Document
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549 
 
 
 
FORM 10-K
 
 
 
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2017.
-OR-
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-36087
 
 
 
PATTERN ENERGY GROUP INC.
(Exact name of Registrant as specified in its charter)
 
 
 
Delaware
 
90-0893251
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
Pier 1, Bay 3, San Francisco, CA 94111
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (415) 283-4000
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Class A Common Stock, par value $0.01 per share
 
NASDAQ Global Select Market
Toronto Stock Exchange
Securities 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  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such 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 and posted 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 submit and 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, to the 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 filer
x
 
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 financial accounting 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  ý
The 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 common stock 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 held by directors, officers, Pattern Renewables LP and certain of its affiliates, and Public Sector Pension Investment Board. Exclusion of shares does not reflect a determination that persons 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 REFERENCE
Portions 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 III of 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 to which this report relates.
 




TABLE OF CONTENTS

 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
 
 
Item 15.
Item 16.


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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K ("Form 10-K") contains statements that may constitute forward-looking statements. You can identify these statements by forward-looking words such as "anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan," "potential," "should," "will," "would," or similar words. You should read statements that contain these words carefully because they discuss our current plans, strategies, prospects, and expectations concerning our business, operating results, financial condition, and other similar matters. While we believe that these forward-looking statements are reasonable as and when made, 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 our business will be those that we anticipate. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause our actual results to differ from those in the forward-looking statements, include but are not limited to, those summarized below and further described in 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 related to 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 those in operation;
conditions in energy markets as well as financial markets generally, which will be affected by interest rates, foreign currency exchange rate fluctuations and 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."

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Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
Statistical Data
The 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 or reports. These publications generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy or completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information.
Currency Information
In this Form 10-K, reference to "C$" and "Canadian dollars" are to the lawful currency of Canada, references to "JPY" and Japanese Yen are to the lawful currency of Japan and references to "$", "US$" and "U.S. dollars" are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars, unless otherwise noted.
MEANING OF CERTAIN REFERENCES
Unless the context provides otherwise, references herein to "we," "our," "us," "our company" and "Pattern" refer to Pattern Energy Group Inc., a Delaware corporation, 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 Development Companies 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 each of 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 Pattern Development Companies in which we and each of the Pattern Development Companies have agreed to various arrangements with respect to how we 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, as contemplated by the Amended and Restated Purchase Rights Agreement between us and Pattern Development 1.0 (Pattern Development 1.0 Purchase Right) and to our right to acquire Pattern Development 2.0 or

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substantially all of its assets, as contemplated by the Amended and Restated Purchase Rights Agreement between us and Pattern Development 2.0 (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, its subsidiaries (excluding us);
“Pattern Development 2.0” refers to Pattern Energy Group 2 LP, a Delaware limited partnership, and, where the context so requires, its subsidiaries. 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 offer with respect to power projects that Pattern Development 2.0 decides to sell, as contemplated by the Amended and Restated Purchase Rights Agreement 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 the Amended and Restated Purchase Rights Agreement between us and Pattern Development 1.0 and the Amended and Restated Purchase Rights Agreement 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.




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PART I
Item 1.    Business

Overview
We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued 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 United 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 output pursuant to long-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 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 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 of Pattern Development 1.0 and subsequently in October 2013 conducted an initial public offering.
Our Relationship with the Pattern Development Companies
Pursuant to the MSA, certain of our executive officers, including our Chief Executive Officer, also are shared executives of the Pattern Development Companies and devote their time to both us and the Pattern Development Companies as is prudent in carrying out their executive responsibilities and fiduciary duties. In December 2016, certain investment funds managed by Riverstone Holdings LLC, which own interests in Pattern Development 1.0, engaged in a transaction in which (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) Pattern Development 1.0 retained the remainder of its assets consisting principally of the other Identified ROFO Projects, non-U.S. development assets, and its ownership interest 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 the growth in the development pipeline. We also entered into other agreements with Pattern Development 2.0 which were amended and restated in June 2017 and relate 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 pursuant to 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 also committed 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 our ownership interest in Pattern Development 2.0 increasing up to 29%. If we do not participate in such subsequent rounds of financing, our ownership interest in Pattern 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 the Pattern Development Companies provides us with access to a pipeline of acquisition opportunities. We believe the Pattern Development Companies’ focus on project development combined with our Project Purchase Rights will complement our acquisition strategy, which focuses on the identification and acquisition of operational and construction-ready power projects and investment in development companies.
Our Relationship with PSP Investments
In June 2017, we entered into a strategic joint venture agreement with PSP Investments. The joint venture agreement provides that PSP Investments has the right to co-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 a person that has been designated by PSP Investments to our board of directors. In 2017, we, together with PSP Investments, acquired the Meikle Wind Energy Project 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 relationship provides us the ability to increase our portfolio with limited capital investment. In 2018, we expect to acquire Mont Sainte-Marguerite (MSM), together with PSP Investments from Pattern Development 1.0. PSP Investments is also an investor in Pattern Development 2.0. Additionally, in June 2017, PSP Investments acquired 8.7 million shares, or approximately 9.9%, of our outstanding Class A common

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stock from Pattern Development 1.0 and an additional 0.6 million shares from the Company's public offering that occurred on October 23, 2017.


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Structure of Our Company
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12098323&doc=20
Industry
Wind 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, growth in solar photovoltaic (PV) capacity was larger than any other form of generation with 75 gigawatts (GW) of solar installed, bringing the installed PV capacity to 303 GW worldwide and representing 1.8% of global electricity demand. In 2017,

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global installed wind capacity grew by nearly 11%, bringing the global total to 540 GW. Projections by the International Energy Agency indicate renewable energy will 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 and public 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 of wind 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 growth opportunities. We require a relatively small share of a very large market to meet our growth objectives, and we believe we will achieve growth through the acquisition of operational and construction-ready projects from the Pattern Development Companies and other third parties.
Our Current Markets
The United States remains the second largest growth market for renewables in the world. In 2016, total wind power capacity in the United States reached 82,634 MW, representing 8% of installed capacity and approximately 6% of total electricity demand. Solar energy capacity reached 41,825 MW, representing 4% of installed capacity and 1% of total electricity demand. Government incentives contribute to the competitiveness of renewable energy by providing accelerated depreciation, tax credits for a portion of the development costs, decreasing the costs associated with developing, and creating demand for renewable energy assets through state renewable portfolio standard (RPS) programs. Additionally, demand has been increasing from commercial and industrial customers, such as major consumer brands and universities, and from the voluntary utility market. Nearly half of Fortune 500 companies and 63% of Fortune 100 companies have at least one climate or clean energy target. The Energy Information Administration expects these demand drivers to push renewable energy to 18% of electricity sales by 2030. 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 GW by 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 last five 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 the country and 3% of energy generation. Clean energy policy occurs mostly at the provincial level. Alberta’s new Renewable Electricity Program is expected to drive development 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 from 9% 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 MW of 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, and two 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 its acquisition of a controlling interest in Green Power Investments (GPI), a well-established operating and development management team in Japan. Roughly 15% of Japan’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 3,230 MW 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 placed a 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 was supported 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 power projects. 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 per kWh. 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 per kWh. 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 of wind 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, which creates opportunities for wind and solar to take advantage of the times of the day when available natural resources match the country’s energy needs. Mining operations in the country are energy-intensive and represent a large source of demand. The copper industry alone accounted for 29% of total energy generated in 2015. Relief from curtailment of renewables that has occurred since 2015 is expected in 2018 from the interconnection of Chile’s largest two system operators.

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Our Developing Markets
The 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 generation and 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 and solar 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 expects energy 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:
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12098323&doc=19

Our Core Values and Financial Objectives
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 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 wind regimes, 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 that also benefits our business by reducing operating risks at our projects.

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Our 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 Strategy
To 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 Projects
We intend to efficiently operate our projects to meet projected revenue and cash available for distribution. We expect to maximize the long-term value of our projects by focusing on value-oriented project availability (by ensuring our projects are operational when the wind is strong and power sale agreement prices are at their highest) and by regularly scheduled and preventative maintenance. We believe that good operating performance begins with a long-term maintenance program for our equipment. We also seek to improve performance or lower operating costs by working closely with our equipment vendors and considering contracting 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 revised long-term turbine manufacturer service arrangements at certain of our projects pursuant to which the turbine manufacturer will continue to provide routine and corrective maintenance service, but we would become responsible for a portion of the maintenance and repairs, including on major component parts. We expect to continue entering into similar arrangements at other projects in the future. We employ on-site personnel, maintain a 24/7 operations control center to monitor our projects and control all critical aspects of commercial asset management.
Selectively Growing Our Business
Our strategy for growth is focused on the acquisition of operational and construction-ready power projects from the Pattern Development Companies and other third parties that, together such measured investments into the development business, we believe will contribute to the growth of our business and enable us to increase 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 our existing business and be consistent with our risk profile, and that any incremental assumption of risk will require commensurate expectations of higher returns. As a result, our near-term growth strategy will remain focused on largely contracted cash flows with creditworthy counterparties and operating or in-construction projects.
We expect that opportunities will continue to arise from our relationship with the Pattern Development Companies, which provide us with the opportunity to acquire projects as they develop, construct and achieve commercial operations at these projects. Additionally, the investment in Pattern Development 2.0 supports growth 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 productive manner or generate a higher return on investment.
Maintaining a Prudent Capital Structure and Financial Flexibility
We 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 fund investments for future growth. Power projects by their nature require significant capital investment, and as a result, we seek to protect our business through careful management 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 our practice has been to structure our project finance arrangements comprised of a mix of debt, tax equity and equity to conform to investment grade-like credit standards. 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.

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Our project capital structure is supplemented with a corporate capital layer that primarily relies on equity capital. Our corporate indebtedness, which includes unsecured senior notes with an aggregate principal amount of $350.0 million which we issued in January 2017 (the 2024 Unsecured Senior Notes), is modest, and intended to ensure broad capital access. In addition, our strategic partnership with PSP Investments is intended to expand capital access and improve flexibility in managing capital requirements.
We seek to ensure financial flexibility and stability through our corporate revolving credit facility, maturity staging, minimization of interest rate exposure, and maintenance of our credit ratings. Our foreign currency denominated project dividends are further managed through a short-to-medium term foreign exchange program. We believe this approach, together with a strategic consideration of project-level financial restructuring and recapitalization opportunities, will contribute to our ability to maintain and, over time, increase our cash available for distribution.    
Working Closely with Our Stakeholders
We believe that close working relationships with our various stakeholders, including suppliers, power sales agreement counterparties, regulators, the local communities where we are located and environmental organizations and with the Pattern Development Companies and other developers enable us to best support our existing projects and will help us access attractive, construction-ready projects.

Competition
We compete with other wind and solar power, infrastructure funds and renewable energy companies, as well as conventional power companies, to acquire profitable construction-ready and operating projects. In addition, competitive conditions may be substantially affected by various forms of energy legislation and regulation considered from time to time by federal, state, provincial and local legislatures and administrative agencies.
Competitive Strengths
We believe we compete with other industry participants by having high quality projects which are positioned to generate stable long-term cash flows which in turn give 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 power sale agreements, a geographically diverse market with varying wind and solar regimes and regulatory environment; and state-of-the-art wind turbines and solar panels. Further contributing to our competitive strength is our approach to project selection which focuses on the acquisition of projects that are operational and have long term power sales agreements with creditworthy counterparties. We believe our relationship with the Pattern Development Companies provides us with access 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 Projects
We 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 the United 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 output pursuant 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 meet our 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 contractual obligations;
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 sales agreements;
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;

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an operations and maintenance service program based on our own on-site personnel and central operations management as well as equipment warranties (for at least the first two years of operation) and service arrangements with qualified providers experienced in wind and solar project maintenance (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.

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The following table provides an overview of our wind and solar projects:
Operating Project
 
Location
 
Commencement of Commercial Operations
 
Rated Capacity in MW(1)
 
Our Owned Capacity(2)
 
Type
 
Contracted
Volume(3)
 
Counterparty
 
Counterparty Credit Rating(4)
 
Contract Expiration
Hatchet Ridge
 
California
 
2010
 
101

 
101

 
PPA
 
100%
 
Pacific Gas & Electric
 
A-/A2
 
2025
Ocotillo
 
California
 
2012(5)
 
265

 
265

 
PPA
 
100%
 
San Diego Gas & Electric
 
A/A1
 
2033
Spring Valley
 
Nevada
 
2012
 
152

 
152

 
PPA
 
100%
 
NV Energy
 
A/Baa2
 
2032
Gulf Wind
 
Texas
 
2009
 
283

 
283

 
Hedge
 
58%
 
Morgan Stanley
 
BBB+/A3
 
2019
Panhandle 1
 
Texas
 
2014
 
218

 
172

 
Hedge
 
80%
 
Citigroup Energy Inc.
 
BBB+/Baa1
 
2027
Panhandle 2
 
Texas
 
2014
 
182

 
75

 
Hedge
 
80%
 
Morgan Stanley
 
BBB+/A3
 
2027
Logan's Gap
 
Texas
 
2015
 
200

 
164

 
PPA
 
58%
 
Wal-Mart Stores, Inc.
 
AA/Aa2
 
2025
Logan's Gap
 
 
 
 
 
 
 
 
 
Hedge
 
17%
 
Merrill Lynch Commodities, Inc.
 
A-/A3
 
2028
Post Rock
 
Kansas
 
2012
 
201

 
120

 
PPA
 
100%
 
Westar Energy, Inc.
 
BBB+/Baa1
 
2032
Lost Creek
 
Missouri
 
2010
 
150

 
150

 
PPA
 
100%
 
Associated Electric Cooperative, Inc.
 
AA/A1
 
2030
Amazon Wind
 
Indiana
 
2015
 
150

 
116

 
PPA
 
100%
 
Amazon.com, Inc.
 
AA-/Baa1
 
2028
St. Joseph
 
Manitoba
 
2011
 
138

 
138

 
PPA
 
100%
 
Manitoba Hydro
 
A+/Aa2
 
2039
Santa Isabel
 
Puerto Rico
 
2012
 
101

 
101

 
PPA
 
100%
 
Puerto Rico Electric Power Authority
 
D/Ca
 
2037
El Arrayán
 
Chile
 
2014
 
115

 
81

 
Hedge
 
74%
 
Minera Los Pelambres
 
NA
 
2034
Grand
 
Ontario
 
2014
 
149

 
67

 
PPA
 
100%
 
Independent Electricity System Operator(7)
 
NA/Aa2
 
2034
South Kent
 
Ontario
 
2014
 
270

 
135

 
PPA
 
100%
 
Independent Electricity System Operator(7)
 
NA/Aa2
 
2034
K2
 
Ontario
 
2015
 
270

 
90

 
PPA
 
100%
 
Independent Electricity System Operator(7)
 
NA/Aa2
 
2035
Armow
 
Ontario
 
2015
 
180

 
90

 
PPA
 
100%
 
Independent Electricity System Operator(7)
 
NA/Aa2
 
2035
Broadview
 
New Mexico
 
2017
 
324

 
272

 
PPA
 
100%
 
Southern California Edison
 
BBB+/A2
 
2037
Meikle
 
British Columbia
 
2017
 
179

 
91

 
PPA
 
100%
 
BC Hydro
 
NA/Aaa
 
2042
Mont Sainte-Marguerite (6)
 
Quebec
 
2018
 
143

 
73

 
PPA
 
100%
 
Hydro-Quebec
 
NA/Aa2
 
2043
Futtsu Solar (8)
 
Japan
 
2016
 
29

 
29

 
PPA
 
100%
 
TEPCO Energy Partner
 
Ba2
 
2036
Kanagi Solar (8)
 
Japan
 
2016
 
10

 
10

 
PPA
 
100%
 
Chugoku Electric Power Company
 
A3
 
2036
Otsuki (8)
 
Japan
 
2006
 
12

 
12

 
PPA
 
100%
 
Shikoku Electric Power Company
 
A-
 
2026
Ohorayama (8)
 
Japan
 
2018
 
33

 
33

 
PPA
 
100%
 
Shikoku Electric Power Company
 
A-
 
2038
Tsugaru (8)
 
Japan
 
2020
 
122

 
122

 
PPA
 
100%
 
Tohoku Electric Power 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 at all 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 of the project.
(3) 
Represents the approximate percentage of a project’s total estimated average annual MWh of electricity generation contracted under power purchase agreements or hedge arrangements.
(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 Projects
Our continuing relationship with the Pattern Development Companies provides us with access to a pipeline of acquisition opportunities. Currently, the Pattern Development 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 total owned or managed capacity of 5,000 MW by year end 2020 through a combination of acquisitions from the Pattern Development Companies and other third parties 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 our Project 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
 
104
Belle River
 
Operational
 
Ontario
 
2016
 
2017
 
PPA
 
100
 
43
El Cabo
 
Operational
 
New Mexico
 
2016
 
2017
 
PPA
 
298
 
125
North Kent
 
Operational
 
Ontario
 
2017
 
2018
 
PPA
 
100
 
35
Henvey Inlet
 
In construction
 
Ontario
 
2017
 
2019
 
PPA
 
300
 
150
Pattern Development 2.0 Projects
 
 
 
 
 
 
 
 
 
 
 
 
Stillwater Big Sky
 
Late stage development
 
Montana
 
2017
 
2018
 
PPA
 
79
 
67
Crazy Mountain
 
Late stage development
 
Montana
 
2017
 
2019
 
PPA
 
80
 
68
Grady
 
Late stage development
 
New Mexico
 
2018
 
2019
 
PPA
 
220
 
188
Sumita
 
Late stage development
 
Japan
 
2019
 
2021
 
PPA
 
100
 
55
Ishikari
 
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 at all 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 or Pattern 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 believe we 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 higher return on investment, we may decide to exit Chile for other opportunities with greater potential. In addition, Pattern Development 1.0 is also concurrently exploring strategic alternatives for its assets in Chile.
Government Incentives and Tax Credits
Renewable energy sources in the United States have benefited from various federal and state governmental incentives, such as production tax credits and investment tax credits. Production tax credits and investment tax credits for wind energy on the federal level were extended in December of 2015, under the Consolidated Appropriations Act which extended the expiration date for tax credits for wind facilities commencing construction, with a five-year phase-down beginning for wind projects commencing construction after December 31, 2014.
Hedging Activity
Most 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 project economics, 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 be exceeded 99.0% of the time. Those hedging agreements are executed for a monthly or hourly production profile that matches the forecasted production profile of the 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 hedging agreements to convert floating-rate debt to fixed-rate debt for some of our projects, usually at the time we close

15


construction 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 to mitigate 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 flows that 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 adverse impact to our short-term liquidity or financial condition.
Geographic information
The table below provides information about our consolidated operations by country. Revenue is recorded in the country in which it is earned and assets 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
 
2016
 
2015
United States
 
$
315,642

 
$
285,187

 
$
258,542

 
$
3,121,387

 
$
2,652,122

 
$
2,791,259

Canada
 
62,063

 
39,207

 
39,178

 
550,183

 
177,093

 
184,115

Chile
 
33,639

 
29,658

 
32,111

 
293,551

 
305,947

 
319,246

Total
 
$
411,344

 
$
354,052

 
$
329,831

 
$
3,965,121

 
$
3,135,162

 
$
3,294,620

Customers
We 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 ended December 31, 2017, San Diego Gas & Electric was our only significant customer representing 13.4% of our total revenue.

16


Suppliers
There are a limited number of renewable equipment suppliers; however, we believe that current manufacturing capacity is adequate. Our equipment supply strategy is largely based on maintaining strong relationships with leading equipment suppliers to secure our supply needs.
Project
 
Supplier
 
Number of
Turbines/Panels
 
Equipment Type
Hatchet Ridge
 
Siemens-Gamesa
 
44
 
SWT-2.3-93
Ocotillo
 
Siemens-Gamesa
 
112
 
SWT-2.3-108
Spring Valley
 
Siemens-Gamesa
 
66
 
SWT-2.3-101
Gulf Wind
 
Mitsubishi
 
118
 
MWT 95/2.4
Panhandle 1
 
General Electric
 
118
 
1.85 - 87
Panhandle 2
 
Siemens-Gamesa
 
79
 
SWT-2.3-108
Logan’s Gap
 
Siemens-Gamesa
 
87
 
SWT-2.3-108
Post Rock
 
General Electric
 
134
 
1.5-82.5
Lost Creek
 
General Electric
 
100
 
1.5-82.5
Amazon Wind
 
Siemens-Gamesa
 
65
 
SWT-2.3-108
St. Joseph
 
Siemens-Gamesa
 
60
 
SWT-2.3-101
Santa Isabel
 
Siemens-Gamesa
 
44
 
SWT-2.3-108
El Arrayán
 
Siemens-Gamesa
 
50
 
SWT-2.3-101
Grand
 
Siemens-Gamesa
 
67
 
SWT-2.3-101
South Kent
 
Siemens-Gamesa
 
124
 
SWT-2.3-101
K2
 
Siemens-Gamesa
 
140
 
SWT-2.3-101
Armow
 
Siemens-Gamesa
 
91
 
SWT-2.3-101
Broadview
 
Siemens-Gamesa
 
141
 
SWT-2.3-108
Meikle
 
General Electric
 
61
 
GE 2.75-120 & GE 3.2-103
Mont Sainte-Marguerite (1)
 
Siemens-Gamesa
 
46
 
SWT-3.2-113
Futtsu Solar (2)
 
Kyocera
 
168,840
 
KK250P-3CF-3CG
Kanagi Solar (2)
 
Kyocera
 
54,720
 
KK250P-3CF-3CG
Otsuki (2)
 
Mitsubishi
 
12
 
MWT 1000 A
Ohorayama (2)
 
General Electric
 
11
 
GE 3.0MW-103
Tsugaru
 
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., with whom 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 equipment manufacturers, primarily Siemens-Gamesa and General Electric. Both of these providers are industry leaders in the renewable service business. As described elsewhere, while we expect over time to increase self-perform activities, we do expect to continue to utilize both original equipment manufacturers and qualified independent service companies for a substantial amount of our service and maintenance needs.
Regulatory Matters
Our operations are subject to regulation by various federal and state government agencies, including, but, not limited to, the following:

17


U.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 Company Act of 2005, as amended, (PUHCA) and therefore are exempt from certain regulation under PUHCA. Other than Gulf Wind, Panhandle 1, Panhandle 2, and Logan’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 future projects 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 to FERC rate regulation are required to obtain acceptance of their rate schedules for wholesale sales of energy (i.e., not retail sales to consumers), capacity and ancillary 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 Transmission Organizations (RTOs).
North American Electric Reliability Corporation
All 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 - Canada
All 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 energy markets are regulated at the provincial level. In Ontario, for example, electricity generation facilities must be licensed by the Ontario Energy Board and may also be 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 the provisions of the market rules for the Ontario electricity market as well as the mandatory reliability standards of the NERC.
Environmental Regulation
Our operations are required to comply with various environmental, health and safety laws and regulations in each of the jurisdictions in which we operate. These existing and future laws and regulations may impact existing and new projects, require us to obtain and maintain permits and approvals, comply with all environmental laws and regulations applicable within each jurisdiction and implement environmental, health and safety programs and procedures to monitor and control risks associated with the construction, operation and decommissioning of regulated or permitted energy assets, all of which involve a significant investment of 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 Guidelines
We are subject to numerous environmental regulations and guidelines related to threatened and endangered species and their habitats, as well as avian and bat species, for the ongoing operations of our facilities. Environmental laws in the U.S., including the Endangered Species Act, the Migratory Bird Treaty Act, and the Bald 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 and the Endangered Species Act of 2007), among others, provide for the protection of migratory birds, eagles and bats and endangered species of birds and bats and their habitats. In addition to regulations, voluntary wind turbine siting guidelines established by the U.S. Fish and Wildlife Service set forth siting, monitoring and coordination 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) Emissions
The 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 as finalizing regulation or setting targets and goals, regarding the reduction of GHG emissions and the increase of renewable energy generation.

18


Environmental Matters— Domestic
We are required to obtain a range of environmental permits and other approvals to build and operate our projects, including, but not limited to, those described below from U.S. federal, state and local governmental authorities. In addition to being subject to these regulatory requirements, we could experience and have experienced significant opposition from third parties when we initially apply for permits 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 or can increase the cost so substantially that the project is no longer attractive to us.
Federal Clean Water Act
Frequently, 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 fill material into waters of the United States, including wetlands and streams. The Clean Water Act also requires that we mitigate any loss of wetland functions and values that accompanies our activities, obtain permits under the Clean Water Act for water discharges, such as storm water runoff associated with construction activities, 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 Permits
As 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 of Land Management. The Bureau of Land Management encourages the development of wind power within acceptable areas, consistent with Environmental Policy Act of 2005 and the Bureau of Land Management’s energy and mineral policy.
National Environmental Policy Act
Our U.S. projects may also be subject to environmental review under the U.S. National Environmental Policy Act (NEPA) which requires federal agencies to evaluate the environmental impact of all "major federal actions" significantly affecting the quality of the human environment. The granting of a land lease, a federal permit or similar authorization for a major development project, or the interconnection of a significant private project into a federal project generally is considered a "major federal action" that requires review under NEPA. As part of the NEPA review, the federal agency considers a broad array of environmental impacts, including impacts on air quality, water quality, wildlife, historical and archaeological resources, geology, socioeconomics and aesthetics and alternatives to 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 redesigned to reduce impacts or agree to provide some form of mitigation to offset impacts before a denial is issued.
National Historic Preservation Act
U.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 to conduct archeological surveys or take other measures to protect these resources. The National Historic Preservation Act requires federal agencies to evaluate the impact of all federally funded or permitted projects on historic properties (buildings, archaeological sites, etc.)
Other State and Local Programs
In 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 and permitting 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 array of environmental impacts before granting state permits. The state environmental review process often resembles the federal NEPA process and may be more stringent 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 transportation requirements. Local or state regulatory agencies may require modeling and measurement of permissible sound levels in connection with the permitting and approval 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 life and establish financial assurances for carrying out the decommissioning plan.

19


Environmental Matters—Canada
We are required to obtain a range of environmental permits and other approvals to build and operate our Canadian projects, including, but not limited to, those described below from Canadian federal, provincial and local governmental authorities. In addition to being subject to these regulatory requirements, we could experience 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 or can increase the cost so substantially that the project is no longer attractive to us.
Ontario Renewable Energy Approvals
Our projects in Ontario are subject to Ontario’s Environmental Protection Act, which requires proponents of significant renewable energy projects to obtain a Renewable Energy Approval (REA). The REA application requires a variety of studies on environmental, archeological and heritage issues. Significant public consultation, as well as consultation with indigenous communities, is also required. Before issuing a REA, the Ontario Ministry of the Environment evaluates a broad range of potential impacts, including on wildlife, wetlands and water resources, communities, scenic areas, species and heritage resources, as well as impacts on 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 comply with. REAs are also subject to appeal by third parties and can result and have resulted in lengthy appeal tribunal hearings.
Quebec Environmental Impact Assessment
Quebec`s Environmental Impact Assessment (EIA) is a required permit for wind energy projects with a nameplate capacity above 10 MW. The EIA requires a variety 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 the decree, the Quebec Ministry of Environment evaluates a broad range of potential impacts, including on wildlife, wetlands and water resources, communities, scenic areas, species and heritage resources, as well as impacts on people.
Quebec Commission for the Protection of Agricultural Land
In 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 only required on land that is zoned agricultural. This permitting body will push proponents to minimize footprints during both the construction phase and the operations phase.
Manitoba Environment Act
The 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 of impacts 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 similar risks.
Endangered Species Legislation
Our Canadian renewable energy projects may be subject to endangered species legislation, either federally or provincially, which prohibits and imposes stringent penalties for harming endangered or threatened species and their habitats. Our projects may also be subject to the Migratory Birds Convention Act, which protects the habitat of migratory species, and which may also trigger federal "Species at Risk" requirements. Because the operation of wind turbines may result in injury or fatalities to birds and bats, avian and bat risk assessments are generally required both prior to permits being issued for projects and after commercial operations. In Ontario, if any of the affected species are listed as endangered or threatened, permits under the Endangered Species Act may also be required.
Other Approvals
Our Canadian projects, and any future projects we may acquire, are subject to a variety of other federal, provincial and municipal permitting and zoning requirements. Most provinces where our projects are located or may be located have laws that require provincial agencies to evaluate a broad array of environmental impacts before granting permits and approvals. These agencies evaluate similar issues as the permitting regimes above, including impact on wildlife, historic sites, aesthetics, wetlands and water resources, scenic areas, endangered and threatened species and communities. In addition, federal government approvals dealing with, among other things, aeronautics,

20


fisheries, navigation or species protection may be required and could in some cases trigger additional environmental assessment requirements. Additional requirements 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 for building 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 – Chile
We 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 Environment
The 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 Service
The Environmental Assessment Service is responsible for assessing whether projects that might have an adverse effect on the environment, including wind projects, comply with Chilean environmental laws and regulations.
Superintendency of Environment
The Superintendency of the Environment’s primary responsibilities are monitoring compliance with the terms of the corresponding environmental licenses, as well as monitoring compliance with government plans to prevent environmental damage or to clean or restore contaminated geographical areas. The Superintendency of the Environment has the power to suspend activities that it deems to have an adverse environmental impact, even if such activities comply with a previously approved environmental impact assessment. In case of noncompliance with environmental regulations, it is enabled to apply fines, revoke the environmental license of a project or determine its closure.
The Environmental Courts, and Health and Safety
The Environmental Courts are principally responsible for hearing appeals of determinations made by the Superintendency of the Environment and for adjudicating claims 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 Chilean Sanitary Code, Labor Code and other labor and health regulations. The Chilean Health Ministry and the Department of Labor are responsible for the enforcement of those standards, with the authority to impose fines among other sanctions. In addition, the Superintendence of Electricity and Fuels has the responsibility to monitor compliance and also the authority to impose fines and stop operations of violators.
Management, Disposal and Remediation of Hazardous Substances
We 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 ownership or operation, we could be responsible for the costs of investigation and cleanup and for any related liabilities, including claims for damage to property, persons or natural 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 we generate is at times sent to third-party disposal facilities. If those facilities become contaminated, we and any other persons who arranged for the disposal or treatment of hazardous substances at those sites may be jointly and severally responsible for the costs of investigation and remediation, as well as for any claims for damage to third parties, their property or natural resources.
Employees
As 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 bargaining agreement.

21


Available Information
We 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 reasonably practicable after those documents are electronically filed with or furnished to the SEC. The information and materials available on our website are not incorporated by reference into this Form 10-K. The SEC maintains a website that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at www.sec.gov.
Item 1A.
Risk Factors.
RISK FACTORS
You 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, or may 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 immaterial also may materially adversely affect our business prospects, financial condition and results of operations and liquidity.
Risks Related to Our Projects
Electricity generated from wind energy depends heavily on suitable wind conditions and wind turbines being available for operation. If wind conditions are unfavorable or below our expectations, or our wind turbines are not available for operation, our projects’ electricity generation and the revenue generated from 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 generation from a wind power project depends heavily on wind conditions, which are variable. Variability in wind conditions can cause our project revenues to vary significantly 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 of long-term wind and other meteorological studies conducted on the project site and its region, which measure the wind’s speed, prevailing direction and seasonal variations. Projections of wind resources also rely upon assumptions about turbine placement, wind turbine power curves, interference between turbines and the effects of vegetation, land use and terrain, which involve uncertainty and require us to exercise considerable judgment. We may make incorrect assumptions in conducting these wind and other meteorological studies. Any of these factors could cause our projects to generate less electricity than we expect and reduce our revenue 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 in daily, monthly and yearly material deviations from the average wind resources we may anticipate during a particular period. If the wind resources at a project are materially below the average levels we expect for a particular period, our revenue from electricity sales from the project could correspondingly be less than expected. A diversified portfolio of projects located in different geographical areas tends to reduce the magnitude of the deviation, but material deviations may still occur. 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 of projects, our consolidated expenses, including operating expenses and interest payments on indebtedness, have less variability than the volume of electricity generated and sold. Accordingly, decreases in the volume of electricity generated and sold by our projects typically result in a proportionately greater decrease in our cash available for distribution. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operation-Factors that Significantly Affect 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 adverse consequences 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, which could 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 the termination of a PPA;

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our projects not generating sufficient cash flow to make payments of principal and interest as they become due on project-related debt, or distributing sufficient cash flow to pay dividends to holders of our Class A shares. For example, certain of our projects have experienced lower than expected production 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 is remedied. 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 as a 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 of electricity and RECs to certain key power purchasers, our projects are highly dependent upon these power purchasers fulfilling their contractual obligations under their respective PPAs. Our projects’ power purchasers may not comply with their contractual payment obligations or may become subject to insolvency or liquidation 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 or at 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 risk factor. 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 or other political action that impairs their contractual performance. In addition to the failure by any key power purchasers to meet their contractual commitments or the 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 were contracted 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 our obligations under our contractual commitments under a PPA. Each such situation could have a material adverse effect on our business prospects, financial condition 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 Puerto Rico Electric Power Authority (PREPA) under a 20-year PPA. On July 2, 2017, the Financial Oversight and Management Board (or Oversight Board) established pursuant to the Puerto Rico Oversight, Management, and Economic Stability Act (or PROMESA) with oversight authority over the Commonwealth of Puerto Rico and 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 filed pursuant to PROMESA thereby commencing a case under Title III thereof which is a specific statutory vehicle that allows the Commonwealth of Puerto Rico and its instrumentalities, such as PREPA, to adjust their debt (similar to a bankruptcy proceeding). While PREPA has previously made payments of amounts due under the 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 court approval. A rejection of the PPA would likely have a material adverse effect on our business prospects, financial condition and results of operations. The fact of PREPA’s insolvency and its filing under Title III each constituted an event of default under the project’s financing agreement. However, in August 2017, the lender issued a letter withdrawing the event of default associated with the PREPA insolvency. Pursuant to our agreement with the lender, the Santa Isabel project may not make distributions to us until such time as lender consents (which will not be unreasonably withheld if PREPA assumes the PPA). Despite such agreement, 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 our financing agreement, or that Santa Isabel will be able to remain current with respect to its payments under the financing agreement. In any such event, another event 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 other standstill 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 debt under the financing agreement immediately due and payable. Even though the Santa Isabel financing agreement is non-recourse to us, it is secured by the Santa Isabel project and any exercise of remedies by the lender could have a material adverse effect on our business prospects, financial condition and results of operations. In addition, on September 20, 2017, Hurricane Maria, a category 4 hurricane, made direct landfall on Puerto Rico and caused substantial damage to PREPA’s electricity transmission and distribution assets. PREPA asserted a force majeure event under the PPA with respect to its assets, claiming relief of its obligations to perform substantially all of its obligations under the PPA, except its obligation to make payments thereunder. While our project equipment did not suffer significant damage, Santa Isabel was not authorized to return to service by PREPA due to system reliability issues until mid-February 2018 and, even after returning 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.

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In connection with the asserted force majeure event, PREPA stated that immediately after Hurricane Maria, PREPA believed approximately 80% of its energy transmission and distribution infrastructure had been damaged, resulting in PREPA being unable to provide electrical power to the majority of its customers. High disaster recovery costs coupled with negligible utility billings of its customers due to interruption of service have contributed to a short term liquidity constraint that PREPA has acknowledged and which is limiting its ability to pay suppliers timely. Further, given the current condition of PREPA’s transmission and distribution assets and the logistical complexity associated with remediating the damage, no assurances can be given as to when the asserted force majeure under the PPA might abate and PREPA’s timely performance might resume under the PPA, or how the disruption will affect PREPA’s bankruptcy-like proceedings under 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 effect on 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 the price of the electricity we generate for sale on a spot-market basis. In addition, excessive building of competing renewable resources in a limited geographic area resulting in congestion and potential curtailment could also adversely affect pricing available on the spot-market. See Item 7A "Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk." Low spot-market power prices, if combined with other factors, could have a material adverse effect on our results of operations and cash available for distribution. Additionally, cheaper conventional fuel sources or competing renewable resources could also have a negative 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 sale agreement 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 adversely affected, 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 our expectations.
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, severe weather, accident, failure of major equipment, shortage of or inability to acquire critical replacement or spare parts, failure in the operation of any future transmission facilities that we may acquire, including the failure of interconnection to available electricity transmission or distribution networks, could damage or require us to shut down our turbines or related equipment and facilities, impeding our ability to maintain and operate our facilities and decreasing electricity generation levels and our revenues. For example, Hurricane Maria resulted in damage to PREPA’s transmission and distribution assets that caused our Santa Isabel project 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 that have affected our Santa Isabel project. In addition, several of our projects had previously experienced blade failures, and no assurances can be given that potential equipment deficiencies will not in fact continue to occur, that we will always have warranty coverage for any such defects, that the warranty provider would fulfill its obligations under such warranty coverage (including any liquidated damages compensation provisions), or that any such effects will not have a material adverse effect 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 an aggregate maximum liability cap and there can be no assurance that the manufacturer or third-party service provider will be able to fulfill its contractual obligations. In addition, such agreements can vary as to what equipment maintenance risks are fully assumed by the service provider and what equipment failure risks 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 arrangements at certain of our projects pursuant to which the turbine manufacturer continues to provide routine and corrective maintenance service, but we are responsible for a portion of the maintenance and repairs, including on major component parts. While the revised service arrangements reduce fixed contract costs, in the event of unexpectedly high turbine component failures for which we as owner have assumed responsibility, we may face decreased revenues of a project and increased project expense which could have a material adverse effect on our business prospects, financial condition, results of operations and ability to make cash distributions to our investors. We expect over time in the future to continue taking on additional risks as an owner, including increased self-performance of maintenance and service work with our own technicians instead of utilizing service providers, which will have expected cost benefits, but will similarly come with additional 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 some significant spare parts and other equipment are often located outside of the jurisdictions in which our power projects operate. Additionally, our operating projects generally do not hold spare substation main transformers. These transformers are designed specifically for each wind power project, and order lead times can be lengthy. If one of our projects had to replace any of its

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substation 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 one of our operating projects due to natural events or operational problems and such events are not fully covered by insurance, our electricity generation levels and revenues 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 investors
Climate change may have the long-term effect of changing wind patterns at our projects. Changing wind patterns could cause changes in expected electricity generation. These events could also degrade equipment or components and the interconnection and transmission facilities’ lives or maintenance costs. We may face decreased revenues of a project and increased project expense which could have a material adverse effect on our business prospects, financial condition, results of operations 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 consider our prospects in light of the risks and uncertainties growing companies encounter in rapidly evolving industries such as ours. Also, our anticipated near-term growth 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 otherwise to effectively manage our capital expenditures and control our costs, including the requisite general and administrative costs necessary to achieve our anticipated growth. These challenges could adversely affect our ability to manage our current or future operating projects in an efficient manner and complete construction of any construction projects in a timely manner, either of which could have a material adverse effect on our business prospects, financial condition and results of operation.
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 will operate. These laws and regulations require our projects to obtain and maintain permits and approvals, undergo environmental impact assessments and review processes and implement environmental, health and safety programs and procedures to control risks associated with the siting, construction, operation and decommissioning of power projects. For example, to obtain permits some projects are, in certain cases, required to undertake programs to protect and maintain local endangered or threatened species. If such programs are not successful, our projects could be subject to increased levels of mitigation, penalties or revocation of our permits.
Violations of environmental and other laws, regulations and permit requirements, including certain violations of laws protecting wetlands, migratory birds, bald and golden eagles and threatened or endangered species, may also result in criminal sanctions or injunctions. In addition, if our projects do not comply with applicable laws, regulations or permit requirements, or if there are endangered or threatened species fatalities at our projects, we may be required to pay penalties or 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 to adopt 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 reporting to 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, in addition, 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 an agreement with U.S. Fish and Wildlife to fund additional research into mitigation measures and incurred nominal fines with respect to the prior eagle incidents, no assurances 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 a result 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 permit will 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 hazardous substances, 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 by governmental 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 on our 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 projects to incur additional material costs or cause our projects to suffer adverse consequences. For example, the Ministry

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of Environment in Ontario has established regulatory requirements governing noise restrictions for wind farms which are an integral part of the permitting framework for our projects in certain jurisdictions. In the event of changes in either the regulatory requirements or permitting framework, there is risk that our projects that were designed for compliance within the existing framework and requirements for noise could still be evaluated by regulators as noncompliant. These risks are enhanced because testing for compliance with noise requirements is technically complex, carries some degree of uncertainty, and does not have significant precedent in that market. In the event of a determination of noncompliance, there is risk that the necessary mitigation, which would likely need to occur during periods 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 noise regulations), and any liabilities, fines or other sanctions resulting from violations of them, could have a material adverse effect on our business prospects, financial condition 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 to complete 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 currently do not own any projects in construction. There may be delays or unexpected developments in completing any of our own future construction projects, which could cause the construction costs of these projects to exceed our expectations. Our construction projects would typically be designed and constructed under fixed-price and schedule engineering, procurement, and construction contracts with reputable construction and equipment suppliers, and would typically have liquidated damages provisions for non-performance by the contractors subject to specified limitations on the amount of damages we can recover from the contractor. We may suffer significant construction delays or construction cost increases as a result of underperformance of these contractors and equipment suppliers, as well as other suppliers, 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 a settlement 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 the remaining budgeted project contingencies. If an equitable settlement cannot be reached, arbitration or legal action could be commenced, and any final judgment or decision 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 timely manner or at all;
failure to complete interconnection to transmission networks, which relies on several third parties, including interconnection facilities provided by local utilities;
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 construction projects from commencing operations or from meeting our original expectations about how much electricity

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they will generate or the returns they will achieve. In addition, substantial delays could cause defaults under our financing agreements or under PPAs that require completion 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 to transition construction projects into financially successful operating projects would have a material adverse effect on our business prospects, financial condition and 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 to risks. Our projects are also exposed to interconnection and transmission facility development and curtailment risks, which may delay the completion of any construction 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 or delay in the operation or development of these interconnection or transmission facilities could result in our losing revenues because such a failure or delay could limit the amount of power our operating projects deliver or delay the completion of any construction projects. For example, we have experienced situations where the 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 the transmission outage at the delivery substation, including making alternative transmission arrangements to deliver power at an alternative substation through alternative 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 arrangements would be equivalent to the revenues that would have been generated had such transmission outage not occurred. Furthermore, individual alternative arrangements made to mitigate the transmission outage may present their own risks, such as possible curtailment risks on the alternative transmission arrangements or pricing risks in the merchant power market, which could adversely affect the overall efficacy of any mitigation efforts. If we were unable to mitigate potential losses, other future sustained transmission outages at a delivery substation could have a material adverse effect on our business prospects, financial condition and results of operations.
In addition, certain of our operating projects’ generation of electricity may be curtailed without compensation (or, in some cases, choose to continue operating but accept negative power prices) due to transmission limitations or limitations on the electricity grid’s ability to accommodate intermittent electricity generating sources, reducing our revenues and impairing our ability to capitalize fully on a particular project’s potential. Such a failure or curtailment at levels above our expectations could have a material adverse effect on our business prospects, financial condition and results of operations. For example, in certain geographic areas in the Electric Reliability Council of Texas (ERCOT) market in Texas, construction of renewable energy projects has exceeded the available capacity of the existing transmission infrastructure resulting in localized congestion on transmission facilities utilized by certain of our projects. While these projects have financial hedges that partially protect revenues against movement in broader power markets, these instruments generally do not provide protection against localized congestion 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 such additional facilities will be sufficient to relieve congestion, or that construction of new generation facilities will not continue to exceed the capacity of any added transmission 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 to available electricity transmission or distribution networks. In some cases, these facilities may span significant distances. A failure in our operation of these facilities 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 of electricity 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 be any excess capacity available in those generator lead facilities, and should a third party request access to such capacity, the relevant regulatory authority in such jurisdiction, 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 the requesting third party at regulated rates. Should this occur in markets with such regulations, the projects could be subject to additional regulatory risks and costly compliance 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 complete any 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 our ability to retain and motivate key employees and attract qualified new employees. Because the wind power industry is relatively new, there is a scarcity of experienced employees in the wind power industry. We may not be able to replace departing members of our management team or key employees. Integrating new executives into our management team and training new employees with no prior experience in the power industry could prove disruptive to our projects, require a disproportionate amount of resources and management attention and ultimately prove unsuccessful. An inability to attract and retain sufficient technical and managerial personnel

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could limit our ability to effectively manage our operating projects and complete any construction projects on schedule and within budget, which could have a material 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 Pattern Development 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 our employees. 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 notice from 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 and services called for under the A&R Multilateral Services Agreement after notice and opportunities to cure. In addition, while Pattern Development 2.0 currently does not have any employees, the A&R Multilateral Services Agreement provides for certain circumstances pursuant to which we can require Pattern Development 2.0 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 of either a Pattern Development 1.0 employee transfer event or (in the event Pattern Development 2.0 has employees) a Pattern Development 2.0 employee transfer event, we will be faced with increased costs associated with employing a larger number of employees. If either Pattern Development 1.0 or Pattern Development 2.0 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&R Multilateral Services Agreement and our development activities remain insignificant, we may not immediately require the services of all such employees. Such events 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 those of 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. The ownership 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, leases and 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 those third 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 a material adverse effect on our business prospects, financial condition and results of operations. In addition, certain lands, such as lands under the jurisdiction of the United States Department of Interior's Bureau of Land Management (BLM), are subject to contractual rights that permit the BLM to periodically adjust rent due on properties 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 on which 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 our business 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 that regulate 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 under PUHCA. Other than Gulf Wind, Panhandle 1, Panhandle 2, and Logan’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 future projects 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 to FERC rate regulation are required to obtain acceptance of their rate schedules for wholesale sales of energy (i.e., not retail sales to consumers), capacity and ancillary services, including their ability to charge “market-based rates.” FERC may revoke or revise an entity’s authorization to make wholesale sales at market-based rates if FERC subsequently determines that such entity and its affiliates can exercise horizontal or vertical market power, create barriers to entry or engage in abusive affiliate transactions or market manipulation. In addition, public utilities in the United States are subject to FERC reporting requirements that impose administrative burdens and that, if violated, can expose the company to criminal and civil penalties 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 current operating 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 is the 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 electricity market in Ontario. The Southwest Power Pool is the RTO and regional market administrator for our Post Rock project. Lost Creek is in the Associated Electric Cooperative, Inc. a subregion of the SERC Reliability Corporation. Amazon Wind is in the PJM RTO. Many of these entities can impose rules, restrictions and terms of service

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that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, ISOs and RTOs have developed bid-based locational pricing 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 actions could 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 mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. Although our U.S. projects are not subject to state utility regulation because 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 provincial regulatory authority with respect to the generation and production of electricity, which varies across provincial jurisdictions. Changes in regulatory treatment at the state 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 of operations.
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 to curtailment of electricity generation, electricity grid management restrictions, interconnection rules and transmission may all have the effect of limiting the revenues from, and increasing the operating costs of, our projects which could have a material adverse effect on our business, financial condition and results of operations.
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 competitive markets. We cannot predict the future design of wholesale power markets or the ultimate effect that on-going regulatory changes will have on our business prospects, 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, manufacturing defects, natural disasters, terrorist attacks and sabotage. We are also exposed to environmental risks. We have insurance policies covering certain risks associated with our business. Our insurance policies do not, however, cover losses as a result of certain force majeure events or terrorism. In addition, our insurance policies for 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 the insurance market on commercially reasonable terms and is often capped at predetermined limits that may not be adequate. Our insurance policies are subject to annual 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 limits of 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 operating part 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 currencies other 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 currency exposure 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 outside the United States. However, any measures that we have implemented or may implement in the future to reduce the effect of currency exchange rate fluctuations and other risks of our global operations may not be effective or may be expensive. We cannot provide assurance that currency exchange rate fluctuations will not otherwise have a material adverse effect on our financial condition or results of operations or cause significant fluctuations in quarterly and annual results of operations.
Foreign currency translation risk arises upon the translation of balance sheet and statement of operations items of our non-U.S. dollar denominated subsidiaries whose 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 purposes of 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. dollar denominated 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 “Other comprehensive

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income (loss), net of tax.” These foreign currency translation differences may have significant negative or positive impacts. Our foreign currency translation risk mainly 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 the functional currency of us or our subsidiary. Exchange differences (gains and losses) arising on the settlement of monetary items or on translation of monetary items at rates different from those at which they were translated on initial recognition during the period or in previous financial statements are recognized the consolidated 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 held by 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 FCPA prohibits U.S. companies and their officers, directors, employees and agents acting on their behalf from corruptly offering, promising, authorizing or providing anything of value to foreign officials for the purposes of influencing official decisions or obtaining or retaining business or otherwise obtaining favorable treatment. The FCPA also requires companies to make and keep books, records and accounts that accurately and fairly reflect transactions and dispositions of assets and to maintain a system of adequate internal accounting controls. As part of our business, we deal with state-owned business enterprises, the employees and representatives of which may be considered foreign officials for purposes of the FCPA. As a result, business dealings between our employees or our agents and any such 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 otherwise prohibited between our company and a private third-party. Violations of these legal requirements are punishable by criminal fines and imprisonment, civil penalties, disgorgement of profits, injunctions, debarment from government contracts as well as other remedial measures. We have established policies and procedures designed to assist us and our personnel in complying with applicable U.S. and non-U.S. laws and regulations; however, we cannot assure stockholders that 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, and El Arrayán, in which we have a 70% interest. In addition, in connection with our strategic partnership with PSP Investments, we have joint venture arrangements with 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 in connection 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 joint venture partner, including certain projects which may be owned by one of the Pattern Development Companies. In addition, our arrangements with PSP Investments 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 the percentage 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 of control over business operations, which could result in an increase in the financial, legal, operational or compliance risks associated with a project, including, but not 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 partners could 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 our company and our stockholders, on the one hand, and our joint venture partners, on the other hand, where our joint venture partners’ business interests are inconsistent with our and our stockholders’ interests. Further, disagreements or disputes between us and our joint venture partners may arise which could result in litigation, 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 a material adverse effect on our business prospects, financial condition and results of operations.

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Security breaches, including cybersecurity breaches, and other disruptions could compromise our business operations and critical and proprietary information and 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, service providers, business partners and other individuals in our data center and on our network. Additionally, we use and are dependent upon information technology systems that utilize sophisticated operational systems and network infrastructure to run our wind farms. Through our 24/7 operations control center, we can, among other things, monitor and control each wind turbine, monitor regional and local climate, track real time market prices and, for some of our projects, monitor certain environmental activities. The secure maintenance of information and information technology systems is critical to our operations. Despite security measures we have employed, including certain measures implemented pursuant to mandatory NERC Critical Infrastructure Protection standards, our infrastructure may be increasingly vulnerable to attacks by hackers or terrorists as a result of the rise in the sophistication and volume of cyberattacks. Also, our information and information 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) corrupt data; or (iv) result in unauthorized access to the information stored on our networks, including, company proprietary information and employee data causing the information 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 of life. Any such attack, breach, access, disclosure or other loss of information could result in lost revenue, the inability to conduct critical business functions, legal claims or proceedings, regulatory penalties, increased regulation, increased protection costs for enhanced cyber security systems or personnel, damage to our reputation and/or the rendering of our disclosure controls and procedures ineffective, all of which could adversely affect our business prospects, financial condition and reputation.
Risks Related to Future Growth and Acquisitions
The 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 conducted by Pattern Development 2.0, under development. We intend to pursue opportunities to acquire projects from third-party owners where we may submit bids from time to time, and from each of the Pattern Development Companies pursuant to our respective Purchase Rights. To enhance alignment and allow us to benefit from development, 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 have substantially 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 economic returns 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, among other things, permitting challenges, failure to procure the requisite financing, equipment or interconnection, local opposition to the project which may entail litigation, or an inability to satisfy the conditions to effectiveness of project agreements such as PPAs and (ii) any of the other projects in its respective development pipeline, in a timely manner, or at all, in either case, which could limit our acquisition opportunities under our respective Purchase Rights 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 projects outside of activities conducted by Pattern Development 2.0. See also “- Our growth strategy is dependent upon the acquisition of attractive power projects developed by third-parties, including Pattern Development 1.0 and Pattern Development 2.0, and an inability of such development companies to obtain the requisite financing to develop and construct projects could have a material adverse effect on our ability to grow our business." In addition, we also must also potentially

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anticipate obtaining funds from equity or debt financings to complete an acquisition or construction of an acquired project which exposes us to similar financing risks;
local opposition to wind turbine installations is growing in certain markets due to concerns about noise, health and other alleged impacts of wind power projects. In addition, indigenous communities in the United States and Canada, including Native Americans and First Nations, are becoming more involved in the development of wind power projects and have certain treaty rights that can negatively affect the viability of power projects. As a result, for these 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 condition and 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 result in a decrease in cash available for distribution per Class A share as a result of incorrect assumptions in our evaluation of such acquisitions, unforeseen consequences or other external events beyond our control. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations may change significantly, and stockholders will not generally have the opportunity to evaluate the economic, financial and other relevant information that we will consider 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 obtaining funds 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 debt instruments, we may need to be able to access the capital markets on commercially reasonable terms when acquisition opportunities arise. For example, we issued senior notes in January 2017 to help finance the acquisition of the Broadview project and to repay other debt previously incurred to finance acquisition opportunities. In addition, we utilized in part proceeds from an underwritten public offering of our Class A shares in October 2017 and at-the-market offerings under an equity distribution agreement we entered into in May 2016 for investment in acquisition opportunities and to repay other debt previously incurred to finance acquisition opportunities. Our ability to access the equity and debt capital markets is dependent on, among other factors, the overall state of the capital markets 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 market price 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 acquisition opportunities.
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 a BB-/Ba3 credit rating from Standard & Poor’s and Moody’s, respectively. An inability to obtain equity or debt financing on commercially reasonable terms could significantly limit our timing and ability to consummate future acquisitions, and to effectuate our growth strategy. In addition, the issuance of additional Class A shares in connection with acquisitions, particularly if consummated at depressed price levels or consummated at price levels that declined significantly between the signing and closing of an acquisition, could cause significant shareholder dilution, expose us to risks of being unable to consummate an acquisition we had agreed to 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 any required construction and other capital costs of the acquired projects. The availability of tax equity financing with respect to any future acquisitions by us will likely 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 their current and future tax position. While uncertainty remains, no assurances can be given that there will not be a material adverse effect on the willingness of investors to provide tax equity financing, an ability by us to obtain alternative financings which would be as attractive as was available from tax equity investors prior 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 existing projects.

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We 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 able to 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 acquisition opportunities, or as a source of capital to complete any construction outstanding or pay capital costs of acquired projects, we may need to consider utilizing other sources of capital, such as cash on hand, borrowings under our existing credit facilities, or arranging additional credit facilities, none of which may be available or may 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 discovered through our due diligence process, including exposure to previously existing liabilities and unanticipated costs associated with the pre-acquisition period; difficulty in integrating the acquired projects into our existing business; and, if the projects are in new markets, the risks of entering markets where we have limited experience. We are entering new markets, such as Japan and Mexico, with different languages and cultures which may further enhance risks relating to assimilating new operations and personnel in these markets, becoming familiar with applicable local laws and regulations, providing effective control over operations in remote locations, and diverting time and attention of management to address integration issues. In addition, while we will perform our due diligence on prospective acquisitions, we may not be able to discover all potential operational deficiencies in such projects or problematic wind characteristics. A failure to achieve the financial 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 may include limited opportunities in a market, changes in business environment or law which reduces the attractiveness of a market, excessive competition in the market, 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 on investment. The disposal of power projects involves numerous risks, many of which are outside of our control, including the ability to locate an attractive buyer of a 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 required to 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 a power 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 an attractive (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 would generate higher returns.
Our growth strategy is dependent upon the acquisition of attractive power projects developed by others, including Pattern Development 1.0 and Pattern Development 2.0 (in which we hold a minority interest), and an inability of such development companies to obtain the requisite financing to develop and construct 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 financing sources to fund projected construction and other projected capital expenditures. As a result, in order to successfully develop a power project, development companies, including Pattern Development 1.0 and Pattern Development 2.0, from which we may seek to acquire power projects, must obtain at-risk funds sufficient 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 projects are 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 to implement 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 we made an initial capital contribution to Pattern Development 2.0 of approximately $60 million for an approximately 20% ownership interest in Pattern Development 2.0. 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% ownership interest 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 in one 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 do not participate in such subsequent rounds of financing, our ownership interest in Pattern Development 2.0 may be diluted.

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As 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 Pattern Development 2.0 by participating in additional capital calls or otherwise decided to invest in other project development opportunities, we would further expose ourselves directly to project development risks, including permitting challenges, failure to secure PPAs, failure to procure the requisite financing, equipment or interconnection, or an inability to satisfy the conditions to effectiveness of project agreements such as PPAs. Generally, project development may entail risks of making investments in assets that are not profitable, and we are, and if we invested further could be further, exposed to significant investment activities that require capital prior to having certainty that a project can move forward. We may lose money invested without generating returns. No assurances can be given that we would be successful in project development activities we undertake, whether through the investment in Pattern Development 2.0 or otherwise, which can diminish our 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 Companies or 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 and finance 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 A share through acquisitions, we must be able to acquire new generation assets, such as the Identified ROFO Projects, on economically favorable terms. If we are unable to make accretive acquisitions from the Pattern Development Companies or third parties because we are unable to identify attractive acquisition opportunities, negotiate acceptable purchase contracts, obtain financing on economically acceptable terms (as a result of the then current market value of our Class A 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 is subject to change. With respect to the U.S. market, legislators and the current U.S. administration have proposed environmental and tax policies that have created 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 benefits from 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 States have benefited from various federal and state governmental incentives, such as PTCs, ITCs, ITC cash grants, loan guarantees, RPS programs and accelerated tax depreciation. PTCs and ITCs for wind energy on the federal level were extended in December 2015. The extension extended the expiration date for tax credits for wind facilities with a five year phase-down for wind projects commencing construction after December 31, 2014. Renewable energy sources in Chile benefit from the 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 2015 and progressively increasing up to 20% by 2025, shall be produced with renewable and non-conventional technologies. Such obligations translate into “green attributes” 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 to renewable 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 extent that these governmental incentive programs may be amended or changed in the future, particularly if amendments or changes are unexpected or unfavorable and after we have developed long-term business plans and strategies based upon them, it could adversely affect the price of electricity sold to power purchasers generated by developed or planned wind power projects, decrease demand for wind power, or reduce the number of projects available to us for acquisition, any of which 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. For example, the U.S. Environmental Protection Agency (EPA) under the current U.S. administration has announced that it is taking measures to repeal 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 generation facilities and increasing renewable generation in order to reduce greenhouse gas emissions. The current U.S. administration has also proposed other environmental policies 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 of various clean energy programs and initiatives designed to curtail climate change. Such a reduction or removal of incentives may diminish the markets in which we operate. As a part of recent comprehensive income tax reform, the corporate tax rate was reduced, and while such reductions may have certain positive impacts on our financial results as applied to our own corporate taxes, a reduction in the corporate tax rate could also have adverse consequences, such as diminishing the capacity of potential investors in our projects to benefit from incentives and reduce the value of accelerated depreciation deductions. As a part of comprehensive tax reform in late 2017, there were proposed amendments in Congress that would have adversely affected the value and ability to preserve benefits of PTCs for wind energy on the federal level. While these amendments

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were 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 and benefits of the PTC. The current administration also made public statements regarding overturning or modifying policies of or regulations enacted by the prior administration that placed limitations on coal and gas electric generation, mining and/or exploration. Efforts to overturn federal and state laws, regulations or policies that are supportive of wind energy generation or that remove costs or other limitations on other types of generation that compete with wind energy projects could 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 renewable energy. Renewable energy developers must anticipate the future policy direction in each of the provinces, and secure viable projects before they can bid to procure a 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 or political 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 with these 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 wind power developers and operators for the limited pool of personnel with requisite industry knowledge and experience. Furthermore, in past years, there have been times of increased demand for wind turbines and their related components, causing turbine suppliers to have difficulty meeting the demand. If these conditions return in the future, turbine and other component manufacturers may give priority to other market participants, including our competitors, who may have resources greater 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 our projects. 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 wholesale market prices. Depending on the regulatory framework and market dynamics of a region, we may also compete with other wind power companies and other renewable energy generators, when our projects bid on or negotiate for long-term power sale agreements or sell electricity or RECs into the spot-market. Our ability to compete on price with other wind power companies and other renewable energy IPPs may be negatively impacted if the regulatory framework of a region favors 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 that may cause upwind array losses to occur at our wind projects. Upwind array losses reflect the diminished wind resource available at a project resulting from interference with available wind caused by adjacent wind turbines. An adjacent wind power project that causes upwind array losses could have a material adverse effect 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 other governmental 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 in prices for these fuels could cause demand for wind power to decrease and adversely affect the demand for renewable energy. For example, low natural gas prices have led, in some instances, to increased natural gas consumption by electricity-generating utilities in lieu of other power sources. To the extent renewable energy and 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 demand for 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 business prospects, 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 wind and 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 or carve-outs since initial RPS adoption. Recent legislation in California, Hawaii, Oregon and Vermont extended targets to 2030 and beyond. However, other states are starting to approach their final targets. Five states reached the

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final 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 only two 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 their demand for renewables, including Ontario, which has halted its Large Renewable Procurement Process. Additionally, hydro power dominates when it comes to meeting 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 for additional wind and solar power generating capacity could decrease, which could have a material adverse effect on our business prospects, financial condition, and results of operations.
New projects being developed that we may acquire may need governmental approvals and permits, including environmental approvals and permits, for construction 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 environmental approvals and permits, and may be subject to the imposition of related conditions that vary by jurisdiction. In some cases, these approvals and permits require periodic renewal and a subsequently issued permit may not be consistent with the permit initially issued. In other cases, these permits may require compliance with terns 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 the permits, 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 or burdensome conditions upon renewal or over time, could impair our ability to construct and operate a project. In addition, we cannot predict whether seeking the permits will attract significant opposition or whether the permitting process will be lengthened due to complexities, legal claims or appeals. Delay in the review and 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 attractive to 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/or Pattern 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 lawsuits brought 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 by commencing 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 or permit 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 incur a 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 delivered notice 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 Development Company 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 and Pattern 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 after construction-readiness following commencement of its construction. We do not control either Pattern Development 1.0 or Pattern Development 2.0, and Pattern Development 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 any time for its own capital, liquidity, shareholder, or other requirements. In the event Pattern Development 1.0 or Pattern Development 2.0 delivered notice for a project 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 acceptable final 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 a competitor), 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 project developed 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. If this 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 projects on

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the identified ROFO list under our respective Project Purchase Right with Pattern Development 1.0 or Pattern Development 2.0 could materially adversely affect our 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/or Pattern Development 2.0, respectively, might be sold to third parties. In addition, each of our respective Project Purchase Rights, Pattern Development 1.0 Purchase Rights and Pattern Development 2.0 Purchase Rights may expire, and the Second Amended and Restated Non-Competition Agreement with Pattern Development 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), Pattern Development 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 1.0 and/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 we are 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, Pattern Development 1.0, Pattern Development 2.0, or its respective equity owners may seek alternative buyers, which 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.
In addition, our Project Purchase Right with Pattern Development 1.0 and our Pattern Development 1.0 Purchase Rights terminate upon the third occasion on which 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 final offer 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 Pattern Development 2.0 Purchase Rights terminate upon winding-up of Pattern Development 2.0. Following termination of our respective Project Purchase Right, and our Pattern 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 and ultimately 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 the right terminate the Second Amended and Restated Non-Competition Agreement upon the earlier of wind-up of Pattern Development 2.0 or the valid rejection by Pattern 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 and Restated Non-Competition Agreement, (among other things) Pattern Development 2.0 is granted an exclusive right, with certain exceptions, to pursue all power generation, storage or transmission development projects in the U.S., Canada and Mexico that have not completed construction, but this does not restrict us from acquiring any company or business that is principally engaged in the business of owning and operating renewable energy facilities. In addition, at any time that Tokyo, Japan-based Green Power Investment Corporation is majority owned by either us, Pattern Development 1.0 or Pattern Development 2.0, such majority owner (which is currently Pattern Development 1.0) is granted exclusive development rights, with certain exceptions, over power generation, storage or transmission 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 implement our 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’s officers and key employees for their strategic guidance and expertise in the selection of projects that we may acquire in the future. Because the wind power industry 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 Development 1.0’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 a suitable 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 may adversely affect our ability to effectively manage our operating projects and complete any construction projects on schedule.”

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We may decide to further expand our acquisition strategy to include other types of power projects or transmission projects besides wind power. Any future additional acquisitions of non-wind power projects or transmission projects may present unforeseen challenges and result in a competitive disadvantage relative 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 projects which we acquired in April 2017, and assuming the consummation of the acquisitions of the Kanagi Solar and Futtsu Solar projects (representing in aggregate 39 MW 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 wind power. In the future, we may further expand our acquisition strategy into other types of power projects or transmission projects besides wind power. There can be no 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 that are 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 a disproportionate amount of our management’s attention and resources, which could have an adverse impact on our business, as well as place us at a competitive disadvantage relative to more established non-wind energy market participants. A failure to successfully integrate such acquisitions into our existing project portfolio as a result of unforeseen operational difficulties or otherwise, could have a material adverse effect on our business prospects, financial condition and results of operations.
We are subject to risks associated with litigation or administrative proceedings that could materially impact our operations, including proceedings in the future related 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 the future, we may be involved in legal proceedings, disputes, administrative proceedings, claims and other litigation that arise in the ordinary course of business related 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 power project 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 our power projects based on alleged negative health effects related to acoustics caused by wind turbines or alleged contamination of groundwater. In addition, we have been and may subsequently become subject to legal proceedings or claims contesting the construction or operation of our power projects. Any such legal proceedings 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 associated with commencing or continuing commercial operations at a power project. Settlement of claims and unfavorable outcomes or developments relating to these proceedings or disputes, such as judgments for monetary damages, injunctions or denial or revocation of permits, 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.
Risks Related to Our Financial Activities
Our 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 debt levels, 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, under certain 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 be required 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; and

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our substantial debt service obligations make us vulnerable to adverse changes in general economic, credit and capital markets, industry and competitive conditions 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 with our 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 we may 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 can borrow, reduce our cash flows and increase the equity investment we may be required to make to complete any construction of our projects. These increases could cause some of our projects to become economically unattractive. If we are unable to raise additional capital or generate sufficient operating cash flow to repay our indebtedness, we could be in default under our lending agreements and could be required to delay construction of our projects, reduce overhead costs, reduce the scope 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 condition and 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 on business 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, capital expenditures, investments or acquisitions, or for other purposes. If we do so, the risks related to our level of indebtedness could intensify. Specifically, a high level of 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 our cash 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 prevailing economic, 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 any such default under our debt agreements could have a material adverse effect on our business by, among other things, limiting our ability to take advantage of financing, 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 restrictions contained in our revolving credit facility and our future debt instruments, some of which may be secured debt. Although our revolving credit facility contains restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and could be amended or waived, and the indebtedness incurred in compliance with these restrictions could be substantial and may also be secured. Accordingly, we may, in compliance with 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 terms of 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 upon conversion settlement, repayment at maturity, or upon exercise of a repurchase obligation, and our debt agreements may limit our ability to pay cash upon conversion, 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 a fundamental 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. In addition, 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 of delivering any fractional share), we will be required

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to 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 to require 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 the notes 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, pay cash 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 cash upon conversions of the convertible notes may be limited by law, regulatory authority or agreements governing our indebtedness. Our failure to repurchase notes at a 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 convertible notes pursuant to the indenture would constitute a default under the indenture governing the issuance of the respective notes. A fundamental change, change of control triggering event, or a default under the indenture could also lead to a default under agreements governing our or our subsidiaries’ indebtedness. If the repayment of the related indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness 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 is triggered, 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 to convert their convertible notes, unless we elect to satisfy our conversion obligation by delivering solely our Class A shares (other than paying cash in lieu of delivering any fractional share), we would be required to settle a portion or all of our conversion obligation through the payment of cash, which could adversely affect our liquidity. In addition, even if holders do not elect to convert their convertible notes, we could be required under applicable accounting rules to reclassify all 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 net working 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 the maturity 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 of their 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 required to increase the conversion rate for a holder that elects to convert its convertible notes in connection with such make-whole fundamental change. Furthermore, our indentures prohibit us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity assumes our obligations thereunder. These and 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 the collateral 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 physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. Limited recourse debt is debt where we have provided a limited 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 liable directly 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 be required to use amounts distributed by our other subsidiaries as well as other sources of available cash, reducing our cash available to execute our business plan and pay dividends to holders of our Class A shares. In addition, if our subsidiaries default on their obligations under non-recourse financing agreements, we may decide to make payments to prevent the lenders of these subsidiaries from foreclosing on the relevant collateral. Such a foreclosure would result in our losing our ownership 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 assets could 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 the

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Hatchet Ridge Wind Lease Financing against certain tax losses. In addition, we have entered into tax equity partnership agreements in connection with six of our projects 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 to support such financings. For example, some of our subsidiaries in the United States had obtained construction bridge loans to finance a portion of project construction costs, and in certain cases, such loans were secured by the ITC cash grant proceeds received from the U.S. Treasury. We have assumed certain indemnities 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 ITC cash 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 project commences 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, we may be required to make payments under the indemnities to prevent the lenders of those subsidiaries from foreclosing on the relevant project collateral. Payment by 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 our cash 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 to make pursuant to these indemnities could have a material adverse effect on our business prospects, financial condition and results of operations and, in turn, on our cash 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 London Interbank Offered Rate (LIBOR) or Canadian Dollar Offered Rate (CDOR), and expose us to interest rate risk. Such rates tend to fluctuate based on general economic conditions, general interest rates, Federal Reserve rates and the supply of and demand for credit in the relevant interbanking market. Increases in the interest rate generally, and particularly when coupled with any significant variable rate indebtedness, could materially adversely impact our interest expenses. If interest 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 in interest 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 the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017, no amounts were outstanding under our revolving credit facility. To the extent 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 into hedges on such indebtedness, our interest expense on such indebtedness will fluctuate based on LIBOR, CDOR or other variable interest rates. Consequently, we may have difficulties servicing such unhedged indebtedness and funding our other fixed costs, and our available cash flow for general corporate requirements may be 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 order to 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 enter into 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 use cash collateral to meet margin requirements, each of which could have a material adverse effect on our business prospects, financial condition, results of operations 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 have entered, and may in the future enter, into financial swaps, day-ahead sales transaction or other hedging arrangements. We may acquire additional assets in the future with similar hedging agreements. In an effort to stabilize our revenue from electricity sales from these projects, we evaluate the electricity sale options for each 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 our electricity 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 the electricity 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 the physical 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 to produce. Under the terms of our existing financial swaps, we are not obligated to physically deliver or purchase electricity. Instead, we receive payments for specified 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 swaps are 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 of electricity we generate from operations may be materially different from our estimates for a variety of reasons, including variable wind conditions and wind turbine availability. If a project does not generate the volume of electricity covered

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by the associated physical sale or financial swap contract, we could incur significant losses if electricity prices in the market rise substantially above the fixed price provided 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 excess production 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 hedging contracts 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 to secure our delivery or payment obligations under these hedging agreements. We are not currently required to post cash collateral or issue letters of credit to backstop 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 were required to do so, our available cash or available borrowing capacity under the credit facilities under which these letters of credit are issued would be correspondingly 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, we contract to sell all or a fixed proportion of the electricity generated by one of our projects, sometimes bundled with RECs and capacity or other environmental attributes, 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 the risk 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 an annual 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 (or RECs 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 its termination.
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 future declines in prices of RECs or other environmental attributes. If our projects do not generate the amount of electricity required to earn the RECs or other environmental 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 liquidated damages. Further, current market conditions may limit our ability to hedge sufficient volumes of our anticipated RECs or other environmental attributes, leaving us exposed 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 risk that regulatory changes will adversely affect prices.
Risks Related to Ownership of our Class A Shares
We 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, including to 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 is dependent on the earnings and the receipt of funds from our project subsidiaries through distributions or intercompany loans. Our power projects’ ability to generate 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 cash distributions from our project subsidiaries after the payment of operating costs, debt service and other expenses. See Item 5 “Market for Registrant’s Common Equity and Related Stockholder Matters-Cash Dividend to Investors.” We may lack sufficient available cash to pay dividends to holders of our Class A shares due to shortfalls attributable to a number of operational, commercial or other factors, including insufficient cash flow generation by our projects, as well as unknown liabilities, the cost associated with governmental regulation, increases in our operating or general and administrative expenses, principal and interest payments on our 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 us under the terms of their indebtedness, or in the event certain specified events occurred under our tax equity arrangements that change the percentage of cash distributions 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 to holders 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 discussed under Item 5 “Market for Registrant’s Common Equity and Related Stockholder Matters-Cash Dividend to Investors.” The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness and the provisions existing and future tax equity arrangements.

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Restrictions on distributions to us by our subsidiaries under our revolving credit facility and the agreements governing their respective project-level debt could limit our ability to pay anticipated dividends to holders of our Class A shares. These agreements contain financial tests and covenants that our subsidiaries must satisfy prior to making distributions. We may agree to similar restrictions on distributions under future debt instruments we may enter into in connection with future 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 be prohibited 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 conditions contributed to one of our projects not satisfying financial tests required to permit distributions to us during certain quarters of 2017 and also resulted in a requirement that such trapped cash be utilized to prepay certain debt at the project level. The terms of our project indebtedness typically require commencement of commercial operations prior to our ability to receive cash distributions from a project. The terms of any such indebtedness also typically include cash management or 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 the funding 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 a specified 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 tax equity investor begins to receive a greater allocation of distributions until the targeted rate of return has been achieved. In addition, the operating agreements also provide 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 minimum performance 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 certain circumstances 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 the event 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 than expected 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 those projects failing to pass financial tests that measure cumulative cash distributions to the members. This resulted in 2017, and could additionally result in 2018, in a change 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 working capital 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 our ability 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 our Board of Directors and depends on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends, consideration of factors such as our payout ratio, and other considerations that our Board of Directors deems relevant. 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 those reserves 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 able to 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. We must perform system and process evaluation and testing of our internal control over financial reporting to allow management to report on the effectiveness of our internal 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 result in a misstatement of our financial statements), it could adversely affect investor perceptions of our company.  Furthermore, if there was a failure in the effectiveness of our internal controls over financial reporting which results in misstatements in

43


our 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 to sanctions or investigations by the stock exchanges on which we list, the SEC, the Canadian Securities Administrators or other regulatory authorities, and could adversely affect our ability to access the capital markets.
Risks Regarding Our Cash Dividend Policy
While 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 A shares 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 our current 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 risks inherent 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 following factors:
Our revolving credit facility includes customary affirmative and negative covenants that will subject certain of our project subsidiaries to restrictions on making distributions to us. Our subsidiaries are also subject to restrictions on distributions under the agreements governing their respective project-level debt. Additionally, we may incur debt in the future to acquire new power projects, the terms of which will likely require commencement of commercial operations prior to our ability to receive cash distributions from such acquired projects. These agreements also likely will contain financial tests and covenants that our subsidiaries must satisfy prior to making distributions. In the future, we may also enter into debt instruments in connection with note or bond offerings which may also contain restrictions on making distributions. If any of our subsidiaries is unable to satisfy applicable financial tests and covenants or are otherwise in default under our financing agreements, it would be prohibited from making distributions to us, which could, in turn, limit our ability 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 substantial amount 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 projects may change under certain circumstances, and if these circumstances occurred and were adverse, our distributions from such wind facilities may be less than expected. For example, two of our wind facilities with tax equity investors have experienced lower than expected production and merchant power prices resulting in each of those projects failing to pass financial tests that measure cumulative cash distributions to the members. This resulted in 2017 in a change of the cash percentage allocated to the tax equity members which will continue until the shortfall is remedied. See "-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 us under the terms of their indebtedness, or in the event certain specified events occurred under our tax equity arrangements that change the percentage of cash distributions to be made 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 in those 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 of our control, including insufficient cash flow generation by our projects, as well as unexpected operating interruptions, insufficient wind resources, legal liabilities, the cost associated with governmental regulation, changes in governmental subsidies or regulations, increases in our operating or selling, general and administrative expenses, principal and interest payments on our and our subsidiaries’ outstanding debt, tax expenses, working capital requirements and anticipated 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 to other 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 laws relating to continuous disclosure obligations and proxy solicitation if we comply with certain reporting requirements applicable in the United States, provided that the 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 time required by applicable U.S. requirements. In some cases, the disclosure obligations applicable in the United States are different or less onerous than the comparable disclosure requirements applicable in Canada for a Canadian reporting issuer that is not exempt from Canadian disclosure obligations. Therefore, there may be less or different publicly available information about us than would be available if we were a Canadian reporting issuer that is not exempt from such Canadian disclosure obligations.

44


Pattern 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 best interests 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 our company. We are party to the Multilateral Management Services Agreement, pursuant to which each of our executive officers (including our Chief Executive Officer) 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 respective businesses. As a result, these shared executives have fiduciary and other duties to these Pattern Development Companies. Conflicts of interest may arise in the future between our company (including our stockholders other than Pattern Development 1.0), and Pattern Development 1.0 and Pattern Development 2.0 (and their respective owners and affiliates). Our directors and executive officers owe fiduciary duties to the holders of our shares. However, Pattern Development 1.0’s and 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’s and 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 voting power of our shares. The voting power of each of these stockholders may limit other stockholders’ ability to influence corporate matters, and as a result, actions may 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 influence over all matters that require approval by our stockholders, including the election of directors. The interests of these significant stockholders may differ from or conflict 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 to our 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, Pattern Development 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 Management Services Agreement between our company, Pattern Development 1.0, and Pattern Development 2.0, and, as a result, in some instances, have fiduciary or other obligations to such Pattern Development Companies. However, neither our Chief Financial Officer, or Chief Investment Officer, receives compensation from, or has an economic interest in, either Pattern Development 1.0 or Pattern Development 2.0. Additionally, while none of our Chief Executive Officer, Executive Vice President, Business Development, and Executive Vice President and General Counsel, receive compensation from either Pattern Development 1.0 or Pattern Development 2.0, such officers have economic interests in such Pattern Development Companies and, accordingly, the benefit to such Pattern Development Companies from a transaction between such Pattern Development Company and our company will proportionately inure to their benefit as holders of economic interests in such Pattern Development Company. Each of Pattern Development 1.0 and Pattern Development 2.0 are related parties under the applicable securities laws governing related party transactions and, as a result, any material transaction between our company and Pattern Development 1.0 or Pattern Development 2.0 is subject to our corporate governance guidelines, which require prior approval of any such transaction by the conflicts committee, which is comprised solely of independent members of our Board of Directors. Those of our executive officers who have economic interests in Pattern Development 1.0 or Pattern Development 2.0 may be conflicted when advising the conflicts committee or otherwise participating in the negotiation or approval of such transactions. These executive officers have significant project- and industry-specific expertise that could prove beneficial to the conflicts committee’s decision-making process and the absence of such strategic guidance could have a material adverse effect on our company’s ability to evaluate any such transaction and, in turn, on our business prospects, financial condition 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 those in 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 among other things, potential competitive business activities or business opportunities. Riverstone is a private equity firm in the business of making investments in entities primarily in the energy industry. As a result, Riverstone’s existing and future portfolio companies (other than Pattern Development 1.0 and Pattern Development 2.0, which are subject to the Second Amended and Restated Non-Competition Agreement) may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

45


Subject to the terms of the Second Amended and Restated Non-Competition Agreement with, and our respective Purchase Rights granted to us by, each of Pattern Development 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, any business opportunity that may be from time to time presented to Riverstone or any of its officers, directors, agents, stockholders, members or partners or business opportunities 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 or desire 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 or controlling stockholder or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of any 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 our director or officer. In view of Riverstone’s policies and practices with respect to the apportionment of business opportunities presented to the investment funds managed or advised by it and their respective portfolio companies, a business opportunity presented to such fund or portfolio company may generally be pursued by 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 such opportunities 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 business opportunity that may be from time to time presented to Riverstone could adversely impact our business or prospects if attractive business opportunities are procured 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, increase our 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 the acquisition 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 fair and 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 an ownership of approximately 21%. We have established certain governance procedures between ourselves and Pattern Development 2.0 to manage conflicts issues which may arise between ourselves and Pattern Development 2.0, which include having the chair of the conflicts committee, or his designee, attend regularly scheduled meetings of the Pattern Development 2.0 board at which the development pipeline will be reviewed and anticipated funding needs will be discussed, and regular 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 our shares from filing derivative claims against us related to these conflicts of interest and related party transactions. Regardless of the merits of their claims, we may be required to expend significant management time and financial resources on the defense of such claims. Additionally, to the extent we fail to appropriately deal with 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 the then 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 historical rates, 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 increase in 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 A shares 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 the extent 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.

46


The 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 their shares. 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 companies in 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 of terrorism 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 and yieldcos. The changes frequently appear to occur without regard to the operating performance of the affected companies. Hence, the price of our Class A shares could 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 A shares 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 to securities 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 could harm 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 costs associated 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 Wall

47


Street Reform and Consumer Protection Act of 2010, as well as rules implemented by the SEC, the Canadian Securities Administrators and the stock exchanges on which 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. Greater expenditures 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 these requirements 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, the Canadian Securities Administrators, the applicable stock exchanges or other regulatory authorities, which would require additional financial and management resources.
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 1.0 can 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 and outstanding voting securities, and a violation of this limitation could result in civil or criminal penalties under the FPA and possible further sanctions imposed by 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 under the 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 amount of our voting securities sufficient to convey direct or indirect control over any of our public utility subsidiaries or (ii) qualify for a blanket authorization granted under 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 market transactions or otherwise. A purchaser of our voting securities would be a “holding company” under the PUHCA and an electric holding company if the purchaser acquired direct or indirect control over 10% or more of our voting securities or if FERC otherwise determined that the purchaser could directly or indirectly exercise control over our management or policies (e.g., as a result of contractual board or approval rights). Under the PUHCA, a “public-utility company” is defined to include an “electric utility company,” which is any company that owns or operates facilities used for the generation, transmission or distribution of electric energy for sale, and which includes EWGs such as our U.S. operating subsidiaries. Accordingly, absent prior authorization by FERC or an increase to the applicable percentage ownership under a blanket authorization, for the purposes of sell-side transactions by us or Pattern Development 1.0 and buy-side transactions involving purchasers of our securities that are electric holding companies, no purchaser can acquire 10% or more of our issued and outstanding voting securities. 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 in violation to civil or criminal penalties under the FPA, including civil penalties of up to approximately $1.25 million per day per violation (which amount is adjusted 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 thereunder or exemptions therefrom, absent prior authorization by FERC, no purchaser of our Class A common stock in the open market, or in subsequent offerings of our voting securities, will be permitted to purchase an amount of our securities that would cause such purchaser and its affiliate and associate companies to collectively hold 10% or more of our voting securities outstanding. Additionally, investors should manage their investment in us in a manner consistent with FERC’s regulations in respect of obtaining direct or indirect “control” of our company. Accordingly, absent prior authorization by FERC, investors in our Class A common stock 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 with an 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 our management 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 in control 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 discourage a 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 by stockholders 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 also discourage proxy contests and make it more difficult for stockholders to elect directors of their choosing and cause us to take corporate actions other than those desired.
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 or convertible 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 of 9,200,000 Class A shares were sold. We also established an “at-the-market” equity distribution program in May 2016 under which we sold approximately 1.2 million 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 of our Class A shares could decline significantly. Moreover, the perception in the public market that we, Pattern Development 1.0 or another significant stockholder might 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 such loan. 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 been pledged 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 to satisfy 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 entered into 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 6.0 million 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 our Class 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 price of 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 and shares issued in connection with an acquisition) or securities convertible into our shares, or the perception that such sales could occur, may adversely affect prevailing market prices for our Class A shares.
Item 1B.
Unresolved Staff Comments. 
None.  
Item 2.
Properties.
Leased Facilities
Our corporate headquarters and executive offices are located in San Francisco, California and we additionally lease office space in Houston, Texas.
Our Projects
We 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 debt secured 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" in this 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 Act for 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 the REA 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 the portion 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 have agreed 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 proceedings primarily involve claims from landowners related to calculation of land royalties and warranty claims we initiate against equipment suppliers. The outcome of these legal proceedings and claims cannot be predicted with certainty. Nevertheless, we believe the outcome of any of such currently existing proceedings, even if determined adversely, would not have a material adverse effect on our financial condition or results of operations. 
Item 4.
Mine Safety Disclosures.
Not applicable.

49


PART 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 the Toronto Stock Exchange (TSX) under the trading symbol “PEGI.” On February 23, 2018, the last reported sale price of our Class A common stock on the NASDAQ 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
 
Low
Fourth Quarter
 
$
24.94

 
$
20.58

 
$
23.01

 
$
18.68

Third Quarter
 
$
26.56

 
$
22.87

 
$
25.13

 
$
22.27

Second Quarter
 
$
25.42

 
$
19.82

 
$
23.02

 
$
17.70

First Quarter
 
$
21.28

 
$
18.83

 
$
21.01

 
$
14.56

The 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
 
Low
Fourth Quarter
 
C$
30.82

 
C$
26.50

 
C$
30.65

 
C$
25.01

Third Quarter
 
C$
32.57

 
C$
29.66

 
C$
33.00

 
C$
29.01

Second Quarter
 
C$
33.35

 
C$
26.65

 
C$
29.74

 
C$
23.24

First Quarter
 
C$
27.74

 
C$
25.35

 
C$
29.20

 
C$
20.50

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 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 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 of our 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 an aggregate 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 net proceeds under the issuances were $25.3 million.
Holders of Record
Because 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 total number of stockholders represented by these record holders. As of February 23, 2018, there were approximately 15 stockholders of record of our Class A common stock.

50


Stock performance chart
This 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 any filing 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) through December 31, 2017 of the cumulative total stockholder return for our Class A common stock, the NASDAQ Composite Index (NASDAQ Composite) and the Philadelphia 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 Pattern Energy Group Inc., the NASDAQ Composite and the Philadelphia Utility Sector Index and also assumes reinvestments of dividends. The stock price performance of the following graph is not necessarily indicative of future stock price performance.

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12098323&doc=14

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Cash Dividend to Investors
We 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 of Class 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 $1.688 per 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 Declared
2018
 
First Quarter
$
0.4220

2017

Fourth Quarter
$
0.4220

Third Quarter
$
0.4200

Second Quarter
$
0.4180

First Quarter
$
0.4138

2016

Fourth Quarter
$
0.4080

Third Quarter
$
0.4000

Second Quarter
$
0.3900

First Quarter
$
0.3810

We have established our quarterly dividend level based on a targeted cash available for distribution payout ratio, after considering the annual cash available for distribution 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 our business. We intend to grow our business primarily through the acquisition of operational and construction ready power projects, which, we believe, will facilitate the 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 raise capital and make investments in new power projects upon or near the commencement of construction of such projects and therefore prior to the expected commencement 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 flow contributions from such projects to our cash available for distribution. In connection with these investments, we may increase our dividends prior to the receipt of such cash flow contributions, which would likely cause our payout ratio to temporarily exceed our targeted run-rate payout ratio. However, the determination of the amount 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 1ARisk Factors—Risks Related to 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 of such 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 may reserve 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 for distribution, 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 which we do not generate sufficient cash available for distribution to fund our stated quarterly dividend. Although these other sources of cash may be substantial and available to fund a dividend payment in a particular period, we exclude these items from our calculation of cash available for distribution because we consider them non-recurring or otherwise not representative of the operating cash flows we typically expect to generate. See Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Metrics—Cash Available for Distribution."

52


Repurchase of Equity Securities
The table below provides information with respect to repurchases of our Class A common stock during the fourth quarter ended December 31, 2017. All shares were tendered to us in satisfaction of employee tax withholding obligations upon the vesting of restricted stock grants under our 2013 Equity Incentive Award Plan. We currently do not have a stock repurchase plan in place. 
Period
 
Total Number of
Shares Purchased
 
Average Price
Paid Per Share
10/1/17-10/31/17
 

 
$

11/1/17-11/30/17
 

 
$

12/1/17-12/31/17
 
42,666

 
$
21.41

 
 
42,666

 
$
21.41

For information on the equity compensation plans see Item 12 "Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters."


53


Item 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 position and cash flows and should be read in conjunction with the consolidated financial statements and notes thereto and Item 7Management’s Discussion and Analysis of Financial Condition and Results of Operations” presented elsewhere in this Form 10-K. We believe that the assumptions underlying the preparation of our historical 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

 
$
201,573

Operating income (expense)
 
10,259

 
5,311

 
37,105

 
57,593

 
48,393

Net income (loss)
 
(82,410
)
 
(52,299
)
 
(55,607
)
 
(39,999
)
 
10,072

Net 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
)
 
$
16,959

Less: Net income attributable to Pattern Energy prior to the initial public offering 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

 
$
0.31

Deemed 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

 
$
1,872,233

Revolving 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

 
$
1,217,820

Total 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 from other assets to long-term debt. In the table above, prior year presentation of long-term debt reflects the reclassification of deferred financing costs.

54


Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and related notes included elsewhere in this Form 10-K. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number 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 Regarding Forward-Looking Statements."
Overview
We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued 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 owned capacity 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 or a 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 be generated 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 in creating a safe, high-integrity work environment, applying rigorous analysis to all aspects of our business and proactively working with our stakeholders to address environmental and community concerns. Our 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 and maintain a strong balance sheet and flexible capital structure.
Our growth strategy is focused on the acquisition of operational and construction-ready power projects from the Pattern Development Companies and other third parties that, together with measured investments into the development business, we believe will contribute to the growth of our business and enable us to increase our dividend per share of Class A common stock over time. The Pattern Development Companies (Pattern Energy Group LP (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. Our continuing relationship with the Pattern Development Companies, including a 21% interest in Pattern Development 2.0, provides us with access to a pipeline of acquisition opportunities. Currently, the Pattern Development Companies have a more than 10 GW pipeline of development projects, all of which are subject to our right 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 Pattern Development Companies and other third parties 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 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 Estimates

55


Recent Developments
On February 26, 2018, we entered into a series of purchase and sale agreements with Pattern Development 1.0 and Green Power Investments (GPI) to purchase 206 MW of renewable energy projects, consisting of Futtsu Solar, Kanagi Solar, Otsuki, Ohorayama and Tsugaru. The acquisition price for the 84 MW project portfolio (Futtsu Solar, Kanagi Solar, Otsuki and Ohorayama) is approximately $131.5 million, subject to certain closing price adjustments. The acquisition price 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 at closing and approximately JPY12.567 billion payable to Pattern Development 1.0 upon the term conversion of the construction loan and to the extent such term conversion does not occur, such second consideration payment will be made upon the commencement of commercial operations at Tsugaru which is expected in 2020. We expect 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 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 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 Meikle Wind Energy Limited Partnership (Meikle) and 70% of the issued and outstanding shares of Meikle Wind Energy Corp. (Meikle Corp) for a purchase price of approximately $67.4 million, paid at closing, in addition to $1.1 million of capitalized transaction-related expenses. Meikle operates the approximately 179 MW wind 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 (PSP Investments) 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, but not 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 capital calls, this would increase our ownership to approximately 29%. On December 26, 2017, we funded an additional capital call for $7.3 million. In February 2018, we also funded approximately $35.2 million into Pattern Development 2.0 of which approximately $27 million will be used by Pattern Development 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 aggregate amount of approximately $500 million in projects acquired by us under our Project Purchase Rights with the Pattern Development Companies, including investments 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 Pattern Development 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 million contingent upon the commercial operation of the Grady Project. As part of the acquisition, we also assumed $51.2 million of construction debt and accrued interest outstanding at Western Interconnect which was immediately extinguished, and concurrently, we entered into a variable rate term loan for $54.4 million. The Grady Project is a wind project on the Identified ROFO Projects list being separately developed by Pattern Development 2.0 which is expected to begin full construction in 2018, and which intends to interconnect through Western Interconnect. Following the commencement of commercial operations of the Grady Project, at which time 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 continue to provide routine and corrective maintenance service, but we have become responsible for a portion of the maintenance and repairs, including on major component parts.

56


Factors that Significantly Affect our Business
Our 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 number of factors, including trends affecting our industry and factors affecting our operating results as discussed below:
Trends Affecting our Industry
The growth in the industry is largely attributable to renewable energy’s increasing cost competitiveness with other power generation technologies, the advantages of wind and solar power over other renewable energy sources and growing public support for renewable energy driven by energy security and environmental concerns.
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 to traditional 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 to compete 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, notably coal, 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 electricity generation 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 trend will continue.
Our Outlook
Our 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 power sale 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 acquire the Identified ROFO Projects, but we will evaluate unaffiliated third-party asset acquisition opportunities as well. In addition, we will continue to evaluate further investment in Pattern Development 2.0 as discussed below.
Factors Affecting our Operational Results
The 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 Projects
Our electricity sales and energy derivative settlements are primarily determined by the price of electricity and any environmental attributes we sell under our power sale 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 performance of our equipment. We base our estimates of each project’s capacity to generate electricity on the findings of our internal and external experts’ long-term meteorological studies, which include on-site data collected from equipment on the property and relevant reference wind data from other sources, as well as specific equipment power curves and estimates for the

57


performance 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 our meteorological analysis is a probabilistic assessment of a project’s likely output. A P50 level of production indicates we believe a 50% probability exists that the electricity generated from a project will exceed a specified aggregate amount of electricity generation during a given period. While we plan for variability around this P50 production level, it generally provides the foundation for our base case expectation. The variability is measured in a spectrum of possible output levels such 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, while recognizing 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 will experience more variability in monthly or quarterly production than we do for annual production. Therefore, our periodic cash flow and payout ratios will also reflect 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 a stand-alone basis. Due to the geographical separation between our projects, the uncertainty variables and wind speed correlations are diverse enough across the portfolio to provide reduction in the overall uncertainty, which we refer to as the portfolio effect. For example, the sum of our individual projects’ P75 output levels is approximately 93% of the aggregate P50 output level (which is unaffected by the portfolio effect), while the P75 output level, when taking into account the portfolio effect, is approximately 96% of our aggregate P50 output level. On a portfolio basis, our P90 and P95 production estimates for the annual electricity generation of our twenty operating projects (excluding projects in Japan we have agreed to acquire) are approximately 91% and 89%, respectively, of our estimated P50 output levels. The portfolio effect results in an improvement in the production stability across the portfolio. A greater diversity of projects in the portfolio has the 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 of turbines from top manufacturers. With a combination of high-quality equipment and scale and in-house operating capability, we have structured our projects such that we may expect high availability and long-term production from the equipment, develop operating expertise and experience, which can be shared among our operators, obtain a high level of attention and focus from the manufacturers and common operating practices. Given our manufacturers’ global fleet sizes and strong balance sheets, the warranties that we secure for our turbines and our operating approach described below, we are confident in our expectations for reliable long-term turbine operation.
Impact of Derivative Instruments
Where possible, we have sought to protect ourselves against electricity and interest rate exposures with a relatively longer term hedging strategy. We expect to hedge 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 in the future, substantial volatility in the components of our net income that relate to the mark-to-market adjustments on our undesignated energy and interest rate derivatives.
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 the economic value of the related operating or financial assets, such as our wind projects and our project loans, for which the application of accounting principles generally 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 our principal financial objectives is to produce stable and sustainable cash available for distribution, we believe that the economic value to our shareholders reflected in these derivative instruments, outweighs the risk of volatility in net income that we expect to report. Accordingly, we believe it is useful to investors to consider supplemental 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.

58


Project Operations
Turbine Availability
Our 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 use reliable and proven wind turbines and other equipment for each of our projects. For the years ended December 31, 2017 and 2016, our turbine availability across our projects was 97.4% and 96.8% respectively, which is in line with industry standards for original investment projections reviewed by independent engineering firms.
Operations and maintenance - self-perform
In early 2017, we revised long-term turbine manufacturer service arrangements at certain of our projects pursuant to which the turbine manufacturer continues to provide 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 an owner, including self-performing maintenance and service work with our own technicians instead of utilizing service providers, which will have continuing expected cost benefits, but will similarly come with increased risks and reduced third party warranty and guarantee protections. We completed this transition to self-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 Financing
We intend to use a portion of our revenue from electricity sales to cover our subsidiaries’ interest expense and principal payments on borrowings under their respective project financing facilities. Our interest expense primarily reflects (i) imputed interest on the lease financing of our Hatchet Ridge project, (ii) periodic interest on the term loan financing arrangements, including the effects of interest rate swaps, at our other operating projects, (iii) interest on our convertible senior notes issued in 2015 and the Unsecured Senior Notes issued in 2017 and (iv) interest on short-term loan facilities, including any borrowings under our revolving credit 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 generally defined 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 market generally 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, our projects, on a portfolio basis, have an expected average annual debt service coverage ratio over the remaining scheduled loan amortization periods of approximately 2.0 to 1.0.
Congestion in the Texas market
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 transmission system limitations which can result in local prices that are lower than the broader market prices (congestion). In the case of adverse congestion, our revenues are negatively 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 the counterparty (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 past these 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 Cost
In addition to reducing our project expense through restructuring service agreements and a transition to self-perform, we are also focused on measures to reduce our general and administrative expenses, including our net related party charges to and from Pattern Development 1.0. We are investing in a number of efficiency initiatives (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 our material weaknesses in internal controls in 2017 resulted in higher audit, consulting and staffing expenses; however, we anticipate that the consequent changes we make to our control environment together with the efficiency initiatives will reduce certain general and administrative costs starting in 2018.
Acquisitions
Our ability to grow our cash available for distribution is substantially dependent on our ability to make acquisitions. During 2017, our acquisitions of Broadview and Meikle increased our operating capacity by 363 MW or 14%. In addition, the Broadview acquisition included the acquisition of Western Interconnect. Our investment in 2017 and our additional commitment to fund capital calls in Pattern Development 2.0 facilitates additional long-term capital for Pattern Development 2.0 to support the growth in the development pipeline.

59


In 2018, we committed to acquire several entities in Japan which when consummated will increase our project portfolio capacity by 206 MW including 39 MW of solar renewable energy projects. Additionally, we expect to complete the acquisition of MSM, of which our proportionate interest will be 51%, in 2018.
Potential Dispositions
As 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 bids for 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 the strategic 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 we did 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 to report 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 it might 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 other third 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 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
 
104
Belle River
 
Operational
 
Ontario
 
2016
 
2017
 
PPA
 
100
 
43
El Cabo
 
Operational
 
New Mexico
 
2016
 
2017
 
PPA
 
298
 
125
North Kent
 
Operational
 
Ontario
 
2017
 
2018
 
PPA
 
100
 
35
Henvey Inlet
 
In construction
 
Ontario
 
2017
 
2019
 
PPA
 
300
 
150
Pattern Development 2.0 Projects
 
 
 
 
 
 
 
 
 
 
 
 
Stillwater Big Sky
 
Late stage development
 
Montana
 
2017
 
2018
 
PPA
 
79
 
67
Crazy Mountain
 
Late stage development
 
Montana
 
2017
 
2019
 
PPA
 
80
 
68
Grady
 
Late stage development
 
New Mexico
 
2018
 
2019
 
PPA
 
220
 
188
Sumita
 
Late stage development
 
Japan
 
2019
 
2021
 
PPA
 
100
 
55
Ishikari
 
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 at all 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 or Pattern 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 believe we 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 higher return on investment, we may decide to exit Chile for other opportunities with greater potential. In addition, Pattern Development 1.0 is also concurrently exploring strategic alternatives for its assets in Chile.
Investment in Pattern Development 2.0
In December 2016, certain investment funds managed by Riverstone Holdings LLC, which own interests in Pattern Development 1.0, engaged in a transaction in which (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 an Identified ROFO Project) were transferred to a newly formed entity, Pattern Development 2.0, and (b) Pattern Development 1.0 retained the remainder of its assets consisting 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, concurrently

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with the entry into the strategic relationship with PSP Investments, we entered into a series of new arrangements and amendments to existing arrangements with each of Pattern Development 1.0 and Pattern Development 2.0, the purpose of which was to increase opportunities for growth with improved alignment with our core 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 Development 2.0 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 to evaluate the potential benefits and risks of an investment in Pattern Development 2.0. Strategic benefits include a strengthened link to Pattern Development 2.0's development pipeline and increased return on investment expectations commensurate with increased development risk. To the extent we invest in Pattern Development 2.0, we will be initially exposed to capital requirements prior to having certainty that a project can move forward. As projects are successfully completed, we anticipate that our return on our capital investment will increase. However, there are risks in project development that we have not yet been exposed to including, but not limited to, permitting challenges, failure to secure PPAs, failure to procure the requisite financing, equipment or interconnection, or an inability to satisfy the conditions to effectiveness of project agreements such as PPAs.

Key Metrics
We regularly review a number of financial measurements and operating metrics to evaluate our performance, measure our growth and make strategic decisions. In addition to traditional U.S. GAAP performance and liquidity measures, such as total revenue, cost of revenue, net loss and net cash provided by operating activities, we also consider cash available for distribution as a supplemental liquidity measure and Adjusted EBITDA, MWh sold and average realized electricity price in evaluating our operating performance. We 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 by investors and analysts to evaluate our liquidity. We disclose Adjusted EBITDA, which is a non-U.S. GAAP measure, because management believes this metric assists investors and analysts in comparing our operating performance across reporting periods on a consistent basis 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 Metrics
We 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 by investors 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 other liquidity 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 cash available 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 our operating performance across reporting periods on a consistent basis by excluding items that our management believes are not indicative of our core operating performance. 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;

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does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our debt, or our proportional interest in the interest expense of our unconsolidated investments or the cash requirements necessary to service interest or principal payments 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 unconsolidated investments 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, amortization and accretion of our unconsolidated investments. The assets being depreciated, amortized and accreted will often have to be replaced in the future, 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-market adjustments 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 venture partners. As we do not control, but do exercise significant influence, we account for the unconsolidated investments in accordance with the equity method of accounting. Net earnings from these investments are reflected within our consolidated statements of operations in "Earnings in unconsolidated investments, net." Adjustments related to our proportionate share from unconsolidated investments include only our proportionate amounts of interest expense, 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 with U.S. GAAP.
Cash Available for Distribution
We define cash available for distribution as net cash provided by operating activities as adjusted for certain other cash flow items that we associate with our operations. 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 are paid 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 cash flows 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 were derived 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.

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The most directly comparable U.S. GAAP measure to cash available for distribution is net cash provided by operating activities. The following table is a reconciliation 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
 
2015
Net cash provided by operating activities (1)
 
$
217,613

 
$
163,664

 
$
117,849

Changes in operating assets and liabilities
 
(31,568
)
 
(11,000
)
 
(6,880
)
Network upgrade reimbursement
 
9,282

 
4,821

 
2,472

Release of restricted cash to fund project and general and administrative costs
 
7,239

 
640

 
1,611

Operations and maintenance capital expenditures
 
(783
)
 
(1,017
)
 
(779
)
Distributions from unconsolidated investments
 
13,358

 
41,698

 
34,216

Reduction of other asset - Gulf Wind energy derivative deposit
 

 

 
6,205

Other
 
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 on investment.
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 million increase 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 the Unsecured 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 million increase 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 were acquired 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 due to 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.

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These 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 EBITDA
We define Adjusted EBITDA as net income (loss) before net interest expense, income taxes, and depreciation, amortization and accretion, including our proportionate share of net interest expense, income taxes, and depreciation, amortization and accretion of unconsolidated investments. Adjusted EBITDA also excludes the effect of certain mark-to-market adjustments and infrequent items not related to normal or ongoing operations, such as early payment of debt, realized derivative gain or loss from refinancing transactions, gain or loss related to acquisitions or divestitures, and adjustments from unconsolidated investments. In calculating Adjusted EBITDA, we exclude mark-to-market adjustments to the value of our derivatives because we believe that it is useful for investors to understand, as a supplement to net income (loss) and other traditional measures of operating results, the results of our operations without regard to periodic, and sometimes 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 distributions in 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, we record gains resulting from such excess distributions in the period the distributions occur. Additionally, when our carrying value in an unconsolidated investment is zero 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 Adjusted EBITDA for the periods presented (unaudited and in thousands):
 
 
Year ended December 31,
 
 
2017
 
2016
 
2015
Net loss
 
$
(82,410
)
 
$
(52,299
)
 
$
(55,607
)
Plus:
 
 
 
 
 
 
Interest expense, net of interest income
 
100,687

 
76,598

 
75,309

Tax provision
 
11,734