the term loan is Canadian Dollar Offered Rate plus 1.50% .Collateral for the term loan includes Meikle’s tangible assets and contractual rights and cash on deposit with the collateral agent. Such credit agreement contains abroad range of covenants that, subject to certain exceptions, restrict Meikle's ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests,dissolve, make distributions, or change its business.Western InterconnectIn April 2017, in connection with the Broadview Project acquisition, the Company assumed a $51.2 million senior construction loan facility, including accruedinterest, which was immediately extinguished. Concurrently, the Company entered into a variable rate term loan maturing on April 21, 2027 for $54.4 million . Theinterest rate on the term loan is LIBOR plus 2.00% (with periodic increases of 0.25% every four years ).Collateral for the term loan includes Western Interconnect's tangible assets and contractual rights and cash on deposit with the depository agent. Such loanagreement contains a broad range of covenants that, subject to certain exceptions, restrict Western Interconnect's ability to incur debt, grant liens, sell or leasecertain assets, transfer equity interests, dissolve, make distributions, or change its business.Financing Lease ObligationsIn December 2010, Hatchet Ridge entered into a sale-leaseback agreement to finance the project facility for 22 years . The Company evaluated the agreement inaccordance with ASC 840 and ASC 360, Property Plant and Equipment, and determined that due to continuing involvement with the project facility, the Companyis precluded from treating the agreement as a sale-lease back transaction and accounts for the agreement as a financing lease obligation.Collateral for the agreement includes Hatchet Ridge’s tangible assets and contractual rights and cash on deposit with the depository agent. Its loan agreementcontains a broad range of covenants that, subject to certain exceptions, restrict Hatchet Ridge’s ability to incur debt, grant liens, sell or lease assets, transfer equityinterests, dissolve, pay distributions and change its business.Payments under the financing lease for the years ended December 31, 2017 , 2016 and 2015 , were $13.4 million , $15.0 million and $16.9 million , respectively.9 . Asset Retirement ObligationThe Company’s asset retirement obligations represent the estimated cost of decommissioning the turbines, removing above-ground installations and restoring thesites at the end of its estimated economic useful life.F-30The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligation (in thousands): December 31, 2017 2016Beginning asset retirement obligations $44,783 $42,197Net additions during the year 8,701 —Foreign currency translation adjustment 208 63Accretion expense 2,927 2,523Ending asset retirement obligations $56,619 $44,78310 . Derivative InstrumentsThe Company employs a variety of derivative instruments to manage its exposure to fluctuations in electricity prices, interest rates and foreign currency exchangerates. Energy prices are subject to wide swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity,generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists primarily on variable-rate debt forwhich the cash flows vary based upon movement in interest rates. Additionally, the Company is exposed to foreign currency exchange rate risk primarily from itsbusiness operations in Canada and Chile.The Company’s objectives for holding these derivative instruments include reducing, eliminating and efficiently managing the economic impact of these exposuresas effectively as possible. The Company does not hedge all of its electricity price risk, interest rate risks, and foreign currency exchange rate risks, therebyexposing the unhedged portions to changes in market prices.As of December 31, 2017 , the Company had other energy-related contracts that did not meet the definition of a derivative instrument or qualified for the NPNSexception and were therefore exempt from fair value accounting treatment.The following tables present the fair values of the Company's derivative instruments on a gross basis as reflected on the Company’s consolidated balance sheets (inthousands): December 31, 2017 Derivative Assets Derivative Liabilities Current Long-Term Current Long-TermFair Value of Designated Derivatives: Interest rate swaps $— $1,968 $4,397 $17,961 Fair Value of Undesignated Derivatives: Interest rate swaps — 228 858 2,542Energy derivative 19,440 7,432 — —Foreign currency forward contracts 5 — 3,154 469Total Fair Value $19,445 $9,628 $8,409 $20,972 December 31, 2016 Derivative Assets Derivative Liabilities Current Long-Term Current Long-TermFair Value of Designated Derivatives: Interest rate swaps $— $40 $8,289 $21,058 Fair Value of Undesignated Derivatives: Interest rate swaps — 1,788 3,238 3,463Energy derivative 16,209 24,707 — —Foreign currency forward contracts 1,369 177 391 —Total Fair Value $17,578 $26,712 $11,918 $24,521The following table summarizes the notional amounts of the Company's outstanding derivative instruments (in thousands except for MWh): December 31, Unit of Measure 2017 2016Designated Derivative Instruments Interest rate swaps USD $253,271 $365,443Interest rate swaps CAD $736,136 $196,425 Undesignated Derivative Instruments Interest rate swaps USD $85,474 $257,389Energy derivative MWh 697,471 1,201,691Foreign currency forward contracts CAD $127,500 $95,800F-31Derivatives Designated as Hedging InstrumentsCash Flow HedgesThe Company has interest rate swap agreements to hedge variable rate project-level debt. Under these interest rate swaps, the projects make fixed-rate interestpayments and the counterparties to the agreements make variable-rate interest payments. For interest swaps that are designated and qualify as cash flow hedges, theeffective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive loss and reclassified into earnings in theperiod or periods during which a cash settlement occurs. The designated interest rate swaps have remaining maturities ranging from approximately 6.0 years to21.0 years .The following table presents the pre-tax effect of the derivative instruments designated as cash flow recognized in accumulated other comprehensive loss, amountsreclassified to earnings for the following periods, as well as, amounts recognized in interest expense (in thousands): Year ended December 31, Description 2017 2016 2015Gains (losses) recognized in accumulated OCI Effective portion of change in fairvalue $(1,980) $(7,584) $(18,023)Gains (losses) reclassified from accumulated OCI into: Interest expense Derivative settlements $(9,995) $(8,411) $(12,904)Loss on derivatives Termination of derivatives $(2,207) $— $(11,221)Loss on derivatives De-designation of derivatives $— $— $(5,918)Interest expense Ineffective portion $136 $346 $(809)The Company estimates that $3.3 million in accumulated other comprehensive loss will be reclassified into earnings over the next twelve months.Derivatives Not Designated as Hedging InstrumentsThe following table presents gains and losses on derivatives not designated as hedges (in thousands): Year ended December 31,Derivative Type Financial Statement Line Item 2017 2016 2015Interest rate derivatives Loss on derivatives $(813) $(1,828)(1 ) $(10,596)Energy derivative Electricity sales $5,155 $(1,181) $19,776Foreign currency forward contracts Loss on derivatives $(6,767) $(1,496) $5,106(1) Amount includes the reclassification of $5.9 million from accumulated other comprehensive loss related to the de-designation of certain interest rate derivative instruments at SpringValley.Interest Rate DerivativesInterest Rate SwapsThe Company has interest rate swap agreements to hedge variable rate project-level debt. Under these interest rate swaps, the projects make fixed-rate interestpayments and the counterparties to the agreements make variable-rate interest payments. For interest rate swaps that are not designated and do not qualify as cashflow hedges, the changes in fair value are recorded in loss on derivatives in the consolidated statements of operations as these hedges are not accounted for underhedge accounting. All of the Company's undesignated interest rate swaps have a remaining maturity of 12.5 years .Energy DerivativeIn 2010, Gulf Wind acquired an energy derivative instrument to manage its exposure to variable electricity prices over the life of the arrangement. The energy priceswap fixes the price for a predetermined volume of production (the notional volume) over the life of the swap contract, through April 2019 , by locking in a fixedprice per MWh. The notional volume agreed to by the parties is approximately 504,220 MWh per year. The energy derivative instrument does not meet the criteriarequired to adopt hedge accounting. As a result, changes in fair value are recorded in electricity sales in the consolidated statements of operations.F-32As a result of the counterparty's credit rating downgrade, the Company received cash collateral related to the energy derivative agreement. The Company does nothave the right to pledge, invest, or use the cash collateral for general corporate purposes. As of December 31, 2017 , the Company has recorded a current asset of$29.8 million to funds deposited by counterparty and a current liability of $29.8 million to counterparty deposit liability representing the cash collateral receivedand corresponding obligation to return the cash collateral, respectively. The cash was deposited into a separate custodial account for which the Company is notentitled to the interest earned on the cash collateral.Foreign Currency Forward ContractsThe Company has established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising fromtransactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in the Company’s cashflow, which may have an adverse impact to the Company's short-term liquidity or financial condition. A majority of the Company’s power sale agreements andoperating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. TheCompany enters into foreign currency forward contracts at various times to mitigate the currency exchange rate risk on Canadian dollar denominated cash flows.These instruments have remaining maturities ranging from three to twenty-one months. The foreign currency forward contracts are considered non-designatedderivative instruments and are not used for trading or speculative purposes. As a result, changes in fair value and settlements are recorded in loss on derivatives inthe consolidated statements of operations.11 . Accumulated Other Comprehensive LossThe following table summarizes changes in the accumulated other comprehensive loss balance, net of tax, by component (in thousands): Foreign Currency Effective Portion ofChange in Fair Value ofDerivatives Proportionate Share ofEquity Investee's OCI TotalBalances at December 31, 2014 $(19,338) $(26,672) $(7,903) $(53,913)Other comprehensive loss before reclassifications (28,947) (16,163) (6,640) (51,750)Amounts reclassified from accumulated other comprehensive loss dueto termination/de-designation of interest rate derivatives — 17,139 — 17,139Other amounts reclassified from accumulated other comprehensiveloss — 12,234 2,412 14,646Net current period other comprehensive loss (28,947) 13,210 (4,228) (19,965)Balances at December 31, 2015 (48,285) (13,462) (12,131) (73,878)Other comprehensive loss before reclassifications 4,785 (6,751) 1,039 (927)Amounts reclassified from accumulated other comprehensive loss — 7,462 4,594 12,056Net current period other comprehensive loss 4,785 711 5,633 11,129Balances at December 31, 2016 (43,500) (12,751) (6,498) (62,749)Other comprehensive income (loss) before reclassifications 15,313 (2,738) 5,807 18,382Amounts reclassified from accumulated other comprehensive loss dueto termination of interest rate derivatives — 2,207 — 2,207Other amounts reclassified from accumulated other comprehensiveloss — 8,935 8,006 16,941Net current period other comprehensive income 15,313 8,404 13,813 37,530Balances at December 31, 2017 $(28,187) $(4,347) $7,315 $(25,219)12 . Fair Value MeasurementThe Company’s fair value measurements incorporate various factors, including the credit standing and performance risk of the counterparties, the applicable exitmarket, and specific risks inherent in the instrument. Nonperformance and credit risk adjustments on risk management instruments are based on current marketinputs when available, such as credit default hedge spreads. When such information is not available, internal models may be used.Assets and liabilities recorded at fair value in the consolidated financial statements are categorized based upon the level of judgment associated with the inputsused to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to valuation of these assets or liabilitiesare set forth below. Transfers between levels are recognized at the end of each quarter. The Company did not recognize any transfers between levels during theperiods presented.F-33Level 1—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.Level 2—Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation withmarket data at the measurement date and for the duration of the instrument’s anticipated life.Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities andwhich reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration isgiven to the risk inherent in the valuations technique and the risk inherent in the inputs to the model.Financial InstrumentsThe carrying value of financial instruments classified as current assets and current liabilities approximates their fair value, based on the nature and short maturity ofthese instruments, and they are presented in the Company’s financial statements at carrying cost. Certain other assets and liabilities were measured at fair valueupon initial recognition and unless conditions give rise to an impairment, are not remeasured.Financial Instruments Measured at Fair Value on a Recurring BasisThe Company’s financial assets and liabilities which require fair value measurement on a recurring basis are classified within the fair value hierarchy as follows (inthousands): December 31, 2017 Level 1 Level 2 Level 3 TotalAssets Interest rate swaps$— $2,196 $— $2,196Energy derivative— — 26,872 26,872Foreign currency forward contracts— 5 — 5 $— $2,201 $26,872 $29,073Liabilities Interest rate swaps$— $25,758 $— $25,758Foreign currency forward contracts— 3,623 — 3,623Contingent consideration— — 21,943 21,943 $— $29,381 $21,943 $51,324 December 31, 2016 Level 1 Level 2 Level 3 TotalAssets Interest rate swaps$— $1,828 $— $1,828Energy derivative— — 40,916 40,916Foreign currency forward contracts— 1,546 — 1,546 $— $3,374 $40,916 $44,290Liabilities Interest rate swaps$— $36,048 $— $36,048Foreign currency forward contracts— 391 — 391 $— $36,439 $— $36,439Level 2 InputsDerivative instruments subject to re-measurement are presented in the financial statements at fair value. The Company's interest rate swaps were valued bydiscounting the net cash flows using the forward LIBOR curve with the valuations adjusted by the Company’sF-34credit default hedge rate. The Company’s foreign currency forward contracts were valued using the income approach based on the present value of the forwardrates less the contract rates, multiplied by the notional amounts.Level 3 InputsEnergy HedgeThe fair value of the energy derivative instrument is determined based on a third-party valuation model. The methodology and inputs are evaluated by managementfor consistency and reasonableness by comparing inputs used by the third-party valuation provider to another third-party pricing service for identical or similarinstruments and also reconciling inputs used in the third-party valuation model to the derivative contract for accuracy. Any significant changes are furtherevaluated for reasonableness by obtaining additional documentation from the third-party valuation provider.The energy derivative instrument is valued by discounting the projected net cash flows over the remaining life of the derivative instrument using forward electricityprices which are derived from observable prices, such as forward gas curves, adjusted by a non-observable heat rate for when the contract term extends beyond aperiod for which market data is available. The significant unobservable input in calculating the fair value of the energy derivative instrument is forward electricityprices. Significant increases or decreases in this unobservable input would result in a significantly lower or higher fair value measurement.Contingent ConsiderationThe Broadview Project acquisition includes contingent consideration, which requires the Company to make an additional payment upon the commercial operationof the Grady Project. The contingent post-closing payment reflects the fair value of the Company's interest in the increase in the projected 25-year transmissionwheeling revenue Western Interconnect will receive from the Grady Project, adjusted for the estimated production loss incurred by Broadview due to wake effectsand transmission losses induced by the operation of the Grady Project. The fair value of the contingent consideration at the acquisition date was $21.3 million . Theestimated fair value of the contingent consideration was calculated by using a discounted cash flow technique which utilized unobservable inputs presented in thetable below. This fair value measurement is based on significant inputs not observable in the market and thus represents a Level 3 measurement as defined in ASC820. As of December 31, 2017 , there were no significant inputs changes in the calculation of the contingent consideration recognized since the acquisition of theBroadview Project. Significant changes in these unobservable inputs may result in significant changes in fair value.The following table presents a reconciliation of the energy derivative contract measured at fair value on a recurring basis using significant unobservable inputs (inthousands):Energy Derivative 2017 2016Balance at beginning of year $40,916 $63,683Total gains (losses) included in electricity sales 5,155 (1,181)Settlements (19,199) (21,586)Balance at end of year $26,872 $40,916During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized unrealized losses of $14.0 million , $22.8 million , and $0.8 million relatingto the energy derivative asset held at December 31, 2017 , 2016 and 2015 , respectively, which were recorded to energy sales in the consolidated statements ofoperations.Contingent Consideration Liability 2017 2016Balances, beginning of year $— $—Broadview Project acquisition 21,284 —Total loss in other income, net 659 —Balances, end of year $21,943 $—During the year ended December 31, 2017 , the Company recognized $0.7 million loss on the contingent consideration liability, which was recorded to otherincome (expense), net in the consolidated statements of operations.F-35The valuation techniques and significant unobservable inputs used in recurring Level 3 fair value measurements were as follows (in thousands, for fair value):December 31, 2017 Fair Value Valuation Technique Significant Unobservable Inputs RangeEnergy derivative $26,872 Discounted cash flow Forward electricity prices $14.44 - $71.45 (1) Discount rate 1.69%-1.96% Contingent consideration $21,943 Discounted cash flow Discount rate 4.00% - 8.00% Annual energy production loss 1.00% December 31, 2016 Fair Value Valuation Technique Significant Unobservable Inputs RangeEnergy derivative $40,916 Discounted cash flow Forward electricity prices $15.83 - $81.76 (1) Discount rate 1.00% - 1.52%(1) Represents price per MWhFinancial Instruments not Measured at Fair ValueThe following table presents the carrying amount and fair value and the fair value hierarchy of the Company’s financial liabilities that are not measured at fairvalue in the consolidated balance sheets, but for which fair value is disclosed (in thousands): Fair Value As reflected onthe balance sheet Level 1 Level 2 Level 3 TotalDecember 31, 2017 Total debt, net$1,930,731 $— $1,937,671 $— $1,937,671December 31, 2016 Total debt, net$1,563,672 $— $1,562,038 $— $1,562,038Long term debt is presented on the consolidated balance sheets, net of financing costs, discounts and premiums. The fair value of variable interest rate long-termdebt is approximated by its carrying cost. The fair value of fixed interest rate long-term debt is estimated based on observable market prices or parameters orderived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied, using the net present value of cash flowstreams over the term using estimated market rates for similar instruments and remaining terms.F-3613 . Income TaxesThe following table presents significant components of the provision for income taxes (in thousands): Year ended December 31, 2017 2016 2015Current: Federal $— $— $—State — — —Foreign 292 378 489Total current expense 292 378 489Deferred: Federal (3,751) — —State — — —Foreign 15,193 8,301 4,454Total deferred expense 11,442 8,301 4,454Total provision for income taxes $11,734 $8,679 $4,943The following table presents the domestic and foreign components of net loss before income tax provision (in thousands): Year ended December 31, 2017 2016 2015U.S. $(119,067) $(71,405) $(66,883)Foreign 48,391 27,785 16,219Total $(70,676) $(43,620) $(50,664)The following table presents a reconciliation of the statutory U.S. federal income tax rate to the Company’s effective tax rate, as a percentage of income beforetaxes for the following periods: Year ended December 31, 2017 2016 2015Computed tax at statutory rate 35.0 % 35.0 % 35.0 %Adjustment for income in non-taxable entities allocable to noncontrollinginterest (32.6)% (25.6)% (13.0)%Foreign rate differential Tax rate differential on pre-tax book income (16.6)% (16.9)% (6.6)%Local tax on branch profits/(losses)—Puerto Rico 0.1 % — % 0.3 %Permanent book/tax differences (domestic only) (3.6)% (0.2)% (0.1)%Valuation allowance 47.7 % (18.8)% (25.1)%Chilean shareholder benefit due to tax regime change 0.1 % 0.7 % 0.4 %Tax credits 31.6 % 7.6 % — %Effect of U.S. tax rate change under Tax Cuts and Jobs Act (78.1)% — % — %Other (0.2)% (1.6)% (0.7)%Effective income tax rate (16.6)% (19.8)% (9.8)%F-37Generally, the amount of income tax expense or benefit allocated to continuing operations is determined without regard to the tax effects of other categories ofincome or loss, such as discontinued operations, extraordinary items, other comprehensive income and items charged or credited to shareholders' equity. However,an exception to the general rule is provided when there is a pre-tax loss from continuing operations, a valuation allowance against deferred tax assets and pre-taxincome from other categories in the current year. In such instances, income from other categories must be considered in allocating the total income tax provisionfor the period among the various categories. Income tax benefit related to continuing operations for the year ended December 31, 2017 includes a benefit ofapproximately $3.6 million as a result of the application of the exception to the general intra-period tax allocation rule. Accumulated other comprehensive incomeincludes a corresponding amount of income tax expense of approximately $3.6 million for the year ended December 31, 2017.The following table presents significant components of the Company’s deferred tax assets and deferred tax liabilities as follows (in thousands): 2017 2016Deferred tax assets: Accruals and prepaids $2,769 $2,331Basis difference in derivatives — 3,411Hatchet Ridge financing 17,351 27,521Asset retirement obligation 6,321 9,012Unrealized loss on derivatives 1,570 6,372Net operating loss carryforwards 274,730 344,522Foreign currency translation adjustments 3,239 12,314Other deferred tax assets 1,490 —Tax credits 41,563 19,270Total gross deferred tax assets 349,033 424,753Less: Valuation allowance (141,317) (171,020)Total gross deferred tax assets net of valuation allowance $207,716 $253,733 Deferred tax liabilities: Property, plant and equipment $(189,342) $(246,267)Partnership interest (65,124) (27,440)Deferred interest, commitment fees and financing costs (1,551) (4,543)Basis difference in subsidiaries (1,087) (865)Basis difference in derivatives (268) —Other deferred tax liabilities (486) (818)Total gross deferred tax liabilities (257,858) (279,933) Total net deferred tax assets/(liabilities) $(50,142) $(26,200)On December 22, 2017, the Tax Act was enacted, which significantly revises the ongoing U.S. corporate income tax law by lowering the U.S. federal corporateincome tax rate from 35% to 21% , implementing a territorial tax system and imposing a one-time tax on foreign unremitted earnings. The Tax Act also establishesseveral new tax provisions effective in 2018.ASC 740 requires a company to record the effects of a tax law change in the period of enactment. On December 22, 2017, the SEC staff issued Staff AccountingBulletin No. 118 (SAB 118) to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared,or analyzed in reasonable detail to complete the accounting for certain income tax effects of the Tax Act. SAB 118 allows registrants to record provisional amountsduring a one year “measurement period” similar to that used when accounting for business combinations. The measurement period ends when the company hasobtained, prepared and analyzed the information necessary to finalize its accounting, but cannot extend beyond one year. Accordingly, the Company's U.S.provision is based on the reasonable estimate guidance provided by SAB 118. The Company made a reasonable estimate of the impact of several provisions of theTax Act, including the repatriation provisions and the Tax Act’s reduction of the U.S. federal tax rate from 35% to 21% which impacts the Company's U.S.deferred tax assets and deferred liabilities. The U.S operations are in a net deferred tax asset position offset by a full valuation allowance and thus, any adjustmentsto the deferred accounts should not impact the tax provision. Although theF-38Company has made a reasonable estimate of the amounts related to the repatriation provisions and deferred tax assets and deferred tax liabilities disclosed, a finaldetermination of the Tax Act’s impact on the Company’s tax provision and deferred tax assets and deferred tax liabilities and related valuation allowancerequirements remains incomplete pending a full analysis of the provisions and their interpretations.The Tax Act also includes a provision to tax global intangible low-taxed income (GILTI) of foreign subsidiaries and a base erosion anti-abuse tax (BEAT) measurethat taxes certain payments between a U.S. corporation and its subsidiaries. The Company may be subject to the GILTI and/or BEAT provisions effectivebeginning January 1, 2018 and is in the process of analyzing their effects, including how to account for the GILTI provision from an accounting policy standpoint.The deferred tax assets and deferred tax liabilities resulted primarily from temporary differences between book and tax basis of assets and liabilities. The U.S.operations are in a net deferred tax asset position offset by full valuation allowance. The change in net deferred tax assets during the period ended December 31,2017 was mainly due to the reduction in the U.S. corporate income tax rate from 35% to 21% under the Tax Act. The Company revalued its ending deferred taxassets and liabilities at December 31, 2017 due to the change in tax rate resulting in a reduction of net deferred tax assets and corresponding valuation allowance of$55.3 million . The change was also due to deferred tax assets established for potential future U.S. foreign tax credits of $28.2 million that may be generated by thereversal of the deferred tax liability (foreign taxes paid) related to temporary differences from Canadian operations that are conducted through a branch for U.S. taxpurposes.The Company regularly assesses the likelihood that future taxable income levels will be sufficient to ultimately realize the tax benefits of the deferred tax assets.Should the Company determine that future realization of the tax benefits is not more likely than not, additional valuation allowance would be established whichwould increase the Company’s tax provision in the period of such determination. The net deferred tax assets and net deferred tax liabilities as of December 31,2017 and 2016 are attributed primarily to the Company’s Canadian, Puerto Rican and Chilean entities. The net change in valuation allowance was a decrease of$29.7 million during the year ended December 31, 2017 . The decrease was primarily driven by operating losses in the U.S. federal and state jurisdictions offset bya change in tax rate in the U.S. federal jurisdiction, as well as potential U.S. foreign tax credits related to Canada branch operations.As of December 31, 2017 , the Company has U.S federal and state net operating loss (NOL) carryforwards in the amount of $1.0 billion and $197.6 million ,respectively, which begin to expire in the year ending December 31, 2032 for federal and state purposes. The Company also has foreign net operating losscarryforwards in Canada of $75.2 million which begin to expire in the year ending December 31, 2029, foreign net operating loss carryforwards in Puerto Rico of$9.2 million that begins to expire in the year ending December 31, 2022, and foreign net operating loss carryforwards in Chile of $61.4 million that can be carriedforward indefinitely. The Company's production tax credits of $13.7 million begin to expire in the year ending December 31, 2033.Internal Revenue Code Section 382 places a limitation (the Section 382 Limitation) on the amount of taxable income that can be offset by NOL and creditcarryforwards, as well as built-in loss items, after a change in control (generally greater than 50% change in ownership) of a loss corporation. California has similarrules. The Company did not have any historic U.S. NOLs prior to October 2, 2013 except for NOLs from its Puerto Rico entity which may be subject toSection 382 Limitation.The Company experienced a change in ownership on May 14, 2014. As a result, the Company’s NOL carryforwards and credits generated through the date ofchange are subject to an annual limitation under Section 382. Accordingly, if the Company generates sufficient taxable income, the NOL carryforwards or creditsprior to the change in ownership are not expected to expire.The Company is required to recognize in the financial statements the impact of a tax position, if that position is more likely than not of being sustained on audit,based on the technical merits of the position. As of December 31, 2017 , the Company does not have any unrecognized tax benefits and does not have any taxpositions for which it is reasonably possible that the amount of gross unrecognized tax benefits will increase or decrease within 12 months after the year endedDecember 31, 2017 .The Company files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and foreign jurisdictions for its Canadian, Chilean and PuertoRican operations. The Company’s U.S. and foreign income tax returns for 2012 through 2017 are subject to examination.The Company has a policy to classify accrued interest and penalties associated with uncertain tax positions together with the related liability, and the expensesincurred related to such accruals are included in the provision for income taxes. The Company did not incur any interest expenses or penalties or have outstandingliabilities on the balance sheet associated with unrecognized tax benefits for the years ended December 31, 2017 , 2016 and 2015 .The Company operates under a tax holiday in Puerto Rico which enacted a special tax rate of 4% for businesses dedicated to the production of energy forconsumption through the use of renewal sources. The Company previously operated under the "Economic Incentives for the Development of Puerto Rico Act" (Act73) which was enacted in order to promote the development of green energy projects throughF-39economic incentives to reduce the island’s dependency on oil. On September 15, 2016, the Company surrendered operations under Act 73 and commencedoperations under the "Green Energy Incentives Act of Puerto Rico" (Act 83) which affords the Company identical tax benefits to Act 73 and extends the special taxrate for 25 years at the date of conversion. The impact of the tax holiday decreased foreign deferred tax benefit by $0.6 million for the year ended December 31,2017 . The impact of the tax holiday on basic and diluted net loss per share of Class A common stock for the year ended December 31, 2017 was $0.01 .14 . Stockholders' EquityPreferred StockThe Company has 100,000,000 shares of authorized preferred stock issuable in one or more series. The Company’s Board of Directors is authorized to determinethe designation, powers, preferences and relative, participating, optional or other special rights of any such series. As of December 31, 2017 and 2016 , there wasno preferred stock issued and outstanding.Common StockOn October 23, 2017, the Company completed an underwritten public offering of its Class A common stock. In total, 9,200,000 shares of the Company's Class Acommon stock were sold at a public offering price of $23.40 per share. This includes 1,200,000 shares purchased by the underwriters to cover over-allotments.Aggregate net proceeds of the equity offering, including the proceeds of the over-allotment option, were approximately $211.9 million after deduction ofunderwriting discounts, commissions, and transaction expenses.On August 12, 2016, the Company completed an underwritten public offering of its Class A common stock. In total, 10,000,000 shares of the Company's Class Acommon stock were sold. In connection with the equity offering, the underwriters had a 30-day option to purchase up to an additional 1,500,000 shares of Class Acommon stock to cover over-allotments. On August 22, 2016, the underwriters partially exercised their over-allotment option and purchased an additional1,300,000 shares of Class A common stock. Aggregate net proceeds of the equity offering, including the proceeds of the over-allotment option, wereapproximately $258.6 million after deduction of underwriting discounts, commissions, and transaction expenses.On May 9, 2016, the Company entered into an Equity Distribution Agreement with RBC Capital Markets, LLC, KeyBanc Capital Markets Inc. and MorganStanley & Co. LLC (collectively, the Agents). Pursuant to the terms of the Equity Distribution Agreement, the Company may offer and sell shares of theCompany’s Class A common stock, par value $0.01 per share, from time to time through the Agents, as the Company’s sales agents for the offer and sale of theshares, up to an aggregate sales price of $200.0 million . For the years ended December 31, 2017 and 2016 , the Company sold 1,068,261 and 1,240,504 shares,respectively, under the Equity Distribution Agreement; net proceeds under the issuances were $25.3 million and $27.5 million and the aggregate compensationpaid by the Company to the Agents with respect to such sales was $0.3 million and $0.3 million , respectively. As of December 31, 2017, approximately $144.2million in aggregate offering price remained available to be sold under the agreement.On July 28, 2015, the Company completed an underwritten public offering of its Class A common stock. In total, 5,435,000 shares of the Company's Class Acommon stock were sold. Net proceeds generated for the Company were approximately $120.8 million after deduction of underwriting discounts, commissions andtransaction expenses.On February 9, 2015, the Company completed an underwritten public offering of its Class A common stock. In total, 12,000,000 shares of the Company’s Class Acommon stock were sold. Of this amount, the Company issued and sold 7,000,000 shares of its Class A common stock and Pattern Development 1.0, the sellingstockholder, sold 5,000,000 shares of Class A common stock. The Company received net proceeds of approximately $196.2 million after deducting underwritingdiscounts and commissions and estimated offering expenses payable by the Company. The Company did not receive any proceeds from the sale of shares sold byPattern Development 1.0.Voting RightsHolders of the Company’s Class A common stock as of December 31, 2017 are entitled to one vote per share on all matters submitted to a vote of stockholders andwill vote as a single class under all circumstances.Dividend RightsHolders of Class A common stock are eligible to receive dividends on common stock held when funds are available and as approved by the Board of Directors.The following table presents cash dividends declared on Class A common stock for the periods presented:F-40 Dividends Per Share Declaration Date Record Date Payment Date2017: Fourth Quarter$0.4220 October 26, 2017 December 29, 2017 January 31, 2018Third Quarter$0.4200 August 3, 2017 September 29, 2017 October 31, 2017Second Quarter$0.4180 May 4, 2017 June 30, 2017 July 31, 2017First Quarter$0.4138 February 24, 2017 March 31, 2017 April 28, 2017Liquidation RightsIn the event of any liquidation, dissolution or winding-up of the Company, holders of Class A common stock will be entitled to share ratably in the Company’sassets that remain after payment or provision for payment of all of its debts and obligations and after liquidation payments to holders of outstanding shares ofpreferred stock, if any.Noncontrolling InterestsThe following table presents the balances for noncontrolling interests by project (in thousands). December 31, 2017 2016El Arrayán $31,828 $32,237Logan's Gap 171,137 180,092Panhandle 1 174,518 190,415Panhandle 2 208,397 170,139Post Rock 160,206 178,676Amazon Wind 133,950 139,687Broadview Project 307,672 —Meikle 65,985 —Noncontrolling interest $1,253,693 $891,246On December 22, 2017, pursuant to a Purchase and Sale Agreement with PSP Investments, the Company sold 49% of its indirect Class B membership interests inPanhandle 2 for consideration of $58.6 million . As of December 31, 2017, the Company owns 51% of Class B membership in Panhandle 2, and, as such, it stillretains a controlling financial interest.F-41The following table presents the components of total noncontrolling interest as reported in stockholders’ equity in the consolidated balance sheets (in thousands). Capital Accumulated Income(Loss) Accumulated OtherComprehensive Income(Loss) NoncontrollingInterestBalances at December 31, 2014$529,539 $9,892 $(8,845) $530,586Acquisition of Post Rock205,100 — — 205,100Buyout of noncontrolling interests(88,747) (14,244) 7,944 (95,047)Contributions from noncontrolling interests334,231 — — 334,231Distributions to noncontrolling interests(7,882) — — (7,882)Net loss— (23,074) — (23,074)Other comprehensive income (loss), net of tax— — 348 348Balances at December 31, 2015972,241 (27,426) (553) 944,262Distributions to noncontrolling interests(17,896) — — (17,896)Other(103) — — (103)Net loss— (35,188) — (35,188)Other comprehensive income, net of tax— — 171 171Balances at December 31, 2016954,242 (62,614) (382) 891,246Acquisition of Broadview and Meikle390,388 — — 390,388Distributions to noncontrolling interests(20,250) — — (20,250)Sale of a partial interest in Panhandle 2 to noncontrolling interests56,174 — — 56,174Other(214) — — (214)Net loss— (64,505) — (64,505)Other comprehensive income, net of tax— — 854 854Balances at December 31, 2017$1,380,340 $(127,119) $472 $1,253,693Allocations of Distributions and Tax Allocations for Tax Equity PartnershipsGenerally, tax equity partnerships have specific commercial terms that dictate distributions of cash and allocation of tax items among the partners, who are dividedinto one of two categories: tax equity and cash investor. A disproportionate share of income and cash is given to tax equity in order for them to achieve a targetafter-tax yield or “flip” near year 10 of project operations. The target yield and flip term vary by agreement and are dependent on project performance. Prior to theflip, tax items (income, US Federal production tax credits) are commonly allocated 99% to the tax equity. On the other hand, distributable cash is divided amongthe partners in percentages that do not match the tax items. Cash distribution percentages can be temporarily increased for tax equity in the event that certaincumulative distribution thresholds are not achieved. Once tax equity reaches their target yield, the allocations and distributions “flip” to different amounts. Afterthe flip, income and cash are typically allocated 5% to the tax equity and 95% to the cash investor. REC sales are often specially addressed in each agreement withmost of the cash and income directed to the cash investor both pre and post-flip.Tax equity partnership imposes a range of affirmative and negative covenants that are similar to what a term lender would require, such as, financial reporting,insurance maintenance and prudent operator standards. Most of these restrictions end once the flip point occurs and any deficit restoration obligation of the taxequity has been eliminated. There are also covenants that specifically seek to preserve the tax attributes of the project that are not customary for project termlenders.If tax equity suffers any losses or damages as the result of a breach of representation, covenant, or other obligation by the cash investor in its capacity as managingmember, tax equity may provide notice to the cash investor and require that any distributions otherwise required to be paid to the cash investor shall, instead, bepaid to tax equity to cover any damages.15 . Equity Incentive Award PlanUnder the Amended and Restated 2013 Equity Incentive Award Plan (2013 Plan), the Company may issue 3,000,000 aggregate number of shares of Class Acommon stock for equity awards including incentive and nonqualified stock options, restricted stock awards (RSAs)F-42and restricted stock units (RSUs) to employees, directors and consultants. RSAs provide the holder with immediate voting rights, but are restricted in all otherrespects until released. RSUs generally entitle the holders the right to receive the underlying shares of the Company's Class A common stock upon vesting. Uponcessation of services to the Company, any nonvested RSAs and RSUs will be forfeited. All nonvested RSAs and RSUs accrue dividends and distributions, whichare subject to vesting and paid in cash upon release. Accrued dividends and distributions are forfeitable to the extent that the underlying awards do not vest. As ofDecember 31, 2017 , there were 2,036,815 aggregate number of Class A shares available for issuance under the 2013 Plan.Stock-Based CompensationStock-based compensation expenses related to, RSAs, RSUs and stock options are recorded as a component of general and administrative expenses in theCompany’s consolidated statements of operations and totaled $5.3 million , $5.4 million and $4.5 million for the years ended December 31, 2017 , 2016 and 2015 ,respectively.Restricted Stock AwardsThe Company granted time-based RSAs to certain employees. The Company measures the fair value of the RSAs at the grant date and accounts for stock-basedcompensation by amortizing the fair value on a straight line basis over the related vesting period.The following table summarizes RSA activity under the 2013 Plan for the year ended December 31, 2017 : Shares Weighted-AverageGrant-Date Fair ValueNonvested at December 31, 2016 126,365 $21.31Granted 125,597 $20.35Vested (137,123) $22.29Forfeited (4,260) $14.81Nonvested at December 31, 2017 110,579 $19.26For the years ended December 31, 2017 , 2016 and 2015 , the total fair value of RSAs vested was $3.0 million , $2.1 million and $1.7 million , respectively. Theweighted-average grant date fair values per RSA granted during the same periods were $20.35 , $18.76 and $29.58 , respectively.As of December 31, 2017 , the total unrecorded stock-based compensation expense for nonvested RSAs was $2.1 million , which is expected to be amortized overa weighted-average period of 1.6 years .RSAs that contain Market ConditionsThe Company granted TSR-RSAs to certain senior management personnel. The number of awards granted represented the target number of shares of Class Acommon stock that may be earned; however, the number of vested TSR-RSAs is assessed at the end of a three -year performance period in accordance with thelevel of total shareholder return of the Company's stock price achieved relative to a peer group during the specified period. Following the date of grant, rights todividends will accrue on the maximum number of shares and may be forfeited if the market or service conditions are not achieved.F-43The Company measures the fair value of these restricted stock awards at the grant date using a Monte Carlo simulation model and amortizes the fair value over thelonger of the requisite period or performance period. The Company estimates expected volatility based on the actual volatility of the Company's daily closing shareprice since listing on September 27, 2013 and the historical volatility of comparable publicly traded companies for a period that is equal to the performance period.The risk-free interest rate is based on the yield on U.S. government bonds for a period commensurate with the performance period. The assumptions used toestimate the fair value of TSR-RSAs are as follows: Years ended December 31, 2017 2016 2015Expected stock price volatility (1) 34% 35% 30%Expected dividend yield N/A N/A N/ARisk-free interest rate 1.60% 1.11% 0.80%Expected performance period in years (2) 2.8 2.8 2.7(1) The expected volatility was estimated using the historical volatility derived from the Company's Class A common stock.(2) The expected performance period was estimated based on the length of the remaining performance period from the grant date.The following table summarizes TSR-RSAs activity under the 2013 Plan for the year ended December 31, 2017 : Shares Weighted-Average Grant-Date Fair ValueNonvested at December 31, 2016 147,804 $27.76Granted 71,073 $19.48Nonvested at December 31, 2017 218,877 $25.07For the years ended December 31, 2017 , 2016 , and 2015 , the weighted-average grant-date fair value per TSR-RSAs granted was $19.48 , $20.63 and $39.16 ,respectively.As of December 31, 2017 , the total unrecorded stock-based compensation expense related to nonvested TSR-RSAs was $1.9 million , which is expected to beamortized over a weighted-average period of 1.7 years .Restricted Stock UnitsIn 2017, 2016 and 2015, the Company granted time-based deferred RSUs to certain independent directors. Deferred RSUs are equity awards that entitle the holderthe right to receive shares of the Company's Class A common stock upon vesting and are settled on, or as soon as administratively possible after the settlement datewhich is January 1 following the date of the director's termination of service. The Company measures the fair value of deferred RSUs at the grant date andaccounts for stock-based compensation by amortizing the fair value on a straight line basis over the related vesting period.During the year ended December 31, 2017 , there were RSU grants of 27,714 shares, all of which vested. For the years ended December 31, 2017 , 2016 and 2015 ,the total fair value of deferred RSUs vested was $0.6 million , $0.5 million and $0.6 million , respectively. The weighted-average grant date fair value of stockawards granted during the same periods was $18.99 , $20.29 and $25.94 , respectively. As of December 31, 2017, there were no nonvested deferred RSUs.Stock OptionsDuring the years ended December 31, 2017 , 2016 and 2015, no options were granted or exercised.A summary of option activity under the employee share option plan as of December 31, 2017 , and changes during the year then ended is presented below.F-44 SharesWeighted-AverageExercise Price WeightedAverageRemainingContractual Life (in years) Aggregate IntrinsicValue ($000)Outstanding at December 31, 2016 429,962$22.00 Forfeited or expired (18,639)$22.00 Outstanding at December 31, 2017 411,323$22.00 5.7 —Exercisable at December 31, 2017 411,323 $22.00 5.7 —16 . Loss Per ShareBasic loss per share is computed by dividing net loss attributable to common stockholders by the weighted average number of common shares outstanding duringthe reportable period. Diluted loss per share is computed by adjusting basic loss per share for the effect of all potential common shares unless they are anti-dilutive.For purpose of this calculation, potentially dilutive securities are determined by applying the treasury stock method to the assumed exercise of in-the-money stockoptions and the assumed vesting of outstanding RSAs and release of deferred RSUs. Potentially dilutive securities related to convertible senior notes aredetermined using the if-converted method.The Company's vested deferred RSUs have non-forfeitable rights to dividends prior to release and are considered participating securities. Accordingly, they areincluded in the computation of basic and diluted loss per share, pursuant to the two-class method. Under the two-class method, distributed and undistributedearnings allocated to participating securities are excluded from net earnings (loss) attributable to common stockholders for purposes of calculating basic anddiluted earnings (loss) per share. However, net losses are not allocated to participating securities since they are not contractually obligated to share in the losses ofthe Company.Potentially dilutive securities excluded from the calculation of diluted earnings (loss) per share because their effect would have been anti-dilutive were 8.9 million,8.0 million and 3.5 million, respectively, for the years ended December 31, 2017 , 2016 and 2015 .The computations for Class A basic and diluted loss per share are as follows (in thousands except share data): Year ended December 31, 201720162015Numerator for basic and diluted loss per share: Net loss attributable to Pattern Energy$(17,905) $(17,111) $(32,533)Less: earnings allocated to participating securities (104) (53) (32)Net loss attributable to common stockholders$(18,009) $(17,164) $(32,565) Denominator for loss per share: Weighted average number of shares: Class A common stock - basic and diluted89,179,343 79,382,388 70,535,568 Loss per share: Class A common stock: Basic and diluted$(0.20) $(0.22) $(0.46) Dividends declared per Class A common share$1.67 $1.58 $1.43F-4517 . Commitments and ContingenciesCommitmentsThe following table summarizes estimates of future commitments related to the various agreements that the Company has entered into as of December 31, 2017 (inthousands): 2018 2019 2020 2021 2022 Thereafter TotalTransmission service agreements (1) $23,600 $23,600 $23,600 $23,600 $23,600 $520,465 $638,465Operating leases (2) 15,822 15,829 15,986 16,557 16,529 320,718 401,441Service and maintenance agreements 39,817 28,008 23,518 23,921 20,367 54,562 190,193Other commitments 46,576 4,130 3,416 2,695 1,545 16,270 74,632Total commitments $125,815 $71,567 $66,520 $66,773 $62,041 $912,015 $1,304,731(1) Future commitments under the transmission service agreements are based on current rates, which are subject to future changes.(2) Certain operating leases have adjustments for market provisions. Amounts in the above table represent the best estimates of future payments to be made under these leases.Transmission Service AgreementsIn connection with the Broadview Project acquisition, the Company became a party to various long-term transmission service agreements expiring between 25 - 30years. The Company recorded transmission service costs related to such agreements of $19.2 million for the year ended December 31, 2017 .Operating LeasesThe Company has entered into various non-cancellable long-term operating lease agreements related to offices and lands for its wind farms which expire in 2053.Certain of these arrangements contain contingent rental payment provisions based upon the volume of electricity generated at a particular windfarm. The Companyrecognizes rent expense under such arrangements on a straight-line basis. For the years ended December 31, 2017 , 2016 and 2015 , the Company recorded rentexpenses of $15.1 million , $13.1 million and $12.0 million , respectively, in project expense in its consolidated statements of operations.Service and Maintenance AgreementsThe Company has entered into service and maintenance agreements with third party contractors to provide turbine operations and maintenance services andmodifications and upgrades for varying periods over the next 17 years . The computation of outstanding commitments includes an estimated annual priceadjustment for inflation of 2% , where applicable. For the years ended December 31, 2017 , 2016 and 2015 , the Company recorded service and maintenanceexpense under these agreements of $47.1 million , $53.4 million and $42.9 million , respectively, in project expense in its consolidated statements of operations.Other CommitmentsIncluded in other commitments are acquisition commitments, payments in lieu of taxes, and various other commitments related to the Company's projects andoperations of its business. The acquisition commitment includes an agreement to purchase an ownership interest in a limited partnership described below.Payments in lieu of taxes include payments the Company is required to make in lieu of taxes as a result of tax savings realized as part of the issuance of theindustrial revenue bonds. See Note 5, Finite-Lived Intangible Assets and Liability, for further discussion.F-46On June 16, 2017, the Company entered into a purchase and sale agreement with Pattern Development 1.0 to purchase (i) a 51% limited partner interest in anewly-formed limited partnership (which will hold 100% of the economic interests in Mont Sainte-Marguerite Wind Farm LP (MSM), (ii) a 70% interest inPattern MSM GP Holdings Inc., and (iii) a 70% interest in Pattern Development MSM Management ULC, in exchange for aggregate consideration of CAD $53.0million (subject to certain adjustments). MSM operates the approximately 143 MW wind farm located near Québec City, Canada.Letters of CreditPower Sale AgreementsThe Company owns and operates wind power projects, and has entered into various long-term PSAs that terminate from 2019 to 2042 . The terms of theseagreements generally provide for the annual delivery of a minimum amount of electricity at fixed prices and in some cases include price escalation over the term ofthe agreement. Under the terms of these agreements, as of December 31, 2017 , irrevocable letters of credit totaling $156.5 million were available to be issued toguarantee the Company's performance for the duration of the agreements.Project Finance and Lease AgreementsThe Company has various project finance and lease agreements which obligate the Company to provide certain reserves to enhance its credit worthiness andfacilitate the availability of credit. As of December 31, 2017 , irrevocable letters of credit totaling $171.6 million which includes letters of credit available underthe Revolving Credit Facility were available to be issued to ensure performance under these various project finance and lease agreements.ContingenciesTurbine Operating Warranties and Service GuaranteesThe Company has various turbine availability warranties from its turbine manufacturers and service guarantees from its service and maintenance providers.Pursuant to these guarantees, if a turbine operates at less than minimum availability during the guarantee measurement period, the service provider is obligated topay, as liquidated damages at the end of the warranty measurement period, an amount for each percent that the turbine operates below the minimum availabilitythreshold. In addition, pursuant to certain of these guarantees, if a turbine operates at more than a specified availability during the guarantee measurement period,the Company has an obligation to pay a bonus to the service provider at the end of the warranty measurement period. As of December 31, 2017 , the Companyrecorded liabilities of $1.6 million associated with bonuses payable to turbine manufacturers and service providers.Contingencies in connection with the Broadview Project AcquisitionThe Company recorded a $7.2 million contingent obligation, payable to a third party who holds a 1% interest in Western Interconnect, at fair value upon theacquisition of the Broadview Project. These contingent payments are subject to certain conditions, including the actual energy production of Broadview in aproduction year and the continued operation of Broadview. Additionally, the Company recorded a $29.0 million contingent obligation, payable to the samecounterparty, at fair value upon the acquisition of the Broadview Project. These contingent payments are subject to certain conditions, including the commercialoperation of the Grady Project. The contingent payment is calculated as a percentage of additional transmission revenue earned by Western Interconnect upon theGrady Project's commercial operation.Contingencies in connection with the Sale of Panhandle 2 interestsIn connection with the sale of Panhandle 2, the Company agreed to indemnify PSP Investments up to $5.0 million to cover PSP Investments's pro rata share of theeconomic impacts resulting from planned transmission outages in the Texas market until December 31, 2019. As of December 31, 2017 , the Company recorded acontingent liability of $3.7 million associated with the indemnity.Legal MattersFrom time to time, the Company has become involved in claims and legal matters arising in the ordinary course of business. Management is not currently aware ofany matters that will have a material adverse effect on the financial position, results of operations, or cash flows of the Company.F-47IndemnityThe Company provides a variety of indemnities in the ordinary course of business to contractual counterparties and to its lenders and other financial partners. TheCompany is party to certain indemnities for the benefit of project finance lenders and tax equity partners of certain projects. These consist principally ofindemnities that protect the project finance lenders from, among other things, the potential effect of any recapture by the U.S. Department of the Treasury of anyamount of the Cash Grants previously received by the projects and eligibility of production tax credits and certain legal matters, limited to the amount of certainrelated costs and expenses.18 . Related Party TransactionsManagement feesThe Company provides management services and receives a fee for such services under agreements with its joint venture investees, South Kent, Grand, K2, andArmow, in addition to various Pattern Development 1.0 subsidiaries and equity method investments. The Company reclassified its presentation of managementservice fees received from related party to other revenue on the consolidated statements of operations.Management Services Agreement and Shared ManagementThe Company has entered into an Amended and Restated Multilateral Management Services Agreement (MSA) with the Pattern Development Companies, whichprovides for the Company and the Pattern Development Companies to benefit, primarily on a cost-reimbursement basis, from the parties’ respective managementand other professional, technical and administrative personnel, all of whom report to the Company’s executive officers. Costs and expenses incurred at the PatternDevelopment Companies or their respective subsidiaries on the Company's behalf will be allocated to the Company. Conversely, costs and expenses incurred at theCompany or its respective subsidiaries on the behalf of a Pattern Development Company will be allocated to the respective Pattern Development Company.Pursuant to the MSA, certain of the Company’s executive officers, including its Chief Executive Officer (shared PEG executives), also serve as executive officersof the Pattern Development Companies and devote their time to both the Company and the Pattern Development Companies as is prudent in carrying out theirexecutive responsibilities and fiduciary duties. The shared PEG executives have responsibilities for both the Company and the respective Pattern DevelopmentCompanies and, as a result, these individuals do not devote all of their time to the Company’s business. Under the terms of the MSA, each of the respective PatternDevelopment Companies is required to reimburse the Company for an allocation of the compensation paid to such shared PEG executives reflecting the percentageof time spent providing services to such Pattern Development Company. The Company reclassified its presentation of related party receivables and payables asdisclosed in prior periods to be presented within other current assets and other current liabilities on the consolidated balance sheets, respectively. In addition, theCompany reclassified its presentation of reimbursements received from the Pattern Development Companies under the MSA from related party income, asdisclosed in prior periods, to a reduction to general and administrative expense on the consolidated statements of operations. The MSA costs incurred by theCompany are included in related party general and administrative on the consolidated statements of operations.Employee Savings PlanThe Company participates in a 401(k) plan sponsored and maintained by Pattern Development 1.0, established on August 3, 2009 and restated on October 3, 2013.The Company also sponsors a Canadian Registered Retirement Savings Plan (RRSP), established on October 2, 2013. Participants in the plans are allowed to defera portion of their compensation, not to exceed the respective Internal Revenue Service or Canada Revenue Agency annual allowance contribution guidelines, andare 100% vested in their respective deferrals and earnings. Participants may choose from a variety of investment options. The Company contributes 5% of basecompensation to each employee’s 401(k) or RRSP account, up to the annual compensation limit. For the years ended December 31, 2017 , 2016 and 2015 , theCompany contributed $0.8 million , $0.7 million and $0.5 million , respectively which was recorded as general and administrative expense on the consolidatedstatements of operations.F-48Related Party TransactionsThe table below presents amounts due from and to related parties as included in the consolidated balance sheets for the following periods (in millions): December 31, 2017 2017 2016Other current assets: Total due from related parties$13.2 $1.1 Other current liabilities: Total due to related parties$10.8 $1.3The table below presents the revenue, reimbursement and (expenses) recognized for management services and under the MSA, as included in the statements ofoperations for the following periods (in thousands): Years Ended December 31,Related Party AgreementFinancial Statement Line Item2017 2016 2015Management feesOther revenue$7,742 $5,793 $3,640MSA reimbursementGeneral and administrative$11,685 $5,074 $2,665MSA costsRelated party general and administrative expense$(13,825) $(9,900) $(7,589)Purchase and Sales AgreementsDuring the years ended December 31, 2017 , and 2016, the Company consummated the following investment and acquisitions with Pattern Development 1.0 and2.0 which are further detailed in Note 3, Acquisitions (in millions):Investment in Pattern Development 2.0 Date of Investment Cash Consideration Debt Assumed ContingentConsiderationPattern Development 2.0 various $67.3 N/A N/AAcquisitions from Pattern Development 1.0 Date of Acquisition Cash consideration Debt Assumed Contingent ConsiderationBroadview Project April 21, 2017 $214.7 $51.1 $21.3Meikle August 10, 2017 67.4 265.6 N/AArmow October 17, 2016 132.3 193.6 N/AInvestment in Pattern Development 2.0On July 27, 2017, the Company funded an initial investment of $60.0 million in Pattern Development 2.0. On December 26, 2017, the Company contributed anadditional $7.3 million to Pattern Development 2.0. As a result of such funding, and the related funding by other investors in Pattern Development 2.0 andconsummation of certain redemptions, the Company holds an approximate 21% ownership interest in Pattern Development 2.0.PSP Investments Joint VentureIn June 2017, the Company entered into a Joint Venture Agreement with PSP Investments pursuant to which PSP Investments will have the right to co-invest up toan aggregate amount of approximately $500 million in projects acquired by the Company under its identified ROFO project list with the Pattern DevelopmentCompanies, including investments in Meikle, MSM and Panhandle 2. As discussed in Note 3, Acquisitions and Note 14, Stockholders' Equity , PSP Investmentsacquired a 49% interest in Meikle and 49% of Class B membership in Panhandle 2 during 2017. In addition, on June 16, 2017, PSP Investments purchasedapproximately 8.7 million shares of the Company's common stock from Pattern Development 1.0 and an additional 0.6 million shares from the Company's publicoffering that occurred on October 23, 2017.F-49Sponsor Services AgreementOn June 16, 2017, the Company entered into a Sponsor Services Agreement with PSP Investments, pursuant to which we will provide certain mutually agreedservices to PSP Investments and its affiliates with respect to the administration of the joint ownership of the project companies that PSP Investments invests inalongside us pursuant to the PSP Investments Joint Venture Agreement in exchange for certain fees set forth in the Sponsor Services Agreement. Related party feeamounts recorded during 2017 were immaterial.19 . Selected Quarterly Financial Data (Unaudited)The following tables summarize the Company’s unaudited quarterly consolidated statements of operations for each of the eight quarters in the two year periodended December 31, 2017 . The quarterly consolidated statements of operations data were prepared on a basis consistent with the audited consolidated financialstatements included in this Annual Report on Form 10-K.Quarterly financial data in thousands, except per share data: Three months ended December 31, September 30, June 30, March 31, 2017 2017 2017 2017Revenue $110,721 $92,030 $107,760 $100,833Gross profit $15,331 $(1,702) $21,115 $27,923Net income (loss) $(21,889) $(48,376) $(14,684) $2,539Net loss attributable to noncontrolling interest $(13,939) $(18,548) $(28,904) $(3,114)Net income (loss) attributable to Pattern Energy $(7,950) $(29,828) $14,220 $5,653Basic and diluted earnings (loss) per share—Class A common stock $(0.08) $(0.34) $0.16 $0.06Cash dividends declared per Class A common share $0.42 $0.42 $0.42 $0.41 Three months ended December 31, September 30, June 30, March 31, 2016 2016 2016 2016Revenue $81,061 $91,914 $93,438 $87,639Gross profit $5,490 $16,837 $16,401 $11,982Net income (loss) $3,445 $(11,050) $(15,646) $(29,048)Net loss attributable to noncontrolling interest $(10,350) $(7,037) $(12,423) $(5,378)Net income (loss) attributable to Pattern Energy $13,795 $(4,013) $(3,223) $(23,670)Basic and diluted earnings (loss) per share—Class A common stock $0.16 $(0.05) $(0.04) $(0.32)Cash dividends declared per Class A common share $0.41 $0.40 $0.39 $0.3820 . Subsequent EventsOn February 22, 2018 , the Company approved a dividend for the first quarter 2018, payable on April 30, 2018 , to holders of record on March 30, 2018 , in theamount of $0.4220 per Class A share, which represents $1.688 on an annualized basis.On February 26, 2018 , the Company entered into a series of purchase and sale agreements with Pattern Development 1.0 and Green Power Investments topurchase 206 MW of renewable energy projects, consisting of Futtsu Solar, Kanagi Solar, Otsuki, Ohorayama and Tsugaru. The acquisition price for the 84 MWproject portfolio (Futtsu Solar, Kanagi Solar, Otsuki and Ohorayama) is approximately $131.5 million , subject certain closing price adjustments. The acquisitionprice of Tsugaru for the 122 MW wind project is approximately $194.0 million , consisting of an initial payment of approximately $79.7 million to be funded atclosing and approximately $114.3 million payable to Pattern Development 1.0 upon the term conversion of the construction loan and to the extent such termconversion does notF-50occur, such second consideration payment will be made upon the commencement of commercial operations at Tsugaru which is expected in 2020.In February 2018, the Company also funded approximately $35.2 million into Pattern Development 2.0 of which approximately $27 million will be used by PatternDevelopment 2.0 to fund the purchase of GPI.F-51Condensed Parent-Company Financial StatementsPattern Energy Group Inc.Condensed Financial Information of ParentBalance Sheets(In thousands of U.S. dollars, except share and par value data) December 31,2017 December 31,2016Assets Current assets: Cash and cash equivalents$9,282 $12,014Derivative assets, current5 1,369Prepaid expenses1,014 583Other current assets24,252 4,882Deferred financing costs, current, net— 11Total current assets34,553 18,859Restricted cash250 250Property, plant and equipment, net4,093 4,362Investments in subsidiaries1,404,245 987,300Investments in unconsolidated subsidiaries311,223 233,294Derivative assets— 177Deferred financing costs— 75Net deferred tax assets181 —Finite-lived intangible assets, net964 1,052Other assets1,132 138Total assets$1,756,641 $1,245,507Liabilities and equity Current liabilities: Accounts payable and other accrued liabilities$11,577 $9,107Accrued interest12,738 4,328Dividend payable41,387 35,960Derivative liabilities, current3,154 391Other current liabilities9,042 1,310Total current liabilities77,898 51,096Long-term debt, net of financing costs of $8,641 and $3,894 as of December 31, 2017 and 2016, respectively552,889 202,910Other long-term liabilities31,405 4,003Total liabilities662,192 258,009Equity: Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 97,860,048 and 87,410,687 sharesoutstanding as of December 31, 2017 and December 31, 2016, respectively980 875Additional paid-in capital1,207,286 1,118,200Accumulated loss(84,615) (66,710)Accumulated other comprehensive loss(25,691) (62,367)Treasury stock, at cost; 157,812 and 110,964 shares of Class A common stock as of December 31, 2017 and 2016,respectively(3,511) (2,500)Total equity1,094,449 987,498Total liabilities and equity$1,756,641 $1,245,507See accompanying notes to parent company financial statementsS- 1Pattern Energy Group Inc.Condensed Financial Information of ParentStatements of Operations and Comprehensive Income (Loss)(In thousands of U.S. dollars) Year ended December 31, 2017 2016 2015Revenue$— $— $—Expenses34,257 34,132 26,818Operating loss(34,257) (34,132) (26,818)Other income (expense): Interest expense(34,889) (14,692) (6,107)Equity in earnings (loss) from subsidiaries14,333 3,054 (19,058)Equity in earnings from unconsolidated subsidiaries, net41,299 30,192 16,119Gain (loss) on undesignated derivatives, net(6,767) (1,496) 5,107Other income (expense), net(1,247) 130 (1,558)Total other income (expense), net12,729 17,188 (5,497)Net loss before income tax(21,528) (16,944) (32,315)Tax provision (benefit)(3,623) 167 218Net loss(17,905) (17,111) (32,533)Other comprehensive income (loss): Proportionate share of subsidiaries' other comprehensive income (loss), net of tax benefit(provision) of ($5,350), $(53) and $1,206, respectively22,863 5,325 (16,085)Proportionate share of affiliates' other comprehensive income (loss) activity, net of tax benefit(provision) of ($4,981), $(2,031) and $1,524, respectively13,813 5,633 (4,228)Total other comprehensive income (loss), net of tax36,676 10,958 (20,313)Comprehensive income (loss)$18,771 $(6,153) $(52,846)See accompanying notes to parent company financial statementsS- 2Pattern Energy Group Inc.Condensed Financial Information of ParentCondensed Statements of Cash Flows(In thousands of U.S. dollars) Year ended December 31, 2017 2016 2015Operating activities Net loss$(17,905) $(17,111) $(32,533)Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation and accretion561 198 —Amortization of financing costs1,982 1,102 472Amortization of debt discount4,726 4,428 1,794Deferred taxes3,387 — —Intraperiod tax allocation(3,569) — —(Gain) loss on derivatives4,773 2,955 (4,110)Stock-based compensation5,322 5,391 4,462Equity in losses (earnings) from subsidiaries(14,333) (3,054) 19,058Equity in earnings from unconsolidated investments, net(41,299) (30,192) (16,119)Other reconciling items— (493) —Changes in operating assets and liabilities: Prepaid expenses(430) (97) 35Other current assets(19,581) (1,616) (1,782)Other assets (non-current)— (138) —Accounts payable and other accrued liabilities2,573 1,691 473Other current liabilities7,727 (333) 1,642Long-term liabilities1,221 3,713 —Accrued interest payable8,410 486 3,842Net cash used in operating activities(56,435) (33,070) (22,766)Investing activities Cash paid for acquisitions, net of cash acquired— — (65,042)Capital expenditures(287) (3,889) —Distributions received from subsidiaries371,999 307,978 244,969Contribution to subsidiaries(682,013) (449,710) (613,089)Investment in Pattern Development 2.0(68,813) — —Other assets(520) (1,236) —Other investing activities— (172) —Net cash used in investing activities(379,634) (147,029) (433,162)S- 3 Year ended December 31, 2017 2016 2015Financing activities Proceeds from public offering, net of issuance costs237,090 286,298 317,432Proceeds from issuance of senior notes, net of issuance costs343,271 — 218,929Refund for deposit for letters of credit— — 3,425Dividends paid(145,207) (120,207) (90,582)Other financing activities(1,817) (916) (860)Net cash provided by financing activities433,337 165,175 448,344Net change in cash, cash equivalents and restricted cash(2,732) (14,924) (7,584)Cash, cash equivalents and restricted cash at beginning of period12,264 27,188 34,772Cash, cash equivalents and restricted cash at end of period$9,532 $12,264 $27,188Supplemental disclosures Cash payments for income taxes$— $167 $218Cash payments for interest expense$19,771 $8,675 $—Equity issuance costs paid in prior period related to current period offerings$— $— $433Schedule of non-cash activities Non-cash increase in additional paid-in capital$(2,003)$—$16,715See accompanying notes to parent company financial statementsS- 4Pattern Energy Group Inc.Note to Parent Company Financial StatementsSupplemental Notes1. Summary of Significant Accounting PoliciesBasis of PresentationThe condensed, standalone financial statements of Pattern Energy Group Inc. (parent company) have been presented in accordance with Rule 12-04, Schedule I ofRegulation S-X as the restricted net assets of the subsidiaries of the parent company exceed 25% of the consolidated net assets of the parent company and itssubsidiaries. The condensed parent company financial statements have been prepared in accordance with United States generally accepted accounting principlesand should be read in conjunction with the parent company’s consolidated financial statements and the accompanying notes thereto.Reconciliation of Cash and Cash Equivalents and Restricted Cash as presented on the Statements of Cash Flows Year ended December 31, 2017 2016 2015 Cash and cash equivalents $9,282 $12,014 $26,938Restricted cash 250 250 250Cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows $9,532 $12,264 $27,188InvestmentsFor purposes of these financial statements, the parent company’s wholly owned and majority owned subsidiaries are recorded based on its proportionate share ofthe subsidiaries’ assets. The parent company’s share of net income of its unconsolidated subsidiaries is included in income using the equity method.Debt2024 Unsecured Senior NotesIn January 2017, the Company issued unsecured senior notes with an aggregate principal amount of $350.0 million (the 2024 Unsecured Senior Notes). Netproceeds to the Company were approximately $345.0 million, after deducting the initial purchasers’ discount, commissions and transaction expenses. The 2024Unsecured Senior Notes bear interest at a rate of 5.875% per year, payable semiannually in arrears on February 1 and August 1, beginning on August 1, 2017 andmaturing on February 1, 2024, unless repurchased or redeemed at an earlier date. The 2024 Unsecured Senior Notes are guaranteed on a senior unsecured basis byPattern US Finance Company, one of the Company's subsidiaries.Convertible Senior Notes due 2020In July 2015, the Company issued $225 million aggregate principal amount of 4.00% convertible senior notes due 2020 (2020 Notes). The 2020 Notes bear interestat a rate of 4.00% per year, payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2016. The 2020 Notes will mature onJuly 15, 2020. The 2020 Notes were sold in a private placement. Upon conversion, the Company may, at its discretion, pay cash, shares of the Company’s Class Acommon stock, or a combination of cash and stock. The 2020 Notes are set at an initial conversation rate of 35.4925 shares of Class A common stock per $1,000principal amount of 2020 Notes, which is equivalent to an initial conversion price of approximately $28.175 per share of Class A common stock. The conversionrate is subject to adjustment in some events (including, but not limited to, certain cash dividends made to holders of the Company's Class A common stock whichexceed the initial dividend threshold of $0.363 per quarter per share). The conversion rate would be adjusted to offset the effect of the portion of the dividend inexcess of $0.363 , provided that the adjustment would result a change of at least 1% in the then effective conversion rate. During the year ended December 31,2017, the conversion rate increased to 35.8997 shares of Class A common stock per $1,000 principal amount of 2020 Notes. The conversion rate will not beadjusted for any accrued and unpaid interest. The 2020 Notes are not redeemable prior to maturity.S- 5The 2020 Notes are guaranteed on a senior unsecured basis by a subsidiary of the Company and are general unsecured obligations of the Company. The obligationsrank senior in rights of payment to the Company’s subordinated debt, equal in right of payment to the Company’s unsubordinated debt and effectively junior inright of payment to any of the Company’s secured indebtedness to the extent of the value of the assets securing such indebtedness.The following table presents a summary of the equity and liability components of the 2020 Notes (in thousands):December 31,2017 2016Principal$225,000 $225,000Less: Unamortized debt discount(13,470) (18,196)Unamortized financing costs(2,794) (3,894)Carrying value of convertible senior notes$208,736 $202,910 Carrying value of the equity component (1)$23,743 $23,743(1)Included in the consolidated balance sheets as additional paid-in capital, net of $0.7 million in equity issuance costs.Commitments and ContingenciesOperating Leases 2018 2019 2020 2021 2022 Thereafter TotalOperating leases $3,678 $3,766 $3,855 $3,947 $4,041 $15,328 $34,615On February 3, 2016, the Company entered into a lease agreement for office facilities in Houston, Texas, effective August 2016, to replace the PatternDevelopment 1.0-leased office facilities which expired in June 2016. In addition, effective January 1, 2016, Pattern Development 1.0 assigned to the Company, allof Pattern Development 1.0’s rights, title, commitments and interest under an office lease, dated as of September 9, 2009, with respect office space in SanFrancisco. As a result of this lease assignment, the Company assumed remaining rental commitments under the lease plus certain annual operating expensereimbursements and customary security deposits. Concurrently with the lease assignment, the Company entered into an extension through 2026 of the office lease,which previously terminated at the end of February 2017. Total future commitments are included in operating leases in the table above.S- 6South Kent Wind LPFinancial Statementsin accordance with accounting principlesgenerally accepted in the United Statesof America (U.S. GAAP)December 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)S- 7South Kent Wind LP ContentsPage Independent Auditor’s ReportS- 9 Financial Statements Balance SheetsS- 10Statements of Operations and Comprehensive Income (Loss)S- 11Statements of Changes in Partners’ EquityS- 12Statements of Cash FlowsS- 13Notes to Financial StatementsS- 14 S- 8February 20, 2018Report of Independent Registered Public Accounting FirmTo the Board of Directors of South Kent Wind LPOpinion on the Financial StatementsWe have audited the accompanying balance sheets of South Kent Wind LP (the Partnership) as of December 31, 2017 and December 31, 2016, and the relatedstatements of operations and comprehensive income, statement of changes in partners' equity, and statement of cash flows for each of the three years in the periodended December 31, 2017, including the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, inall material respects, the financial position of the Partnership as of December 31, 2017 and December 31, 2016, and its results of operations and its cash flows foreach of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America (USGAAP).Basis for OpinionThese financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financialstatements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) andare required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of theSecurities and Exchange Commission and the PCAOB.We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditto obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion./s/ PricewaterhouseCoopers LLPChartered Professional Accountants, Licensed Public AccountantsToronto, CanadaWe have served as the Partnership's auditor since 2011.PricewaterhouseCoopers LLP PwC Tower, 18 York Street, Suite 2600, Toronto, Ontario, Canada M5J 0B2T: +1 416 863 1133, F: +1 416 365 8215, www.pwc.com/ca“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.S- 9South Kent Wind LPBalance SheetsAs of December 31, 2017 and 2016(In thousands of Canadian Dollars) 2017 2016ASSETS Current assets: Cash and cash equivalents $12,842 $16,074Restricted cash (note 3) 1,982 2,057Accrued revenue (note 2) 20,911 21,706Other current assets 386 429Total current assets 36,121 40,266Property, plant and equipment - net of accumulated depreciation of $116,245 and $86,966 in 2017 and 2016, respectively(note 4) 620,841 650,010Intangible assets - net of accumulated amortization of $812 and $770 in 2017 and 2016, respectively (note 5) 626 668Total assets $657,588 $690,944 LIABILITIES & EQUITY Current liabilities: Accounts payable and other accrued liabilities $3,187 $2,705Accounts payable and other accrued liabilities - related parties (note 11) 217 193Current portion of long-term debt, net of financing costs of $3,296 and $3,426 in 2017 and 2016, respectively (notes 2and 6) 23,523 22,347Current portion of long-term contingent liabilities (note 10) 541 1,050Derivative liabilities, current (note 8) 6,415 11,397Other current liabilities 235 160Total current liabilities 34,118 37,852Long-term debt, net of financing costs of $8,095 and $11,391 in 2017 and 2016, respectively (notes 2 and 6) 581,027 604,550Long-term contingent liabilities, net of current (note 10) 7,500 8,000Derivative liabilities (note 8) 19,384 36,876Asset retirement obligation (note 7) 6,493 6,153Total liabilities 648,522 693,431Commitments and contingencies (note 10) Equity: Partners’ capital (130,122) (61,730)Accumulated net income 139,188 59,243Total partners’ equity 9,066 (2,487)Total liabilities and equity $657,588 $690,944See accompanying notes to financial statements.S- 10South Kent Wind LPStatements of Operations and Comprehensive IncomeFor the years ended December 31, 2017, 2016 and 2015(In thousands of Canadian Dollars) 2017 2016 2015Revenue (note 2): Energy delivered $65,867 $87,142 $102,076Compensation for forgone energy 64,739 38,326 22,345Other revenue 2,376 2,297 2,981 Total revenue 132,982 127,765 127,402Cost of revenue: Project expenses 10,900 13,064 13,232Project expenses - related parties (note 11) 1,491 1,469 1,446Depreciation, amortization and accretion 29,662 29,698 29,710 Total cost of revenue 42,053 44,231 44,388Gross profit 90,929 83,534 83,014Operating expenses: General and administrative 524 504 929General and administrative - related parties (note 11) 523 516 507 Total operating expenses 1,047 1,020 1,436Operating income 89,882 82,514 81,578Other expense: Interest expense (note 6) (31,477) (32,596) (35,342)Unrealized gain (loss) on derivatives (note 8) 22,474 3,269 (18,428)Other expense, net (934) (912) (1,099) Total other expense (9,937) (30,238) (54,869)Net income 79,945 52,276 26,709Other comprehensive income - - -Comprehensive income $79,945 $52,276 $26,709See accompanying notes to financial statements.S- 11South Kent Wind LPStatements of Changes in Partners’ EquityFor the years ended December 31, 2017, 2016 and 2015(In thousands of Canadian Dollars) Partners’capital Accumulatednet income (loss) TotalBalance at January 1, 2015 $53,412 $(19,742) $33,670 Cash distribution (50,712) - (50,712)Net loss - 26,709 26,709 Balance at December 31, 2015 2,700 6,967 9,667 Cash distribution (64,430) - (64,430)Net income - 52,276 52,276 Balance at December 31, 2016 (61,730) 59,243 (2,487) Cash distribution (68,392) - (68,392)Net income - 79,945 79,945 Balance at December 31, 2017 $(130,122) $139,188 $9,066See accompanying notes to financial statements.S- 12South Kent Wind LPStatements of Cash FlowsFor the years ended December 31, 2017, 2016 and 2015(In thousands of Canadian Dollars) 2017 2016 2015Cash flows from operating activities: Net income (loss) $79,945 $52,276 $26,709Adjustment to reconcile net income (loss) to net cash provided by (used in)operating activities: Unrealized loss (gain) on derivatives (22,474) (3,269) 18,428Depreciation, amortization and accretion 29,662 29,698 29,710Amortization of deferred financing costs 3,426 3,546 3,388Changes in assets and liabilities, net: Accrued revenue 794 (3,539) (2,204)Accounts payable and other accrued liabilities (3) 103 (2,555)Other, net 118 182 168 Net cash provided by operating activities 91,468 78,997 73,644 Cash flows from investing activities: Capital expenditures (610) (4,247) (247)Decrease in restricted cash 75 4,494 8,302Increase in restricted cash 0 (1) (836) Net cash provided by (used in) investing activities (535) 246 7,219 Cash flows from financing activities: Proceeds from long-term debt - - 5,106Repayment of long-term debt (25,773) (22,109) (23,185)Deferred financing costs paid - - (5,129)Distribution to partners (68,392) (64,430) (50,712) Net cash (used in) provided by financing activities (94,165) (86,539) (73,920) Net change in cash and cash equivalents (3,232) (7,296) 6,943 Cash and cash equivalents - Beginning of year 16,074 23,370 16,427 Cash and cash equivalents - End of year $12,842 $16,074 $23,370 Supplemental disclosure: Cash payments for interest and commitment fees $27,978 $28,894 $31,954Schedule of non-cash activities: Remeasurement of asset retirement obligation $— $— $1,027See accompanying notes to financial statements.S- 13South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)1General informationThe PartnershipSouth Kent Wind LP (the Partnership), a limited partnership under the laws of the Province of Ontario, was formed on January 10, 2011, as a joint ventureproject between Samsung Renewable Energy Inc. (Samsung) and Pattern South Kent LP Holdings LP, a subsidiary of Pattern Renewable Holdings CanadaULC (PRHC), each as 49.99% limited partners of the Partnership, and South Kent Wind GP Inc. (the GP), as the 0.02% general partner of the Partnership.The Partnership was created to develop, build and operate a wind power project in the Regional Municipality of Chatham-Kent with generation capacitytotaling approximately 270 megawatts (MW) of power (the Project).On February 24, 2013, Samsung transferred all of its LP interest in the Partnership to SRE SKW LP Holdings LP, an affiliate of Samsung.On October 2, 2013, in a series of transactions: (i) Pattern South Kent GP Holdings Inc., a wholly owned subsidiary of PRHC, transferred all of the generalpartner interests in Pattern South Kent LP Holdings LP to PRHC, causing Pattern South Kent LP Holdings LP to be dissolved by operation of law and PRHCto acquire the LP interests in the Partnership that previously were held by Pattern South Kent LP Holdings LP; (ii) PRHC transferred its LP interest in thePartnership and its ownership interest in Pattern South Kent GP Holdings Inc., which owned PRHC’s ownership interest in the GP, to Pattern CanadaOperations Holdings ULC (PCOH), a wholly owned subsidiary of Pattern Energy Group Inc. (Pattern); and (iii) Pattern South Kent GP Holdings Inc. wasdissolved.On December 17, 2014, PCOH transferred all of its LP interest in the Partnership to Pattern Canada Finance Company ULC, a wholly owned subsidiary ofPCOH.The Partnership is controlled by its general partner, the GP, also a joint venture controlled by affiliates of Samsung and Pattern. As of December 31, 2017 and2016, the Partnership’s ownership interests were distributed as follows: 2017 2016SRE SKW LP Holdings LP 49.99% 49.99%Pattern Canada Finance Company ULC 49.99 49.99South Kent Wind GP Inc. 0.02 0.02Total 100.00% 100.00%The ProjectThe Project is a 270 MW wind project consisting of 124 Siemens wind turbine generators located in the Regional Municipality of Chatham-Kent, Ontario. OnMarch 28, 2014 the Project achieved the Commercial Operation Date (“COD”) and commenced commercial operations.The Partnership has a power purchase agreement ("PPA") with the Independent Electricity System Operator (IESO) for a period of 20 years from the COD.The IESO oversees the wholesale electricity market, where the price of energy is determined. It also administers the rules that govern the market and, throughan arm's-length market monitoring function, ensures that it is operated fairly and efficiently. The IESO is an agent among the market participants in Ontarioand is neither exposed to, nor benefits from, any transactions. In such capacity, the IESO executes agreements to help the market meet the renewable energymandates of the government of the Province of Ontario. There are approximately 70 electric distribution companies in Ontario, all of which have governmentmandates to purchase renewable energy. The PPA provides for guaranteed pricing from IESO that removes volatility caused by fluctuations in market rates.The Ontario government established the Global Adjustment (“GA”) which is designed to adjust consumer rates depending on the price of energy. The IESOestablishes a monthly variable GA rate based on GA costs and Ontario electricity demand which effectively establishes a pass through mechanism to theconsumer and eliminates the IESO's economic exposure to our contract price.S- 14South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)2 Summary of significant accounting policiesThe principal accounting policies applied in the preparation of these financial statements are set out below. These policies have been consistently applied tothe periods presented, unless otherwise stated.Basis of preparationThe accompanying financial statements are presented using accounting principles generally accepted in the United States of America (U.S. GAAP). Thepreparation of U.S. GAAP financial statements requires management to make certain estimates and assumptions that affect the reported amounts of assets andliabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expensesduring the reporting period. Because the use of estimates is inherent in the financial reporting process, actual results could differ from those estimates.In recording transactions and balances resulting from business operations, the Partnership uses estimates based on the best information available. Estimatesare used for such items as accrued revenue, asset retirement obligation, valuation of derivative contracts and contingencies.These financial statements do not include assets, liabilities, revenue and expenses of the GP and limited partners. The financial statements of the Partnershipreflect no provision or liability for income taxes because profits and losses of the Partnership are allocated to the partners and are included in the income taxreturns of the partners. Income and losses for tax purposes may differ from the financial statement amounts and the partners’ equity reflected in the financialstatements does not necessarily reflect their tax basis.Functional and presentation currencyItems included in the financial statements of the Partnership are measured using the currency of the primary economic environment in which the Partnershipoperates (the functional currency). The financial statements are presented in Canadian Dollars, which is the Partnership’s functional and presentationcurrency.Fair value of financial instrumentsASC 820, Fair Value Measurements, defines fair value as the price at which an asset could be exchanged or a liability transferred in an orderly transactionbetween knowledgeable, willing parties in the principal or most advantageous market for the asset or liability. Where available, fair value is based onobservable market prices or derived from such prices. Where observable prices or inputs are not available, valuation models are applied. These valuationtechniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments ormarket and the instruments’ complexity.Cash and cash equivalentsCash and cash equivalents include cash on hand, deposits held at call with banks and other short-term highly liquid investments with original maturities ofthree months or less.Restricted cashRestricted cash mainly consists of cash reserves required under the Partnership’s loan agreements and security deposits required to collateralize commercialbank letter of credit facilities related to easement rights (note 3).Trade receivablesThe Partnership’s trade receivables are generated by selling energy in Ontario, Canada through the IESO as a settlement agent. The allowance for doubtfulaccounts, if needed, is computed based upon management’s estimates of uncollectible accounts. As of December 31, 2017 and 2016, the Partnership has nooutstanding trade receivables.S- 15South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)Accrued revenueAccrued revenue represents revenues recognized on contracts for which billings have not been presented to customers as of the balance sheet date. Theseamounts are billed and generally collected within two months.Concentration of credit riskFinancial instruments that potentially subject the Partnership to concentrations of credit risk consist primarily of cash and cash equivalents and restricted cash.The Partnership places its cash and cash equivalents and restricted cash with creditworthy institutions located in Canada, which the management believes tohave minimal risk. At times, such balances may be in excess of the Canada Deposit Insurance Corporation (CDIC) insurance coverage limit. CDIC insurancecurrently covers up to $100 per depositor at each insured bank.The Partnership’s derivative agreements expose the Partnership to losses under certain circumstances, such as the counterparty defaulting on its obligationsunder the swap agreements or if the swap agreements provide an imperfect hedge. Counterparties to the Partnership’s derivative contracts are major financialinstitutions that have been accorded investment grade ratings.Property, plant and equipmentProperty, plant and equipment are stated at historical cost, less accumulated depreciation. Historical cost includes expenditure that is directly attributable tothe acquisition of the items. Subsequent costs are included in the asset’s carrying value or recognized as separate assets, as appropriate, only when it isprobable that the future economic benefits associated with the item will flow to the Partnership and the cost of the item can be reliably measured.The asset retirement obligation included in property, plant and equipment is stated at the present value of future cash flows of asset retirement obligation atthe time of COD.Depreciation on property, plant and equipment is calculated using the straight-line method to allocate their cost to their residual values over their estimateduseful life. The power plant is depreciated over 25 years and the remaining assets are depreciated over 5 years. The assets’ residual values and useful lives arereviewed and adjusted, if appropriate, at the end of each reporting period. Repair and maintenance costs are expensed as incurred.Intangible assets (lease options)Lease options are recognized at fair value at the acquisition date and subsequently accounted for at cost. Lease options have a finite useful life and are carriedat cost less accumulated amortization. Amortization is calculated using the straight-line method to allocate the cost of lease options over the period ofexpected future benefit (i.e., the contract period of each lease option). Separately acquired lease options are capitalized on the basis of the costs incurred toenter into the respective contract.Impairment of long-lived assetsThe Partnership periodically evaluates whether events have occurred that would require revision of the remaining useful life of equipment and improvementsand purchased intangible assets or render them not recoverable. If such circumstances arise, the Partnership uses an estimate of the undiscounted value ofexpected future operating cash flows to determine whether the long-lived assets are impaired. If the aggregate undiscounted cash flows are less than thecarrying amount of the assets, the resulting impairment charge to be recorded is calculated based on the excess of the carrying value of the assets over the fairvalue of such assets, with the fair value determined based on an estimate of discounted future cash flows. Through December 31, 2017, no impairmentcharges were recorded.Deferred financing costsFinancing costs incurred in connection with obtaining construction and term financing, which include direct financing, legal and other upfront costs ofborrowing, are capitalized and recorded as a reduction to long-term debt and amortized over the lives of the respective loans using the effective-interestmethod. Amortization of deferred financing costs is capitalized during construction or expensed following COD.S- 16South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)DerivativesThe Partnership recognizes its derivative instruments as either assets or liabilities in the balance sheets at fair value. The accounting for changes in the fairvalue (i.e., gains or losses) of a derivative instrument depends on whether it qualifies and has been designated as part of a hedging relationship and, further,on the type of hedging relationship.For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure to variability in expected future cash flows that areattributable to a particular risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of other comprehensiveincome (OCI). Changes in the fair value of these derivatives are subsequently reclassified into earnings in the period the hedged transaction affects earnings.The ineffective portion of changes in fair value is recorded as a component of net income (loss) in the statements of operations and comprehensive income(loss).For undesignated derivative instruments, their change in fair value is reported as a component of net income (loss) in the statements of operations andcomprehensive income (loss).The Partnership enters into derivative transactions for the purpose of managing exposure to fluctuations in interest rates, such as interest rate swaps. Interestrate swaps are instruments used to fix the interest rate on variable interest rate debt.Accounts payable and other accrued liabilitiesTrade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Payables with paymentterms extended beyond one year from the balance sheet dates are presented as non-current liabilities.Contingent liabilitiesContingent liabilities are recognized when: the Partnership has a present legal obligation as a result of past events; it is probable that an outflow of resourceswill be required to settle the obligation; and the amount can be reasonably estimated.Asset retirement obligationThe Partnership records an asset retirement obligation for the estimated costs of decommissioning turbines, removing above-ground installations andrestoring sites, at the time when a contractual decommissioning obligation materializes. The Partnership records accretion expense, which represents theincrease in the asset retirement obligation, over the remaining life of the associated wind project. Accretion expense is recorded as cost of revenue in thestatements of operations and comprehensive income (loss) using accretion rates based on a credit adjusted risk free interest rate of 5.54%.Revenue recognitionRevenue is recognized based upon the amount of electricity delivered or curtailed at rates specified under the contracts, assuming all other revenuerecognition criteria are met. When curtailment revenue is earned, it is recorded as compensation for forgone revenue. The Partnership evaluates its PPA todetermine whether it is in substance a lease or derivative and, if applicable, recognizes revenue pursuant to ASC 840, Leases and ASC 815, Derivatives andHedging, respectively. As of December 31, 2017, the PPA was not considered a lease or a derivative instrument, as multiple market participants purchase theenergy at market-based prices with IESO working as a settlement agent. As a result, revenue (including any revenue from the price guaranteed by IESO), isrecognized on an accrual basis.The Partnership recognizes revenue under other revenue for warranty settlements and liquidated damages from a turbine manufacturer upon resolution ofoutstanding contingencies and for economic development adder from the IESO based on the amount of energy delivered. Any cash receipts for amountssubject to future adjustment or repayment are deferred in other liabilities until the final settlement amount is considered fixed and determinable.S- 17South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)Cost of revenueThe Partnership’s cost of revenue is comprised of direct costs of operating and maintaining its project facilities, including labor, turbine service arrangements,metering service and shadow settlement, environmental fee, land lease royalties, property tax, insurance, depreciation, amortization and accretion.Comprehensive incomeComprehensive income consists of net income and other comprehensive income. Other comprehensive income is included in accumulated othercomprehensive income in the accompanying statements of changes in partners’ equity.Recent accounting pronouncementsIn February 2017, the FASB issued ASU 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20):Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (ASU 2017-05). ASU 2017-05 is meant toclarify the scope of ASC Subtopic 610-20, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets and to add guidance for partialsales of nonfinancial assets. ASU 2017-05 is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidanceand is effective at the same time as ASU 2014-09. Further, the Partnership is required to adopt this guidance at the same time that it adopts the guidance inASU 2014-09 which creates ASC Topic 606, Revenue from Contracts with Customers and supersedes ASC Topic 605, Revenue Recognition (ASU 2014-09).The Partnership has assessed the future impact of this guidance on its financial statements and related disclosures and expects to adopt these updatesbeginning January 1, 2018. The adoption of ASU 2017-05 is not expected to have a material impact on its financial statements and related disclosures.In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18), which requires that a statementof cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cashequivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalentswhen reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments do not provide a definitionof restricted cash or restricted cash equivalents. The Partnership is currently assessing the future impact of this guidance on its financial statements andrelated disclosures and expects to adopt these updates beginning January 1, 2018.In May 2014, the FASB issued ASU 2014-09, which creates FASB Accounting Standards Codification (ASC) Topic 606, Revenue from Contracts withCustomers and supersedes ASC Topic 605, Revenue Recognition (ASU 2014-09). The new standard replaces industry-specific guidance and establishes asingle five-step model to identify and recognize revenue. The core principle of the new standard is that an entity should recognize revenue upon transfer ofcontrol of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for thosegoods or services. Additionally, the new standard requires the entity to disclose further quantitative and qualitative information regarding the nature andamount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizingrevenues from contracts with customers. The adoption of ASC 606 will not have material impact on the financial statements.In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments(ASU 2016-13), which requires the measurement of all expected credit losses for financial assets including trade receivables held at the reporting date basedon historical experience, current conditions, and reasonable and supportable forecasts. ASU 2016-13 is effective for fiscal years, and interim periods withinthose fiscal years, beginning after December 15, 2020. The adoption of ASU 2016-13 is not expected to have a material impact on its financial statements andrelated disclosures.In February 2016, the FASB issued ASU 2016-02, Leases (ASU 2016-02), which requires lessees to recognize right-of-use assets and lease liabilities, for allleases, with the exception of short-term leases, at the commencement date of each lease. Under the new guidance, lessor accounting is largely unchanged.ASU 2016-02 simplifies the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and liabilities. ASU 2016-02is effective for annual periods beginning after December 15, 2019. Early adoption is permitted. The amendments of this update should be applied using amodified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. ThePartnership is currently in the initial stages of evaluating the impact of the new standard on its accounting policies, processes andS- 18South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)system requirements. The Partnership is also assessing the future accounting impact of this update on its financial statements and related disclosures as itapplies to its PPA, land lease arrangements and other lease arrangements. As the Partnership progresses further in its analysis, the scope of this assessmentcould be expanded to review other types of contracts.3Restricted cashThe following table presents the components of restricted cash: December 31 2017 2016Completion reserve account $1,982 $2,03210% holdback account for contractors - 25Subtotal 1,982 2,057Less: Current portion (1,982) (2,057)Restricted cash, non-current - -The amount in the completion reserve account is reserved to pay outstanding project costs specified during term conversion (note 6). Upon full payment ofoutstanding project costs, the remaining balance will be released from restricted cash.4Property, plant and equipmentThe following is a summary of property, plant and equipment, at cost less accumulated depreciation, at: December 31, 2017 2016Power plant $731,212 $731,212Furniture, fixtures and equipment 501 501Asset retirement obligation - asset 5,263 5,263Capital spares 110 -Subtotal 737,086 736,976Less: Accumulated depreciation (116,245) (86,966) $620,841 $650,010Depreciation expense of $29,279, $29,332 and $29,361 was charged to the statements of operations and comprehensive income (loss) for the years endedDecember 31, 2017, 2016 and 2015, respectively.S- 19South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)5Intangible assets December 31, 2017 2016Beginning net book value 668 711Amortization expense (42) (43)Closing net book value 626 668 December 31, 2017 2016Cost 1,438 1,438Accumulated amortization (812) (770)Net book value 626 668Amortization expense of $42, $43 and $43 was charged to the statements of operations and comprehensive income (loss) for the years ended December 31,2017, 2016 and 2015, respectively.6Long-term debtUpon achievement of the COD on March 28, 2014, and the construction facility converted to a term loan on August 28, 2014. On May 7, 2015, thePartnership amended the credit agreement to reduce the related interest rate to Canadian Dealer Offered Rate (CDOR) plus 1.625% per annum. A fee facilitywas added with a principal amount of $5,106 to cover all fees for the amendment. The modifications have resulted in a current effective interest rate of3.175% with a maturity date of August 2021. In connection with the credit agreement, the Partnership entered into interest rate swaps that would fix theinterest rate for 90% of the outstanding notional amount.Collateral under the financing agreement consists of substantially all of the Partnership’s assets. Its loan agreement contains a broad range of covenants that,subject to certain exceptions, restrict the Partnership’s ability to incur debt, grant liens, sell or lease assets, transfer equity interest, dissolve, pay distributionsand change its business. The Partnership is in compliance with all loan covenants. All of the limited and general partners and shareholders of general partnerspledged shares of partnership units or common stock owned as collateral for the loan.Terms and conditions of outstanding borrowings were as follows: As of December 31, 2017 Principal Deferredfinancing costs Net of financing costs Interest rate Maturity dateTerm loan $615,941 $(11,391) $604,550 3.175% August 2021Less: current portion (26,819) 3,296 (23,523) Net of current $589,122 $(8,095) $581,027 As of December 31, 2016 Principal Deferredfinancing costs Net of financing costs Interest rate Maturity dateTerm loan $641,714 $(14,817) $626,897 2.565% August 2021Less: current portion (25,773) 3,426 (22,347) Net of current $615,941 $(11,391) $604,550 S- 20South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)Future maturities of long-term debt are as follows as of December 31, 2017:2018$26,8192019 28,1442020 29,9742021 37,0332022 34,900Thereafter 459,071 $615,941The following table presents a reconciliation of interest expense presented in the Partnerships’ statements of operations and comprehensive income (loss) forthe years ended December 31, 2017, 2016 and 2015: 2017 2016 2015Interest incurred$28,051 $29,050 $31,954Amortization of deferred financing costs 3,426 3,546 3,388Interest expense$31,477 $32,596 $35,342Letters of credit facilitiesOn August 28, 2014, letters of credit of $40,600 and $12,000 were issued upon term conversion for a debt service reserve and operations and maintenancereserve, respectively, with a seven-year term. Funds, when and if drawn on the facility, accrue interest at 0.625% plus Prime Rate, and at the partners’ option,the rate can be converted to a rate of CDOR plus 1.625% per annum. In addition, the Partnership shall pay letter of credit fees on the basis of the undrawnamount of the facility at 1.625% per annum. As of December 31, 2017 and 2016, the letters of credit facility did not have an outstanding balance, and noamounts were drawn in 2017 and 2016. Letter of credit fees of $855, $857 and $1,015 were charged to other expense in the statements of operations andcomprehensive income (loss) for the years ended December 31, 2017, 2016 and 2015, respectively.7Asset retirement obligationThe Partnership’s asset retirement obligation represents the estimated cost of decommissioning the turbines, removing above-ground installations andrestoring the sites at the end of its estimated useful life.The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation: December 31, 2017 2016Asset retirement obligation - Beginning of year $6,153 $5,829Accretion expense 340 324Asset retirement obligation - End of year $6,493 $6,1538DerivativesThe Partnership uses interest rate derivatives to manage its exposure to fluctuations in interest rates. Interest rate risk exists primarily on variable-rate debt forwhich the cash flows vary based upon movement in market prices. The Partnership’s objectives for holding these derivative instruments include reducing,eliminating and efficiently managing the economic impact of interest rate exposures as effectively as possible. The Partnership does not hedge all of itsinterest rate risks, thereby exposing the unhedged portions to changes in market prices.S- 21South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)The following tables present the fair values of the Partnership's derivative instruments on a gross basis as reflected on the Partnership’s balance sheets: December 31, 2017 December 31, 2016 Derivative liabilities Derivative liabilities Current Long-term Current Long-termFair value of undesignatedderivatives: Interest rate swaps $6,415 $19,384 $11,397 $36,876Total fair value $6,415 $19,384 $11,397 $36,876The following table summarizes the notional amounts of the Partnership's outstanding derivative instruments: December 31, Unit of measure 2017 2016Undesignated derivative instruments Interest rate swaps CAD $549,751 $572,947The changes in the fair value of these swaps are recognized directly into earnings as follows: December 31, 2017 20162015Gains (losses) recognized in earnings $22,474 $3,269(18,428)9Fair value measurementThe Partnership’s fair value measurements incorporate various factors, including the credit standing and performance risk of the counterparties, the applicableexit market, and specific risks inherent in the instrument. Non-performance and credit risk adjustments on risk management instruments are based on currentmarket inputs when available, such as credit default hedge spreads. When such information is not available, internal models are used.Assets and liabilities recorded at fair value in the financial statements are categorized based on the level of judgment associated with the inputs used tomeasure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to valuation of these assets or liabilitiesare as follows:Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation withmarket data at the measurement date and for the duration of the instrument’s anticipated life.Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities and whichreflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given tothe risk inherent in the valuation technique and the risk inherent in the inputs to the model.Short-term financial instruments consist principally of cash and cash equivalents, restricted cash, and accounts payable and other accrued liabilities. Based onthe nature and short maturity of these instruments, their fair value is approximated using carrying cost and they are presented in the financial statements atcarrying cost.Long-term debt is presented on the balance sheets at amortized cost. The fair value of variable interest rate for long-term debt is approximated by its carryingcost.Derivatives are presented in the financial statements at fair value. The interest rate swaps were valued by discounting the net cash flows using the forwardCDOR curve with the valuations adjusted by the Project’s credit default swap rate.S- 22South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)The Partnership’s financial assets (liabilities) which require fair value measurement on a recurring basis are classified within the fair value hierarchy asfollows: Level 1 Level 2 Level 3December 31, 2017 Interest rate swaps $- $(25,799) $- December 31, 2016 Interest rate swaps $- $(48,273) $-10Commitments and contingencies1)CommitmentsLand Lease AgreementsThe Partnership has entered into various long-term land lease agreements. The annual fees range from minimum rent payments varying by lease to maximumrent payments of a certain percentage of energy delivered revenues, varying by lease.Lease payments, including amortization of the lease option, of $2,392, $2,949 and $3,253 were charged to the statements of operations and comprehensiveincome (loss) for the years ended December 31, 2017, 2016 and 2015, respectively.The future payments related to these leases as of December 31, 2017 are as follows:2018 $4,1442019 4,1612020 4,1802021 4,1982022 4,220Thereafter 48,353Total $69,256Service and Maintenance AgreementThe Partnership has entered into service and maintenance agreements with Siemens to provide and carry out turbine maintenance and service activities for theProject until April 2020. Based on the terms of the agreements, Siemens shall be entitled to receive a daily base fee per turbine that may be subject to periodicprice adjustments for inflation, over the terms of the agreements. As of December 31, 2017, outstanding commitments with Siemens were $1,629, includingan estimated annual price adjustment for inflation of 2%, where applicable, payable over the full term of the agreement.2)ContingenciesCommunity Fund AgreementOn April 17, 2013, the GP, in its capacity as general partner and on behalf of the Partnership, entered into the South Kent Wind Community Fund Agreementwith Chatham-Kent Community Foundation, in which the Partnership committed to twenty annual contributions of $500 plus an initial contribution of$1,000. The remaining payments are recorded as a contingent liability in the amount of $8,000.Turbine Availability WarrantyThe Partnership has a turbine availability warranty from its turbine manufacturer. Pursuant to the warranty, if a turbine operates at less than minimumavailability during the warranty period, the turbine manufacturer is obligated to pay, as liquidated damages,S- 23South Kent Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)an amount for each percent that the turbine operates below the minimum availability threshold. In addition, if a turbine operates at more than a specifiedavailability during the warranty period, the Partnership has an obligation to pay a bonus to the turbine manufacturer. As of December 31, 2017, thePartnership recorded a liability of $41 associated with bonuses payable to the turbine manufacturer.11Related party transactionsThe Partnership is controlled by the GP, which is jointly controlled by Samsung and Pattern in accordance with the terms of the Shareholder Agreement.Certain terms of the Samsung Pattern Joint Venture Wind Development Agreement, entered into between Samsung and an affiliate of PRHC on July 27,2010, directed the responsibilities of Samsung and PRHC for the Project.The following transactions were carried out with related parties:a)Management, Operation, and Maintenance Agreement (MOMA)On March 8, 2013, the Partnership entered into a MOMA with Pattern Operators Canada ULC, which is owned by PCOH to operate and manage themaintenance of the wind plant and to perform certain other services pertaining to the wind plant in accordance with terms and conditions set forth in theMOMA.$1,491, $1,469 and $1,446 were charged to the project expense in the statements of operations and comprehensive income (loss) for the years endedDecember 31, 2017, 2016 and 2015, respectively.b)Project Administration Agreement (PAA)On March 8, 2013, the Partnership entered into the PAA with SRE Wind PA LP (PA), which is 100% owned by Samsung to supply projectadministrative services.$523, $516 and $507 were invoiced to the Partnership for the years ended December 31, 2017, 2016 and 2015, respectively, and expensed as generaland administrative expense in the statements of operations and comprehensive income (loss).c)The Partnership recorded the following balances with related parties: 2017 2016Related party payable to Pattern Operators Canada ULC $168 $144Related party payable to SRE Wind PA LP 49 49 $217 $19312Subsequent eventsThe Partnership declared distributions to partners in the amount of $12,282 on February 14, 2018.S- 24Grand Renewable Wind LPFinancial Statementsin accordance with accounting principlesgenerally accepted in the United States ofAmerica (U.S. GAAP)December 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)S- 25Grand Renewable Wind LP ContentsPage Independent Auditor’s ReportS- 27 Financial Statements Balance SheetsS- 28Statements of Operations and Comprehensive Income (Loss)S- 29Statements of Changes in Partners’ EquityS- 30Statements of Cash FlowsS- 31Notes to Financial StatementsS- 32 S- 26February 20, 2018Report of Independent Registered Public Accounting FirmTo the Board of Directors of Grand Renewable Wind LPOpinion on the Financial StatementsWe have audited the accompanying balance sheets of Grand Renewable Wind LP (the Partnership) as of December 31, 2017 and December 31, 2016, and therelated statements of operations and comprehensive income, statement of changes in partners’ equity, and statement of cash flows for each of the three years in theperiod ended December 31, 2017, including the related notes (collectively referred to as the financial statements). In our opinion, the financial statements presentfairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and December 31, 2016, and its results of operations and its cashflows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States ofAmerica (US GAAP).Basis for OpinionThese financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financialstatements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) andare required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of theSecurities and Exchange Commission and the PCAOB.We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditto obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion./s/ PricewaterhouseCoopers LLPChartered Professional Accountants, Licensed Public AccountantsToronto, CanadaWe have served as the Partnership's auditor since 2011.PricewaterhouseCoopers LLP PwC Tower, 18 York Street, Suite 2600, Toronto, Ontario, Canada M5J 0B2T: +1 416 863 1133, F: +1 416 365 8215, www.pwc.com/ca“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.S- 27Grand Renewable Wind LPBalance SheetsAs of December 31, 2017 and 2016(In thousands of Canadian Dollars) 2017 2016 ASSETS Current assets: Cash and cash equivalents $2,563 $3,673 Restricted cash (note 3) 4,336 4,334 Accrued revenue (note 2) 11,043 11,085 Other current assets 312 348 Total current assets 18,254 19,440 Property, plant and equipment - net of accumulated depreciation of $53,439 and $36,060 in 2017 and 2016, respectively(note 4) 379,850 397,105 Intangible assets - net of accumulated amortization of $258 and $174 in 2017 and 2016, respectively (note 5) 1,414 1,498 Total assets $399,518 $418,043 LIABILITIES & EQUITY Current liabilities: Accounts payable and other accrued liabilities $1,785 $1,865 Accounts payable and other accrued liabilities - related parties (note 11) 355 329 Current portion of long-term debt, net of financing costs of $1,356 and $1,413 in 2017 and 2016, respectively (notes 2and 6) 16,015 13,125 Derivative liabilities, current (note 8) 4,811 7,767 Other current liabilities (note 10) 603 524 Total current liabilities 23,569 23,610 Long-term debt, net of financing costs of $4,287 and $5,643 in 2017 and 2016, respectively (notes 2 and 6) 333,116 349,132 Derivative liabilities (note 8) 35,756 46,260 Asset retirement obligation (note 7) 2,992 2,809 Total liabilities 395,433 421,811 Commitments and contingencies (note 10) Equity: Partners’ capital 8,350 28,230 Accumulated net loss 8,148 (5,896) Accumulated other comprehensive loss (12,413) (26,102) Total partners’ equity 4,085 (3,768) Total liabilities and equity $399,518 $418,043 See accompanying notes to financial statements.S- 28Grand Renewable Wind LPStatements of Operations and Comprehensive IncomeFor the years ended December 31, 2017, 2016 and 2015(In thousands of Canadian Dollars) 2017 2016 2015Revenue (note 2): Energy delivered $39,693 $44,353 $56,138Compensation for forgone energy 24,866 19,172 5,227Other revenue 712 713 1,046Total revenue 65,272 64,238 62,411 Cost of revenue: Project expenses 8,780 8,270 8,179Project expenses - related parties (note 11) 1,277 1,258 1,244Depreciation, amortization and accretion 17,562 17,545 17,498Total cost of revenue 27,619 27,073 26,921 Gross profit 37,653 37,165 35,490 Operating expenses: General and administrative 1,015 1,125 1,546General and administrative - related parties (note 11) 419 412 406Total operating expenses 1,434 1,537 1,952 Operating income 36,219 35,628 33,538 Other (expense) income: Interest expense (note 6) (21,079) (21,648) (21,958)Unrealized loss on derivatives (note 8) (230) (7,253) (3,354)Other (expense) income, net (867) (883) (434)Total other expense (22,176) (29,784) (25,746) Net income 14,044 5,844 7,792 Other comprehensive income (loss): Derivative activity (notes 8 and 10): Effective portion of change in fair value of derivatives 6,121 (826) (14,397)Reclassifications to net income (loss) 7,568 8,582 8,320 Total change in effective portion of change infair market value of derivatives 13,689 7,756 (6,077)Comprehensive income $27,733 $13,600 $1,715See accompanying notes to financial statements.S- 29Grand Renewable Wind LPStatements of Changes in Partners’ EquityFor the years ended December 31, 2017, 2016 and 2015(In thousands of Canadian Dollars) Partners’capital Accumulated netincome(loss) Accumulatedothercomprehensiveloss TotalBalance at January 1, 2015 $67,990 $(19,532) $(27,781) $20,677Cash distribution (20,310) — — (20,310)Other comprehensive loss — — (6,077) (6,077)Net income — 7,792 — 7,792Balance at December 31, 2015 47,680 (11,740) (33,858) 2,082Cash distribution (19,450) — — (19,450)Other comprehensive loss — — 7,756 7,756Net income — 5,844 — 5,844Balance at December 31, 2016 28,230 (5,896) (26,102) (3,768)Cash distribution (19,880) — — (19,880)Other comprehensive income — — 13,689 13,689Net income — 14,044 — 14,044Balance at December 31, 2017 $8,350 $8,148 $(12,413) $4,085See accompanying notes to financial statements.S- 30Grand Renewable Wind LPStatements of Cash FlowsFor the years ended December 31, 2017, 2016 and 2015(In thousands of Canadian Dollars) 2017 2016 2015Cash flows from operating activities: Net income (loss) $14,044 $5,844 $7,792Adjustments to reconcile net income (loss) to net cash provided by (used in) operatingactivities Unrealized loss on derivatives 230 7,253 3,354Depreciation, amortization and accretion 17,646 17,628 17,582Amortization of deferred financing costs 1,413 1,248 1,593Interest expense added on principal — — 5,832Changes in assets and liabilities, net: Accrued revenue 42 (1,855) (5,732)Sales tax recoverable — — 6,586Accounts payable and other accrued liabilities (28) (4,546) (15,460)Other, net 87 210 (1,963)Net cash provided by (used in) operating activities 33,434 25,782 19,584 Cash flows from investing activities: Capital expenditures (125) (2,240) (18,082)Decrease in restricted cash 15 8,124 8,039Increase in restricted cash (16) (17) (14,252)Net cash provided by (used in) investing activities (126) 5,867 (24,295) Cash flows from financing activities: Proceeds from long-term debt — — 39,968Repayment of long-term debt (14,538) (13,897) (12,172)Distribution to partners (19,880) (19,450) (20,310)Net cash (used in) provided by financing activities (34,418) (33,347) 7,486 Net change in cash and cash equivalents (1,110) (1,697) 2,775Cash and cash equivalents - Beginning of year 3,673 5,371 2,596Cash and cash equivalents - End of year $2,563 $3,673 $5,371 Supplemental disclosure: Cash payments for interest and commitment fees $19,615 $20,291 $16,218 Schedule of non-cash activities: Remeasurement of asset retirement obligation $— $— $598See accompanying notes to financial statements.S- 31Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)1General informationThe PartnershipGrand Renewable Wind LP (the Partnership), a limited partnership under the laws of the Province of Ontario, was formed on January 10, 2011 as a jointventure project between Samsung Renewable Energy Inc. (Samsung) and Pattern Grand LP Holdings LP, a subsidiary of Pattern Renewable Holdings CanadaULC (PRHC), each as 49.99% limited partners of the Partnership, and Grand Renewable Wind GP Inc. (the GP), as the 0.02% general partner of thePartnership. The Partnership was created to develop, build and operate a wind power project in Haldimand County with generation capacity totalingapproximately 149 megawatts (MW) of power (the Project).On February 24, 2013, Samsung transferred its LP interest in the Partnership to SRE GRW LP Holdings LP, an affiliate of Samsung.On December 20, 2013, in a series of transactions: (i) Pattern Grand GP Holdings Inc., a wholly owned subsidiary of PRHC, transferred all of the generalpartner interests in Pattern Grand LP Holdings LP to PRHC, causing Pattern Grand LP Holdings LP to be dissolved by operation of law and PRHC to acquirethe LP interests in the Partnership that previously were held by Pattern Grand LP Holdings LP, (ii) PRHC transferred its LP interest in the Partnership and itsownership interest in Pattern Grand GP Holdings Inc., which owned PRHC’s ownership interest in the GP, to Pattern Canada Operations Holdings ULC,(PCOH), a wholly owned subsidiary of Pattern Energy Group Inc. (Pattern), and (iii) Pattern Grand GP Holdings Inc. was dissolved.On December 17, 2014, PCOH transferred all of its LP interest in the Partnership to Pattern Canada Finance Company ULC, a wholly owned subsidiary ofPCOH.Six Nations agreementsOn May 25, 2012, the Partnership entered into certain agreements with the Six Nations of the Grand River, a band within the meaning of the Indian Act(Canada) through its elected council (the Six Nations), in which the Partnership provides an option for economic participation by way of an annual royaltyfrom the Partnership or the right to purchase a 10% interest in the Partnership.On June 11, 2013, the Six Nations exercised its option to purchase a 10% LP interest in the Partnership and the Partnership Agreement was amended andrestated to reflect such ownership. Affiliates of Samsung and Pattern each maintain a 45% interest in the Partnership. The Six Nations is not involved in theGP.The Partnership is controlled by its general partner, the GP, also a joint venture controlled by affiliates of Samsung and Pattern. The Partnership’s ownershipinterests were distributed as follows: December 31, 2017 2016SRE GRW LP Holdings LP 44.99% 44.99%Pattern Canada Finance Company ULC 44.99 44.99Six Nations of the Grand River 10.00 10.00Grand Renewable Wind GP Inc. 0.02 0.02Total 100.00% 100.00%The ProjectThe Project is a 149 MW wind project consisting of 67 Siemens wind turbine generators located in Haldimand County, Ontario. On December 9, 2014 theProject achieved the Commercial Operation Date (“COD”) and commenced commercial operations.The Partnership has a power purchase agreement ("PPA") with the Independent Electricity System Operator (“IESO”) for a period of 20 years from the COD.The IESO oversees the wholesale electricity market, where the price of energy is determined. It also administers the rules that govern the market and, throughan arm's-length market monitoring function, ensures that it is operated fairly and efficiently. The IESO is an agent among the market participants in Ontarioand is neither exposed to, norS- 32Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)benefits from, any transactions. In such capacity, the IESO executes agreements to help the market meet the renewable energy mandates of the government ofthe Province of Ontario. There are approximately 70 electric distribution companies in Ontario, all of which have government mandates to purchaserenewable energy. The PPA provides for guaranteed pricing from IESO that removes volatility caused by fluctuations in market rates. The Ontariogovernment established the Global Adjustment (“GA”) which is designed to adjust consumer rates depending on the price of energy. The IESO establishes amonthly variable GA rate based on GA costs and Ontario electricity demand which effectively establishes a pass through mechanism to the consumer andeliminates the IESO's economic exposure to our contract price.A 100 MW solar facility developed by an affiliate of Samsung is sharing the usage and ownership of the transmission line and substation. The Projectconnected to the Ontario transmission grid by way of a 20 km transmission line sited in the municipal road allowance.2Summary of significant accounting policiesThe principal accounting policies applied in the preparation of these financial statements are set out below. These policies have been consistently applied tothe periods presented, unless otherwise stated.Basis of preparationThe accompanying financial statements are presented using accounting principles generally accepted in the United States of America (U.S. GAAP). Thepreparation of U.S. GAAP financial statements requires management to make certain estimates and assumptions that affect the reported amounts of assets andliabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expensesduring the reporting period. Because the use of estimates is inherent in the financial reporting process, actual results could differ from those estimates.In recording transactions and balances resulting from business operations, the Partnership uses estimates based on the best information available. Estimatesare used for such items as accrued revenue, asset retirement obligation, valuation of long-term derivative contracts and contingencies.These financial statements do not include assets, liabilities, revenue and expenses of the GP and limited partners. The financial statements of the Partnershipreflect no provision or liability for income taxes because profits and losses of the Partnership are allocated to the partners and are included in the income taxreturns of the partners. Income and losses for tax purposes may differ from the financial stateme nt amounts and the partners’ equity reflected in thefinancial statements does not necessarily reflect their tax basis.Functional and presentation currencyItems included in the financial statements of the Partnership are measured using the currency of the primary economic environment in which the Partnershipoperates (the functional currency). The financial statements are presented in Canadian dollars, which is the Partnership’s functional and presentation currency.Fair value of financial instrumentsASC 820, Fair Value Measurements, defines fair value as the price at which an asset could be exchanged or a liability transferred in an orderly transactionbetween knowledgeable, willing parties in the principal or most advantageous market for the asset or liability. Where available, fair value is based onobservable market prices or derived from such prices. Where observable prices or inputs are not available, valuation models are applied. These valuationtechniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments ormarket and the instruments’ complexity.S- 33Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)Cash and cash equivalentsCash and cash equivalents include cash on hand, deposits held at call with banks and other short-term highly liquid investments with original maturities ofthree months or less.Restricted cashRestricted cash mainly consists of cash reserves required under the Partnership’s loan agreements (note 3).Trade receivablesThe Partnership’s trade receivables are generated by selling energy in Ontario, Canada through the IESO as a settlement agent. The allowance for doubtfulaccounts, if needed, is computed based upon management’s estimates of uncollectible accounts. As of December 31, 2017 and 2016, the Partnership has nooutstanding trade receivables.Accrued revenueAccrued revenue represents revenues recognized on contracts for which billings have not been presented to customers as of the balance sheet date. Theseamounts are billed and generally collected within two months.Concentration of credit riskFinancial instruments that potentially subject the Partnership to concentrations of credit risk consist primarily of cash and cash equivalents and restricted cash.The Partnership places its cash and cash equivalents and restricted cash with creditworthy institutions located in Canada, which the management believes tohave minimal risk. At times, such balances may be in excess of the Canada Deposit Insurance Corporation (CDIC) insurance coverage limit. CDIC insurancecurrently covers up to $100 per depositor at each insured bank.The Partnership’s derivative agreements expose the Partnership to losses under certain circumstances, such as the counterparty defaulting on its obligationsunder the swap agreements or if the swap agreements provide an imperfect hedge. Counterparties to the Partnership’s derivative contracts are major financialinstitutions that have been accorded investment grade ratings.Property, plant and equipmentProperty, plant and equipment are stated at historical cost, less accumulated depreciation. Historical cost includes expenditure that is directly attributable tothe acquisition of the items. Subsequent costs are included in the asset’s carrying value or recognized as separate assets, as appropriate, only when it isprobable that the future economic benefits associated with the item will flow to the Partnership and the cost of the item can be reliably measured.The asset retirement obligation included in property, plant and equipment is stated at the present value of future cash flows of asset retirement obligation atthe time of COD.Depreciation on property, plant and equipment is calculated using the straight-line method to allocate their cost to their residual values over their estimateduseful lives. The power plant is depreciated over 25 years and the remaining assets are depreciated over 5 years. The assets’ residual values and useful livesare reviewed and adjusted, if appropriate, at the end of each reporting period. Repair and maintenance costs are expensed as incurred.Intangible assetsAmortization is calculated using the straight-line method and recorded against revenue over the remaining term of the PPA.Impairment of long-lived assetsThe Partnership periodically evaluates whether events have occurred that would require revision of the remaining useful life of equipment and improvementsand purchased intangible assets, or render them not recoverable. If such circumstances arise, theS- 34Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)Partnership uses an estimate of the undiscounted value of expected future operating cash flows to determine whether the long-lived assets are impaired. If theaggregate undiscounted cash flows are less than the carrying amount of the assets, the resulting impairment charge to be recorded is calculated based on theexcess of the carrying value of the assets over the fair value of such assets, with the fair value determined based on an estimate of discounted future cashflows. Through December 31, 2017, no impairment charges were recorded.Deferred financing costsFinancing costs incurred in connection with obtaining construction and term financing, which include direct financing, legal and other upfront costs ofborrowing, are capitalized and recorded as a reduction to long-term debt and amortized over the lives of the respective loans using the effective-interestmethod. Amortization of deferred financing costs is capitalized during construction or expensed following COD.DerivativesThe Partnership recognizes its derivative instruments as either assets or liabilities in the balance sheets at fair value. The accounting for changes in the fairvalue (i.e., gains or losses) of a derivative instrument depends on whether it qualifies and has been designated as part of a hedging relationship and the type ofhedging relationship.For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure to variability in expected future cash flows that areattributable to a particular risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of other comprehensiveincome (OCI) or loss (OCL). Changes in the fair value of these derivatives are subsequently reclassified into earnings in the period that the hedgedtransaction affects earnings. The ineffective portion of changes in fair value is recorded as a component of net income (loss) in the statements of operationsand comprehensive income (loss).For undesignated derivative instruments, their change in fair value is reported as a component of net income in the statements of operations andcomprehensive income.The Partnership enters into derivative transactions for the purpose of managing exposure to fluctuations in interest rates, such as interest rate swaps. Interestrate swaps are instruments used to fix the interest rate on variable interest rate debt.Accounts payable and other accrued liabilitiesTrade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Payables with paymentterms extended beyond one year from the balance sheet dates are presented as non-current liabilities.Contingent liabilitiesContingent liabilities are recognized when: the Partnership has a present legal obligation as a result of past events; it is probable that an outflow of resourceswill be required to settle the obligation; and the amount can be reasonably estimated.Asset retirement obligationThe Partnership records an asset retirement obligation for the estimated costs of decommissioning turbines, removing above-ground installations andrestoring sites, at the time when a contractual decommissioning obligation materializes. The Partnership records accretion expense, which represents theincrease in the asset retirement obligation, over the remaining life of the associated wind project. Accretion expense is recorded as cost of revenue in thestatements of operations and comprehensive income (loss) using accretion rates based on a credit adjusted risk free interest rate of 6.51%.S- 35Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)Revenue recognitionRevenue is recognized based upon the amount of electricity delivered or curtailed at rates specified under the contracts, assuming all other revenuerecognition criteria are met. When curtailment revenue is earned, it is recorded as compensation for forgone revenue. The Partnership evaluates its PPA todetermine whether it is in substance a lease or derivative and, if applicable, recognizes revenue pursuant to ASC 840 Leases and ASC 815 Derivatives andHedging, respectively. As of December 31, 2017, the PPA was not considered a lease or a derivative instrument, as multiple market participants purchase theenergy at market-based prices with IESO working as a settlement agent. As a result, revenue (including any revenue from the price guaranteed by IESO), isrecognized on an accrual basis.The Partnership recognizes revenue for warranty settlements and liquidated damages from a turbine manufacturer in other revenue upon resolution ofoutstanding contingencies. Any cash receipts for amounts subject to future adjustment or repayment are deferred in other liabilities until the final settlementamount is considered fixed and determinable.Cost of revenueThe Partnership’s cost of revenue is comprised of direct costs of operating and maintaining its project facilities, including labor, turbine service arrangements,metering service and shadow settlement, environmental fee, land lease royalties, property tax, insurance, depreciation, amortization and accretion.Comprehensive incomeComprehensive income consists of net income and other comprehensive income. Other comprehensive income is included in accumulated othercomprehensive income in the accompanying statements of changes in partners’ equity.Recent accounting pronouncementsIn February 2017, the FASB issued ASU 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20):Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (ASU 2017-05). ASU 2017-05 is meant toclarify the scope of ASC Subtopic 610-20, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets and to add guidance for partialsales of nonfinancial assets. ASU 2017-05 is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidanceand is effective at the same time as ASU 2014-09. Further, the Partnership is required to adopt this guidance at the same time that it adopts the guidance inASU 2014-09 which creates ASC Topic 606, Revenue from Contracts with Customers and supersedes ASC Topic 605, Revenue Recognition (ASU 2014-09).The Partnership has assessed the future impact of this guidance on its financial statements and related disclosures and expects to adopt these updatesbeginning January 1, 2018. The adoption of ASU 2017-05 is not expected to have a material impact on its financial statements and related disclosures.In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18), which requires that a statementof cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cashequivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalentswhen reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments do not provide a definitionof restricted cash or restricted cash equivalents. The Partnership is currently assessing the future impact of this guidance on its financial statements andrelated disclosures and expects to adopt these updates beginning January 1, 2018.In May 2014, the FASB issued ASU 2014-09, which creates FASB Accounting Standards Codification (ASC) Topic 606, Revenue from Contracts withCustomers and supersedes ASC Topic 605, Revenue Recognition (ASU 2014-09). The new standard replaces industry-specific guidance and establishes asingle five-step model to identify and recognize revenue. The core principle of the new standard is that an entity should recognize revenue upon transfer ofcontrol of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for thosegoods or services. Additionally, the new standard requires the entity to disclose further quantitative and qualitative information regarding the nature andamount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizingrevenues from contracts with customers. The adoption of ASC 606 will not have material impact on the financial statements.S- 36Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments(ASU 2016-13), which requires the measurement of all expected credit losses for financial assets including trade receivables held at the reporting date basedon historical experience, current conditions, and reasonable and supportable forecasts. ASU 2016-13 is effective for fiscal years, and interim periods withinthose fiscal years, beginning after December 15, 2020. The adoption of ASU 2016-13 is not expected to have a material impact on its financial statements andrelated disclosures.In February 2016, the FASB issued ASU 2016-02, Leases (ASU 2016-02), which requires lessees to recognize right-of-use assets and lease liabilities, for allleases, with the exception of short-term leases, at the commencement date of each lease. Under the new guidance, lessor accounting is largely unchanged.ASU 2016-02 simplifies the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and liabilities. ASU 2016-02is effective for annual periods beginning after December 15, 2019. Early adoption is permitted. The amendments of this update should be applied using amodified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. ThePartnership is currently in the initial stages of evaluating the impact of the new standard on its accounting policies, processes and system requirements. ThePartnership is also assessing the future accounting impact of this update on its financial statements and related disclosures as it applies to its PPA, land leasearrangements and other lease arrangements. As the Partnership progresses further in its analysis, the scope of this assessment could be expanded to reviewother types of contracts.3Restricted cashThe following table presents the components of restricted cash: December 31, 2017 2016Completion reserve account $4,336 $4,334Subtotal 4,336 4,334Less: Current portion (4,336) (4,334)Restricted cash, non-current $— $—The amount in the completion reserve account is reserved to pay outstanding project costs specified during term conversion (note 6). Upon full payment ofoutstanding project costs, the remaining balance will be released from restricted cash.4Property, plant and equipmentThe following is a summary of property, plant and equipment, at cost less accumulated depreciation, at: December 31, 2017 2016Power plant $430,421 $430,421Furniture, fixtures and equipment 281 281Asset retirement obligation - asset 2,463 2,463Capital spares 124 —Subtotal 433,289 433,165Less: Accumulated depreciation (53,439) (36,060) $379,850 $397,105Depreciation expense of $17,379, $17,373 and $17,337 was charged to the statements of operations and comprehensive income (loss) for the years endedDecember 31, 2017, 2016 and 2015, respectively.S- 37Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)5Intangible assets December 31, 2017 2016Beginning net book value $1,498 $1,581Amortization expense (84) (83)Closing net book value $1,414 $1,498 December 31, 2017 2016Cost $1,672 $1,672Accumulated amortization (258) (174)Net book value $1,414 $1,498Amortization expense of $84, $83, and $84 was charged as a reduction to revenue in the statements of operations and comprehensive income (loss) for theyears ended December 31, 2017, 2016 and 2015, respectively.6Long-term debtUpon achievement of the COD in December 2014, the construction facility converted to term loan on July 29, 2015. The loan matures on July 29, 2022. Inconnection with the financing agreement, the Partnership entered into interest rate swaps on 90% of the loan commitment.Collateral under the financing agreement consists of substantially all of the Partnership’s assets. The loan agreement contains a broad range of covenants that,subject to certain exceptions, restrict the Partnership’s ability to incur debt, grant liens, sell or lease assets, transfer equity interest, dissolve, pay distributionsand change its business. The Partnership is in compliance with all loan covenants. All of the limited and general partners and shareholders of general partnerspledged shares of partnership units or common stock owned as collateral for the loan.Terms and conditions of outstanding borrowings were as follows: As of December 31, 2017 Principal Deferredfinancing costs Net of financing costs Interest rate Maturity dateTerm loan $354,774 $(5,643) $349,131 3.80% July 2022Less: current portion (17,371) 1,356 (16,015) Net of current $337,403 $(4,287) $333,116 As of December 31, 2016 Principal Deferredfinancing costs Net of financing costs Interest rate Maturity dateTerm loan $369,313 $(7,056) $362,257 3.19% July 2022Less: current portion (14,538) 1,413 (13,125) Net of current $354,775 $(5,643) $349,132 S- 38Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)Future maturities of long-term debt are as follows as of December 31, 2017:2018 $17,3712019 18,4182020 19,5252021 19,6802022 17,901Thereafter 261,880 $354,775The following table presents a reconciliation of interest expense presented in the Partnerships’ statements of operations and comprehensive income (loss) forthe years ended December 31, 2017, 2016 and 2015: 2017 2016 2015Interest incurred $19,666 $20,400 $20,023Commitment fees incurred — — 342Amortization of deferred financing costs 1,413 1,248 1,593Interest expense $21,079 $21,648 $21,958Letters of credit facilitiesOn July 29, 2015, letters of credit of $24,000, $8,000 and $5,000 were issued upon term conversion for a debt service reserve, operations and maintenancereserve, and decommissioning reserve, respectively, with a seven-year term. Funds, when and if drawn on the facility, accrue interest at 1.25% plus PrimeRate, and at the partners’ option, the rate can be converted to a rate of CDOR plus 2.25% per annum. In addition, the Partnership shall pay letter of credit feeson the basis of the undrawn amount of the facility at 2.25% per annum. As of December 31, 2017, the letters of credit facility did not have an outstandingbalance, and no amounts were drawn in 2017. Letter of credit fees of $832 and $835 were charged to other expense in the statements of operations andcomprehensive income (loss) for the year ended December 31, 2017 and 2016, respectively .7Asset retirement obligationThe Partnership’s asset retirement obligation represents the estimated cost of decommissioning the turbines, removing above-ground installations andrestoring the sites at the end of its estimated useful life.The following table presents a reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation: December 31, 2017 2016Asset retirement obligation - Beginning of year $2,809 $2,637Accretion expense 183 172Asset retirement obligation - End of year $2,992 $2,8098DerivativesThe Partnership uses interest rate derivatives to manage its exposure to fluctuations in interest rates. Interest rate risk exists primarily on variable-rate debt forwhich the cash flows vary based upon movement in market prices. The Partnership’s objectives for holding these derivative instruments include reducing,eliminating and efficiently managing the economic impact of interest rate exposures as effectively as possible. The Partnership does not hedge all of itsinterest rate risks, thereby exposing the unhedged portions to changes in market prices.S- 39Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)The following tables present the fair values of the Partnership's derivative instruments on a gross basis as reflected on the Partnership’s balance sheets: December 31, 2017 December 31, 2016 Derivative liabilities Derivative liabilities Current Long-term Current Long-termFair value of designated derivatives: Interest rate swaps $4,811 $7,601 $7,767 $18,335 Fair value of undesignated derivatives: Interest rate swaps $— $28,155 $— $27,925Total fair value $4,811 $35,756 $7,767 $46,260The following table summarizes the notional amounts of the Partnership's outstanding derivative instruments: December 31 Unit of measure 2017 2016Designated derivative instruments Interest rate swaps CAD $321,998 $335,082The following table presents losses on derivative contracts designated and qualifying as cash flow hedges recognized in accumulated other comprehensiveloss, as well as, losses on other derivative contracts and amounts reclassified to earning for the following periods: December 31 Description 2017 20162015Income (losses) recognized in accumulated OCL Effective portion $13,689 $7,756$(6,077)Losses recognized in earnings on other derivative contracts Effective portion $(230) $(7,253)$(3,354)Losses reclassified from accumulated OCL into interest expense Derivative settlements $(7,568) $(8,582)$(8,320)No ineffectiveness was recorded on these swaps for the years ended December 31, 2017 and 2016. The Partnership estimates that $5,868 in accumulatedother comprehensive loss will be reclassified into earnings over the next twelve months.9Fair value measurementThe Partnership’s fair value measurements incorporate various factors, including the credit standing and performance risk of the counterparties, the applicableexit market, and specific risks inherent in the instrument. Non-performance and credit risk adjustments on risk management instruments are based on currentmarket inputs when available, such as credit default hedge spreads. When such information is not available, internal models are used.Assets and liabilities recorded at fair value in the financial statements are categorized based upon the level of judgment associated with the inputs used tomeasure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to valuation of these assets or liabilitiesare as follows:Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation withmarket data at the measurement date and for the duration of the instrument’s anticipated life.Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities and whichreflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given tothe risk inherent in the valuation technique and the risk inherent in the inputs to the model.S- 40Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)Short-term financial instruments consist principally of cash and cash equivalents, restricted cash, and accounts payable and other accrued liabilities. Based onthe nature and short maturity of these instruments their fair value is approximated using carrying cost and they are presented in the financial statements atcarrying cost.Long-term debt is presented on the balance sheets at amortized cost. The fair value of variable interest rate for long-term debt is approximated by its carryingcost.Derivatives are presented in the financial statements at fair value. The interest rate swaps were valued by discounting the net cash flows using the forwardCDOR curve with the valuations adjusted by the Project’s credit default swap rate.The Partnership’s financial assets (liabilities) which require fair value measurement on a recurring basis are classified within the fair value hierarchy asfollows: Level 1 Level 2 Level 3December 31, 2017 Interest rate swaps $— $(40,568) $—December 31, 2016 Interest rate swaps $— $(54,027) $—10Commitments and contingencies1)CommitmentsLand Lease AgreementsThe Partnership has entered into various long-term land lease agreements. The annual fees range from minimum rent payments varying by lease to maximumrent payments of a certain percentage of energy delivered revenues, varying by lease.Lease payments, including amortization of the lease option, of $1,719, $1,936 and $1,864 were charged to the statements of operations and comprehensiveincome (loss) for the years ended December 31, 2017, 2016, and 2015, respectively.The future payments related to these leases as of December 31, 2017 are as follows:2018 $1,8772019 1,9152020 1,9532021 1,9922022 2,031Thereafter 30,402Total $40,170Service and Maintenance AgreementThe Partnership has entered into service and maintenance agreements with Siemens to provide and carry out turbine maintenance and service activities for theProject until January 2021. Based on the terms of the agreements, Siemens shall be entitled to receive a daily base fee per turbine that may be subject toperiodic price adjustments for inflation, over the terms of the agreements. As of December 31, 2017, outstanding commitments with Siemens were $4,180,including an estimated annual price adjustment for inflation of 2%, where applicable, payable over the full term of the agreement.2)ContingenciesCommunity Vibrancy FundS- 41Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)On September 26, 2011, the Partnership entered into a Community Vibrancy Fund (CVF) Agreement with the Corporation of Haldimand County, in whichthe Partnership will make annual payments into a fund managed by the municipality in amounts of $3.5 per MW of the Project installed capacity plus $5 perkilometer (km) of high voltage overhead transmission line that is installed in municipal right-of-way. The payments are calculated annually and are owed forthe 20-year term of the PPA. In exchange for CVF payments, the municipality undertakes certain obligations to support the Project, including entering into aroad use agreement in which the Project may utilize municipal right-of-ways for collection and transmission lines.Turbine Availability WarrantyThe Partnership has a turbine availability warranty from its turbine manufacturer. Pursuant to the warranty, if a turbine operates at less than minimumavailability during the warranty period, the turbine manufacturer is obligated to pay, as liquidated damages, an amount for each percent that the turbineoperates below the minimum availability threshold. In addition, if a turbine operates at more than a specified availability during the warranty period, thePartnership has an obligation to pay a bonus to the turbine manufacturer. As of December 31, 2017, the Partnership recorded a liability of $436 associatedwith bonuses payable to the turbine manufacturer.11Related party transactionsThe Partnership is controlled by the GP, which is jointly controlled by Samsung and Pattern in accordance with the terms of the Shareholder Agreement.Certain terms of the Samsung and Pattern Joint Venture Wind Development Agreement, entered into between Samsung and an affiliate of PRHC on July 27,2010, directed the responsibilities of Samsung and PRHC for the Project.The following transactions were carried out with related parties:a)Management, Operation, and Maintenance Agreement (MOMA)Balance of Plant MOMAOn September 13, 2013, the Partnership entered into a MOMA with Pattern Operators Canada ULC, which is owned by PCOH to operate and managethe maintenance of the wind plant and to perform certain other services pertaining to the wind plant in accordance with terms and conditions set in theMOMA.The amounts of $1,225, $1,206 and $1,187 were invoiced to the Partnership for the years ended December 31, 2017, 2016 and 2015, respectively, whichwere charged to the statements of operations and comprehensive income (loss) for the years ended December 31, 2017, 2016 and 2015, respectively.Transmission Line MOMA (TL MOMA)On September 13, 2013, the Partnership and Grand Renewable Solar LP entered into TL MOMA with Pattern Operators Canada ULC, which is 100%owned by an affiliate of Pattern, to operate and manage the maintenance of the transmission line and common assets of the substation and to performcertain other services pertaining to the wind plant in accordance with terms and conditions set in TL MOMA.The amounts of $52, $52 and $57 were charged to the statements of operations and comprehensive income for the years ended December 31, 2017,2016 and 2015, respectively.b)Engineering Procurement and Construction Contract (EPC contract)Transmission Line EPCOn September 13, 2013, the Partnership entered into TL EPC contract with Grand Renewable Solar LP, and SRE GRW EPC LP, which is 100% ownedby Samsung to build the transmission line, and $0 and $(1) were capitalized to property, plant and equipment on the balance sheets as of December 31,2017 and 2016, respectively.S- 42Grand Renewable Wind LPNotes to Financial StatementsDecember 31, 2017, 2016 and 2015(In thousands of Canadian Dollars)c)Project Administration Agreement (PAA)On September 13, 2013, the Partnership entered into PAA with SRE Wind PA LP (PA), which is 100% owned by Samsung to receive projectadministrative services.$419, $412 and $406 were charged to the statements of operations and comprehensive income (loss) for the years ended December 31, 2017, 2016 and2015, respectively.d)Transmission Facilities Co-ownership Agreement (TFCA)On March 8, 2013, the Partnership entered into the TFCA with a planned 100 MW solar project developed by an affiliate of Samsung which providesfor the co-ownership of the transmission line and substation of the Project. Under the co-ownership agreement, the Project and the solar project eachcontributed 50% of the construction and operating costs of the transmission line and substation and each received a 50% undivided interest in suchshared facilities.e)The Partnership recorded the following balances with related parties: 2017 2016Related party payable to Pattern Operators Canada ULC $276 $290Related party payable to SRE Wind PA LP 79 39 $355 $32912Subsequent eventsThe Partnership declared distributions to partners in the amount of $2,100 on February 14, 2018.S- 43SP Armow Wind Ontario LPFinancial Statementsin accordance with accounting principlesgenerally accepted in the United States ofAmerica (U.S. GAAP)As of December 31, 2017 and 2016, andfor the year ended December 31, 2017and for the period from October 18 to December 31, 2016(In thousands of Canadian Dollars)S- 44SP Armow Wind Ontario LP ContentsPage Independent Auditor’s ReportS- 46 Financial Statements Balance SheetS- 47Statement of Operations and Comprehensive IncomeS- 48Statement of Changes in Partners’ EquityS- 49Statement of Cash FlowsS- 50Notes to Financial StatementsS- 51 S- 45February 20, 2018Report of Independent Registered Public Accounting FirmTo the Board of Directors of SP Armow Wind Ontario LPOpinion on the Financial StatementsWe have audited the accompanying balance sheets of SP Armow Wind Ontario LP (the Partnership) as of December 31, 2017 and December 31, 2016, and therelated statements of operations and comprehensive income, statement of changes in partners' equity, and statement of cash flows for the year ended December 31,2017 and for the period from October 18, 2016 to December 31, 2016, including the related notes (collectively referred to as the financial statements). In ouropinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and December 31, 2016,and its results of operations and its cash flows for the period ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016 in conformitywith accounting principles generally accepted in the United States of America (US GAAP).Basis for OpinionThese financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financialstatements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) andare required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of theSecurities and Exchange Commission and the PCAOB.We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditto obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performingprocedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financialstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overallpresentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion./s/ PricewaterhouseCoopers LLPChartered Professional Accountants, Licensed Public AccountantsToronto, CanadaWe have served as the Partnership's auditor since 2011.PricewaterhouseCoopers LLP PwC Tower, 18 York Street, Suite 2600, Toronto, Ontario, Canada M5J 0B2T: +1 416 863 1133, F: +1 416 365 8215, www.pwc.com/ca“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.S- 46SP Armow Wind Ontario LPBalance SheetAs of December 31, 2017 and December 31, 2016(In thousands of Canadian Dollars) 2017 2016ASSETS Current assets: Cash and cash equivalents$10,685 $21,856Restricted cash (note 3) 10 814Accrued revenue (note 2) 12,935 13,115Other current assets 1,406 1,457Total current assets 25,036 37,242 Restricted cash (note 3) 3,172 7,086Property, plant and equipment - net of accumulated depreciationof $45,627 and $23,724 in 2017 and 2016, respectively (note 4) 501,405 522,867Other assets 872 923Total assets$530,485 $568,118 LIABILITIES & EQUITY Current liabilities: Accounts payable and other accrued liabilities$2,440 $3,642Accounts payable and other accrued liabilities - related parties (note 10) 183 374Current portion of long-term debt, net of financing costs of $1,338 and $1,381 in 2017 and 2016,respectively (notes 2 and 5) 18,972 6,020Contingent liabilities (note 9) 579 446Derivative liabilities, current (note 7) 3,703 7,357Other current liabilities 1,938 1,959Total current liabilities 27,815 19,798 Long-term debt, net of financing costs of $5,142 and $6,480 in 2017 and 2016, respectively (notes 2 and 5) 484,681 503,653Derivative liabilities (note 7) 22,338 35,555Asset retirement obligation (note 6) 5,274 5,023Total liabilities 540,108 564,029 Commitments and contingencies (note 9) Equity: Partners’ capital (49,840) 13,567Accumulated net income 66,258 33,434Accumulated other comprehensive loss (26,041) (42,912)Total partners’ equity (9,623) 4,089Total liabilities and equity$530,485 $568,118See accompanying notes to financial statements.S- 47SP Armow Wind Ontario LPStatement of Operations and Comprehensive IncomeFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars) 2017 2016Revenue (note 2): Energy delivered$55,718 $16,498Compensation for forgone energy 34,284 6,473Other revenue 1,014 300Total revenue 91,016 23,271 Cost of revenue: Project expenses 9,633 2,040Project expenses - related parties (note 10) 1,377 277Depreciation, amortization and accretion 22,153 4,544Total cost of revenue 33,163 6,861Gross profit 57,853 16,410 Operating expenses: General and administrative 1,147 237General and administrative - related parties (note 10) 413 83Total operating expenses 1,560 320Operating income 56,293 16,090 Other expense: Interest expense (note 5) (22,838) (4,898)Other expense, net (631) (148)Total other expense (23,469) (5,046)Net income 32,824 11,044 Other comprehensive income: Derivative activity (notes 7 and 8): Effective portion of change in fair value of derivatives 9,191 17,064Reclassifications to net income 7,680 2,154 Total change in effective portion of change infair market value of derivatives 16,871 19,218Comprehensive income$49,695 $30,262See accompanying notes to financial statements.S- 48SP Armow Wind Ontario LPStatement of Changes in Partners’ EquityFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars) Partners’capital Accumulatednet income Accumulatedothercomprehensiveloss TotalBalance at October 18, 2016 $25,020 $22,390 $(62,130) $(14,720)Other comprehensive income — — 19,218 19,218Net income — 11,044 — 11,044Cash distribution (11,453) — — (11,453)Balance at December 31, 2016 $13,567 $33,434 $(42,912) $4,089Other comprehensive income — — 16,871 16,871Net income — 32,824 — 32,824Cash distribution (63,407) — — (63,407)Balance at December 31, 2017 $(49,840) $66,258 $(26,041) $(9,623)See accompanying notes to financial statements.S- 49SP Armow Wind Ontario LPStatement of Cash FlowsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars) 2017 2016Cash flows from operating activities: Net income$32,824$11,044Adjustments to reconcile net income to net cash used in operating activities: Depreciation, amortization and accretion 22,153 4,544Amortization of deferred financing costs 1,381 285Changes in assets and liabilities, net: Accrued revenue 181 (2,654)Accounts payable and other accrued liabilities (487) 424Other, net 81 (4,869)Net cash provided by operating activities 56,133 8,774 Cash flows from investing activities: Capital expenditures (441) (326)Net changes in sales taxes recoverable and accounts payable and other accrued liabilities related toinvesting activities (773) (851)Decrease in restricted cash 4,835 458Increase in restricted cash (117) —Net cash used in investing activities 3,504 (719) Cash flows from financing activities: Repayment of long-term debt (7,401) —Distribution to partners (63,407) (11,453)Net cash used in financing activities (70,808) (11,453) Net change in cash and cash equivalents (11,171) (3,605)Cash and cash equivalents - Beginning of the period 21,856 25,254Cash and cash equivalents - End of the period$10,685$21,856 Supplemental non-cash activities disclosure: Effective portion of change in fair value of derivatives$(9,191)$— Supplemental cash activities disclosure: Cash payments for interest$21,478$7,482See accompanying notes to financial statements.S- 50SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)1General informationThe PartnershipSP Armow Wind Ontario LP (the Partnership), a limited partnership under the laws of the Province of Ontario, was formed on August 29, 2011 as a jointventure project between Samsung Renewable Energy Inc. (Samsung) and Pattern Armow LP Holdings LP, a subsidiary of Pattern Renewable HoldingsCanada ULC (PRHC), each as 49.99% limited partners of the Partnership, and SP Armow Wind Ontario GP Inc. (the GP), as the 0.02% general partner of thePartnership. The Partnership was created to develop, build and operate a wind power project in Kincardine, Bruce County with generation capacity totalingapproximately 180 megawatts (MW) of power (the Project).On August 6, 2014, Samsung transferred all of its LP interest in the Partnership to SRE Armow LP Holdings LP, an affiliate of Samsung.On October 17, 2016, Pattern Armow LP Holdings LP transferred all of its LP interest in the Partnership to Pattern Canada Finance Company ULC, a whollyowned subsidiary of Pattern Energy Group Inc. (Pattern).The Partnership is controlled by its general partner, the GP, also a joint venture controlled by affiliates of Samsung and Pattern. As of December 31, 2017 and2016, the Partnership’s ownership interests were distributed as follows: 2017 2016SRE Armow LP Holdings LP 49.99% 49.99%Pattern Canada Finance Company ULC 49.99% 49.99%SP Armow Wind Ontario GP Inc. 0.02% 0.02% 100.00% 100.00%The ProjectThe Project is a 179 MW wind project consisting of 91 Siemens wind turbine generators located in Haldimand County, Ontario. On December 7, 2015 theProject achieved the Commercial Operation Date (“COD”) and commenced commercial operations.The Partnership has a power purchase agreement ("PPA") with the Independent Electricity System Operator (“IESO”) for a period of 20 years from the COD.The IESO oversees the wholesale electricity market, where the price of energy is determined. It also administers the rules that govern the market and, throughan arm's-length market monitoring function, ensures that it is operated fairly and efficiently. The IESO is an agent among the market participants in Ontarioand is neither exposed to, nor benefits from, any transactions. In such capacity, the IESO executes agreements to help the market meet the renewable energymandates of the government of the Province of Ontario. There are approximately 70 electric distribution companies in Ontario, all of which have governmentmandates to purchase renewable energy. The PPA provides for guaranteed pricing from IESO that removes volatility caused by fluctuations in market rates.The Ontario government established the Global Adjustment (“GA”) which is designed to adjust consumer rates depending on the price of energy. The IESOestablishes a monthly variable GA rate based on GA costs and Ontario electricity demand which effectively establishes a pass through mechanism to theconsumer and eliminates the IESO's economic exposure to our contract price.2Summary of significant accounting policiesThe principal accounting policies applied in the preparation of these financial statements are set out below. These policies have been consistently applied tothe period presented, unless otherwise stated.S- 51SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)Basis of presentationIn accordance with Rule 3-09 of Regulation S-X, full financial statements of significant equity investments are required to be presented in the annual reportof the investor. For purposes of S-X 3-09, the investee’s separate annual financial statements should only depict the period of the fiscal year in which it wasaccounted for by the equity method by the investor. On Oct 17, 2016, Pattern purchased its interest in the partnership. Accordingly, the accompanyingfinancial statements have been prepared for the year ended December 31, 2017 and the comparatives financial statements have been prepared for the periodfrom October 18, 2016 to December 31, 2016 (stub period).Basis of preparationThe accompanying financial statements are presented using accounting principles generally accepted in the United States of America (U.S. GAAP). Thepreparation of U.S. GAAP financial statements requires management to make certain estimates and assumptions that affect the reported amounts of assets andliabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expensesduring the reporting period. Because the use of estimates is inherent in the financial reporting process, actual results could differ from those estimates.In recording transactions and balances resulting from business operations, the Partnership uses estimates based on the best information available. Estimatesare used for such items as accrued revenue, asset retirement obligation, valuation of derivative contracts and contingencies.These financial statements do not include assets, liabilities, revenue and expenses of the GP and limited partners. The financial statements of the Partnershipreflect no provision or liability for income taxes because profits and losses of the Partnership are allocated to the partners and are included in the income taxreturns of partners. Income and losses for tax purposes may differ from the financial statement amounts and the partners’ equity reflected in the financialstatements does not necessarily reflect their tax basis.Functional and presentation currencyItems included in the financial statements of the Partnership are measured using the currency of the primary economic environment in which the Partnershipoperates (the functional currency). The financial statements are presented in Canadian dollars, which is the Partnership’s functional and presentation currency.Fair value of financial instrumentsASC 820, Fair Value Measurements, defines fair value as the price at which an asset could be exchanged or a liability transferred in an orderly transactionbetween knowledgeable, willing parties in the principal or most advantageous market for the asset or liability. Where available, fair value is based onobservable market prices or derived from such prices. Where observable prices or inputs are not available, valuation models are applied.These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for theinstruments or market and the instruments’ complexity.Cash and cash equivalentsCash and cash equivalents include cash on hand, deposits held on call with banks and other short-term highly liquid investments with original maturities ofthree months or less.Restricted cashRestricted cash consists of cash reserves required under the Partnership’s loan agreements and security deposits required to collateralize commercial bankletter of credit facilities related primarily to a power purchase agreement (PPA) and road use agreements (note 3).S- 52SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)Trade receivablesThe Partnership’s trade receivables are generated by selling energy in Ontario, Canada through the IESO as a settlement agent. The allowance for doubtfulaccounts, if needed, is computed based upon management’s estimates of uncollectible accounts. As of December 31, 2017 and 2016, the Partnership has nooutstanding trade receivables.Accrued revenueAccrued revenue represents revenues recognized on contracts for which billings have not been presented to customers as of the balance sheet date. Theseamounts are billed and generally collected within two months.Concentration of credit riskFinancial instruments that potentially subject the Partnership to concentrations of credit risk consist primarily of cash and cash equivalents and restricted cash.The Partnership places its cash and cash equivalents and restricted cash with creditworthy institutions located in Canada, which management believes to haveminimal risk. At times, such balances may be in excess of the Canada Deposit Insurance Corporation (CDIC) insurance coverage limit. CDIC insurancecurrently covers up to $100 per depositor at each insured bank.The Partnership’s derivative agreements expose the Partnership to losses under certain circumstances, such as the counterparty defaulting on its obligationsunder the swap agreements or if the swap agreements provide an imperfect hedge. Counterparties to the Partnership’s derivative contracts are major financialinstitutions that have been accorded investment grade ratings.Property, plant and equipmentProperty, plant and equipment are stated at historical cost, less accumulated depreciation. Historical cost includes expenditure that is directly attributable tothe acquisition of the items. Subsequent costs are included in the asset’s carrying value or recognized as separate assets, as appropriate, only when it isprobable that the future economic benefits associated with the item will flow to the Partnership and the cost of the item can be reliably measured.The asset retirement obligation included in property, plant and equipment is stated at the present value of future cash flows of asset retirement obligation atthe time of COD.Depreciation on property, plant and equipment is calculated using the straight-line method to allocate their cost to their residual values over their estimateduseful lives. The power plant is depreciated over 25 years and the remaining assets are depreciated over 5 years. The assets’ residual values and useful livesare reviewed and adjusted, if appropriate, at the end of each reporting period. Repair and maintenance costs are expensed as incurred.Impairment of long-lived assetsThe Partnership periodically evaluates whether events have occurred that would require revision of the remaining useful life of equipment and improvementsor render them not recoverable. If such circumstances arise, the Partnership uses an estimate of the undiscounted value of expected future operating cashflows to determine whether the long-lived assets are impaired. If the aggregate undiscounted cash flows are less than the carrying amount of the assets, theresulting impairment charge to be recorded is calculated based on the excess of the carrying value of the assets over the fair value of such assets, with the fairvalue determined based on an estimate of discounted future cash flows. Through December 31, 2017, no impairment charges were recorded.Deferred financing costsFinancing costs incurred in connection with obtaining construction and term financing, which include direct financing, legal and other upfront costs ofborrowing, are capitalized and recorded as a reduction to long-term debt and amortized over the lives of the respective loans using the effective-interestmethod. Amortization of deferred financing costs is capitalized during construction or expensed following COD.S- 53SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)DerivativesThe Partnership recognizes its derivative instruments as either assets or liabilities in the balance sheets at fair value. The accounting for changes in the fairvalue (i.e., gains or losses) of a derivative instrument depends on whether it qualifies and has been designated as part of a hedging relationship and, further,on the type of hedging relationship.For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure to variability in expected future cash flows that areattributable to a particular risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of other comprehensiveincome or loss (OCI or OCL). Changes in the fair value of these derivatives are subsequently reclassified into earnings in the period the hedged transactionaffects earnings. The ineffective portion of changes in fair value is recorded as a component of net income (loss) in the statements of operations andcomprehensive income (loss).For undesignated derivative instruments, their change in fair value is reported as a component of net income in the statements of operations andcomprehensive income (loss).The Partnership enters into derivative transactions for the purpose of managing exposure to fluctuations in interest rates, such as interest rate swaps. Interestrate swaps are instruments used to fix the interest rate on variable interest rate debt.Accounts payable and other accrued liabilitiesTrade payables are an obligation to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Payables withpayment terms extended beyond one year from the balance sheet dates are presented as non-current liabilities.Contingent liabilitiesContingent liabilities are recognized when: the Partnership has a present legal obligation as a result of past events; it is probable that an outflow of resourceswill be required to settle the obligation; and the amount can be reasonably estimated.Asset retirement obligationThe Partnership records an asset retirement obligation for the estimated costs of decommissioning turbines, removing above-ground installations andrestoring sites, at the time when a contractual decommissioning obligation materializes. The Partnership records accretion expense, which represents theincrease in the asset retirement obligation, over the remaining life of the associated wind project. Accretion expense is recorded as cost of revenue in thestatements of operations and comprehensive income (loss) using accretion rates based on a credit adjusted risk free interest rate of 4.989%.Revenue recognitionRevenue is recognized based upon the amount of electricity delivered or curtailed at rates specified under the contracts, assuming all other revenuerecognition criteria are met. When curtailment revenue is earned it is recorded as compensation for forgone revenue. The Partnership evaluates its PPA todetermine whether it is in substance a lease or derivative and, if applicable, recognizes revenue pursuant to ASC 840 Leases and ASC 815 Derivatives andHedging, respectively. As of December 31, 2017, the PPA was not considered a lease or a derivative instrument, as multiple market participants purchase theenergy at market-based prices with IESO working as a settlement agent. As a result, revenue (including any revenue from the price guaranteed by IESO), isrecognized on an accrual basis.The Partnership recognizes revenue for warranty settlements and liquidated damages from a turbine manufacturer in other revenue upon resolution ofoutstanding contingencies. Any cash receipts for amounts subject to future adjustment or repayment are deferred in other liabilities until the final settlementamount is considered fixed and determinable.Cost of revenueThe Partnership’s cost of revenue is comprised of direct costs of operating and maintaining its project facilities, including labor, turbine service arrangements,metering service and shadow settlement, environmental fee, land lease royalties, property tax, insurance, depreciation, amortization and accretion.S- 54SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)Comprehensive incomeComprehensive income (loss) consists of net income and other comprehensive loss. Other comprehensive loss i s included in accumulated othercomprehensive loss in the accompanying statements of changes in partners’ equity.Recent accounting pronouncementsIn February 2017, the FASB issued ASU 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20):Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (ASU 2017-05). ASU 2017-05 is meant toclarify the scope of ASC Subtopic 610-20, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets and to add guidance for partialsales of nonfinancial assets. ASU 2017-05 is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidanceand is effective at the same time as ASU 2014-09. Further, the Partnership is required to adopt this guidance at the same time that it adopts the guidance inASU 2014-09 which creates ASC Topic 606, Revenue from Contracts with Customers and supersedes ASC Topic 605, Revenue Recognition (ASU 2014-09).The Partnership has assessed the future impact of this guidance on its financial statements and related disclosures and expects to adopt these updatesbeginning January 1, 2018. The adoption of ASU 2017-05 is not expected to have a material impact on its financial statements and related disclosures.In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18), which requires that a statementof cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cashequivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalentswhen reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments do not provide a definitionof restricted cash or restricted cash equivalents. The Partnership is currently assessing the future impact of this guidance on its financial statements and relateddisclosures and expects to adopt these updates beginning January 1, 2018.In May 2014, the FASB issued ASU 2014-09, which creates FASB Accounting Standards Codification (ASC) Topic 606, Revenue from Contracts withCustomers and supersedes ASC Topic 605, Revenue Recognition (ASU 2014-09). The new standard replaces industry-specific guidance and establishes asingle five-step model to identify and recognize revenue. The core principle of the new standard is that an entity should recognize revenue upon transfer ofcontrol of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for thosegoods or services. Additionally, the new standard requires the entity to disclose further quantitative and qualitative information regarding the nature andamount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizingrevenues from contracts with customers. The adoption of ASC 606 will not have material impact on the financial statements.In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments(ASU 2016-13), which requires the measurement of all expected credit losses for financial assets including trade receivables held at the reporting date basedon historical experience, current conditions, and reasonable and supportable forecasts. ASU 2016-13 is effective for fiscal years, and interim periods withinthose fiscal years, beginning after December 15, 2020. The adoption of ASU 2016-13 is not expected to have a material impact on its financial statements andrelated disclosures.In February 2016, the FASB issued ASU 2016-02, Leases (ASU 2016-02), which requires lessees to recognize right-of-use assets and lease liabilities, for allleases, with the exception of short-term leases, at the commencement date of each lease. Under the new guidance, lessor accounting is largely unchanged.ASU 2016-02 simplifies the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and liabilities. ASU 2016-02is effective for annual periods beginning after December 15, 2019. Early adoption is permitted. The amendments of this update should be applied using amodified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. ThePartnership is currently in the initial stages of evaluating the impact of the new standard on its accounting policies, processes and system requirements. ThePartnership is also assessing the future accounting impact of this update on its financial statements and related disclosures as it applies to its PPA, land leasearrangements and other lease arrangements. As the Partnership progresses further in its analysis, the scope of this assessment could be expanded to reviewother types of contracts.S- 55SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)3Restricted cashThe following table presents the components of restricted cash: December 31, 2017 2016Completion reserve account$3,172 $5,086Security deposits for letters of guarantee 10 2,01010% holdback account for contractors — 804Subtotal 3,182 7,900Less: Current portion (10) (814)Restricted cash, non-current$3,172 $7,086The amount completion reserve account is reserved to pay outstanding project costs specified during term conversion. Upon full payment of outstandingproject costs, the remaining balance will be released from restricted cash.The Partnership maintains term deposits that are restricted as security for the letters of guarantee. $5,400 was provided to the IESO as the security depositunder the PPA in 2014, and $69 was additionally provided to the IESO for electricity use in 2015. These amounts were released during 2016. The Partnershipalso provided $2,000 to the Municipality of Kincardine and $50 to the County of Bruce as the security deposits for road use in 2014. The security deposit of$50 was reduced to $10 in 2016.The 10% holdback account relates to amounts withheld from payments to contractors in compliance with local regulations, which will be released tocontractors when specific performance conditions are substantially met.4Property, plant and equipmentThe following is a summary of property, plant and equipment, at cost less accumulated depreciation, at: December 31, 2017 2016Power plant$542,095 $541,654Machinery and equipment 169 169Asset retirement obligation – asset 4,768 4,768Subtotal 547,032 546,591Less: Accumulated depreciation (45,627) (23,724) $501,405 $522,867Depreciation expense of $21,903 and $4,494 was charged to the statements of operations and comprehensive income (loss) for the years ended December 31,2017 and the stub period, respectively.5Long-term debtUpon achievement of the COD in December 2015, the construction facility converted to term loan on May 20, 2016. The loan matures on May 20, 2023. Inconnection with the financing agreement, the Partnership entered into interest rate swaps on 90% of the loan commitment.Collateral under the financing agreement consists of substantially all of the Partnership’s assets. The loan agreement contains a broad range of covenants that,subject to certain exceptions, restrict the Partnership’s ability to incur debt, grant liens, sell or lease assets, transfer equity interest, dissolve, pay distributionsand change its business. The Partnership is in compliance with all loanS- 56SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)covenants. All of the limited and general partners and shareholders of general partners pledged shares of partnership units or common stock owned ascollateral for the loan.Terms and conditions of outstanding borrowings were as follows:As of December 31, 2017 Principal Deferredfinancing costs Net of financing costs Interest rate Maturity dateTerm loan $510,133 $(6,480) $503,653 3.035% May 20, 2023Less: current portion (20,310) 1,338 (18,972) Net of current $489,823 $(5,142) $484,681 As of December 31, 2016 Principal Deferredfinancing costs Net of financing costs Interest rate Maturity dateTerm loan $517,534 $(7,861) $509,673 2.525% May 20, 2023Less: current portion (7,401) 1,381 (6,020) Net of current $510,133 $(6,480) $503,653 The following are the amounts due for long-term debt as of December 31, 2017:2018 $20,3102019 23,3522020 25,2502021 26,5142022 27,836Thereafter 386,871 $510,133Interest and commitment fees incurred, and interest expense recorded in the Partnership’s statements of operations and comprehensive income (loss) are asfollows: 2017 2016Interest incurred$21,457$4,613Amortization of financing cost 1,381 285Interest expense$22,838$4,898Letter of credit facilitiesOn May 20, 2016, letters of credit of $30,000 and $11,000 were issued upon term conversion for a debt service reserve and operations and maintenancereserve, respectively, with a seven-year term. Funds, when and if drawn on the facility, accrue interest at 0.625% plus Prime Rate, and at the partners’ option,the rate can be converted to a rate of CDOR plus 1.625% per annum. In addition, the Partnership shall pay letter of credit fees on the basis of the undrawnamount of the facility at 1.625% per annum. As of December 31, 2017 and 2016, the letters of credit facility did not have an outstanding balance, and noamounts were drawn in 2017 and 2016. Letter of credit fees of $666 and $140 were charged to other expense in the statements of operations andcomprehensive income for the year ended December 31, 2017 and the stub period, respectively.S- 57SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)6Asset retirement obligationThe Partnership’s asset retirement obligation represents the estimated cost of decommissioning the turbines, removing above-ground installations andrestoring the sites at a date that is 25 years from the commencement of commercial operations.The following table presents a reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation: December 31, 2017 2016Asset retirement obligation, beginning of the period$5,023 $4,973Accretion expense 251 50Asset retirement obligation, end of the period$5,274 $5,0237DerivativesThe Partnership uses interest rate derivatives to manage its exposure to fluctuations in interest rates. Interest rate risk exists primarily on variable-rate debt forwhich the cash flows vary based upon movement in market prices. The Partnership’s objectives for holding these derivative instruments include reducing,eliminating and efficiently managing the economic impact of interest rate exposures as effectively as possible. The Partnership does not hedge all of itsinterest rate risks, thereby exposing the unhedged portions to changes in market prices.The following tables present the fair values of the Partnership's derivative instruments on a gross basis as reflected on the Partnership’s balance sheets: December 31, 2017 December 31, 2016 Derivative liabilities Derivative liabilities Current Long-term Current Long-termFair value of designated derivatives: Interest rate swaps $3,703 $22,338 $7,357 $35,555Total fair value $3,703 $22,338 $7,357 $35,555The following table summarizes the notional amounts of the Partnership's outstanding derivative instruments: December 31, Unit of measure 2017 2016Designated derivative instruments Interest rate swaps CAD $459,119$478,597The following table presents losses on derivative contracts designated and qualifying as cash flow hedges recognized in accumulated other comprehensiveloss for the following periods: December 31, Description 2017 2016Gain recognized in accumulated OCI Effective portion $16,871$19,218Losses reclassified from accumulated OCL into interest expense Derivativesettlements $(7,680)$(2,154)No ineffectiveness was recorded on these swaps for the years ended December 31, 2017 and stub period. The Partnership estimates that $5,805 inaccumulated other comprehensive loss will be reclassified into earnings over the next twelve months.S- 58SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)8Fair value measurementThe Partnership’s fair value measurements incorporate various factors, including the credit standing and performance risk of the counterparties, the applicableexit market, and specific risks inherent in the instrument. Non-performance and credit risk adjustments on risk management instruments are based on currentmarket inputs when available, such as credit default swap spreads. When such information is not available, internal models are used.Assets and liabilities recorded at fair value in the financial statements are categorized based on the level of judgment associated with the inputs used tomeasure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to valuation of these assets or liabilitiesare as follows:Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation withmarket data at the measurement date and for the duration of the instrument’s anticipated life.Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities and whichreflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given tothe risk inherent in the valuation technique and the risk inherent in the inputs to the model.Short-term financial instruments consist principally of cash and cash equivalents, restricted cash, accounts payable and other accrued liabilities. Based on thenature and short maturity of these instruments their fair value is approximated using carrying cost and they are presented in the financial statements atcarrying cost.Long-term debt is presented on the balance sheets at amortized cost. The fair value of variable interest rate for long-term debt is approximated by its carryingcost.Derivatives are presented in the financial statements at fair value. The interest rate swaps were valued by discounting the net cash flows using the forwardCDOR curve with the valuations adjusted by the counterparties’ credit default swap rate.The following table presents the fair values according to each defined level.Financial assets (liabilities) measured on a recurring basis: Level 1 Level 2 Level 3December 31, 2017 Interest rate swaps $— $(26,041) $—December 31, 2016 Interest rate swaps $— $(42,912) $—9Commitments and contingencies1)CommitmentsLand lease agreementsThe Partnership has entered into various long-term land lease agreements. The annual fees range from minimum rent payments to maximum rent payments ofa certain percentage of energy delivered revenues, varying by lease.S- 59SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)Lease payments, including amortization of the lease option, of $1,735 and $369 were charged to the statements of operations and comprehensive income(loss) for the years ended December 31, 2017 and the stub period, respectively.The future payments related to these leases as of December 31, 2017 are as follows:2018 $1,9352019 2,0512020 2,0512021 2,0542022 2,054Thereafter 36,387Total $46,532Service and Maintenance AgreementThe Partnership has entered into service and maintenance agreements with Siemens to provide and carry out turbine maintenance and service activities for theProject until January 2019. Based on the terms of the agreements, Siemens shall be entitled to receive a daily base fee per turbine that may be subject toperiodic price adjustments for inflation, over the terms of the agreements. As of December 31, 2017, outstanding commitments with Siemens were $5,611,including an estimated annual price adjustment for inflation of 2%, where applicable, payable over the full term of the agreement.2)ContingenciesDevelopment AgreementOn May 21, 2014, the Partnership entered into a Development Agreement (DA) with the Corporation of the Municipality of Kincardine, in which thePartnership committed to twenty annual contributions of $630 plus an initial contribution of $1,030. In exchange for DA payments, the municipalityundertakes certain obligations to support the Project, including entering into a road use agreement.Turbine Availability WarrantyThe Partnership has a turbine availability warranty from its turbine manufacturer. Pursuant to the warranty, if a turbine operates at less than minimumavailability during the warranty period, the turbine manufacturer is obligated to pay, as liquidated damages, an amount for each percent that the turbineoperates below the minimum availability threshold. In addition, if a turbine operates at more than a specified availability during the warranty period, thePartnership has an obligation to pay a bonus to the turbine manufacturer. As of December 31, 2017, the Partnership recorded a liability of $579 associatedwith bonuses payable to the turbine manufacturer.10Related party transactionsThe Partnership is controlled by the GP, which is jointly controlled by Samsung and Pattern in accordance with the terms of the Shareholder Agreement.Certain terms of the Samsung Pattern Joint Venture Wind Development Agreement, entered into between Samsung and an affiliate of PRHC on July 27,2010, directed the responsibilities of Samsung and PRHC for the Project.The following transactions were carried out with related parties:a)Management, Operation, and Maintenance Agreement (MOMA)S- 60SP Armow Wind Ontario LPNotes to Financial StatementsFor the year ended December 31, 2017 and the period from October 18, 2016 to December 31, 2016(In thousands of Canadian Dollars)On October 24, 2014, the Partnership entered into a MOMA with Pattern Operators Canada ULC, which is owned by an affiliate of Pattern to operateand manage the maintenance of the wind plant and to perform certain other services pertaining to the wind plant in accordance with terms andconditions set forth in the MOMA.$1,377 and $277 were charged to the statements of operations and comprehensive income (loss) for the years ended December 31, 2017 and the stubperiod, respectively.c)Project Administration Agreement (PAA)On October 24, 2014, the Partnership entered into the PAA with SRE Wind PA LP (PA), which is 100% owned by Samsung to supply projectadministrative services.$413 and $83 were charged to the statements of operations and comprehensive income (loss) for the years ended December 31, 2017 and the stubperiod, respectively.d)The Partnership recorded the following balances with related parties: 2017 2016Related party payable to Pattern Operators Canada ULC $144 $128Related party payable to SRE Wind PA LP 39 38Related party payable and accrued liabilities to SRE Armow EPC LP — 208 $183 $374S- 61FINANCIAL STATEMENTSK2 Wind Ontario Limited PartnershipAs of December 31, 2017 and 2016 andfor the years ended December 31, 2017, 2016 (audited) andfor the period from June 17, 2015 to December 31, 2015 (unaudited)with Report of Independent Registered Public Accounting Firm S- 62K2 Wind Ontario Limited PartnershipAudited Financial StatementsAs of December 31, 2017 and 2016 andfor the year ended December 31, 2017 and December 31, 2016 (audited) andfor the period from June 17, 2015 to December 31, 2015 (unaudited) Contents Page Report of Independent Registered Public Accounting Firm S- 64 Audited Financial Statements Balance Sheets S- 65Statements of Operations and Comprehensive Income (Loss) S- 66Statements of Changes in Partners' Capital (Deficit) S- 67Statements of Cash Flows S- 68Notes to Financial Statements S- 69S- 63Report of Independent Registered Public Accounting FirmThe PartnersK2 Wind Ontario Limited PartnershipWe have audited the accompanying financial statements of K2 Wind Ontario Limited Partnership, which comprise the statements of financial position as ofDecember 31, 2017 and 2016, and the related statements of operations and comprehensive income, changes in partners’ capital and cash flows for the years thenended, and the related notes to the financial statements.Management’s Responsibility for the Financial StatementsManagement is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles;this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free ofmaterial misstatement, whether due to fraud or error.Auditor’s ResponsibilityOur responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standardsgenerally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement.An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected dependon the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making thoserisk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design auditprocedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control.Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significantaccounting estimates made by management, as well as evaluating the overall presentation of the financial statements.We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.OpinionIn our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of K2 Wind Ontario Limited Partnership atDecember 31, 2017 and 2016, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accountingprinciples./s/ Ernst & Young LLPSan Francisco, CaliforniaFebruary 28, 2018S- 64K2 Wind Ontario Limited PartnershipBalance Sheets(In thousands of Canadian Dollars) December 31, 2017 2016Assets Current assets: Cash and cash equivalents$16,000 $17,975Trade receivables21,344 25,091Prepaid expenses1,652 1,751Other current assets205 49Deferred financing costs, net of accumulated amortization of $235 and $173 as of December31, 2017 and December 31, 2016, respectively61 61Total current assets39,262 44,927 Restricted cash8,061 8,081Property, plant and equipment, net785,897 820,929Deferred financing costs877 939Total assets$834,097 $874,876 Liabilities and partners' (deficit) capital Current liabilities: Accounts payable and other accrued liabilities$2,457 $5,569Accrued interest3,128 3,277Accrued construction costs624 668Related party payable157 155Derivative liabilities, current7,915 13,339Other current liabilities287 289Current portion of long-term debt, net32,429 29,872Total current liabilities46,997 53,169 Long-term debt, net710,276 742,704Asset retirement obligation5,278 5,004Derivative liabilities59,400 79,286Total liabilities821,951 880,163Commitments and contingencies (Note 8) Partners' capital (deficit): Capital (deficit)(49,086) 10,933Accumulated income (loss)128,547 76,406Accumulated other comprehensive income (loss)(67,315) (92,626)Total partners' capital (deficit)12,146 (5,287)Total liabilities and partners' capital (deficit)$834,097 $874,876 See accompanying notes.S- 65K2 Wind Ontario Limited PartnershipStatements of Operations and Comprehensive Income (Loss)(In thousands of Canadian Dollars) Year endedDecember 31,2017(Audited) Year endedDecember 31,2016(Audited) Period fromJune 17, 2015 toDecember 31,2015(UnauditedRevenue: Electricity sales$87,012 $99,525 $69,125Compensation for forgone energy56,089 40,389 228Total revenue143,101 139,914 69,353 Cost of revenue: Operations and maintenance11,443 11,042 5,405General and administrative6,255 6,066 4,179Depreciation and accretion35,306 35,295 19,140Total cost of revenue53,004 52,403 28,724 Operating income (loss)90,097 87,511 40,629 Other income (expense): Interest expense(38,043) (39,503) (13,469)Other income (expense), net87 (1) 84Total other income (expense)(37,956) (39,504) (13,385)Net income (loss)52,141 48,007 27,244 Other comprehensive income (loss): Effective portion of change in fair market value of derivatives11,190 (15,597) (24,305)Reclassifications to net income (loss)14,121 15,978 1,466Total other comprehensive income (loss)25,311 381 (22,839)Total comprehensive income (loss)$77,452 $48,388 $4,405 See accompanying notes.S- 66K2 Wind Ontario Limited PartnershipStatements of Changes in Partners' Capital (Deficit)(In thousands of Canadian Dollars) ContributedSurplus AccumulatedIncome (Loss) AccumulatedOtherComprehensiveIncome (Loss) TotalBalances at June 17, 2015 (unaudited)$130,783 $1,155 $(70,168) $61,770Distributions(48,005) — — (48,005)Net income (loss)— 27,244 — 27,244Other comprehensive income (loss)— — $(22,839) (22,839)Balances at January 1, 2016$82,778 $28,399 $(93,007) $18,170Distributions(71,845) — — (71,845)Net income (loss)— 48,007 — 48,007Other comprehensive income (loss)— — 381 381Balances at December 31, 201610,933 76,406 (92,626) (5,287)Distributions(60,019) — — (60,019)Net income (loss)— 52,141 — 52,141Other comprehensive income (loss)— — 25,311 25,311Balances at December 31, 2017$(49,086) $128,547 $(67,315) $12,146 See accompanying notes.S- 67K2 Wind Ontario Limited PartnershipStatements of Cash Flows(In thousands of Canadian Dollars) Year endedDecember 31,2017 (Audited) Year endedDecember 31,2016 (Audited) Period fromJune 17, 2015 toDecember 31,2015(Unaudited)Operating activities Net income (loss)$52,141 $48,007 $27,244Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and accretion35,306 35,295 19,140Amortization of financing costs1,401 1,460 737Changes in operating assets and liabilities: Trade receivables3,747 (5,717) (12,897)Prepaid expenses99 (208) (167)Other current assets(156) 215 19,891Accounts payable and other accrued liabilities(3,110) 2,337 5,434Accrued interest(149) (617) 3,894Other current liabilities1 24 (3,736)Net cash provided by (used in) operating activities89,280 80,796 59,540 Investing activities Capital expenditures(44) (9,433) (81,043)Net cash provided by (used in) investing activities(44) (9,433) (81,043) Financing activities Payment for deferred financing costs— (62) (25)Proceeds from long-term debt— — 94,842Capital distributions(60,019) (71,845) (48,005)Repayment of long-term debt(31,212) (32,581) —Net cash provided by (used in) financing activities(91,231) (104,488) 46,812 Net change in cash and cash equivalents and restricted cash(1,995) (33,125) 25,309Cash and cash equivalents and restricted cash at beginning26,056 59,181 33,872Cash and cash equivalents and restricted cash at end of year$(24,061) $26,056 $59,181 Supplemental disclosures Cash payments for interest expense, net of capitalized interest$36,790 $38,780 $1,125 Schedule of non-cash activities Change in property, plant and equipment associated with accrued liabilities andcapitalized interest— $792 $39,986 See accompanying notes. S- 68K2 Wind Ontario Limited PartnershipNotes to Financial Statements1. General informationBusinessK2 Wind Ontario Limited Partnership (K2 Wind or the Company), a limited partnership under the laws of the Province of Ontario, was formed on July 27, 2011,as a joint venture project between Capital Power L.P., Samsung Renewable Energy Inc. (Samsung) and Pattern Renewable Holdings Canada ULC (PRHC), eachholding a 33.33% ownership interest as limited partners of the Company, and K2 Wind Ontario Inc. (the GP), holding a 0.01% ownership interest as generalpartner of the Company.The GP is a corporation jointly owned among affiliates of Samsung, Pattern, and Capital Power. The Samsung affiliate originally owned a 50% GP interest and thePattern and Capital Power affiliates each originally owned a 25% GP interest.On June 17, 2015, Pattern K2 LP Holdings LP transferred all of its interests in K2 Wind to PRHC and PRHC subsequently transferred all of its interests in K2Wind to Pattern Canada Finance Company ULC, a wholly owned subsidiary of Pattern Energy Group Inc. (Pattern).On March 15, 2016, Samsung transferred a portion of its GP interest so that each of the Samsung, Pattern and Capital Power affiliates then held equal 33.33%interests in the GP.On July 7, 2016, CP K2 Holdings Inc.’s LP interest in K2 Wind, was transferred through an internal reorganization to Capital Power LP Holdings Inc., an entitywholly owned by Capital Power.On August 5, 2016, Samsung sold its LP interest in K2 Wind to K2 Wind Co LP and its GP interest to K2 Wind Co GP Inc. K2 Wind Co LP and K2 Wind Co GPInc. are owned by a consortium of Axium Infrastructure Canada II LP, ATRF INF (DB) LTD. and The Manufacturers Life Insurance Company.The partners’ liability and losses for K2 Wind are limited to each limited partner’s capital contribution plus any unpaid capital contributions agreed to by thepartners. The partners shall not be required to make additional capital contributions, or have any personal liability, in respect of the liabilities or the obligations ofK2 Wind.The ProjectK2 Wind owns a 270 megawatt (MW) wind project consisting of 140 wind turbine generators located in the township of Ashfield Colborne Wawanosh in Ontario,Canada (the Project). The Project reached its commercial operation date (COD) on May 29, 2015.The Company has a power purchase agreement (PPA) with the Independent Electricity System Operator (IESO) for a period of 20 years from the COD. The IESOoversees the wholesale electricity market, where the price of energy is determined. It also administers the rules that govern the market and, through an arm's-lengthmarket monitoring function, ensures that it is operated fairly and efficiently. The IESO is an agent among the market participants in Ontario and is neither exposedto, nor benefits from, any transactions. In such capacity, the IESO executes agreements to help the market meet the renewable energy mandates of the governmentof the Province of Ontario. There are approximately 70 electric distribution companies in Ontario, all of which have government mandates to purchase renewableenergy. The PPA provides for guaranteed pricing from IESO that removes volatility caused by fluctuations in market rates. The Ontario government established theGlobal Adjustment (GA) which is designed to adjust consumer rates depending on the price of energy. The IESO establishes a monthly variable GA rate based onGA costs and Ontario electricity demand which effectively establishes a pass through mechanism to the consumer and eliminates the IESO's economic exposure toour contract price.2. Summary of Significant Accounting PoliciesBasis of PresentationThe accompanying financial statements are presented using United States Generally Accepted Accounting Principles (U.S. GAAP). The preparation of U.S. GAAPbasis financial statements requires management to make certain estimates and assumptions that affect the reported amounts and disclosures in the financialstatements and the reported amounts of assets and liabilities, and to disclose contingent assets and liabilities at the date of the financial statements and the reportedamounts of revenues and expenses during the reporting period. Because the use of estimates is inherent in the financial reporting process, actual results could differfrom those estimates.S- 69K2 Wind Ontario Limited PartnershipNotes to Financial StatementsThese financial statements do not include assets, liabilities, revenue and expenses of the GP and limited partners.Use of EstimatesThe preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amountsof assets and liabilities, disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expensesduring the reporting period. Actual results could differ from those estimates, and such differences may be material to the financial statements.Functional and Presentation CurrencyItems included in the financial statements of the Company are measured using the currency of the primary economic environment in which the Company operates,the (functional currency). The financial statements are presented in Canadian dollars, which is the Company’s functional and presentation currency.Fair Value of Financial InstrumentsASC 820, Fair Value Measurement , defines fair value as the price at which an asset could be exchanged or a liability transferred in an orderly transaction betweenknowledgeable, willing parties in the principal or most advantageous market for the asset or liability. Where available, fair value is based on observable marketprices or derived from such prices. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve somelevel of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’complexity.Cash and Cash EquivalentsCash and cash equivalents consist of cash in banks and highly liquid investments with original maturities of three months or less.Restricted CashRestricted cash consists of cash balances required to collateralize commercial bank letter of credit facilities related primarily to the PPA and for reserves requiredunder the Company’s credit agreements. Non-current restricted cash includes $5.0 million and $5.0 million as of December 31, 2017 and December 31, 2016,respectively, of construction completion costs that were moved into a restricted cash account upon conversion of the construction loan to term loan.Reconciliation of Cash and Cash Equivalents and Restricted Cash as presented on the Statements of Cash FlowsRestricted cash consists of cash balances which are restricted as to withdrawal or usage and includes cash to collateralize bank letters of credit related primarily tointerconnection rights, PPA and for certain reserves required under the Company's loan agreements. The following table provides a reconciliation of cash, cashequivalents, and restricted cash reported within the balance sheets that sum to the total of the same such amounts shown in the statements of cash flows (inthousands): Year ended December 31, 2017 20162015 Cash and cash equivalents $16,000 $17,975$38,711Restricted cash - current — —4,163Restricted cash 8,061 8,08116,307Cash, cash equivalents and restricted cash shown in the statements of cash flows $24,061 $26,056$59,181Trade ReceivablesThe Company’s trade receivables are generated by selling energy in Ontario, Canada through the IESO as a settlement agent. The Company believes that allamounts are collectible and an allowance for doubtful accounts is not required as of December 31, 2017 and 2016.S- 70K2 Wind Ontario Limited PartnershipNotes to Financial StatementsProperty, Plant and EquipmentThe Project is recorded at historical cost on the balance sheets. The Project is being depreciated using the straight-line method over its 25-year life beginning at theCOD. Capitalized assets acquired in support of the plant operations are recorded at cost and depreciated using the straight-line method over the estimated usefullife of the asset.The remaining assets are depreciated over two to five years. Improvements to property, plant and equipment deemed to extend the useful economic life of an assetare capitalized. Repair and maintenance costs are expensed as incurred.Impairment of Long-Lived AssetsThe Company periodically evaluates long-lived assets for potential impairment whenever events or changes in circumstances have occurred that indicate thatimpairment may exist, or the carrying amount of the long-lived asset may not be recoverable. An impairment loss is recognized only if the carrying amount of along-lived asset is not recoverable based on its estimated future undiscounted cash flows. An impairment loss is calculated based on the excess of the carryingvalue of the long-lived asset over the fair value of such long-lived asset, with the fair value determined based on an estimate of discounted future cash flows.During the years ended December 31, 2017, 2016 and for the period from June 17, 2015 to December 31, 2015, no impairment losses were recorded in thestatements of operations and comprehensive income (loss).Deferred Financing CostsFinancing costs incurred in connection with obtaining construction and term financing are deferred and amortized over the terms of the respective loans using theeffective-interest method. Deferred financing costs are capitalized and recorded as an offset to the respective loans in the Company's balance sheets and areamortized to interest expense in the statements of operations and comprehensive income (loss). Deferred financing costs incurred in connection with obtainingletters of credit are recorded as a separate asset in the Company's balance sheets and are amortized using the straight-line method over the term of the letters ofcredit to interest expense in the statements of operations and comprehensive income (loss).Derivatives and Risk ManagementThe Company may enter into interest rate swaps, interest rate caps, forwards and other agreements to manage its interest rate risk. The Company recognizes itsderivative instruments as assets or liabilities at fair value in the balance sheets. The Company does not have contracts subject to master netting agreements withcounterparties, as such assets and liabilities are presented gross on the balance sheets.Accounting for changes in the fair value of a derivative instrument depends on whether it has been designated as part of a hedging relationship and on the type ofhedging relationship. For derivative instruments that qualify and are designated as cash flow hedges, the effective portion of change in fair value of the derivativeis reported as a component of other comprehensive income (loss) (OCI) until the contract settles and the hedged item is recognized in earnings. The ineffectiveportion of change in fair value is recorded as a component of net income (loss) on the statements of operations and comprehensive income (loss). The Companydiscontinues hedge accounting when it has determined that a derivative contract no longer qualifies as an effective hedge or when it is no longer probable that thehedged forecasted transaction will occur.Concentration of Credit RiskFinancial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents, restricted cash, debt,derivatives and revenue. The Company places its cash and restricted cash with high-quality institutions. The Company’s derivative instruments are placed withcounterparties that are credit worthy institutions.Contingent LiabilitiesContingent liabilities are recognized when the Company has a present legal obligation as a result of past events for which it is probable that an outflow of resourceswill be required to settle the obligation, and the amount can be reasonably estimated. Contingent liabilities are not recognized for future operating losses.Other LiabilitiesOther liabilities are recognized when the Company has a present legal obligation as a result of past events for which it is probable that an outflow of resources willbe required to settle the obligation, and the amount can be reasonably estimated.S- 71K2 Wind Ontario Limited PartnershipNotes to Financial StatementsAsset Retirement ObligationsThe Company records an asset retirement obligation (ARO) for the estimated costs of decommissioning turbines, removing above-ground installations andrestoring sites, at the time when a contractual decommissioning obligation is incurred. The ARO represents the present value of the expected costs and timing ofthe related decommissioning activities. The ARO asset and liability are recorded in property, plant and equipment and asset retirement obligation, respectively, onthe accompanying balance sheets. The Company records accretion expense, which represents the increase in the asset retirement obligation, over the remaining oroperational life of the Project. Accretion expense is recorded as operating costs in the statements of operations and comprehensive income (loss) using an accretionrate based on a credit adjusted risk-free interest rate. Changes resulting from revisions to the timing or amount of the original estimate of cash flows are recognizedas an increase or a decrease in the asset retirement cost, or income when the asset retirement cost is depleted.Income TaxesThe financial statements of the Company reflect no provision or liability for income taxes because profits and losses of the Company are allocated to the partnersand are included in the income tax returns of the partners.Income and losses for tax purposes may differ from the financial statement amounts and the partners’ capital (deficit) reflected in the financial statements does notnecessarily reflect their tax basis.Revenue RecognitionThe Company sells the electricity it generates through the IESO. Revenue is recognized based upon the amount of electricity delivered or curtailed at ratesspecified under the contracts, assuming all other revenue recognition criteria are met. Revenue earned from curtailment is recorded as compensation for forgoneenergy in the statements of operations and comprehensive income (loss). The Company evaluates its PPA to determine whether it is in substance a lease orderivative and, if applicable, recognizes revenue pursuant to ASC 840, Leases , and ASC 815, Derivatives and Hedging , respectively. As of December 31, 2017,the PPA was not considered a lease or a derivative instrument, as multiple market participants purchase the energy at market-based prices with IESO working as asettlement agent. As a result, revenue (including any revenue from the price guaranteed by IESO), is recognized on an accrual basis.Cost of RevenueThe Company’s cost of revenue is comprised of direct costs of operating and maintaining its project facilities, including labor, turbine service arrangements,metering service and shadow settlement, environmental fee, land lease royalties, property tax, insurance, depreciation and accretion.Recently Adopted Accounting PronouncementsIn February 2017, the FASB issued ASU 2017-05 , Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifyingthe Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (ASU 2017-05) . ASU 2017-05 is meant to clarify the scope ofASC Subtopic 610-20, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets and to add guidance for partial sales of nonfinancial assets.ASU 2017-05 is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidance and is effective at the same time asASU 2014-09. Further, the Company is required to adopt this guidance at the same time that it adopts the guidance in ASU 2014-09 which creates ASC Topic 606,Revenue from Contracts with Customers and supersedes ASC Topic 605 , Revenue Recognition (ASU 2014-09). The adoption of ASU 2017-05 on January 1, 2018did not have impact on Company's financial statements and related disclosures.Recently Issued Not Yet Adopted Accounting PronouncementsIn August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), which amends the presentationand disclosure requirements and changes how companies assess effectiveness. The amendments are intended to more closely align hedge accounting withcompanies’ risk management strategies, simplify the application of hedge accounting, and increase transparency as to the scope and results of hedging programs.ASU 2017-12 is effective for annual periods beginning after December 15, 2018, including interim periods within those periods. Early application is permitted.The Company is currently assessing the future impact of this update on its consolidated financial statements and related disclosures.In June 2016, the FASB issued ASU 2016-13, Financial Instruments -Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments(ASU 2016-13), which requires the measurement of all expected credit losses for financial assets including trade receivables held at the reporting date based onhistorical experience, current conditions, and reasonable and supportable forecasts. ASUS- 72K2 Wind Ontario Limited PartnershipNotes to Financial Statements2016-13 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The adoption of ASU 2016-13 is notexpected to have a material impact on its consolidated financial statements and related disclosures.In February 2016, the FASB issued ASU 2016-02, Leases , which requires lessees to recognize right-of-use assets and lease liabilities, for all leases, with theexception of short-term leases, at the commencement date of each lease. Under the new guidance, lessor accounting is largely unchanged. ASU 2016-02 simplifiesthe accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and liabilities. ASU 2016-02 is effective for annual periodsbeginning after December 15, 2018, and interim periods within those annual periods. Early adoption is permitted. The amendments of this update should be appliedusing a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. ThePartnership is currently in the initial stages of evaluating the impact of the new standard on its accounting policies, processes and system requirements. ThePartnership has assigned internal resources in addition to the engagement of a third party service provider to assist in evaluation. The Partnership is also assessingthe future accounting impact of this update on its consolidated financial statements and related disclosures as it applies to its PPAs, land leases, office leases andequipment leases. As the Partnership progresses further in its analysis, the scope of this assessment could be expanded to review other types of contracts.In the first quarter of 2018, the Company will adopt Accounting Standards Codification (ASC) Topic 606 , Revenue from Contracts with Customers . The newstandard replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the new standard isthat an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which anentity expects to be entitled in exchange for those goods or services. Additionally, the new standard requires the entity to disclose further quantitative andqualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significantjudgments and estimates used in recognizing revenues from contracts with customers. The adoption of ASC 606 will not have material impact on Company'sfinancial statements.3. Property, Plant and EquipmentThe aggregate cost of property, plant and equipment and accumulated depreciation were as follows (in thousands): December 31, 2017 2016Land$1,067 $1,067Operating wind farm875,705 875,705Furniture, fixtures, and equipment52 52Subtotal876,824 876,824Accumulated depreciation(90,927) (55,895)Property, plant and equipment, net$785,897 $820,929The Company recorded depreciation expense related to property, plant and equipment of $35.0 million, $35.0 million and $19.0 million (unaudited) for the yearsended December 31, 2017, 2016 and for the period from June 17, 2015 to December 31, 2015, respectively.4. Long-Term DebtOn November 20, 2015, the Company entered into a term loan in the amount of $818.0 million with an amortization period of 18 years, at a variable rate interest atCanadian Dollar Offered Rate (CDOR) plus 1.75% per annum. The loan has a maturity date on November 20, 2022 due to prepayment requirements in thepartnership’s credit agreement. In connection with the term loan, the Company entered into interest rate swaps on 90% of the loan commitment. The interest rateswaps are organized in two tranches with fixed effective interest rates of 3.11% and 4.45% for years 1-7 and years 8-18, respectively. As of December 31, 2017,$754.2 million was outstanding under the term loan including the current portion, and no amount was drawn on the letter of credit facilities.Collateral under the financing agreement consists of substantially all of the Company’s assets. Its loan agreement contains a broad range of covenants that, subjectto certain exceptions, restrict the Company’s ability to incur debt, grant liens, sell or lease assets, transfer equity interest, dissolve, pay distributions and change itsbusiness. All the limited partners, general partners and shareholders of general partners pledged shares of partnership units or common stock owned as collateralfor the loan. As of December 31, 2017, the Company was in compliance with all loan covenants.S- 73K2 Wind Ontario Limited PartnershipNotes to Financial StatementsTerms and conditions of outstanding borrowings were as follows (in thousands): As of December 31, 2016 December 31, ContractualInterest Rate EffectiveInterest Rate Maturity Date 2017 2016 Principal $754,207 $785,419 3.16% 4.69% November 2022Unamortized financing costs (11,502) (12,843) Current portion (32,429) (29,872) Long-term debt, less current portion $710,276 $742,704 The following are the amounts due under the Partnership’s term loan for the next five years and thereafter as of December 31, 2017 (in thousands):2018 33,7142019 37,3282020 39,3382021 41,4672022 41,660Thereafter 560,700Total long-term debt, including current maturities $754,207Interest and commitment fees incurred and interest expense for long-term debt consisted of the following (in thousands): Year ended December 31, Period fromJune 17, 2015to December31, 2015(Unaudited) 2017 2016 Interest and commitment fees incurred$35,583 $36,984 $12,405Letter of credit fees incurred1,059 1,059 327Amortization of financing costs1,401 1,460 737Interest expense$38,043 $39,503 $13,469The Company has two letter of credit facilities available in the amount of $60.5 million as set out in the Company’s credit agreement. As of December 31, 2017and 2016, no amounts had been drawn on these letters of credit.5. Asset Retirement ObligationThe Company’s ARO represents the estimated cost of decommissioning the turbines, removing above-ground installations and restoring the sites at a date that is 25years from the COD. As of December 31, 2017 and 2016, the Company recorded $5.3 million and $5.0 million, respectively, in ARO using a project specific creditadjusted risk free rate at COD of 5.46%.S- 74K2 Wind Ontario Limited PartnershipNotes to Financial StatementsThe following table presents a reconciliation of the beginning and ending aggregate carrying amounts of the ARO for the following periods (in thousands): December 31, 2017 2016Beginning asset retirement obligation$5,004 $4,745Accretion expense274 259Ending asset retirement obligation$5,278 $5,0046. Derivatives and Risk ManagementThe Company uses interest rate derivatives to manage its exposure to fluctuation in interest rates. Interest rate risk exists primarily on variable-rate debt for whichthe cash flows vary based upon movement in interest rates. The Company’s objectives for holding these derivative instruments include reducing, eliminating andefficiently managing the economic impact of interest rate exposure as effectively as possible. The Company does not hedge of all of its interest rate risk, therebyexposing the unhedged portion to changes in market prices.The following tables present the fair values of the Company's designated derivative instruments on a gross basis as reflected on the Company’s balance sheets (inthousands): December 31, 2017 2016Derivative Liabilities Current Long-Term Current Long-TermInterest rate swaps $7,915 $59,400 $13,339 $79,286Total Fair Value $7,915 $59,400 $13,339 $79,286The following table summarizes the notional amounts of the Company's outstanding designated derivative instruments (in thousands): December 31, Unit of Measure 2017 2016Interest rate swaps CAD $678,786 $706,877The Company’s interest rate swaps have remaining maturities ranging from approximately 4.7 years to 15.4 years.The following table presents gains and losses on derivative contracts designated and qualifying as cash flow hedges recognized in accumulated othercomprehensive income (loss), as well as, amounts reclassified to earning for the following periods (in thousands): December 31,Period fromJune 17, 2015to December31, 2015(Unaudited) Description 2017 2016Gains (losses) recognized in accumulated OCI Effective portion $11,190 $(15,597)$(24,035)Gains (losses) reclassified from accumulated OCI into: Interest expense Derivative settlements $14,121 $15,978$1,466The Company estimates that $7.9 million in accumulated other comprehensive income (loss) will be reclassified into earnings over the next twelve months.No ineffectiveness was recorded on these swaps for the years ended December 31, 2017, 2016 and for the period from June 17 to December 31, 2015. The changesin the fair value of these swaps are recognized into other comprehensive income (loss).No margin cash collateral was received or recorded from the counterparty during the years ended December 31, 2017 and 2016.S- 75K2 Wind Ontario Limited PartnershipNotes to Financial Statements7. Fair Value MeasurementsThe Company’s fair value measurements incorporate various factors, including the credit standing and performance risk of the counterparties, the applicable exitmarket, and specific risks inherent in the instrument. Non-performance and credit risk adjustments on risk management instruments are based on current marketinputs when available, such as credit default hedge spreads. When such information is not available, internal models may be used.Assets and liabilities recorded at fair value in the combined financial statements are categorized based upon the level of judgment associated with the inputs used tomeasure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to valuation of these assets or liabilities are asfollows:Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation withmarket data at the measurement date and for the duration of the instrument’s anticipated life.Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities andwhich reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration isgiven to the risk inherent in the valuations technique and the risk inherent in the inputs to the model.The carrying value of financial instruments classified as current assets and current liabilities approximates their fair value, based on the nature and short maturity ofthese instruments, and they are presented in the Company’s financial statements at carrying cost. The fair values of cash and cash equivalents and restricted cashare classified as Level 1 in the fair value hierarchy. Certain other assets and liabilities were measured at fair value upon initial recognition and unless conditionsgive rise to an impairment, are not remeasured.Long term debt is presented on the balance sheets at amortized cost. The fair value of variable interest rate long-term debt is approximated by its carrying cost, andis classified as Level 2 in the fair value hierarchy.The Company’s financial assets and (liabilities) which require fair value measurement on a recurring basis are classified within the fair value hierarchy as follows(in thousands): Fair Value Measurements Units Level 1 Level 2 Level 3December 31, 2017 Interest rate swaps $— $67,315 $—Total Fair Value $— $67,315 $— December 31, 2016 Interest rate swaps $— $92,625 $—Total Fair Value $— $92,625 $—Level 2 InputsDerivative instruments subject to re-measurement are presented in the financial statements at fair value. The Company's interest rate swaps were valued bydiscounting the net cash flows using the forward Canadian dollar offered rate curve with the valuations adjusted by the Company’s credit default hedge rate.S- 76K2 Wind Ontario Limited PartnershipNotes to Financial Statements8. Commitments, Contingencies and WarrantiesCommitmentsThe Company has entered into various purchase, construction, as well as other commitments, land leases, and turbine operations and maintenance agreements.Detailed below are estimates of future commitments under these arrangements as of December 31, 2017 (in thousands): 2018 2019 2020 2021 2022 Thereafter TotalPurchase and other commitments $713 $716 $719 $722 $725 $8,717 $12,312Land leases 2,944 2,955 2,956 2,957 2,958 64,004 78,774Service and maintenance 5,046 — — — — — 5,046Total Commitments $8,703 $3,671 $3,675 $3,679 $3,683 $72,721 $96,132Purchase and other commitmentsThe Company has entered into various commitments with service providers related to the projects and operations of its business. Outstanding commitments includethose related to construction, and commitments related to donations to local community and government organizations.In March 2013, the Company entered into an agreement with the local township in which the Company will make annual payments into a fund managed by thetownship in amounts of $2,600 per nameplate MW of the Project installed capacity. The payments are calculated annually and are owed for the 20-year term of thePPA. In exchange for payments, the township undertakes certain obligations to support the Project, including entering into a road use agreement in which theProject may utilize municipal right-of-ways for collection and transmission lines.The Company has also made various public statements that payments will be made to local landowners, for which the Company will not receive any futurebenefits. The Company considers these statements to be cancellable and not legally binding; therefore the Company has not recognized a liability for theseamounts, nor are the payments included in the table above. Payments under the statements are approximately $0.5 million per year, for the next 18 years.Land leasesThe Company has acquired leases for land where the wind farm will be located through the exercise of land options acquired from Capital Power and also executednew land lease agreements in 2014. The leases provide for the land interests necessary for the construction and operation of the project. The Company recorded$2.9 million, $2.7 million and $1.7 million (unaudited) of lease expense in the statements of operations and comprehensive income (loss) for the years endedDecember 31, 2017, 2016 and for the period from June 17, 2015 to December 31, 2015, respectively.Service and maintenanceThe Company has entered into service and maintenance agreements with third party contractors to provide turbine operations and maintenance services andmodifications and upgrades for a three year period beginning after the COD. The computation of outstanding commitments includes an estimated annual priceadjustment for inflation of 2%, where applicable. For the years ended December 31, 2017, 2016 and for the period from June 17, 2015 to December 31, 2015, theCompany recorded service and maintenance expense under these agreements of $7.3 million, $7.1 million and $3.8 million (unaudited), respectively, in projectexpense in the statements of operations.Warranties and GuaranteesTurbine Operating Warranties and Service GuaranteesThe Company entered in to a warranty agreement with Siemens for a two-year period from the commissioning of each turbine. Pursuant to the warranty, if theturbines operate at less than a specified percentage of availability during each consecutive thirty month period, Siemens is obligated to pay liquidated damages tothe Company. In addition, the Company will pay Siemens a bonus if the availability of the turbines exceeds a certain specified availability percentage during thethirty-month period. As of December 31, 2017, the Company recorded a liability of $0.3 million associated with bonuses to Siemens.S- 77K2 Wind Ontario Limited PartnershipNotes to Financial StatementsSiemensOn March 8, 2013, an Operational Incentive Agreement was entered into among Samsung, an affiliate of PRHC and Siemens. The agreement defines operationalobjectives, the terms and conditions upon which the Company may make operational incentive payments to Siemens for achieving one or more of such operationalobjectives under the turbine supply agreements for joint development projects. Siemens earned an initial payment of $1.1 million, which was paid in 2013 forhaving satisfied the Peak Capacity Objective defined under the agreement. The Company did not record any liability related to the agreement as of December 31,2017.Legal ProceedingsRenewable Energy ApprovalDuring the third quarter of 2015, rights to appeal prior decisions granting the Renewable Energy Approval (REA) under Ontario's Environmental Protection Actfor the Project were exhausted without further appeal. As a result, a stay of a previously filed civil suit against the Project pending final determination of the REAwas lifted, allowing such suit to move forward if the claimants so chose to continue such suit. The Project has been awarded their legal fees in connection with theportion of the claim that was stricken, and has reached a settlement agreement under which the Project will waive entitlement to the legal fees and in returnPlaintiff has agreed to full dismissal of all pending claims.9. Related Party TransactionsThe Company is controlled by the GP, which was jointly controlled by Pattern, Samsung, and Capital Power in accordance with the Unanimous ShareholderAgreement dated December 5, 2011. At December 31, 2017, the GP was jointly controlled by Pattern, Axium and Capital Power following Samsung's sale ofinterest in the Company.The following transactions were carried out with the related parties:Management, Operation, and Maintenance Agreement (MOMA)On March 20, 2014, the Company entered into the MOMA with Pattern Operators Canada ULC (POC), which is owned by an affiliate of Pattern to operate andmanage the maintenance of the wind plant and to perform certain other services pertaining to the wind plant in accordance with terms and conditions set in theMOMA.The fixed annual fee for the service is $0.9 million pro-rated for the period from March 20, 2013 until the COD and thereafter the annual fee was increased to $1.4million until expiry of the contract in 2035. Additionally, the Company recorded expense of $1.5 million, $1.4 million and $0.8 million (unaudited) to operationsand maintenance expense in the statements of operations and comprehensive income (loss) for the years ended December 31, 2017, 2016 and for the period fromJune 17, 2015 to December 31, 2015, respectively. As of December 31, 2017 and 2016, the Company recorded $0.2 million and $0.1 million, respectively, inrelated party payable.Project Administration Agreement (PAA)On March 20, 2014, the Company entered into the PAA with POC, which is 100% owned by an affiliate to receive project administrative services. A fixed annualfee of $0.4 million is payable during the period between the COD until expiry of the PPA in 2035. The Company recorded expense of $0.4 million, $0.4 millionand $0.2 million to general and administrative expense in the statements of operations and comprehensive income (loss) for the years ended December 31, 2017 ,2016 and for the period from June 17, 2015 to December 31, 2015 respectively. As of December 31, 2017 and 2016, the Company did not record any related partypayable.10. Subsequent EventsThe Company evaluated subsequent events through February 27, 2018, which is the date these financial statements were available to be issued and noted that therewere no subsequent events to disclose.S- 78 CONSOLIDATED FINANCIAL STATEMENTS Pattern Energy Group Holdings 2 LP As of December 31, 2017 and for the period fromJuly 27, 2017 through December 31, 2017with Report of Independent Auditors S- 79Pattern Energy Group Holdings 2 LPConsolidated Financial StatementsAs of December 31, 2017 and for the period fromJuly 27, 2017 through December 31, 2017Contents Page Report of Independent Auditors S- 81 Consolidated Financial Statements Consolidated Balance Sheet S- 82Consolidated Statement of Operations S- 83Consolidated Statement of Comprehensive Income (Loss) S- 84Consolidated Statement of Changes in Partners' Capital S- 85Consolidated Statement of Cash Flows S- 86Notes to Consolidated Financial Statements S- 87S- 80Report of Independent AuditorsTo the Partners,Pattern Energy Group Holdings 2 LP. We have audited the accompanying consolidated financial statements of Pattern Energy Group Holdings 2 LP, whichcomprise the consolidated balance sheet as of December 31, 2017, and the related consolidated statements of operations, comprehensive income (loss), changes inpartners’ capital and cash flows for the period from July 27, 2017 through December 31, 2017, and the related notes to the consolidated financial statements.Management’s Responsibility for the Financial StatementsManagement is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles;this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free ofmaterial misstatement, whether due to fraud or error.Auditor’s Responsibility Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standardsgenerally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financialstatements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the 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 ofthe financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on theeffectiveness of the entity’s internal control. Accordingly, we express no such opinion.An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management,as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate toprovide a basis for our audit opinion.OpinionIn our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pattern Energy GroupHoldings 2 LP at December 31, 2017, and the consolidated results of its operations and its cash flows for the period from July 27, 2017 through December 31,2017 in conformity with U.S. generally accepted accounting principles. /s/ Ernst & Young LLPFebruary 24, 2018S- 81Pattern Energy Group Holdings 2 LPConsolidated Balance Sheet(In thousands of U.S. Dollars) December 31, 2017Assets Current assets: Cash and cash equivalents $40,211Restricted cash, current 2,451Prepaid expenses and other current assets 6,893Total current assets 49,555 Restricted cash 14,242Related party receivable 17,248Major equipment advances 50,495Deferred development costs 17,825Construction in progress 164,288Property, plant and equipment, net of accumulated depreciation 2,710Unconsolidated investments 6,063Other assets 12,170Total assets $334,596 Liabilities and partners' capital Current liabilities: Accounts payable and other accrued liabilities $16,985Related party payable, current 11,565Current portion of long-term debt 101,920Total current liabilities 130,470 Other long-term liabilities 843Total liabilities 131,313Commitments and contingencies (Note 11) Partners' capital: General partners —Limited partners 202,846Accumulated other comprehensive income (loss) 98Total capital before noncontrolling interest 202,944Noncontrolling interest 339Total partners' capital 203,283Total liabilities and partners' capital $334,596 See accompanying notes to consolidated financial statements.S- 82Pattern Energy Group Holdings 2 LPConsolidated Statement of Operations(In thousands of U.S. Dollars) For the period from July27, 2017 throughDecember 31, 2017Revenue: Total revenue $— Operating expenses: Development expense 18,065General and administrative 2,722Related party expenses 11,777Total operating expenses 32,564 Operating loss (32,564) Other income (expense): Interest expense (1,240)Equity in losses of unconsolidated investments (1,829)Other income, net 156Total other expense (2,913) Net loss (35,477) Net loss attributable to noncontrolling interest —Net loss attributable to controlling interest $(35,477) See accompanying notes to consolidated financial statements.S- 83Pattern Energy Group Holdings 2 LPConsolidated Statement of Comprehensive Income (Loss)(In thousands of U.S. Dollars) For the period from July27, 2017 throughDecember 31, 2017Net loss $(35,477)Other comprehensive income Foreign currency translation, net of tax 98Total other comprehensive income, net of tax 98Comprehensive loss (35,379) Less comprehensive loss attributable to noncontrolling interest: Net loss attributable to noncontrolling interest —Comprehensive loss attributable to noncontrolling interest —Comprehensive loss attributable to controlling interest $(35,379) See accompanying notes to consolidated financial statements.S- 84Pattern Energy Group Holdings 2 LPConsolidated Statement of Changes in Partners' Capital(In thousands of U.S. Dollars) GeneralPartners LimitedPartners AccumulatedOtherComprehensiveIncome (loss) Total Noncontrollinginterest TotalPartners'CapitalBalances at July 27, 2017 $— $103,633 $— $103,633 $339 $103,972Contributions — 229,956 — 229,956 — 229,956Redemptions — (89,023) — (89,023) — (89,023)Distributions — (6,243) — (6,243) — (6,243)Net loss — (35,477) — (35,477) — (35,477)Other comprehensive income, net of tax — — 98 98 — 98Balances at December 31, 2017 $— $202,846 $98 $202,944 $339 $203,283 See accompanying notes to consolidated financial statements.S- 85Pattern Energy Group Holdings 2 LPConsolidated Statement of Cash Flows(In thousands of U.S. Dollars) For the period fromJuly 27, 2017 throughDecember 31, 2017Operating activities Net loss $(35,477) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation 80Amortization of financing costs 547Unrealized loss on exchange rate changes 129Equity in losses in unconsolidated investments 1,829Prepaid expenses and other current assets (2,861)Related party receivable 47Other assets 1,038Accounts payable and other accrued liabilities 10,194Related party payable 4,003Long-term liabilities 581Net cash used in operating activities (19,890) Investing activities Assets acquired in common control transactions (13,833)Cash paid for asset acquisitions (4,750)Capital expenditures (55,064)Contribution to unconsolidated investments (3,119)Other current and non-current assets (38)Net cash used in investing activities (76,804) Financing activities Capital contributions 229,956Redemptions (89,023)Distributions in common control transactions (6,243)Payment for financing costs (712)Net cash provided by financing activities 133,978 Effect of exchange rate changes on cash, cash equivalents, and restricted cash 37Net change in cash, cash equivalents, and restricted cash 37,321Cash, cash equivalents, and restricted cash at beginning of period 19,583Cash, cash equivalents, and restricted cash at end of period $56,904 See accompanying notes to consolidated financial statements.S- 86Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 20171. OrganizationOn November 10, 2016, Pattern Energy Group Holdings 2 LP ("PEG LP 2") and its subsidiaries (collectively referred to as "Pattern Development 2.0", "we","our", or the "Partnership") were formed as a Delaware limited partnership with the purpose, through its subsidiaries, to acquire and develop early to mid-stagerenewable energy generation and electrical transmission assets ("Project Entities").On July 12, 2017, PEG LP 2’s General Partner executed the Second Amended and Restated Agreement of Limited Partnership of Pattern Energy Group Holdings 2LP (“Capital and Redemption Agreement”) with R/C Wind II LP ("Riverstone"), Pattern Energy Group Holdings LP ("PEGH"), Management ("Existing LPs") andnew investors, Riverstone Pattern Energy II Holdings LP (“Riverstone II”) and Pattern Energy Group, Inc. (“PEGI”). Per the terms of the Capital and RedemptionAgreement, a capital call was approved by PEG LP 2’s Board of Directors. The Capital and Redemption Agreement became effective on July 27, 2017 when PEGLP 2 received $205.0 million from the capital call. The capital call funds were used to redeem approximately 49% of the Existing LPs’ investment including all ofPEGH’s investment, purchase Project Entities, and provide working capital funds. On December 26, 2017, PEG LP 2's Board of Directors approved an additionalcapital call of $25.0 million.BusinessOn the December 8, 2016, PEG LP 2 entered into a contribution agreement with PEGH. PEGH, through its wholly owned subsidiary, Pattern Energy Group LP(“Pattern Development 1.0”), contributed all of its equity interests in certain development subsidiaries of $25.6 million plus $82.5 million in cash to PatternDevelopment 2.0 in exchange for partnership interests in the Partnership (the “Contribution”).In June 2017, Pattern Development 1.0 and Pattern Development 2.0 entered into three separate agreements to transfer additional equity interests to thePartnership. PEGH sold equity interests in development subsidiaries in the United States, Canada, and Mexico (the “Second Contribution”) to the Partnership for$20.0 million.As a result of the transactions with PEGH, the Partnership’s purchase of Project Entities from third parties, and the Partnership’s formation of greenfield ProjectEntities, the Partnership has varying interests in approximately 46 Project Entities in various degrees of development, which constitutes a pipeline of approximately7,000 MWs of electricity.2. Summary of Significant Accounting PoliciesBasis of Presentation and Principles of ConsolidationThe accompanying consolidated financial statements have been prepared in accordance with the accounting principles generally accepted in the United States (U.S.GAAP). They include the results of wholly-owned and partially-owned subsidiaries in which the Partnership has a controlling interest with all significantintercompany accounts and transactions eliminated.The consolidated financial statements include the accounts of PEG LP 2 and all other entities in which the Partnership has a controlling financial interest and thosevariable interest entities ("VIEs") where the Partnership is the primary beneficiary. Results of operations of acquired entities are included from the date ofacquisition or the date the Partnership became the primary beneficiary of the VIE. Noncontrolling interests represent the portion of the Partnership’s net income(loss), net assets and comprehensive income (loss) that is not allocable to the Partnership and is calculated based on ownership percentage for certain ProjectEntities. The Partnership’s investments in which the Partnership exercises significant influence, but not a controlling interest, are accounted for using the equitymethod. When the Partnership holds a non-controlling interest in a Project Entity and does not exercise significant influence over the investment, the Partnershiprecords the investment under the cost method.Asset AcquisitionsWhen the Partnership acquires assets and liabilities that do not constitute a business, the fair value of the purchase consideration, including the transaction costs ofthe asset acquisition, is assumed to be equal to the fair value of the net assets acquired. The purchase consideration, including transaction costs, is allocated to theindividual assets and liabilities assumed based on their relative fair values. Contingent consideration associated with the acquisition is generally recognized whenthe contingency is resolved. No goodwill is recognized in an asset acquisition.S- 87Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 2017Variable Interest EntitiesIn the normal course of our business, we have 100% ownership interests in Project Entities that have been determined to be VIEs because the Project Entities lacksufficient equity to develop, construct, and operate the project. The Partnership is the primary beneficiary since we have the power to direct the activities that mostsignificantly impact the VIE’s economic performance and the obligation to fund the development of the project. When a Project Entity begins construction andobtains construction financing, we generally determine that the Project Entity is no longer a VIE because the entity has sufficient equity to finance the constructionwithout additional subordinated financial support. We also enter into joint venture agreements with third parties to develop and construct projects. We generallyhave a variable interest in these entities and an obligation to co-develop the project. Prior to construction financing these entities are usually VIEs, but we generallyare not the primary beneficiary.Use of EstimatesThe preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect thereported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reportedamounts of expenses during the reporting period. Actual results could differ from those estimates and such differences may be material to the consolidatedfinancial statements. Significant items subject to such estimates and assumptions include the useful lives of fixed assets and recoverability of long-lived assets.Fair Value MeasurementsThe Partnership’s fair value measurements incorporate various factors, including the credit standing and performance risk of the counterparties, the applicable exitmarket and specific risks inherent in the instrument. Nonperformance and credit risk adjustments on risk management instruments are based on either (i) actualmarket data or (ii) assumptions that other market participants would use in pricing and asset or liability, including estimates or risk. When such information is notavailable, internal models may be used. (Refer to Footnote 9. Fair Value Measurements ).Assets and liabilities recorded at fair value in the consolidated financial statements are categorized based upon the level of judgment associated with the inputsused to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to valuation of these assets or liabilitiesare as follows:Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with marketdata at the measurement date and for the duration of the instrument’s anticipated life.Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities and which reflectmanagement’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the riskinherent in the valuations technique and the risk inherent in the inputs to the model.Cash, Cash Equivalents and Restricted CashCash and cash equivalents consist of all cash balances and highly-liquid investments with original maturities of three months or less.Restricted cash consists of cash balances which are restricted as to withdrawal or usage and includes cash held in reserves required under the Partnership’s letter ofcredit ("LC") agreements.Reconciliation of Cash, Cash Equivalents, and Restricted Cash as presented on the Statements of Cash Flows For the period from July27, 2017 throughDecember 31, 2017 Cash and cash equivalents $40,211 Restricted cash - current 2,451 Restricted cash 14,242 Cash, cash equivalents and restricted cash shown in the statements of cash flows $56,904 S- 88Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 2017Major Equipment AdvancesMajor equipment advances represent amounts advanced to suppliers for the manufacture of wind turbines and solar panels in accordance with componentequipment supply agreements and for which the Partnership has not taken title. These advances are reclassified to construction in progress when the Partnershiptakes legal title of the equipment.Deferred Development Costs and Construction in ProgressThe Partnership expenses all project development costs until a project is determined to be technically feasible and likely to achieve commercial success. When theproject is deemed feasible, project development costs are recorded as deferred developments costs. Deferred development costs represent the accumulated cost ofinitial permitting, environmental reviews, land rights and obligations, and preliminary design and engineering work.Upon commencement of construction, all construction costs along with applicable previously deferred development costs are recorded as a component ofconstruction in progress. Construction in progress represents the accumulation of project development costs and construction costs, including costs incurred for thepurchase of major equipment, such as turbines and modules for which the Partnership has taken legal title, civil engineering, electrical, and other related costs.Construction in progress is reclassified to property, plant and equipment when the project achieves commercial operation.As of December 31, 2017, construction in progress consists primarily of $161.8 million related to wind generation turbines purchased.Capitalization of Other CostsThe Partnership capitalizes certain employee compensation and other indirect costs ("indirect costs") associated with development and construction projects.Indirect costs are capitalized based on time estimates spent on each project when the project is determined to be probable or technically feasible and likely toachieve commercial success.The Partnership capitalizes interest and related financing fees related to the long-term debt used to finance projects in construction. Capitalization is discontinuedwhen the project achieves commercial operation.Property, Plant and EquipmentProperty, plant and equipment represent land, computer software, and other equipment. Property, plant and equipment are stated at cost, less accumulateddepreciation. Depreciation is calculated using the straight-line method over the respective assets’ useful lives, varying between two to ten years. Land is notdepreciated. Improvements to property, plant and equipment deemed to extend the useful economic life of an asset are capitalized. Repair and maintenance costsare expensed as incurred.Impairment of Long-Lived AssetsThe Partnership periodically evaluates long-lived assets for potential impairment whenever events or changes in circumstances have occurred that indicate thatimpairment may exist, or the carrying amount of the long-lived asset may not be recoverable. An impairment loss is recognized only if the carrying amount of along-lived asset is not recoverable based on its estimated future undiscounted cash flows. An impairment loss is calculated based on the excess of the carryingvalue of the long-lived asset over the fair value of such long-lived asset, with the fair value determined based on an estimate of discounted future cash flows.Income TaxesThe Partnership is organized as a pass-through entity for U.S. federal and state income tax purposes. Federal and state income taxes are assessed at the owner leveland each owner is liable for its own tax payments. The Partnership is subject to other state-based taxes. Certain entities are corporations or have elected to be taxedas corporations. In these circumstances, income tax is accounted for under the asset and liability method. The Partnership is subject to Canadian, Dutch, andMexican income taxes based upon the tax laws and rates in effect in the countries in which operations are conducted.The asset and liability method requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have beenincluded in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between thefinancial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect ofa change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The Partnership recognizesdeferred tax assets to the extent that it believes these assets are more likely than not to be realized. In making such a determination, the Partnership considers allavailableS- 89Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 2017positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning and results ofrecent operations. If the Partnership determines that it would be able to realize its deferred tax assets in the future in excess of their net recorded amount, it wouldmake an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes. The Partnership records uncertain taxpositions in accordance with ASC 740, Income Taxes, on the basis of a two-step process whereby (1) it determines whether it is more likely than not that the taxpositions will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more likely than not recognitionthreshold, it recognizes the largest amount of tax benefit that is more than 50 percent likely to be realized upon ultimate settlement with the related tax authority.The Partnership has a policy to classify interest and penalties associated with uncertain tax positions together with the related liability and the expenses incurredrelated to such accruals, if any, are included in the provision for income taxes.Concentration of Credit RiskFinancial instruments that potentially subject the Partnership to concentrations of credit risk consist primarily of cash and cash equivalents, major equipmentadvances, and transmission security deposits. The Partnership’s cash and cash equivalents are with high quality institutions. The Partnership has exposure to creditrisk to the extent cash and cash equivalent balances, including restricted cash, exceed amounts covered by federal deposit insurance. Exposure to credit risk formajor equipment advances and transmission security deposits are limited by the amount of the deposit. Major equipment advances are with large creditworthycompanies and transmission security deposits are held with public utilities. The Partnership believes that its credit risk is immaterial.As of December 31, 2017, the Partnership paid $7.3 million in transmission security deposits to public utilities companies in southwest U.S. and $50.5 million inmajor equipment advances to a major turbine supplier.Foreign Currency TranslationThe assets and liabilities of foreign subsidiaries, where the local currency is the functional currency, are translated from their respective functional currencies intoU.S. dollars (“USD”) at the rates in effect at the balance sheet date and revenue and expense amounts are translated at average rates during the period, with theresulting foreign currency translation adjustments recorded in other comprehensive income (loss), net of tax, in the consolidated statements of changes in partners’capital and comprehensive income (loss). Where the USD is the functional currency, re-measurement adjustments are recorded in other (expense) income, net inthe accompanying consolidated statements of operations.Recently Adopted Accounting StandardsIn June 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-10, Development Stage Entities ("ASU2014-10"), which eliminated the definition of a development stage entity and the financial reporting requirements specific to development state entities. Theamendments changed the method that previously existed in ASC 810 for determining whether a development stage entity had sufficient equity at risk and thereforewas a VIE. ASU 2014-10 is effective for non-public companies for fiscal years beginning after December 15, 2016.In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis (“ASU 2015-02”) to modify the analysis thatcompanies must perform in order to determine whether a legal entity should be consolidated. ASU 2015-02 simplifies current guidance by reducing the number ofconsolidation models; eliminating the risk that a reporting entity may have to consolidate based on a fee arrangement with another legal entity; placing moreweight on the risk of loss in order to identify the party that has a controlling financial interest; reducing the number of instances that related party guidance needs tobe applied when determining the party that has a controlling financial interest; and changing rules for companies in certain industries that ordinarily employ limitedpartnership or VIE structures.In October 2016, the FASB issued ASU 2016-17, Consolidation (Topic 810) - Interests Held through Related Parties That Are under Common Control (“ASU2016-17”). The ASU changes how a single decision maker considers its indirect interests when performing the primary beneficiary analysis under the VIE model.For non-public companies, this guidance (as well as that in ASU 2015-02) is effective for annual periods beginning after December 15, 2016, and interim periodswithin annual periods after December 15, 2017.The Partnership adopted ASU 2014-10, 2015-02, and 2016-17 as of January 1, 2017. Due to the change in methodology for determining whether a developmentstage entity has sufficient equity at risk, substantially all of the Partnership’s development stage Project Entities became VIEs as of January 1, 2017. The change ofstatus to VIE will not have any impact to the financial statements, other than disclosures, since all of the Project Entities were previously consolidated under thevoting interest model and the primary beneficiaries and Project Entities in each case are under common control; therefore, there’s no change to the reportingmanner or accounting basis for the Project Entities.S- 90Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 2017Recently Issued Accounting Standards not yet AdoptedIn February 2017, the FASB issued ASU 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifyingthe Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets ("ASU 2017-05"). ASU 2017-05 is meant to clarify the scopeof ASC Subtopic 610-20, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets and to add guidance for partial sales of nonfinancialassets. ASU 2017-05 is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidance and is effective at the sametime as ASU 2014-09, Revenue from Contracts from Customers , which creates ASC Topic 606, Revenue from Contracts with Customers and supersedes ASCTopic 605, Revenue Recognition ("ASU 2014-09"). Further, the Partnership is required to adopt this guidance at the same time that it adopts the guidance in ASU2014-09. The Partnership is currently assessing the future impact of this update on its consolidated financial statements and related disclosures.In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business ("ASU 2017-01"), which provides a screen to determine when a set is nota business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable assetor a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. ASU 2017-01 iseffective for annual periods beginning after December 15, 2018. Early application of this ASU is allowed for transactions for which the acquisition date occursbefore the issuance date or effective date of this amendment, only if the transaction has not been reported in previously issued financial statements. Earlyapplication of this ASU is also permitted for transactions in which a subsidiary is deconsolidated or a group of assets is derecognized that occur before the issuancedate or effective date of the amendments, only if the transaction has not been reported in previously issued financial statements. The amendments should be appliedprospectively on or after the effective date and no disclosures are required at transition. The Partnership is currently assessing the future impact of this update on itsconsolidated financial statements and related disclosures.In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments("ASU 2016-13"), which requires the measurement of all expected credit losses for financial assets including trade receivables held at the reporting date based onhistorical experience, current conditions, and reasonable and supportable forecasts. ASU 2016-13 is effective for fiscal years beginning after December 15, 2020.The adoption of ASU 2016-13 is not expected to have a material impact on its consolidated financial statements and related disclosures.In February 2016, the FASB issued ASU 2016-02, Leases ("ASU 2016-02"), which requires lessees to recognize right-of-use assets and lease liabilities, for allleases, with the exception of short-term leases, at the commencement date of each lease. Under the new guidance, lessor accounting is largely unchanged. ASU2016-02 simplifies the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and liabilities. ASU 2016-02 iseffective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. Early adoption is permitted. The amendments ofthis update should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of theearliest period presented. The Partnership is in the initial stages of evaluating the impact of the new standard on its accounting policies, processes and systemrequirements. The Partnership is also assessing the accounting impact of the ASU 2016-02 as it applies to its power purchase agreements ("PPAs"), land leases,office leases and equipment leases. As the Partnership progresses further in its analysis, the scope of this assessment could be expanded to review other types ofcontracts.In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). The new standard replaces industry-specific guidanceand establishes a single five-step model to identify and recognize revenue. The core principle of the new standard is that an entity should recognize revenue upontransfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange forthose goods or services. Additionally, the new standard requires the entity to disclose further quantitative and qualitative information regarding the nature andamount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenuesfrom contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606) Principal versus AgentConsiderations (Reporting Revenue Gross versus Net ), which clarifies how to apply the implementation guidance on principal versus agent considerations relatedto the sale of goods or services to a customer as updated by ASU 2014-09. In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers( Topic 606 ) Identifying Performance Obligations and Licensing, which clarifies two aspects of Topic 606: identifying performance obligations and the licensingimplementation guidance, while retaining the related principles for those areas, as updated by ASU 2014-09. In May 2016, the FASB issued ASU 2016-12,Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients , which makes narrow scope amendments to Topic606 including implementation issues on collectability, non-cash consideration and completed contracts at transition. In December 2016, the FASB issued ASU2016-20, Technical Corrections and Improvements to Topic 606, "Revenue from Contracts with Customers," which make additional narrow scope amendments toTopic 606 including loan guarantee fees, impairment testing of contract costs, provisions for losses on construction-type and production-type contracts.S- 91Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 2017The new standard permits adoption by either using (i) the full retrospective approach for all periods presented in the period of adoption or (ii) a modifiedretrospective approach with the cumulative effect of initially applying the new standard recognized at the date of initial application and providing certain additionaldisclosures. The new standard is effective for annual reporting periods beginning after December 15, 2018, with early adoption permitted for annual reportingperiods beginning after December 15, 2016. The Partnership plans to adopt the new standard effective January 1, 2019.The Partnership currently plans to adopt using the modified retrospective approach. However, a final decision regarding the adoption method has not been finalizedat this time. The Partnership's final determination will depend on a number of factors, such as the significance of the impact of the new standard on its financialresults and its ability to analyze the information necessary to assess the impact on its prior period consolidated financial statements, as necessary.The Partnership is in the process of evaluating the impact of the new standards on its accounting policies, processes and system requirements. The Partnership hasassigned internal resources in addition to the engagement of a third party service provider to assist in evaluation. The Partnership is also assessing the accountingimpact of the new standard as it applies certain elements of its revenue arrangements such as contracts that contain the sale of electricity and related renewableenergy credits, contracts that contain volume variability, and contracts that contain modification clauses. As the Partnership progresses further in its analysis, thescope of this assessment could be expanded to include other contract elements that could have an accounting impact under the new standard.The Partnership continues to assess the potential impacts of the new standard and cannot reasonably estimate quantitative information related to the impact of thenew standard on its consolidated financial statements at this time.3. Asset AcquisitionsThe Partnership enters into agreements to purchase renewable energy assets to increase the Partnership’s portfolio of Project Entities. The purchase agreementsusually require an initial payment and contingent payments based on the project reaching certain milestones. For the period July 27, 2017 through December 31,2017, the Partnership paid $4.8 million in initial and milestone payments included in deferred development costs.S- 92Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 20174. Property, Plant and EquipmentThe following table presents the categories within property, plant and equipment, and accumulated depreciation as of December 31, 2017 (in thousands): December 31, Depreciable Life(Years) 2017 Development equipment$2,434 2-10Computer software12 3-5Land1,320 3,766 Less: accumulated depreciation(1,056) Property, plant and equipment, net$2,710 The Partnership recorded depreciation expense in the consolidated statement of operations related to property, plant and equipment of $80 thousand for the periodfrom July 27, 2017 through December 31, 2017.5. Variable Interest EntitiesConsolidated Variable Interest EntitiesWe have Project Entities in the U.S., Canada, and Mexico, in the development stage where the Partnership has 100% of the ownership interests, the entities areVIEs and we are the primary beneficiary.As a result of the Contribution and the Second Contribution, the Partnership became the direct and indirect parent of five Project Entity structures that are subjectto a profit-sharing arrangement under an X/Y share structure. The X shares have 100% of the voting interests and will receive 10% of the distributions after thePartnership has been returned all of its invested capital. The Y shares are non-voting and have no obligations to fund capital into the projects. The Project Entitiesare in the development stage, are VIEs and the Partnership has been determined to be the primary beneficiary.The following presents the carrying amounts of the consolidated VIEs’ assets and liabilities included in the consolidated balance sheet (in thousands). Assetspresented below are restricted for settlement of the consolidated VIEs’ obligations and all liabilities presented below can only be settled using the VIE’s resources.S- 93Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 2017 December 31, 2017Assets Current assets: Cash and cash equivalents $5,616Restricted cash 2,451Other current assets 6,199Total current assets 14,266 Related party receivable 17,248Deferred development costs 16,395Construction in progress 164,288Property, plant and equipment, net 1,364Unconsolidated investments —Other assets 9,057Total assets $222,618 Liabilities Current liabilities: Accounts payable and other accrued liabilities $16,174Related party payable, current 628Current portion of long-term debt 101,920Total current liabilities 118,722 Other long-term liabilities 843Total liabilities $119,565Unconsolidated Variable Interest EntitiesThe Partnership has variable interests through its equity interest in joint ventures projects in the U.S., Canada, and Mexico. The Project Entities are VIEs, but thePartnership is not the primary beneficiary; therefore, the Project Entities are accounted for under the equity method of accounting (Refer to Footnote 6.Unconsolidated Investments ).As of December 31, 2017, the Partnership’s maximum exposure to loss is estimated at $6.1 million, which represents the carrying value of the investments inunconsolidated VIEs. The maximum exposure to loss represents the maximum loss that the Partnership could be required to recognize assuming all the investees’assets are worthless, without consideration of the probability of a loss or of any actions the Partnership may take to mitigate any such loss.6. Unconsolidated InvestmentsThe unconsolidated investments of $6.1 million comprise of seven investments with ownership percentages varying from 29.0% to 51.0%.As a result of the Second Contribution, the Partnership has guaranteed 49.0% of the future contingent payments for a project under an asset purchase agreement.The guaranty is a guarantee of payment, not of collection or performance. The guarantee will terminate if the Partnership abandons the project or pays allcontingent payment obligations up to the aggregate maximum recovery amount of $7.4 million.S- 94Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 20177. Other AssetsThe following table presents the major components of other long-term assets as of December 31, 2017 (in thousands): December 31, 2017Deposits $9,642Other long-term assets 2,528Other assets $12,1708. Long-Term DebtThe following table presents long-term debt as of December 31, 2017 (in thousands): Loan Balance ContractualInterestRate MaturityLoan Facility $103,443 LIBOR plus3.25% June 2018Less: deferred financing costs (1,523) Total debt 101,920 Less: current portion of long-term debt (101,920) Long-term debt, net $— On December 22, 2016, the Partnership entered into a financing agreement with two lenders for an equipment loan ("Loan Facility") of $68.4 million that has amaturity date of June 28, 2018. On April 28, 2017, a third lender was added to the financing agreement and that lender provided an additional $35.0 million. TheLoan Facility accrues interest at LIBOR plus 3.25%. The financing provides for a LC facility of $44.2 million to satisfy security requirements under a transmissionservices agreement ("TSA") with the public utilities companies in southwest U.S.Collateral for the Loan Facility includes a secured interest in a Project Entity's tangible assets, contractual rights and cash on deposit with the depository agent. TheLoan Facility contains a broad range of covenants that, subject to certain exceptions, restrict the Project Entity’s ability to incur debt, grant liens, sell or leasecertain assets, transfer equity interests, dissolve, make distributions, or change their business.As of the date of these financial statements, no events or conditions which constitutes an event of default in relation to these covenants existed.For the period from July 27, 2017 through December 31, 2017, the Partnership incurred interest and amortized financing costs of $3.4 million, which wascapitalized to construction in progress in the consolidated balance sheet and commitment fees related to letters of $1.2 million, which was recorded in interestexpense.9. Fair Value MeasurementsThe carrying value of financial instruments classified as current assets and current liabilities approximates their fair value based on the nature of their shortmaturity, and these instruments are presented in the Partnership's consolidated financial statements at carrying cost. The fair values of cash and cash equivalentsand restricted cash are classified as Level 1 in the fair value hierarchy.The carrying value of debt is presented on the consolidated balance sheet, net of financing costs, discounts and premiums, which approximates the fair value of thevariable interest rate debt. These debt fair values are Level 3 measurements because they are estimated based on the Partnership's incremental borrowing rates.(Refer to Footnote 2. Summary of Significant Accounting Policies ).Nonrecurring Fair Value MeasurementsS- 95Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 2017Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, suchas when there is evidence of impairment.The Partnership periodically evaluates the carrying value of long-lived assets to be held and used when events or circumstances warrant such a review. Fair value isdetermined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved. These assets wouldgenerally be classified within Level 3 of the fair value hierarchy.10. Income TaxesThe Partnership did not record any current or deferred tax expenses for the period from July 27, 2017 through December 31, 2017. The following table presents theprincipal components of the Partnership’s net deferred tax assets and liabilities as of December 31, 2017 (in thousands): December 31, 2017Deferred tax assets/(liabilities): Net operating loss carryforwards$905Other142Property, plant and equipment543Capitalized start-up costs75Investment in partnerships(9)Total gross deferred tax assets/(liabilities)1,656Less: valuation allowance(1,656)Total net deferred tax assets/(liabilities)$—The deferred tax assets and deferred tax liabilities resulted primarily from temporary differences between book and tax basis of assets and liabilities. ThePartnership regularly assesses the likelihood that future taxable income levels will be sufficient to ultimately realize the tax benefits of the deferred tax assets.Should the Partnership determine that future realization of the tax benefits is more likely than not, an adjustment would be made to the deferred tax asset valuationallowance, which would reduce the provision for the income taxes in the period of such determination.As of December 31, 2017, the Partnership has net operating loss carryforwards in the amount of $3.3 million, which will begin to expire commencing in 2029 forU.S., Canada, and Mexico tax purposes.The Partnership is required to recognize in the financial statements the impact of a tax position, if that position is more likely than not of being sustained on audit,based on the technical merits of the position. As of December 31, 2017, the Partnership does not have any unrecognizable tax benefits and does not have any taxpositions for which it is reasonably possible that the amount of gross unrecognized tax benefits will increase or decrease within 12 months of the year endedDecember 31, 2017. The Partnership files income tax returns in the U.S. federal jurisdiction, and various state jurisdictions. The Partnership's U.S. and foreignincome tax returns for 2013 and forward are subject to examination.The Partnership has a policy to classify accrued interest and penalties associated with uncertain tax positions together with the related liability, and the expensesincurred related to such accruals are included in the provision for income taxes. The Partnership did not incur any interest expense or penalties associated withunrecognized tax benefits during the year ended December 31, 2017.11. Commitments and ContingenciesFrom time to time, the Partnership becomes involved in claims and legal matters arising in the ordinary course of business. Management is not currently aware ofany matters that will have a material adverse effect on the consolidated results of operations or cash flows of the Partnership.S- 96Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 2017CommitmentsThe Partnership entered into various commitments with service providers related to the Partnership’s Project Entities and operations of its business. Outstandingcommitments with these vendors were $12.8 million as of December 31, 2017.The following table summarizes estimates of future commitments related to the various agreements that the Partnership has entered into (in thousands): 2018 2019 2020 2021 2022 Thereafter TotalPurchase agreements $149,396 $11,266 $— $— $— $— $160,662Operating leases 3,702 3,795 3,819 1,391 1,479 6,123 20,309Total Commitments $153,098 $15,061 $3,819 $1,391 $1,479 $6,123 $180,971Purchase AgreementsOn September 29, 2017, the Partnership entered into a turbine agreement with a major turbine producer to purchase wind turbines for $160.7 million. Thepayments and delivery of turbines are scheduled to begin in 2018.Operating LeasesRent expense recorded in the consolidated statement of operations as general and administrative expense was $2.1 million for the period from July 27, 2017through December 31, 2017.The Partnership entered into various long-term land leases and other land agreements for various projects in development. The leases have various terms based onthe project's stage of development and most of the leases are cancelable if we do not proceed with construction or reach commercial operation. Some leases containprovisions that require us to purchase the property or part of the property if we reach commercial operation. Many of the leases have damage clauses that require usto pay for damages caused during our development activities. The leases include both fixed minimum and contingent rent based on us reaching developmentmilestones and upon reaching commercial operation. If the project reaches commercial operation the contingent rent portion of the land leases will generally bebased on total megawatts of electricity produced and delivered to the grid. Contingent rental payments are generally recognized as rent expenses as incurred.ContingenciesUnrecorded Contingent ConsiderationUnrecorded contingent consideration exists in our acquisition of Project Entities which are asset acquisitions. The nature of the contingencies may vary by contractbut generally these contingent payments become due and payable upon (i) signing of a PPA, (ii) closing construction financing or (iii) the commercial operationsdate. In addition to achieving these milestones, the contingent consideration liabilities may also be subject to purchase price adjustments, such as the final amountof the PPA price, the name plate capacity or annual energy production level of the project. The amount of unrecorded contingent consideration is estimated to be$54.5 million at December 31, 2017.The Partnership entered into agreements with law firms to engage them as counsel in connection with the development of one or more transmission expansionprojects. Pursuant to the agreements, certain billings are only due if ground-breaking and construction financing occurs. As of December 31, 2017, we have notaccrued any future payments under these agreements.Letters of CreditsDuring development activities, the Partnership routinely enters into long term agreements, many of which require security deposits to guarantee our performanceunder the agreements. As of December 31, 2017, the Partnership has obtained letters of credit to provide security for four PPAs totaling $14.5 million and threeinterconnection agreements totaling $17.1 million. These letters of credit are recorded on the consolidated balance sheet as of December 31, 2017 as $14.2 millionand $17.2 million in restricted cash and related party receivable, respectively. The LCs are generally released when the project begins commercial operations.The Partnership entered into long term TSAs in order to be able to schedule the generator's energy to specific locations on the transmission providers' system. Thevarious TSAs terminate from 2018 to 2048. To ensure its performance under the terms of the TSA, the Partnership obtained an LC facility of $44.2 million. As ofDecember 31, 2017, the Partnership has not drawn on this LC facility.S- 97Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 201712. Related Party TransactionsMultilateral Service AgreementThe Partnership entered into a Multilateral Management Services Agreement ("MSA") with PEGH and PEGI, collectively, the Pattern Companies, which providesfor the Partnership and the Pattern Companies to benefit, primarily on a cost-reimbursement basis, plus a 5.0% fee on certain direct costs, from the parties'respective management and other professional, technical and administrative personnel. Pursuant to the MSA, certain of PEGI’s executive officers, including itsChief Executive Officer and executive officers of PEGH ("shared Pattern executives"), also serve as executive officers of the Partnership and devote their time tothe Partnership and the other Pattern Companies as is prudent in carrying out their executive responsibilities and fiduciary duties. The shared Pattern executiveshave responsibilities for the Partnership, PEGI and PEGH and, as a result, these individuals do not devote all of their time to the Partnership’s business. Under theterms of the MSA, the Partnership is required to reimburse the Pattern Companies for an allocation of the compensation paid to such shared Pattern executivesreflecting the percentage of time spent providing services to the Partnership.Furthermore, since the Partnership has no employees, the MSA costs are allocated from PEGI and PEGH to the Partnership and not vice versa. The MSA costs areincluded in related party general and administrative expenses, as applicable on the consolidated statement of operations. The MSA was further amended andrestated in June 2017.Other Arrangements with Pattern CompaniesThe Partnership entered into a purchase rights agreement that provides PEGI the right of first offer with respect to any power project that the Partnership decides tosell as well as a right of first offer with respect to Pattern Development 2.0 itself.Pattern Development 2.0 was formed as a result of Project Entities contributed by Pattern Development 1.0 for an amount of $25.6 million as well as cash in theamount of $82.5 million. In June 2017, Pattern Development 1.0 and Pattern Development 2.0 entered into the Second Contribution to transfer additional ProjectEntities to the Partnership for $23.5 million. Five of the Project Entities contributed to the Partnership have an X/Y equity structure. The structure is designed toprovide residual returns of PEGH. (Refer to Footnote 5. Variable Interest Entities ).From January 1, 2017 through April 27, 2017, PEGH contributed $13 million in exchange for partnership interest in the Partnership. On July 12, 2017, PEG LP 2’sGeneral Partner executed the Capital and Redemption Agreement with Existing LPs and new investors, Riverstone II and PEGI.Per the terms of the Capital and Redemption Agreement, a Capital Call was approved by PEG LP 2’s Board of Directors on July 12, 2017. The capital call fundswere used to redeem all of PEGH’s investment in the Partnership. PEGI contributed $60.0 million giving PEGI approximately 20% equity ownership in thePartnership. On December 26, 2017, PEGI contributed an additional $7.3 million increasing PEGI's equity ownership to approximately 21%.The Partnership funded LC deposits to guarantee the PPA performance of Grady Wind Energy Center, LLC ("Grady") and interconnection security deposits forother development projects. As of December 31, 2017, the Partnership has $17.2 million recorded in its consolidated balance sheet as a related party receivablerelated to these LC deposits. The deposits are held by Pattern Development 1.0 as restricted cash. The LC deposits will be released when the respective projectsbecome operational, which is projected in 2019.Services AgreementsAs a result of the Contribution, the Partnership, through its wholly owned subsidiary, Grady, has a TSA with Western Interconnect LLC ("WI") (a subsidiary ofPEGI), which enables Grady to connect to the grid once the windfarm is operational. Currently, Grady has not yet commenced construction, and no payments aredue under these agreements. Grady has only provided a deposit to WI for the amount of $0.5 million, which is recorded as related party receivable.Grady has a one-third undivided interest in common facilities shared with Broadview KW and Broadview JN (subsidiaries of PEGI), and collectively the threeprojects are parties to a common facilities operations and maintenance agreement with a subsidiary of PEGI, Pattern Operators LP. As a result of the undividedinterest in the common shared facilities, in 2016, Grady recorded a $2.4 million deemed distribution related to the construction of the shared facility withBroadview JN. No other amounts are due or payable under the common facilities operations and maintenance agreement as Grady is still in early development andnot yet operational.S- 98Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 2017The following table presents amounts receivable from related parties as included in the consolidated balance sheet (in thousands): December 31, 2017Related party receivable: Amounts due from Pattern Development 1. 0 $16,789Amounts due from PEGI 459Total related party receivable $17,248The following table presents amounts payable from related parties recognized under the MSA as included in the consolidated balance sheet (in thousands): December 31, 2017Related party payable: Amounts due to Pattern Development 1.0 $9,468Amounts due to PEGI 2,097Total related party payable $11,565The table below presents expenses recognized for management services under the MSA, as included in the consolidated statement of operations for the period fromJuly 27, 2017 through December 31, 2017 (in thousands): TotalRelated party expense from Pattern Development 1.0 $10,094Related party expense from PEGI 1,683Total related party expenses $11,77713. Partnership CapitalClass A and Class B UnitsThe Capital and Redemption Agreement effective July 27, 2017, authorized PEG LP 2 to issue Class A units to the Class A limited partners (the “Class APartners”) and Class B units to the Class B limited partners (the “Class B Partners”).PEG LP 2 is authorized to issue additional Class A units at $1.00 per share and admit additional Class A Partners with certain approvals and conditions as indicatedin the Capital and Redemption Agreement. For the period from July 27, 2017 through December 31, 2017,PEG LP 2 received capital contributions of $230.0 million from the Class A Partners. Additionally, during 2017 the Partnership redeemed $89.0 million to Class APartners.PEG LP 2 is authorized to issue up to 1,000,000 Class B units, of which six Class B-1 units were issued on December 8, 2016, and 752,494 Class B-2 units wereissued on June 16, 2017. A total of 752,500 Class B units have been issued to Class B Partners.Distributions and AllocationsClass A Partners are entitled to receive a Class A Preference Amount, which is equal to an annual pre-tax return of 8.0% compounded quarterly on all unreturnedcapital contributions.S- 99Pattern Energy Group Holdings 2 LPNotes to Consolidated Financial StatementsDecember 31, 2017Class A units are senior to the Class B units with respect to distributions. Upon sale or liquidation of the Partnership, distributions would occur in the followingorder:•First, 100% to the Class A Partners in proportion to their unreturned capital contributions until unreturned capital contributions have been reduced to zero;•Second, 100% to the Class A Partners in proportion to their unpaid preference amounts until unpaid preference amounts have been reduced to zero;•Third, 50% to the Class A Partners in proportion to their respective Class A Unit Sharing Percentages and 50% to the Class B Limited Partners inproportion to their respective Class B Unit Sharing Percentages, until the Class B Payout occurs; and•Thereafter, 85% to the Class A Partners and 15% to the Class B Partners.Board of Directors and Voting RightsThe Board of Directors shall consist of not less than five Directors: (a) three of whom shall be appointed by Riverstone II (“Riverstone Delegates”), and (b) two ofwhom shall be appointed by the Class B Majority (“Class B Delegates”). Each Director shall have one vote; however, Riverstone Delegates may cast more thanone vote in certain circumstances to always give the Riverstone Delegates three votes.14. Subsequent EventThe Partnership has evaluated subsequent events through February 24, 2018, which is the date these consolidated financial statements were available to be issued,and noted the following subsequent event.On February 12, 2018, the Partnership executed four Purchase and Sale Development Service Agreements ("PurchaseAgreements") to purchase assets related to four solar farm projects. The total initial payment under the Purchase Agreements was $200 thousand with additionalfuture contingent payments of approximately $8.0 million due to the seller based upon the projects achieving certain milestones.S- 100Item 16.Form 10-K SummaryNone.S- 101Exhibit 21.1Pattern Energy Group Inc.Subsidiaries of the Registrant PatternName Domicile OwnershipBroadview B Member LLC Delaware 100%Broadview Corporate Holdings LLC Delaware 100%Broadview Energy Holdings LLC Delaware 84%Broadview Energy JN Investments LLC Delaware 84%Broadview Energy JN, LLC Delaware 84%Broadview Energy KW Investments LLC Delaware 84%Broadview Energy KW, LLC Delaware 84%Broadview Energy Project Finco LLC Delaware 84%Broadview Finance Company LLC Delaware 100%Broadview Finco Pledgor Delaware 100%Don Goyo Holdings SpA Chile 70%Don Goyo Transmission S.A. Chile 70%Fowler Ridge IV B Member LLC Delaware 100%Fowler Ridge IV Holdings LLC Delaware 65%Fowler Ridge IV Wind Farm LLC Delaware 65%Grand Renewable Wind GP Inc. Canada 50%Grand Renewable Wind LP Ontario 45%Hatchet Ridge Holdings LLC Delaware 100%Hatchet Ridge Wind, LLC Delaware 100%K2 Wind Ontario Inc. Ontario 33%K2 Wind Ontario Limited Partnership Ontario 33%Lincoln County Wind Project Holdco, LLC Delaware 100%Logan’s Gap B Member LLC Delaware 100%Logan’s Gap Holdings LLC Delaware 82%Logan’s Gap Wind LLC Delaware 82%Lost Creek Wind Finco, LLC Delaware 100%Lost Creek Wind Holdco, LLC Delaware 100%Lost Creek Wind, LLC Delaware 100%Meikle Wind Energy Corp British Columbia 70%Meikle Wind Energy Limited Partnership British Columbia 51%Nevada Wind Holdings LLC Delaware 100%Ocotillo Express LLC Delaware 100%Ocotillo Wind Holdings LLC Delaware 100%PAN2 B2 LLC Delaware 2%Panhandle B Holdco LLC Delaware 100%Panhandle B Member LLC Delaware 100%Panhandle B Member 2 LLC Delaware 100%Panhandle Wind Holdings LLC Delaware 100%Panhandle Wind Holdings 2 LLC Delaware 41%Parque Eólico El Arrayán SpA Chile 70%Pattern Canada Finance Company ULC Nova Scotia 100% PatternName Domicile OwnershipPattern Canada Operations Holdings ULC Nova Scotia 100%Pattern Chile Holdings LLC Delaware 100%Pattern Chile Holdings SpA Chile 100%Pattern Chile Operators SpA Chile 100%Pattern El Arrayan Chile SpA Chile 100%Pattern El Arrayan Holding SpA Chile 100%Pattern Energy Group Holding 2 LP Delaware 21%Pattern Finance Chile LLC Delaware 100%Pattern Finance Chile SpA Chile 100%Pattern Gulf Wind Equity LLC Delaware 100%Pattern Gulf Wind Holdings LLC Delaware 100%Pattern Gulf Wind LLC Delaware 100%Pattern Operators Canada ULC Nova Scotia 100%Pattern Operators GP LLC Delaware 100%Pattern Operators LP Delaware 100%Pattern Operators Puerto Rico LLC Delaware 100%Pattern Panhandle Wind LLC Delaware 79%Pattern Panhandle Wind 2 LLC Delaware 41%Post Rock Wind Power Project, LLC Delaware 60%Pattern Santa Isabel LLC Delaware 100%Pattern St. Joseph Holdings Inc. Canada 100%Pattern US Finance Company LLC Delaware 100%Pattern US Operations Holdings LLC Delaware 100%Pattern Western Interconnect Holdings LLC Delaware 100%Santa Isabel Holdings LLC Delaware 100%South Kent Wind GP Inc. Canada 50%South Kent Wind LP Ontario 50%Spring Valley Wind LLC Nevada 100%St. Joseph Windfarm Inc. Canada 100%SP Armow Wind Ontario GP Inc. Canada 50%SP Armow Wind Ontario LP Ontario 50%Western Interconnect Investments LLC Delaware 99%Western Interconnect LLC Delaware 99%WI Holdings Pledgor LLC Delaware 100%Exhibit 23.1Consent of Independent Registered Public Accounting FirmWe consent to the incorporation by reference in the following Registration Statements:(1)Registration Statement (Form S-3 No. 333-199217) and related Prospectus of Pattern Energy Group Inc., and(2)Registration Statement (Form S-8 No. 333-191641) pertaining to Pattern Energy Group Inc.’s 2013 Equity Incentive Award Plan, as amended;of (i) our reports dated March 1, 2018, with respect to the consolidated financial statements and schedule of Pattern Energy Group Inc. and the effectiveness ofinternal control over financial reporting of Pattern Energy Group Inc. included in this Annual Report (Form 10-K) of Pattern Energy Group Inc. for the year endedDecember 31, 2017, (ii) our report dated February 28, 2018, with respect to the financial statements of K2 Wind Ontario Limited Partnership included in thisAnnual Report (Form 10-K) of Pattern Energy Group Inc. for the year ended December 31, 2017 and (iii) our report dated February 24, 2018, with respect to thefinancial statements of Pattern Energy Group Holdings 2 LP included in this Annual Report (Form 10-K) of Pattern Energy Group Inc. for the period from July27, 2017 to December 31, 2017./s/ Ernst & Young LLPSan Francisco, CaliforniaMarch 1, 2018Exhibit 23.2CONSENT OF INDEPENDENT AUDITORSWe consent to the incorporation by reference in the Registration Statements on Form S-3 (File No.333-199217) and Form S-8 (File No. 333-191641) of PatternEnergy Group Inc. of our report dated February 20, 2018 relating to the financial statements of South Kent Wind LP, of our report dated February 20, 2018 relatingto the financial statements of Grand Renewable Wind LP and of our report dated February 20, 2018 relating to the financial statements of SP Armow Wind OntarioLP, which appear in this Form 10-K of Pattern Energy Group Inc./s/ PricewaterhouseCoopers LLPChartered Professional Accountants, Licensed Public AccountantsToronto, Ontario, CanadaMarch 1, 2018 PricewaterhouseCoopers LLPPwC Tower, 18 York Street, Suite 2600, Toronto, Ontario, Canada M5J 0B2T: +1 416 863 1133, F: +1 416 365 8215, www.pwc.com/ca“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.Exhibit 31.1Certification of Chief Executive OfficerPursuant to Exchange Act Rules 13a-14(a) and 15d-14(a),As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002I, Michael M. Garland, certify that:1. I have reviewed this Annual Report on Form 10-K of Pattern Energy Group Inc.;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in ExchangeAct Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in the Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrantand have:a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensurethat material information relating to the registrant, including its combined subsidiaries, is made known to us by others within those entities, particularly during theperiod in which this report is being prepared;b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision,to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance withgenerally accepted accounting principles;c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectivenessof the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscalquarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’sinternal control over financial reporting; and5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; andb) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control overfinancial reporting. Date: March 1, 2018By/s/ Michael M. Garland Michael M. Garland Chief Executive Officer and Director (Principal Executive Officer)Exhibit 31.2Certification of Chief Financial OfficerPursuant to Exchange Act Rules 13a-14(a) and 15d-14(a),As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002I, Michael J. Lyon, certify that:1. I have reviewed this Annual Report on Form 10-K of Pattern Energy Group Inc.;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in ExchangeAct Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in the Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrantand have:a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensurethat material information relating to the registrant, including its combined subsidiaries, is made known to us by others within those entities, particularly during theperiod in which this report is being prepared;b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision,to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance withgenerally accepted accounting principles;c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectivenessof the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscalquarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’sinternal control over financial reporting; and5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; andb) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control overfinancial reporting. Date: March 1, 2018By/s/ Michael J. Lyon Michael J. Lyon Chief Financial Officer (Principal Financial Officer)Exhibit 32Certification of Chief Executive OfficerPursuant to 18 U.S.C. Section 1350, As AdoptedPursuant to Section 906 of the Sarbanes-Oxley Act of 2002Pursuant to 18 U.S.C. § 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned officer of Pattern Energy Group Inc. (the “ Company”) hereby certifies, to such officer’s knowledge, that:(i) the accompanying Annual Report on Form 10-K of the Company for the annual period ended December 31, 2017 (the “ Report ”) fully complies with therequirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: March 1, 2018By/s/ Michael M. Garland Michael M. Garland Chief Executive OfficerCertification of Chief Financial OfficerPursuant to 18 U.S.C. Section 1350, As AdoptedPursuant to Section 906 of the Sarbanes-Oxley Act of 2002Pursuant to 18 U.S.C. § 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned officer of Pattern Energy Group Inc. (the “ Company”) hereby certifies, to such officer’s knowledge, that:(i) the accompanying Annual Report on Form 10-K of the Company for the annual period ended December 31, 2017 (the “ Report ”) fully complies with therequirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: March 1, 2018By/s/ Michael J. Lyon Michael J. Lyon Chief Financial Officer

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