Pattern Energy 10-K 2013 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2013.

-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 Market Toronto Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

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  x

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  x    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  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and” “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	x	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.)    Yes  ¨    No  x

As of June 28, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, there was no established public market for registrant’s common stock. The registrant’s Class A common stock began trading on the NASDAQ Global Market under the symbol “PEGI” and on the Toronto Stock Exchange under the symbol “PEG” on October 2, 2013.

On February 25, 2014, the registrant had 35,548,051 shares of Class A common stock outstanding, $0.01 par value, and 15,555,000 shares of Class B common stock outstanding, $0.01 par value.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement relating to its 2014 annual meeting of stockholders (the “2014 Proxy Statement”) are incorporated by reference into Part III of this Form 10-K where indicated. The 2014 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

	PART I
Item 1.	Business.	5
Item 1A.	Risk Factors.	25
Item 1B.	Unresolved Staff Comments.	50
Item 2.	Properties.	50
Item 3.	Legal Proceedings.	56
Item 4.	Mine Safety Disclosures	56
	PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters.	57
Item 6.	Selected Financial Data.	61
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	62
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	94
Item 8.	Financial Statements and Supplementary Data.	94
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	94
Item 9A.	Controls and Procedures.	94
Item 9B.	Other Information.	95
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance.	96
Item 11.	Executive Compensation.	96
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	96
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	96
Item 14.	Principal Accounting Fees and Services.	96
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	97

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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. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in Part I, Item 1A “Risk Factors.”

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.

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:

• “Conversion Event” refers to the event pursuant to which all of our Class B shares will automatically convert into Class A shares on a one-for-one basis upon the later of December 31, 2014 and the date on which our South Kent project has achieved “Commercial Operations.” “Commercial Operations” refers to the date upon which our South Kent project has achieved commercial operations under its power purchase agreement;

• “FERC” refers to the U.S. Federal Energy Regulatory Commission;

• “FIT” refers to feed-in-tariff regime;

• “FPA” refers to the Federal Power Act;

• “Gulf Wind Call Right” refers to the right to acquire the Pattern Development retained Gulf Wind interest at any time between the October 2, 2014 and October 2, 2015, at its then current fair market value;

• “Initial ROFO Projects” refers to six projects that we identified at the time of our initial public offering as development projects, each owned by Pattern Development and subject to our Project Purchase Right, that were predominantly operational or construction ready, including the Gulf Wind, Grand, Panhandle, Armow, K2 and Meikle projects;

• “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;

• “JOBS Act” refers to Jumpstart Our Business Startups Act of 2012;

• “Management Services Agreement” refers to the bilateral services agreement between us and Pattern Development;

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• “MW” refers to megawatts;

• “MWh” refers to megawatt hours;

• “Non-Competition Agreement” refers to a non-competition agreement between us and Pattern Development pursuant to which Pattern Development agrees that, for so long as any of our Purchase Rights are exercisable, it will not compete with us for acquisitions of power generation or transmission projects from third parties;

• “OCC” refers to our operations control center;

• “Pattern Development” refers to Pattern Energy Group LP and its subsidiaries (other than us and our subsidiaries);

• “Pattern Development’s retained Gulf Wind interest” refers to the retained interest of approximately 27% in the Gulf Wind project, owned by Pattern Development;

• “power sale agreements” refers to PPAs and/or hedging arrangements, as applicable;

• “PPAs” refers to power purchase agreements;

• “Project Purchase Right” refers to a right of first offer with respect to any power project that Pattern Development decides to sell, including the Initial ROFO Projects;

• “PTCs” refers to production tax credits;

• “PUHCA” refers to the Public Utility Holding Company Act of 2005, as amended;

• “Purchase Rights” refers to the Project Purchase Rights, and the rights to acquire the Pattern Development retained Gulf Wind interest, and the right to acquire Pattern Development itself or substantially all of its assets, as contemplated by the Purchase Rights Agreement between us and Pattern Development;

• “RECs” refers to renewable energy credits;

• “reintegration event” refers to the event contemplated by the Management Services Agreement pursuant to which, upon the completion of the first 20 consecutive trading day period during which our total market capitalization is no less than $2.5 billion, the employees of Pattern Development will become our employees;

• “Riverstone” refers to Riverstone Holdings LLC;

• “RPS” refers to Renewable Portfolio Standards;

• “Sarbanes-Oxley Act” refers to the Sarbanes-Oxley Act of 2002;

• “Shared PEG Executives” refers to certain of our executive officers, including our Chief Executive Officer, who will also serve as executive officers of Pattern Development and devote their time to both our company and Pattern Development as is prudent in carrying out their executive responsibilities and fiduciary duties;

• “Samsung” means Samsung C&T Corporation;

• “U.S. Treasury” refers to the U.S. Department of the Treasury.

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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. Including the Panhandle 2 project which we have agreed to acquire from Pattern Development, and which we expect to acquire before the end of 2014, we own interests in ten wind power projects located in the United States, Canada and Chile that use proven, best-in-class technology and have a total owned capacity of 1,255 MW, consisting of six operating projects and four projects under construction. We expect that our four construction projects will all commence commercial operations prior to the end of the fourth quarter of 2014. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price power sale agreement with a creditworthy counterparty. Ninety-three percent of the electricity to be generated by our projects will be sold under these power sale agreements which have a weighted average remaining contract life of approximately 18 years.

We intend to use a substantial portion of the cash available for distribution generated from our projects to pay regular quarterly dividends to holders of our Class A shares. Our quarterly dividend has initially been set at $0.3125 per Class A share, or $1.25 per Class A share on an annualized basis. We have established our initial quarterly dividend level based on a target payout ratio of approximately 80% after considering our expected sustainable cash flow to be generated from our operating projects together with the impact of the Class A shares to be issued upon the Conversion Event and the additional cash available for distribution that we estimate our construction projects will generate. The declaration and amount of our initial and future dividends, if any, will be subject to our actual earnings and capital requirements and the discretion of our Board of Directors.

Our growth strategy is focused on the acquisition of operational and construction-ready power projects from third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per Class A share over time. We expect that our continuing relationship with Pattern Development, a leading developer of renewable energy projects, will be an important source of growth for our business.

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:

• creating a safe, high-integrity, exciting 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

• proactively working 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.

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; and

• maintain a strong and flexible capital structure.

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Our Projects

The following table provides an overview of our projects:

Location and Start-up

Capacity (MW)

Power Sale Agreements

Projects

Location

Construction Start(1)

Commercial Operations(2)

Rated(3)

Owned(4)

Type

Contracted Volume(5)

Counterparty

Counterparty Credit Rating(6)

Expiration

Operating Projects

Gulf Wind

Texas

Q1 2008

Q3 2009

283

113

Hedge

(7)

~58

%

Credit Suisse Energy LLC

A/A1

2019

Hatchet Ridge

California

Q4 2009

Q4 2010

101

101

PPA

100

%

Pacific Gas & Electric

BBB/A3

2025

St. Joseph

Manitoba

Q1 2010

Q2 2011

138

138

PPA

100

%

Manitoba Hydro

AA/Aa1(8)

2039

Spring Valley

Nevada

Q3 2011

Q3 2012

152

152

PPA

100

%

NV Energy

BBB+/Baa2

2032

Santa Isabel

Puerto Rico

Q4 2011

Q4 2012

101

101

PPA

100

%

Puerto Rico Electric Power Authority

BBB/Baa3

2037

Ocotillo(9)

California

Q3 2012

Q4 2012

223

223

PPA

100

%

San Diego Gas & Electric

A/A1

2033

Q2 2013

42

42

PPA

100

%

San Diego Gas & Electric

A/A1

2033

1,040

870

Construction Projects

South Kent

Ontario

Q1 2013

Q2 2014

270

135

PPA

100

%

Ontario Power Authority

AA-/Aa2(10)

2034

El Arrayán

Chile

Q3 2012

Q2 2014

115

36

Hedge

(11)

~74

%

Minera Los Pelambres

NA

2034

Grand

Ontario

Q3 2013

Q4 2014

149

67

PPA

100

%

Ontario Power Authority

AA-/Aa2(10)

2035

Panhandle 2(12)

Texas

Q4 2013

Q4 2014

182

147

Hedge

(13)

~80

%

Morgan Stanley

A-/Baa2

2024+

716

385

1,756

1,255

⁽¹⁾  Represents date of commencement of construction.

⁽²⁾  Represents date 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 wind and other conditions, a project or a turbine will not operate at its rated capacity at all times and the amount of electricity generated will be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors discussed elsewhere in this Form 10-K. See Item 1A “Risk Factors.”

⁽⁴⁾  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.

⁽⁵⁾  Represents the percentage of a project’s total estimated average annual MWh of electricity generation contracted under power sale agreements.

⁽⁶⁾  Reflects the counterparty’s corporate credit ratings issued by S&P/Moody’s as of December 31, 2013. Subsequent to December 31, 2013, PREPA, the Puerto Rican counterparty, was downgraded to Ba2 by Moody’s.

⁽⁷⁾  Represents a 10-year fixed-for-floating power price swap. See Item 2 “Properties—Gulf Wind.”

⁽⁸⁾  Reflects the corporate credit ratings of the Province of Manitoba, which owns 100% of Manitoba Hydro-Electric.

⁽⁹⁾  We initially commenced commercial operations on 223 MW of electricity generating capacity in the fourth quarter of 2012 and commenced commercial operations on the remaining 42 MW of electricity generating capacity from Ocotillo’s additional 18 turbines in July 2013.

⁽¹⁰⁾  Reflects the corporate credit ratings of the Province of Ontario, which owns 100% of the Ontario Power Authority.

⁽¹¹⁾  Represents a 20-year fixed-for-floating swap. See Item 2 “Properties—Construction Projects—El Arrayán.”

⁽¹²⁾  The Panhandle project was separated into a separate Panhandle 1 project, with an owned capacity of 179 MW, and the Panhandle 2 project, with an owned capacity of 147 MW; acquisition of Panhandle 2 pending, scheduled to close in the fourth quarter of 2014.

⁽¹³⁾  Represents a fixed-for-floating swap of more than ten years duration. See Item 2 “Properties—Construction Projects—Panhandle 2.”

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Each of our projects has gone through a rigorous vetting process in order to meet our investment and our lenders’ financing criteria. The development of each project was managed and overseen by our management team over a period of several years and each project was designed to meet or exceed industry, environmental, community and safety standards applicable for industrial-scale power projects. As a result, our projects generally have the following characteristics:

• multi-year on-site wind data analysis tied to one or more long-term wind energy reference sources. Pattern Development employs a full-time, five-person meteorological team that manages and verifies third party wind analysis. Our wind analysis is carefully vetted through detailed studies by internal and independent experts in meteorology and statistics to derive an expected production profile based on daily and seasonal wind patterns, structural interference, topography and atmospheric conditions. Our average on-site wind data collection is over four years (or approximately seven years including post-construction data collection);

• long-term power sale agreement designed to ensure a predictable revenue stream. As is typical in our industry, we sell our electricity at a fixed price on a contingent, as-produced basis such that only the electricity that we generate is sold to and must be purchased by the counterparty at the agreed price. Our power sale agreements have a weighted average remaining contract life of approximately 18 years;

• contractually secured real estate property and easement rights for a period well in excess of the project’s expected useful life and contractual obligations. Each of our projects has land rights for 30 years or more;

• a firm right to interconnect to the electricity grid through interconnection agreements, which defines the cost allocation and schedule for interconnection, as well as any upgrades required to connect the project to the transmission system. Our interconnection agreements allow our projects to connect to the electricity transmission system. Market rules and protocols generally govern dispatch of our electricity generation and allow it to flow freely into the grid as it is produced, except in very limited circumstances where our projects can be curtailed, for example during system emergencies. To date, our projects have on average been curtailed less than 1% per year;

• long-term, limited-recourse, amortizing project financing designed to match the long-lived nature of our power projects and the related power sales agreements. The interest rates on our long-term loans are fixed for the tenor of the loans or are subject to fixed-for-floating swaps that match the amortization schedules of the debt;

• all necessary construction and operating permits and other requisite federal, state or provincial and local permits, and regulatory approvals secured, which critical permits typically include federal aviation, state or provincial environmental approvals and local zoning and land-use permits and are designed to protect the community, cultural resources, plants, animal and other affected resources at or near the facility;

• fixed-price turbine supply and construction contracts with guaranteed completion dates to ensure that our projects are completed on time and within the estimated budget. The construction period for our projects has typically been less than one year, although in certain instances circumstances warrant a longer construction period;

• an operations and maintenance service program based on our own on-site personnel and central operations management as well as equipment warranties and service arrangements with qualified contractors experienced in wind project maintenance. We have existing equipment warranties for approximately 77% of our operating turbine units; and

• safety, environmental and community programs to support our existing projects and relationships in the communities in which we operate.

For additional information regarding each of our projects, see Item 2 “Properties.” Our ability to transition each of our construction projects to commercial operations and achieve anticipated power output at all of our operating projects is subject to numerous risks and uncertainties as described under Item 1A “Risk Factors.”

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Our Strategy

We intend to make profitable investments in environmentally responsible power projects, while embracing a long-term commitment to the communities in which we operate. 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 revenues 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 PPA 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, if 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 but to contract with reliable third parties for on-going major maintenance of our turbines and similar specialized services such as repairs on our substations or transmission lines. As a result, we have and expect to continue to employ on-site personnel, maintain a 24/7 OCC to monitor our projects and control all critical aspects of commercial asset management. We also believe it is important to invest in our employees to give our operating personnel the tools to pursue our objectives through regular training, performance incentives, integrating teams of different experts, use of advanced software programming and regular upgrading of our automated systems. See Item 1 “Business—Organization of Our Business.”

Completing Our Construction Projects on Schedule and Within Budget

We intend to promote the success of our business by completing our construction projects on schedule and within budget, transitioning projects under construction to commercial operation on a timely basis and efficiently operating our projects to maximize project revenues and minimize operating costs. Including the Panhandle 2 project which we have agreed to acquire from Pattern Development, and which we expect to acquire before the end of 2014, our construction projects consist of interests in four projects that we expect will contribute an additional owned capacity of 385 MW in 2014, for an aggregate of 1,255 MW together with our currently operating projects.

We utilize experienced, creditworthy contractors and proven technology to build high-quality power projects. In addition, over the past 11 years, our management team has overseen the construction and commencement of commercial operations of 25 wind power projects, and our project and construction management capabilities are well respected throughout our industry. By capitalizing on these significant construction and operational resources available to us, including those available to us through the Management Services Agreement, we intend to complete the construction and commence commercial operations at our construction projects in accordance with construction schedules and within budget.

Maintaining a Prudent Capital Structure and Financial Flexibility

We intend to maintain a conservative approach to our capital structure to protect our ability to pay regular dividends and fund investments to provide for future growth. Power projects by their nature require significant up front capital investment and as a result we believe it prudent to match these long-lived assets with long-term debt and/or equity. The average maturity of our project-level debt is approximately 13 years and we have an expected average annual debt service coverage ratio over the remaining scheduled loan amortization periods of approximately 1.7 to 1.0. This prudent capital structure coupled with our predictable price for our electricity and our standard operations and maintenance programs help to achieve a stable cash flow profile.

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Consistent with our existing indebtedness, we expect to typically utilize fixed-rate indebtedness (or swapping any variable rate indebtedness) with strong debt service coverage ratios to finance projects. 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 Pattern Development and other developers enable us to best support our existing projects and will help us access attractive, construction-ready projects. For example, by working closely with the regulatory agencies and the community, we believe that we create an environment within which if problems are identified we can work constructively and efficiently to resolve the problems and minimize the impact to our operations.

Selectively Growing Our Business

Our strategy for growth is focused on the acquisition of operational and construction-ready power projects from Pattern Development and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per Class A share 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 new opportunities will arise from our relationship with Pattern Development, which provides us with the opportunity to acquire projects that it successfully develops and efficiently completing construction and achieving commercial operations at these projects. At the time of our initial public offering, we identified six projects at Pattern Development with an aggregate owned capacity of 746 MW as the Initial ROFO Projects. Pattern Development subsequently increased the owned capacity of the Panhandle project by 78 MW to 326 MW, which includes the Panhandle 1 project, with an owned capacity of 179 MW, and the Panhandle 2 project, with an owned capacity of 147 MW. We agreed in December 2013 to acquire two of the Initial ROFO Projects, Grand and Panhandle 2, with an aggregate owned capacity of 212 MW. The remaining Initial ROFO Projects represent a total Pattern Development-owned capacity of 610 MW, and our Gulf Wind Call Right and Project Purchase Right will provide us the initial opportunity to purchase these projects, as well as any other of the currently owned and future construction-ready power projects that Pattern Development intends to sell.

Our management team will rigorously review and analyze new market opportunities and selectively consider opportunities offered by Pattern Development as well as those offered by other third parties, either independently or jointly with Pattern Development. We believe our management team provides us with the experience to bring both currently owned and subsequently acquired domestic and international power projects online.

Reintegration of Pattern Development Employees

Under the terms of the Management Services Agreement, upon the completion of the first 20 consecutive trading day period during which our total market capitalization is no less than $2.5 billion, the employees of Pattern Development will become our employees. We refer to this event as the employee reintegration. For the purposes of determining the employee reintegration date, total market capitalization will be determined by multiplying the number of our issued and outstanding Class A shares (assuming all of our then outstanding Class B shares had converted into Class A shares prior to such date) and the closing price of our Class A shares

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as reported on the then primary stock exchange on which our Class A shares are listed. We will not be required to make any payments to Pattern Development upon the occurrence of the employee reintegration, other than the payment of any statutory severance payments that may as a result be due and payable to Canadian and Chilean employees who may be employed at that time. The employee reintegration will result in our complete internalization of the administrative, technical and other services that were initially provided to us by Pattern Development under the Management Services Agreement. The occurrence of the employee reintegration will neither alter our Purchase Rights nor the terms of the Management Services Agreement.

Upon the employee reintegration, we expect that our principal focus will continue to be owning operational and under-construction power projects. However, the employee reintegration is expected to enhance our long-term ability to independently develop projects and grow our business. Following the employee reintegration, we will continue to provide management services to Pattern Development (including services from the reintegrated departments of Pattern Development) to the extent required by Pattern Development’s remaining development activities, and Pattern Development will continue to pay us for those services primarily on a cost reimbursement basis.

Competitive Strengths

We believe our key competitive strengths include:

Our High-Quality Projects

We believe our high-quality projects are better positioned to generate stable long-term cash flows compared to typical projects in the industry and will generate available cash in excess of our initial dividend level, providing us the financial resources for investing in new opportunities. Having high-quality projects also provides us access to low-cost project-level debt and strong stakeholder relationships. The key attributes and strengths of our projects are:

Long-Term, Fixed-Price Power Sale Agreements. We believe our long-term, fixed-price power sale agreements with nine distinct creditworthy counterparties will deliver stable long-term revenues, although we note on February 10, 2014 the credit rating of PREPA, the Puerto Rican counterparty, was downgraded. Our power sale agreements cover 93% of the electricity to be generated across our projects with a weighted average remaining contract life of approximately 18 years.

Geographically Diverse Markets and Wind Regimes. Our geographically diverse projects are located across regions generally characterized by high demand for renewable energy, documented reliable wind resources, deregulated energy markets and favorable renewable energy policies. The geographic diversity of our projects—from California to Puerto Rico, and Manitoba to Chile—helps insulate us against regional wind fluctuations as well as adverse regulatory conditions in any one jurisdiction.

State-of-the-Art Wind Turbine Technologies. Our projects utilize state-of-the-art, proven, reliable wind turbine technologies. Our projects utilize Siemens 2.3 MW and Mitsubishi MWT95/2.4 wind turbines, some of the most reliable and proven turbine technologies available in the market. The wind turbines were in each case specifically selected for the site conditions to ensure optimal performance and longevity of the machines. Our turbines have an average asset age of less than two and a half years.

Our Strong Reputation in the Industry

We believe the success of our team has created a highly respected organization which attracts talented people and new opportunities. Our integrity, expertise, and solutions-oriented approach is attractive to stakeholders and parties providing services to our existing projects as well as those who are looking for buyers of their assets.

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Our Spring Valley project received the Wind Project of the Year Award in 2012 from POWER-GEN International (the publisher of Power Engineering and Renewable Energy World), which we believe is considered among the most prestigious awards in the renewable energy industry. Our El Arrayán project also won two Chilean International Renewable Energy Awards, presented at the Chilean International Renewable Energy Congress (CIREC) 2012 annual conference in Santiago. The awards were the Best Renewable Energy Project in 2012 (Mejor proyecto de Energía Renovable de 2012) and the Best Renewable Energy Joint Venture (Mejor colaboración entre dos empresas). In 2013, our Ocotillo project received an award for its outstanding environmental analysis and documentation from the California Association of Environmental Professionals and also received the Renewable Project Finance Deal of the Year award from Power Finance & Risk published by Power Intelligence. Also in 2013, our Santa Isabel project won the Outstanding Project of the Year Award in Land Surveying and Environmental Engineering from the Professional College of Engineers and Land Surveyors of Puerto Rico.

Our Approach to Project Selection

Our approach to project selection aims to deliver superior financial results and minimize long-term operating risks by focusing on the acquisition of projects that are operational or construction-ready and have long-term power sales agreements with creditworthy counterparties. Once we identify an attractive opportunity, we apply rigorous analysis in a timely, disciplined and functionally integrated manner to evaluate the wind regime, technology options, site design improvement, regional market trends and regulatory, financial and legal constraints. The most attractive projects offer the proper combination of land accessibility, power transmission capacity, attractive power sales markets and favorable and dependable winds. We believe the members of our management team are recognized by their industry peers as skilled in identifying, analyzing and executing successful power project acquisitions.

Our approach to project selection has also enabled us to successfully execute new projects in a complex renewable energy market characterized by economic, political and regulatory changes that affect energy investment opportunities. Examples include the cyclical nature of U.S. federal incentives and the challenge of realizing the full value of these incentives, increasing environmental and permitting concerns, reduced PPA opportunities that are influenced by changing power markets, a cyclical wind turbine supply environment that alternates between tight and loose supply constraints, changes in wind turbine technology, changes in availability of debt markets, and changes in electricity market structure. Our management team has had success in identifying and executing attractive acquisitions through all of these changing circumstances. For example, through our innovative approach to our business, we developed a financial structure to realize value for PTCs, implemented ground-breaking radar technology to protect bird and bat populations, became one of the first IPPs to capture value from a number of newly deregulated markets and found long-term debt solutions even when the debt markets were highly constrained.

As a fundamental principle, we seek to acquire projects that will contribute measurable improvements in our Adjusted EBITDA and our cash available for distribution and that will have a risk profile consistent with our current business objectives. In addition, we view projects as long-term partnerships with all stakeholders, and the benefits that we pledge to the community are fundamental to creating a positive environment for a project’slong-term success. This has frequently resulted in community benefits on some of our projects that exceed market expectations and occasionally in decisions to cancel projects where our management team felt that we could not adequately address stakeholder concerns.

Our Relationship with Pattern Development

Our continuing relationship with Pattern Development provides us with access to a pipeline of acquisition opportunities. We believe Pattern Development’s ownership position in our company incentivizes Pattern Development to support the successful execution of our objectives and business strategy, including through the

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preparation of projects to the stage where they are construction-ready. Pattern Development has a dedicated development team of professionals with significant experience across the spectrum of power project development:

• site selection;

• meteorological and market analysis;

• land acquisition;

• transmission rights;

• power contract negotiation;

• project financing;

• construction management;

• government relations;

• community outreach; and

• environmental permitting.

Pattern Development also has teams devoted to engineering, legal and project financing that enable it to develop and construct projects through to commercial operations. We believe Pattern Development’s focus on project development combined with our Project Purchase Right will complement our acquisition strategy, which focuses on the identification and acquisition of operational and construction-ready power projects.

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Our Proven Management Team

Our proven management team has extensive experience in all aspects of the independent power business, a demonstrated track record of success in power project investment management, operation and construction. Our and Pattern Development’s management teams include professionals who have a history of financial and technological innovation in the power industry as well as a proven track record in managing energy assets during both periods of growth and economic challenge. While working together at Pattern Development and prior to its formation, members of our management team were responsible for, and successfully financed and managed, over $12 billion of infrastructure assets, including over 3,000 MW of wind power projects (representing a wind business compound annual growth rate, or “CAGR” of 34% from 2003 to 2014, measured by cumulative wind MW installed), several independent transmission projects and other conventional power assets. Before forming Pattern Development in 2009, our and Pattern Development’s management teams developed, financed, constructed or acquired and operated 2,100 MW of wind power projects, as well as transmission projects and other power projects. Since the formation of Pattern Development in 2009, the Pattern Development management team has acquired and developed the operational and in-construction wind power projects that comprise our owned capacity of 1,255 MW, representing a CAGR of 51%, and more than a 3,000 MW portfolio of development assets, which we will have preferential rights to acquire as described above in Item 1 “Business—Our Relationship with Pattern Development.” Additionally, our and Pattern Development’s management teams have extensive acquisition, finance and commodity-hedging expertise, allowing us to react to opportunities, optimize our capital structure and manage risk. We believe our and Pattern Development’s management teams’ extensive experience and involvement in bringing domestic and international power and infrastructure projects, from the initial development stage through financing to on-going operations and maintenance, positions us to operate our projects efficiently and generate strong cash available for distribution.

Organization of Our Business

Our business is organized around our current projects. In the future, we expect that our business will include additional operating and construction-ready projects acquired from Pattern Development and other third parties. In addition to our executive officers, we employ 34 full-time staff in two key functional areas associated with operations and maintenance and commercial management. We rely on some services to be performed by third parties, including Pattern Development, but have all the core functions required for overseeing constructing, operating and managing of our projects.

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Operations and Maintenance

Our operations team’s objective is to maximize revenues from each of our projects rather than focus solely on technical plant performance metrics. In order for us to maximize our revenues, we seek to operate and maintain our equipment so that we can ensure our equipment is productive during times of optimal wind resources and power prices. Our approach to achieving efficient operations involves the following key strategic objectives;

• Safety. We believe that the safety of our workers, our contractors, our visitors and the community is paramount and takes precedence over all other aspects of operations. To date, we have not experienced any serious lost-time incident or worksite accidents at any of our sites. We achieve this through promoting a strong safety culture, implementing a formal safety management program, employing a full time in-house safety program manager and conducting annual site safety audits.

• Equipment reliability and fleet management. We have selected high-quality equipment with a goal of having a concentration of equipment from top manufacturers. We employ the Siemens 2.3 MW turbine at nine of our ten project sites and the Mitsubishi MWT95/2.4 at the tenth. With a combination ofhigh-quality equipment and scale, we have structured our fleet 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 manufacturer; and

• maintain a shared spare parts inventory and common operating practices.

• Long-term service and maintenance. Good operating performance begins with a long-term maintenance approach to the equipment. While approximately 77% of our operating turbine units remain under warranty, on-going maintenance and replacement of parts is essential to equipment longevity. All of our wind turbines are managed under service agreements that ensure regular repair and replacement of parts. In some situations, we conduct competitive solicitations between the manufacturers as well as top-tier, third-party, independent service providers for conducting wind turbine service and maintenance. As a matter of operating practice, our turbine service program typically does not require shut down of the entire facility and is performed around the project’s production profile to minimize lost revenue.

• Inspection. As our warranty contracts and service arrangements expire, we conduct extensivethird-party end of warranty inspections to identify any potential equipment or service issues which can be remedied by the manufacturer pursuant to their contractual obligations under the warranty and ensure the projects start their post-warranty periods with reliably functioning equipment.

• Staff training. We employ highly experienced personnel from a variety of power generation sectors. In addition, we bring into the organization a broad base of best industry practices. After hiring, we provide our operators with on-going training, in-house and from manufacturers and from third parties, to keep them current on latest industry practices and experiences.

• Focus on our value-added capabilities. In order to maximize efficiencies, we concentrate our resources on our core operating areas. In particular, we believe it is critical to have on-site management personnel that are our employees and provide oversight of all site activities to assure our safety and financial objectives have priority. We contract with third parties, often the turbine manufacturer, for on-going major maintenance of the turbines and similar specialized services such as repairs on our substations or transmission lines.

• Maximize structural efficiencies. Our operating resources are allocated across three key areas, site operations, our 24/7 OCC and other central support services.

• Site-operators. All of our projects have on-site operators, which allows for direct management of the projects and all contractors working on site. In addition, these individuals also strive for a high

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level of involvement in the communities we serve, including with respect to our power purchasers, the regulatory agencies and local communities. Each of our projects has the latest, state-of-the-art supervisory control and data acquisition systems that help us efficiently assess operating faults and plan preventative maintenance.

• 24/7 Operations Control Center. Our OCC, located in Houston, Texas, focuses on monitoring and controlling each wind turbine to prevent downtime, monitoring regional and local climate, tracking real time market prices and, for some of our projects, monitoring certain environmental activities. In addition, the OCC supports various other central activities such as safety, power marketing, and regulatory compliance and maintains constant communications with each of our site operators, which frees our site operators to concentrate on day-to-day equipment and safety activities.

• Central Support Services. In addition to our OCC, our Houston office also hosts the balance of our operations organization which provides critical support to the operating projects. This team includes our operations management team and specialists in safety, environmental management, regulatory compliance, contract management, turbine specialists and asset administration.

• Equipment improvements. We believe that our foundation of reliable and proven equipment allows us to make further operating improvements over time. For example, we are in continuing discussions with Siemens and other innovative suppliers regarding potential equipment improvement to our projects, which could include retrofitting our blades with vortex generators and dino tails to improve the shape of the power curve, or software adjustments, such as increasing the cut-out speed and allowing continued operation through higher wind periods, or power curve clipping to minimize noise anomalies. We continuously evaluate new technologies to identify promising solutions which will improve our projects’ performance and increase our electricity generation.

Commercial Management

Our commercial management group is tasked with protecting the long-term value of our projects’ commercial arrangements. We have adopted a commercial strategy of managing our projects and other assets with an in-house commercial management group acting as “owner’s representatives.” The role of the commercial management group is to oversee contract management, environmental management, community relations, power marketing and finance and to closely monitor the performance of each project from an owner’s point of view in order to maximize financial performance and minimize risk. Although the commercial management group manages the day-to-day aspects of commercial management, functional and managerial expertise is often brought in to support key areas such as legal, finance and power marketing.

• Contract Management. With a group of seasoned managers, our commercial management group optimizes the commercial performance of our assets, services the project debt, manages project agreements and compliance with relevant laws, regulations and rules and has ultimate responsibility for the financial performance of each project. The team also manages our real estate obligations as well as our corporate insurance program, local government obligations, home office, remote facilities and mobile assets. Our commercial management group also facilitates a seamless transfer of responsibilities from the development team through construction to commercial operations in order to ensure all contractual and regulatory obligations are clearly captured and tracked in a formal compliance program.

• Environmental Management and Community Relations. Adaptive environmental management is increasingly the standard by which power projects are managed and our company has been a leader in adopting strategies to minimize environmental impacts, such as bird and bat fatalities. Each project has different circumstances so our environmental and community programs range from hiring of local personnel and historical preservation to use of advanced radar systems to monitor birds and bats and presence of on-site biologists to assist in species recognition and mitigation management. By

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proactively addressing the concerns of the regions, our environmental management and community relations program seeks to minimize additional costs and burdens from a potential increase in regulations or law suits.

• Power Marketing. A crucial element of a successful project is assuring revenue from the sale of power and other environmental attributes. We manage the risk associated with fluctuations in electricity prices across our business by seeking to commit the electricity we generate under long-term, fixed-price power sale agreements and have been able to secure 93% of our electricity sales under such arrangements. Our uncontracted power and renewable attributes are sold in the spot market or under shorter term contracts to optimize revenue realization. We believe this management philosophy will result in a steady, predictable source of revenue for each of our projects.

• Finance. Our projects are typically funded with construction financing during the construction phase which converts to long-term financing when the project commences commercial operations. Debt at each individual project is project financed, which means that, with very limited exceptions, the lenders have no or only limited recourse to other assets of the company other than the assets that are being financed. Debt for our projects is typically provided by commercial banks and institutional lenders that have the expertise to evaluate the risks associated with the construction and operation of a wind power project, including evaluation of the equipment technology, construction, operations and wind resources. These lenders provide construction financing for many sizable industrial and infrastructure projects. Since debt comprises a significant portion of total project capitalization, achievement of construction financing is a general indication that lenders and their independent consultants have carefully evaluated the project and find it viable for long-term financing. Given the complexity involved in financing large infrastructure assets, projects are often completed with a syndicate of lenders, and the credibility we have established among the financial community allows lenders to have confidence in the quality of our projects and enables us to secure competitive financing terms and other financing efficiencies for our projects. Over the years our team has developed close relationships with many of the active renewable energy lenders.

Engineering and Construction

The key leadership in our engineering and construction group resides within our company, which provides us with the in-house capabilities required to evaluate a project’s design and construction process. We will rely as necessary upon additional personnel from third-party sources and Pattern Development, with respect to the construction of our projects. We also typically enter into fixed-price construction contracts for our projects’ construction with a guaranteed completion date to encourage completion on time and within budget.

Project design involves close and frequent communication with both field development personnel as well as the construction contractor in order to develop a project that conforms to local geotechnical and topographic characteristics while accommodating permitting and real estate restrictions. The developer also strives to integrate experience obtained from operating projects in order to design projects with optimal maintenance and equipment-availability profiles. During construction, we are responsible for overseeing the construction contractor and turbine-vendor activities to ensure that the construction schedule is met. Collaboration among engineers and managers on each of our projects and our major equipment suppliers allows us to efficiently transition from construction to commercial operations and to identify and process technical improvements over the life-cycle of each project.

Our engineering and construction team is comprised of highly experienced project and construction managers and includes personnel who have supervised the design and completion of construction of 25 wind power projects representing over 2,600 MW over the last eleven years. We set, and ensure compliance with, design specifications and take an active role in supervising field work, safety compliance, quality control and adherence to project schedules. Each project has a dedicated resident construction manager, and other engineering and construction functions are centralized, which allows the group to efficiently scale its resources to support our developing global platform and growth strategy.

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Investing

We are organized in a manner that will allow us to independently and comprehensively evaluate investments in new projects. Key members of our management team, including Messrs. Garland, Armistead, Elkort, Lyon, and Pedersen, have spent extensive periods of their careers in the investment advisory, principal investment and finance field. While working together at Pattern Development and prior to its formation, members of our management team were responsible for, and successfully financed and managed, over $12 billion of infrastructure assets, including over 3,000 MW of wind projects, several independent transmission projects and other conventional power projects.

As a major part of our growth strategy, we intend to seek to acquire projects that would contribute measurable amounts to our Adjusted EBITDA and our cash available for distribution. Our approach to project selection is focused on projects (i) with strong economics that will support our long-term financial goals, as determined by intensive analysis and in-depth due diligence, (ii) in which we can add value and which have characteristics that are strategically compatible with our other projects and overall business, and (iii) which meet our core values, including our commitments to environmental stewardship and being a good neighbor in the communities in which our projects are located. To achieve proper investment management, we have implemented processes to ensure rigorous analysis and proper internal approval controls, including preparing formal investment approval documentation, maintaining strict limits on delegation of authority for making capital commitments, and vetting our assumptions with independent technical experts and advisors. In addition, we believe that alignment and independence is critical to successful investing. As a result, we require that certain of our executive officers maintain a minimum ownership interest in our company and have structured our Board of Directors to include a conflicts committee to review specific matters that the Board of Directors believes may involve conflicts of interest, primarily acquisitions from Pattern Development or its affiliates.

We view projects as long-term partnerships with all the stakeholders, and the benefits that we pledge to the community are fundamental to creating a positive environment for a project’s long-term success.

Competition

We compete with other wind 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. Such laws and regulations may substantially increase the costs of acquiring, constructing and operating projects, and some of our competitors may be better able to adapt to and operate under such laws and regulations.

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Suppliers

Operating equipment for wind power projects primarily consists of turbines. Turbine costs represent the majority of our wind power project investment costs. There are a limited number of turbine suppliers and, although demand for turbines in the past has generally been high relative to manufacturing capacity, we believe that current turbine manufacturing capacity is adequate. Our turbine supply strategy is largely based on maintaining strong relationships with leading turbine suppliers to secure our supply needs.

Project	Supplier	Number of Turbines	Turbine Type
Operating Projects
Gulf Wind	Mitsubishi	118	MWT 95/2.4
Hatchet Ridge	Siemens	44	SWT-2.3-93
St. Joseph	Siemens	60	SWT-2.3-101
Spring Valley	Siemens	66	SWT-2.3-101
Santa Isabel	Siemens	44	SWT-2.3-108
Ocotillo	Siemens	112	SWT-2.3-108
Construction Projects
El Arrayán	Siemens	50	SWT-2.3-101
South Kent	Siemens	124	SWT-2.3-101
Grand	Siemens	67	SWT-2.3-101
Panhandle 2(1)	Siemens	79	SWT-2.3-108

⁽¹⁾  Acquisition pending, scheduled to close in the fourth quarter of 2014.

To date, our projects have purchased or agreed to purchase 646 turbines from Siemens. Siemens has been active in the wind power industry since 1980. It has a reputation for conservative engineering, robust design and high reliability. The SWT-2.3MW turbine technology has a significant and well established track record. First installed in February 2005, Siemens has installed 6,430 SWT-2.3MW turbines worldwide, with 3,424 in the United States, as of December 2013. Siemens data indicates that fleet availability for the 2.3MW turbine exceeds 97%. Apart from Siemens we have relationships with other reputable turbine manufacturers such as General Electric, Mitsubishi and others, and some of our future projects may utilize turbines from these and other manufacturers.

In May 2013, a blade separated from the turbine hub on one of the Siemens SWT-2.3-108 wind turbines at our Ocotillo project. Our Santa Isabel project also employs Siemens SWT-2.3-108 turbines. All of our turbines using this blade have been successfully retrofitted, or replaced, and the retrofits have a 20-year life certification. For information regarding the consequences of the blade separation event, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors that Significantly Affect Our Business—Electricity Sales and Energy Derivative Settlements of Our Operating Projects.”

Other important suppliers include the 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. We believe there are a sufficient number of capable engineering and construction companies available in our markets to meet our needs.

Customers

We sell our electricity and environmental attributes, including RECs, primarily to local utilities underlong-term, fixed-price PPAs or, in limited instances, local liquid ISO markets. For the year ended December 31, 2013, Manitoba Hydro, San Diego Gas & Electric, Pacific Gas and Electric Company (“PG&E”) and Electric Reliability Council of Texas (“ERCOT”) accounted for 18%, 17%, 15% and 12%, respectively, of our total revenue.

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Hedging Activity

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. We enter into these hedging agreements to reduce our exposure to potential volatility in spot-market electricity prices. We seek to hedge 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. We will also consider hedging agreements beyond the initial volume up to an amount that is expected to be exceeded over half the time. Those hedging agreements are executed for a shorter term in order to reduce volatility of our cash flows.

We also enter into interest rate hedging agreements to convert floating-rate debt to fixed-rate debt for some of our projects. Additionally, our El Arrayán project enters into currency exchange rate hedging agreements to manage construction costs that may be payable or receivable in a foreign currency and do not have a same currency offset.

We expect to initiate a program of exchange rate management due to the substantial portion of our electricity sales that are Canadian dollar denominated. For additional information regarding our hedging activities, please read Item 7A “Quantitative and Qualitative Disclosure about Market Risk.”

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Structure of Our Company

⁽¹⁾  These funds and these employees hold indirect interests in Pattern Development.

⁽²⁾  Pattern Development holds an interest of approximately 27% in Gulf Wind, representing Pattern Development-owned capacity of 76 MW.

⁽³⁾  We have agreed to acquire Panhandle 2 from Pattern Development and expect to complete the acquisition before the end of 2014.

Employees

As of December 31, 2013, we had 44 full-time employees of whom 12 are based in our corporate headquarters, 15 are based at our project sites and 17 are based at our other offices, including our OCC, in Houston, Texas. None of our employees are represented by a labor union or covered by any collective bargaining agreement. We believe that our relationship with our employees is good.

Insurance

We maintain insurance on terms generally carried by companies engaged in similar business and owning similar properties in the United States, Canada and Chile and whose projects are financed in a manner similar to

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our projects. As is common in the wind industry, however, we do not insure fully against all the risks associated with our business either because insurance is not available or because the premiums for some coverage are prohibitive. For example, we do not maintain terrorism insurance. We maintain varying levels of insurance for the development, construction and operation phases of our projects, including property insurance, which, depending on the location of each project, may include catastrophic windstorm, flood and earthquake coverage (CAT coverage); transportation insurance; advance loss of profits insurance; business interruption insurance; general liability and umbrella liability insurance; time element pollution liability insurance; auto liability insurance; worker’s compensation and employers’ liability insurance; and (except in Chile) title insurance. The “all risk” property insurance coverage is currently maintained in amounts based on the full replacement value of our projects (subject to certain sub-limits for windstorm, flood and earthquake risks) and the business interruption insurance generally provides 15 months of coverage in amounts that vary from project to project based on the revenue generation potential of each project. All types of coverage are subject to applicable deductibles. We generally do not maintain insurance for certain environmental risks, such as environmental contamination.

Industry

Wind power has been one of the fastest growing sources of electricity generation in North America and globally over the past decade. According to the Global Wind Energy Council, or “GWEC,” from 2001 through 2012, total net electricity generation from wind power in the United States and Canada grew at a CAGR of 27% and 37%, respectively. The growth in the industry is largely attributable to renewable energy’s increasing cost competitiveness with other power generation technologies, the advantages of wind power over other renewable energy sources and growing public support for renewable energy driven by concerns regarding security of energy supply and the environment. As global demand for electricity generation from wind power has increased, technology enhancements—supported by U.S. government incentives—have reduced the cost of wind power by more than 80% over the last twenty years, according to the American Wind Energy Association, or “AWEA.”

The United States is the second largest market for wind power in the world by electricity generating capacity. According to the U.S. Department of Energy, or “DOE,” wind power was the second largest source of new electricity generating capacity in the United States after natural gas for six of the seven years between 2005 and 2011. According to AWEA, wind power became a leading source of new electricity generating capacity in the United States for the first time in 2012. The success of wind power in the United States is evidenced by over $120 billion in investments to date, according to AWEA.

The Canadian wind power industry has also experienced dramatic growth in recent years. In 2012, Canada experienced 936 MW of new installed wind power generating capacity, representing an investment of approximately C$2 billion. This investment resulted in wind power generating capacity in Canada reaching approximately 6,500 MW as of January 2013. According to the Canadian Wind Energy Association, or “CanWEA,” new installed wind power generating capacity is expected to average 1,500 MW annually over the next four years. Ontario, one of our markets, is the national leader in installed capacity, with approximately 2 gigawatts, or “GW,” of wind power generating capacity, although recent changes to the Ontario government FIT regime may make future projects less attractive and PPAs more difficult to obtain. CanWEA forecasts total wind power generating capacity in Canada to exceed 12 GW by 2016.

Chile, also one of our markets, has an abundant wind resource, which GWEC estimates could provide the potential for more than 40 GW of generating capacity. As of the end of 2011, Chile had approximately 200 MW of installed wind power generating capacity, representing approximately 1% of total electricity generating capacity and, according to GWEC, approximately 200 MW of wind power projects were under construction in Chile and an additional 2,700 MW were under development.

Given supply diversity requirements, falling equipment costs, the inherent stability of the cost of wind power as an energy resource and an active market for the purchase and sale of power projects, we believe that our

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markets present a substantial opportunity for growth. 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 Pattern Development and other third parties.

While we currently operate solely in wind power markets, we expect to continue to evaluate other types of independent power projects for possible acquisition, including renewable energy projects other than wind power projects and non-renewable energy projects.

Regulatory Matters

Environmental Regulation

We are subject to various environmental, health and safety laws and regulations in each of the jurisdictions in which we operate. These laws and regulations require us to obtain and maintain permits and approvals, undergo environmental review processes and implement environmental, health and safety programs and procedures to monitor and control risks associated with the siting, construction, operation and decommissioning of wind power projects, all of which involve a significant investment of time and can be expensive.

We incur costs in the ordinary course of business to comply with these laws, regulations and permit requirements. We do not anticipate material capital expenditures for environmental controls for our operating projects in the next several years. However, these laws and regulations frequently change and often become more stringent, or subject to more stringent interpretation or enforcement. Future changes could require us to incur materially higher costs.

Failure to comply with these laws, regulations and permit requirements may result in administrative, civil and criminal penalties, imposition of investigatory, cleanup and site restoration costs and liens, denial or revocation of permits or other authorizations and issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property or for injunctive relief have been brought and may in the future result from environmental and other impacts of our activities.

Environmental Permitting—United States

We are required to obtain from U. S. federal, state and local governmental authorities a range of environmental permits and other approvals to build and operate our projects, including, but not limited to, those described below. 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 U.S. Clean Water Act from the U.S. Army Corps of Engineers, or the “Army Corps,” for the discharge of dredged or fill material into waters of the United States, including wetlands and streams. The Army Corps may also require us to mitigate any loss of wetland functions and values that accompanies our activities. In addition, we are required to 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. Certain activities, such as installing a power line across a navigable river, may also require permits under the Rivers and Harbors Appropriation Act of 1899.

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

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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. Obtaining a grant requires that the proposed project prepare a plan of development and demonstrate that it will adhere to the Bureau of Land Management’s best management practices for wind power development, including meeting criteria for protecting biological, archeological and cultural resources.

National Environmental Policy Act and Endangered Species Requirements

Our U.S. projects may also be subject to environmental review under the U.S. National Environmental Policy Act, or “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 archeological resources, geology, socioeconomics and aesthetics and alternatives to the project. The NEPA review process, especially if it involves preparing a full Environmental Impact Statement, can be time-consuming and expensive. 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.

Federal agencies granting permits for our U.S. projects also consider the impact on endangered and threatened species and their habitat under the U.S. Endangered Species Act, which prohibits and imposes stringent penalties for harming endangered or threatened species and their habitats. Our projects also need to consider the Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act, which protect migratory birds and bald and golden eagles and are administered by the U.S. Fish and Wildlife Service. Most states also have similar laws. Because the operation of wind turbines may result in injury or fatalities to birds and bats, federal and state agencies often recommend or require that we conduct avian and bat risk assessments prior to issuing permits for our projects. They may also require ongoing monitoring or mitigation activities as a condition to approving a project. In addition, 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. Among other things, 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.) through a process known as “Section 106 Review”.

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. State agencies evaluate similar issues as federal agencies, including the project’s impact on wildlife, historic sites, aesthetics, wetlands and water resources, agricultural operations and scenic areas. States may impose different or additional monitoring or mitigation requirements than federal agencies. Additional approvals may be required for specific aspects of a project, such as stream or wetland crossings, impacts to designated significant wildlife habitats, storm water management and highway department authorizations for oversize loads and state road closings during construction. Permitting requirements related to transmission lines may be required in certain cases.

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Our projects also are subject to local environmental and regulatory requirements, including county and municipal land use, zoning, building and transportation requirements. Permitting at the local municipal or county level often consists of obtaining a special use or conditional use permit under a land use ordinance or code, or, in some cases, rezoning in connection with the project. Obtaining a permit usually depends on our demonstrating that the project will conform to development standards specified under the ordinance so that the project is compatible with existing land uses and protects natural and human environments. 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.

Environmental Permitting—Canada

We are required to obtain from Canadian federal, provincial and local governmental authorities a range of environmental permits and other approvals to build and operate our Canadian projects, including, but not limited to, those described below. 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, environmentalnon-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’sEnvironmental Protection Act, which requires proponents of significant wind 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 Aboriginal 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 and communities. 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. Renewable energy approvals are also subject to appeal by third parties and can result and have resulted in lengthy appeal tribunal hearings.

Manitoba Environment Act

The ManitobaEnvironment 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 theEnvironment 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 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 theMigratory 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 theEndangered Species Act may also be required.

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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, esthetics, wetlands and water resources, scenic areas, endangered and threatened species and communities. In addition, federal government approvals dealing with, among other things, aeronautics, 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’sGreen 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.

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.

Intellectual Property

We do not own any intellectual property material to the conduct of our business. However, we own various information that includes, without limitation, financial, business, scientific, technical, economic, and engineering information, formulas, designs, methods, techniques, processes, and procedures, all of which is protected confidential and proprietary information.

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, 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, financial condition and results of operations and liquidity.

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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, 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, 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 Project.”

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’ hedging arrangements being ineffective or more costly;

• 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; and

• 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.

We may be unable to complete our current and 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.

There may be delays or unexpected developments in completing our current and any future construction projects, which could cause the construction costs of these projects to exceed our expectations. Most of our construction projects are constructed under fixed-price and fixed-schedule contracts with construction and

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equipment suppliers. However, these contracts provide for limitations on the liability of these contractors to pay us liquidated damages for cost overruns and construction delays. 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. Additionally, various other factors could contribute to construction-cost overruns and construction delays, including:

• inclement weather conditions;

• failure to receive turbines 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 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 our construction projects into financially successful operating projects would have a material adverse effect on our business, financial condition and results of operations and our ability to pay dividends.

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, in February 2014, credit ratings of PREPA, the Puerto Rican power purchaser, and the Commonwealth of Puerto Rico were downgraded. 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. Failure by any key power purchasers to meet its contractual commitments or the insolvency or liquidation of one or more of our power purchasers could have a material adverse effect on our business, financial condition and results of operations.

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A prolonged environment of low prices for natural gas, or other conventional fuel sources, 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 to decrease and adversely affect both the price available to us under power sale agreements that we may enter into in the future and the price of the electricity we generate for sale on a spot-market basis. Approximately 7% of the electricity generated from our projects will be subject to spot-market pricing through at least April 2019. 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 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 power 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. Accordingly, in such event, our future growth prospects could be adversely affected if we remain solely focused on renewable energy projects and are unable to transition to conventional power projects such as gas-fired power projects.

Natural events and operational problems may cause our power production 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. In addition, 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. Even though our projects enter into warranty agreements with the turbine manufacturer for two- to five-year terms, such agreements are typically subject to an aggregate maximum cap and there can be no assurance that the supplier will be able to fulfill its contractual obligations.

In addition, 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 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 could materially decrease, which could have a material adverse effect on our business, financial condition and results of operation.

We have a 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 or that we expect will commence commercial operations prior to the end of 2014. 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

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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 our construction projects in a timely manner, either of which could have a material adverse effect on our business, 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.

If our projects do not comply with applicable laws, regulations or permit requirements, we may be required to pay penalties or fines or curtail or cease operations of the affected projects. 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.

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, financial condition and results of operations.

Environmental, health and safety laws, regulations and permit requirements may change or become more stringent. Any such changes could require our projects to incur additional material costs. Our projects’ costs of complying with current and future environmental, health and safety laws, regulations and permit requirements, and any liabilities, fines or other sanctions resulting from violations of them, could have a material adverse effect on our business, financial condition and results of operations.

Our projects rely on interconnections to transmission lines and other transmission facilities that are owned and operated by third parties. Our projects are exposed to interconnection and transmission facility development and curtailment risks, which may delay the completion of our 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 our construction projects. In addition, certain of our operating projects’ generation of electricity may be curtailed without compensation 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, financial condition and results of operations.

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In the future we may acquire projects with their own generator leads to available electricity transmission or distribution networks. In some cases, these facilities may cover 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, should there be any excess capacity available in those generator lead facilities, and should a third party request access to such capacity, FERC would, 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, 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 our 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 could limit our ability to effectively manage our operating projects and complete our construction projects on schedule and within budget, which could have a material adverse effect on our business, financial condition and results of operations.

The reintegration event may adversely affect our costs.

Following the occurrence of the reintegration event, we may be faced with increased costs associated with employing a larger number of employees. If Pattern Development reduces the scope of its development activities and is therefore not paying us for the services of the reintegrated employees pursuant to the terms of the Management 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, 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 measures 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, financial condition and results of operations. In addition, certain lands, such as lands under the jurisdiction of the U.S. Department of Interior’s Bureau of Land Management, or the “Bureau of Land Management,” are subject to contractual rights that permit the Bureau of Land Management to adjust rent due on properties to market terms. Any such loss or curtailment of our rights to use the land on which our projects are located and any increase in rent due on such lands could have a material adverse effect on our business, financial condition and results of operations.

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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, financial condition and results of operations.

Our current projects in operation in the United States are operating as “Exempt Wholesale Generators,” or “EWGs,” as defined under the Public Utility Holding Company Act of 2005, as amended, or “PUHCA,” and therefore are exempt from certain regulation under PUHCA. Other than Gulf Wind and the Panhandle 2 project once we acquire it, 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 Regional Transmission Organizations, or “RTOs.” Several of our current operating projects are subject to the California ISO, or “CAISO,” which is the ISO that prescribes rules for the terms of participation in the California energy market; ERCOT, which is the ISO that prescribes the rules for and terms of participation in the Texas energy market; and the Independent Electricity System Operator, or “IESO,” which is the ISO that administers the wholesale electricity market in Ontario. Many of these entities can impose rules, restrictions and terms of service 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 North American Electric Reliability Corporation, or “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. Changes in regulatory treatment at the state 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 current wind power projects and any potential future wind power projects in Ontario could be affected by market rule changes intended to address surplus baseload generation.

Market rule changes recently implemented in Ontario, one of the markets in which we operate, could have a significant effect on the economics of renewable energy projects, particularly certain current and planned wind power and solar power projects. These rule changes are intended to address surplus baseload generation, or “SBG,” in Ontario, given the speed of investment in renewable energy projects under Ontario’s current renewable power programs and the relative inflexibility of existing nuclear, run-of-river hydro and certain other must-run electricity generation resources. The IESO is engaging in discussions with stakeholders under the IESO Renewable Integration (SE-91) process, or “SE-91,” regarding a process through which certain renewable energy resource projects would be actively dispatched. This may result in such facilities being curtailed before nuclear, hydroelectric or natural gas resources during conditions of SBG. Market Rule Amendment MR-00381, or “MR-00381,” was approved on November 29, 2012 by the Board of Directors of the IESO and took effect in

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September 2013. MR-00381 includes amendments providing for the active dispatch of variable generation, including, in particular, wind and solar facilities that are market participants and directly connected to the IESO-controlled grid. Stakeholder discussions will continue under the SE-91 process in respect of implementing MR-00381 over the coming months. As part of MR-00381, the IESO will actively dispatch all variable generation projects that are registered market participants through five-minute constrained economic dispatch. The implementation of MR-00381 will likely impact wind power and solar projects that have contracts under a FIT program or similar PPAs with the Ontario Power Authority, or “OPA,” because these projects sell only the electricity they generate and successfully deliver. Although the contractual provisions included in our and Pattern Development’s PPAs with the OPA provide significant limitations on exposure to dispatch, implementation of MR-00381 may limit the revenues we derive from our projects in Ontario, which could have a material adverse effect on our business, 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, 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 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 force majeure. In addition, our insurance policies for some of our projects cover losses as a result of certain types of natural disasters, terrorist attacks 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. In addition, 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, 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 related to buying, selling and financing our business in currencies other than the local currencies of the countries in which we operate. A portion of our revenue for the years ended December 31, 2013 and 2012 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. Currency exchange rate fluctuations may disrupt the business of our suppliers by making their purchases of raw materials more expensive and more difficult to finance. Historically, we have reduced our exposure by aligning our costs with the currency in which we obtain revenues or, if that is impracticable, through financial instruments that provide offsets or limits to our exposures. However, any measures that we may implement in the future to reduce the effect of currency exchange rate fluctuations and other risks of our global

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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.

In addition, foreign currency translation risk arises upon the translation of statement of financial position and income statement items of our foreign subsidiaries whose functional currency is a currency other than the U.S. dollar into U.S. dollars for purposes of preparing the consolidated financial statements included elsewhere in this Form 10-K, which are 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 income statement 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 income, net of tax”. These currency translation differences may have significant negative or positive impacts. Upon the disposal of a non-U.S. dollar denominated subsidiary, the cumulative amount of exchange differences relating to that non-U.S. dollar denominated subsidiary are reclassified from equity to profit or loss. Our foreign currency translation risk mainly relates to our operations in Canada and Chile.

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 in profit or loss in the period in which they arise. In order to reduce significant foreign currency transaction risk from our operating activities, we may use forward exchange contracts 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, or the “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 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, financial condition and results of operations.

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We own, and in the future may acquire, certain projects in joint ventures, and our partners’ interests may conflict with our and our stockholders’ interests.

We own, and in the future may acquire, certain projects in joint ventures, including South Kent and Grand, in each of which we have a 50% and 45% interest, respectively, and El Arrayán, in which we have a 31.5% interest. In the future, we may invest in other projects with a joint venture partner, including certain Pattern Development-owned development projects. 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 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 could result in litigation, which could 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, financial condition and results of operations.

Risks Related to Our Acquisition Strategy and Future Growth

The growth of our business depends on locating and acquiring interests in additional attractive independent power and transmission projects at favorable prices.

Our business strategy includes acquiring power and transmission projects that are either operational, construction-ready, or in limited circumstances, under development. We intend to pursue opportunities to acquire projects from third-party IPPs and from Pattern Development pursuant to our Purchase Rights. 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 Purchase Rights, from other IPPs, 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;

• Pattern Development’s failure to complete the development of (i) the Initial ROFO Projects, which could result from, among other things, permitting challenges, failure to procure the requisite financing, equipment or interconnection, or an inability to satisfy the conditions to effectiveness of project agreements such as PPAs and (ii) any of the other projects in its development pipeline, in a timely manner, or at all, in either case, which could limit our acquisition opportunities under our Purchase Rights;

• our failure to exercise our Purchase Rights or acquire assets from Pattern Development;

• our failure to successfully develop and finance projects, to the extent that we decide to pursue development activities with respect to new power projects; and

• 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.

Any of these factors could prevent us from executing our growth strategy or otherwise have a material adverse effect on our business, financial condition and results of operations.

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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.

Acquisition 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. 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, financial condition and results of operations.

Our growth strategy is dependent upon the acquisition of attractive power projects developed by third-parties, including Pattern Development, 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, from which we may seek to acquire power projects, must obtain at-risk funds sufficient to complete the development phase of their projects. We, on the other hand, must anticipate obtaining funds from equity or debt financings, including tax equity transactions, or from government grants in order to successfully complete our acquisitions and fund the required construction and other capital costs of the acquired projects. We currently intend to acquire power projects that are construction-ready, which is generally the point in time when the project is able to procure construction financing. 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 as well as limit a project’s ability to obtain financing to complete the construction of a project we may seek to acquire. If development companies from which we seek to acquire projects are unable to raise funds when needed or if we or they are unable to secure construction financing, 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, 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 Pattern Development 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. We have established a three-year targeted annual growth rate in our cash available for distribution per Class A share of 8% to 10%. 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 Initial ROFO Projects, on economically favorable terms. If we are unable to make accretive acquisitions from Pattern Development or third parties because we are unable to identify attractive acquisition opportunities, negotiate

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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 Canada, the United States and Chile benefits from governmental support that is subject to change.

The energy industry in Canada and the United States, 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 RFPs and the Ontario FIT program 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. ITC cash grants expired with respect to wind energy on December 31, 2012. PTCs and ITCs for wind energy currently expired on December 31, 2013. Renewable energy sources in Chile benefit from the Renewable and Non-Conventional Energy Law, which guarantees a fixed-price for renewable energy until 2024. The existence of these incentives is reflected in, and allows us to reduce, the price we charge for electricity generated by our projects. To the extent that these governmental incentive programs are not renewed or similar incentives are not made available, new wind power projects may need to increase the price of electricity sold to power purchasers, which could result in decreased demand for wind power, and could reduce the number of projects available to us for acquisition which could have a material adverse effect on our ability to implement our growth strategy and, ultimately, our business, financial condition and 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, 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 procurements 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 recent 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.

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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, 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 results of operations and cash available for distribution.

Some states and provinces with RPS programs have met, or will in the near future, meet such targets through projects under contract, which could cause demand for new wind power and other power capacity to decrease.

Some states with RPS targets have met, or in the near future will meet, their targets through the recent increase in renewable energy development activity. For example, California, which has one of the most aggressive RPS in the United States, is poised to meet its current target of 25% renewable energy generation by 2016 and has the potential to meet its goal of 33% renewable power generation by 2020 with already-proposed new renewable power projects. Ontario anticipates meeting its renewable energy target of 10.7 GW by 2018. As a result of achieving these targets, and if these U.S. states and Canadian provinces do not increase their targets in the near future, demand for additional wind power generating capacity could decrease. To the extent other states and provinces do not become market leaders in their stead or increase their RPS targets, demand for power from wind power and other renewable energy projects could decrease in the future, which could have a material adverse effect on our business and our growth.

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 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. We cannot predict whether all permits required for a given project will be granted or whether the conditions associated with the permits will be achievable. The denial or loss of a permit essential to a project or the imposition of impractical conditions upon renewal could impair our ability to construct and operate a project. In addition, we cannot predict whether 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.

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In developing certain of our projects Pattern Development experienced delays in obtaining non-appealable permits and we 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 have 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. See Item 3“Legal Proceedings.” In Ontario, anti-wind advocacy groups opposed the environmental permit granted to our South Kent and Grand projects. The permits were appealed before the Environmental Review Tribunal, which later dismissed the appeals. We are subject to the risk of being unable to complete our projects if any of the key permits are revoked. 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, financial condition and results of operations.

Our strategic relationship with Pattern Development through which we expect Pattern Development to help us locate and obtain new projects is limited. Our Purchase Rights may expire and if we do not exercise our Project Purchase Right or if we are not competitive with third party offers, Pattern Development is generally not restricted from competing with us, other than with respect to the Non-Competition Agreement, and, in certain circumstances, Pattern Development may sell its projects to third parties.

To the extent we do not exercise our Purchase Rights (or upon their expiration), Pattern Development may sell its projects (including the Pattern Development retained Gulf Wind interest) or Pattern Development itself or substantially all of its assets may be sold to third parties, including our competitors. Even if we are interested in acquiring an asset or investing in an opportunity offered to us by Pattern Development, Pattern Development may offer 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 or its equity owners or if we decline to make an offer, Pattern Development or its 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, financial condition and results of operations.

Additionally, our Gulf Wind Call Right terminates upon the second anniversary of the completion of our initial public offering, or October 2, 2015; and our Project Purchase Right and our Pattern Development Purchase Right terminate upon the fifth anniversary of the completion of our initial public offering, or October 2, 2018, but are subject to automatic five-year renewals unless either party dissents at the time of renewal. In addition, our Project Purchase Right and our Pattern Development Purchase Right terminate upon the third occasion on which we decline to exercise our Project Purchase Right with respect to an operational or construction-ready project and following which Pattern Development has sold the project to an unrelated third party. Following termination of our Project Purchase Right and our Pattern Development Purchase Right, Pattern Development 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, financial condition and results of operations.

Once our Purchase Rights terminate, the Non-Competition Agreement with Pattern Development will also terminate, and at such time, Pattern Development will no longer be restricted from competing with us for acquisitions.

The loss of one or more of our or Pattern Development’s executive 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 our and Pattern Development’s executive 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 executives and employees in the wind power industry. As a result, if one or more of our or Pattern Development’s executive officers or key employees leaves and neither we nor Patten Development are able 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, financial condition and results of operations.

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While we currently own only wind power projects, in the future, we may decide to expand our acquisition strategy to include other types of power projects or transmission projects. Any future acquisition of non-wind power projects or transmission projects may present unforeseen challenges and result in a competitive disadvantage relative to our more-established competitors.

In the future, we may expand our acquisition strategy to include other types of power projects or transmission projects. There can be no assurance that we will be able to identify 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 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, 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 or claims contesting the construction or operation of our projects. 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. 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, 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 as of December 31, 2013 is approximately $1.2 billion, or approximately 66% of our total capitalization of $1.9 billion at such date.

Of this amount, approximately $397.4 million represents project-level debt that matures prior to 2021. We do not have available cash or short-term liquid investments sufficient to repay all of this medium-term indebtedness and we have not obtained commitments for refinancing this debt. Therefore, we may not be able to extend the maturity of this indebtedness or to otherwise successfully refinance current maturities if the project finance markets deteriorate substantially or we choose not to raise corporate-level debt in place of project-level debt. Refinancing such indebtedness may force us to accept then-prevailing market terms that are less favorable than the existing indebtedness. If, for any reason, we are unable to refinance the existing indebtedness, those projects may be in default of their existing obligations, which may result in a foreclosure on the project collateral and loss of the project. Any such events could have a material adverse effect on our business, financial condition and results of operations.

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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, which could be difficult to cure, or result in our bankruptcy;

• our debt service obligations require us to dedicate a substantial portion of our cash flow to pay principal and interest on our debt, thereby reducing the funds available to us and our ability to borrow to operate and grow our business;

• our limited financial flexibility could reduce our ability to plan for and react to unexpected opportunities; and

• 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, 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 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 wind power 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, financial condition and results of operations.

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 wind power 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, financial condition and results of operations and, in turn, on our cash available for distribution.

We are subject to indemnity 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 (“MetLife”), the owner participant, under the Hatchet Ridge Wind Lease Financing against certain tax losses.

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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 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, 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, financial condition and results of operations and, in turn, on our cash available for distribution. See “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Description of Certain Financing Arrangements.”

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, 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 or a financial swap, or both. If we sell our electricity into an ISO market without a PPA, we may enter into a financial swap to stabilize all or a portion of our estimated revenue stream. 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 market price for the same quantities of electricity. These financial swaps cover quantities of electricity that we estimate we are highly likely to produce. As a result, gains or losses under the financial swaps are designed to be offset by decreases or increases in our revenues from spot 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 by the associated swap contract, we could incur significant losses if electricity prices in the market rise substantially above the fixed-price provided for in the swap. If a project generates more electricity than is contracted in the 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 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, but we may be required to do so in the future. However, 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

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generated by one of our projects, sometimes bundled with RECs and capacity or other environmental attributes, to a power purchaser, often a utility. 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, 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. If the project generates less than the committed volumes, we may be required to buy the shortfall of electricity 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 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 our 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 Policy.” 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.

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 Policy.” The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness.

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

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Class A shares. These agreements contain financial tests and covenants that our subsidiaries must satisfy prior to making distributions. 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. The terms of our project-level 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, 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. If our projects do not generate sufficient cash available for distribution, we may be required to fund dividends from working capital, borrowings under our revolving credit facility, proceeds from future offerings, the sale of assets or by obtaining other debt or equity financing, 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. See “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Description of Credit Agreements.”

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 will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board of Directors deems relevant. 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 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.

Risks Regarding Our Cash Dividend Policy

We do not have a sufficient operating history as an independent company upon which to rely in evaluating whether we will have sufficient cash available for distribution and other sources of liquidity to allow us to pay dividends on our Class A shares at our initial quarterly dividend level on an annualized basis. 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, 2014, 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 maintain our initial dividend and to grow our business and 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 $120.0 million revolving credit facility with a four-year term includes customary affirmative and negative covenants that will subject certain of our project subsidiaries to restrictions on making distributions to us. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Description of Credit Agreements—Revolving Credit Facility.” 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 likely will contain financial tests and covenants that our subsidiaries must satisfy prior to making distributions. The current financial tests and covenants applicable to our subsidiaries are described in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—

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Description of Credit Agreements.” If any of our subsidiaries is unable to satisfy these restrictions or is 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.

• 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.

Pattern Development’s general partner and its officers and directors have fiduciary or other obligations to act in the best interests of Pattern Development’s owners, which could result in a conflict of interest with us and our stockholders.

Pattern Development holds approximately 47.4% of our outstanding Class A shares and 99.0% of our outstanding Class B shares, representing in the aggregate an approximate 63.1% voting interest in our company. The remaining 1.0% of our outstanding Class B shares are held by members of our management. Until the Conversion Event, neither Pattern Development nor the management holders of our Class B shares will be entitled to receive any dividends on their Class B shares. We are party to the Management Services Agreement, pursuant to which each of our executive officers (including our Chief Executive Officer), with the exception of our Chief Financial Officer and Senior Vice President, Operations, will also be shared PEG executives and devote their time to both our company and Pattern Development as needed to conduct our respective businesses. As a result, these shared PEG executives have fiduciary and other duties to Pattern Development. Conflicts of interest may arise in the future between our company (including our stockholders other than Pattern Development) and Pattern Development (and its owners and affiliates). Our directors and executive officers owe fiduciary duties to the holders of our shares. However, Pattern Development’s general partner and certain of its officers and directors also have a fiduciary duty to act in the best interest of Pattern Development’s limited partners, which interest may differ from or conflict with that of our company and our other stockholders.

Pattern Development’s share ownership limits other stockholders ability to influence corporate matters.

Pattern Development or its affiliates hold approximately 63.1% of the combined voting power of our shares, and this concentration of voting power limits 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 its ownership in our company, Pattern Development has significant influence over all matters that require approval by our stockholders, including the election of directors. As a result, Pattern Development or its affiliates have the ability to exercise substantial influence over our company, including with respect to decisions relating to our capital

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structure, issuing additional Class A shares or other equity securities, paying dividends on our Class A shares, incurring additional debt, making acquisitions, selling properties or other assets, merging with other companies and undertaking other extraordinary transactions. In any of these matters, the interests of Pattern Development and its affiliates may differ from or conflict with the interests of our other stockholders. Pursuant to the Shareholder Agreement, for so long as Pattern Development beneficially owns at least 33 1/3% of our shares, Pattern Development’s consent will be necessary for us to take certain material corporate actions. Pattern Development may withhold its consent, which could adversely affect our business.

Certain of our executive officers will continue to have an economic interest in, as well as provide services to Pattern Development, which could result in conflicts of interest.

Certain of our executive officers provide services to Pattern Development pursuant to the terms of the Management Services Agreement between our company and Pattern Development and, as a result, in some instances, have fiduciary or other obligations to Pattern Development. Additionally, our Chief Executive Officer, Executive Vice President, Business Development, Executive Vice President and General Counsel, Senior Vice President, Fiscal and Administrative Services and Senior Vice President, Engineering and Construction have economic interests in Pattern Development and, accordingly, the benefit to Pattern Development from a transaction between Pattern Development and our company will proportionately inure to their benefit as holders of economic interests in Pattern Development. Pattern Development will be a related party under the applicable securities laws governing related party transactions and, as a result, any material transaction between our company and Pattern Development (except the occurrence of the reintegration event) will be subject to our corporate governance guidelines, which will 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 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, 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, which will be subject to the Non-Competition Agreement) may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

Subject to the terms of the Non-Competition Agreement with, and our Purchase Rights granted to us by, Pattern Development , 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. Riverstone has advised us that it does not have a formal policy regarding business opportunities presented to the investment funds managed or advised by it and their respective portfolio companies, but Riverstone’s practice has been that any business opportunities may be pursued by any such fund or directed to any such portfolio company except when the business opportunity has been presented to an employee of Riverstone or its affiliates solely in his or her capacity as a director of a portfolio company.

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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 Pattern Development could damage our reputation, increase our exposure to potential litigation and have a material adverse effect on our business, 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 to determine whether the offer is fair and reasonable (including any acquisitions by us of assets of Pattern Development pursuant to our Purchase Rights). However, our establishment of a conflicts committee 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, 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.

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;

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• 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.”

In addition, 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. 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.

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. In particular, once we are no longer an emerging growth company as defined in the JOBS Act, 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 are not able to comply with these requirements in a timely manner, or if we identify deficiencies in our internal control over financial reporting that are deemed to be material weaknesses, the market price of our shares could 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, which would require additional financial and management resources. However, for as long as we remain an emerging growth company, we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act. We may take advantage of these reporting exemptions until we are no longer an emerging growth company. We will remain an emerging growth company for up to five years, although if the market value of our shares that is held by non-affiliates exceeds $700 million as of any June 30 before that time, we would cease to be an emerging growth company as of the following December 31.

Our ability to successfully implement our business plan and comply with Section 404 of the Sarbanes-Oxley Act requires us to be able to prepare timely and accurate financial statements. Any delay in the implementation of, or disruption in the transition to, new or enhanced systems, procedures or controls, may cause our operations to suffer and we may be unable to conclude that our internal control over financial reporting is effective as required under Section 404 of the Sarbanes-Oxley Act. Moreover, we cannot be certain that these measures would ensure that we implement and maintain adequate controls over our financial processes and reporting in the future. Even if we were to conclude that our internal control over financial reporting provided reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP, because of its inherent limitations, internal control over financial reporting may not prevent or detect fraud or misstatements. This, in turn, could have an adverse impact on trading prices for our Class A shares, and could adversely affect our ability to access the capital markets.

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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, and such costs may increase when we cease to be an emerging growth company.

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 Act of 2010, as well as rules implemented by the SEC, the Canadian Securities Administrators and the stock exchanges on which we expect our Class A shares will be traded.

Such costs may increase when we cease to be an emerging growth company. For as long as we remain an emerging growth company, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a non-binding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. We may take advantage of these reporting exemptions until we are no longer an emerging growth company. We will remain an emerging growth company for up to five years unless we no longer qualify for such status prior to that time. We would cease to be an emerging growth company if we have more than $1.0 billion in annual revenues, have more than $700 million in market value of our shares held by non-affiliates or issue more than $1.0 billion of non-convertible debt over a three-year period. If the market value of our shares that is held by non-affiliates exceeds $700 million as of any June 30, before that time, we would cease to be an emerging growth company as of the following December 31. After we are no longer an emerging growth company, we expect to incur additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not emerging growth companies.

The expenses incurred by public companies for reporting and corporate governance purposes have increased dramatically over the past several years. We expect these rules and regulations to increase our legal and financial compliance costs substantially and to make some activities more time consuming and costly. We are currently unable to estimate these costs with a high degree of certainty. 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. Because the JOBS Act has only recently been enacted, it is not yet clear whether investors will accept the more limited disclosure requirements that we may be entitled to follow while we are an emerging growth company. To the extent investors are not comfortable with a more limited disclosure regime, they may not be comfortable purchasing and holding our Class A shares if we elect to comply with the reduced disclosure requirements.

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 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, 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 Public Utility Holding Company Act of 2005, or “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

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Development, 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 a general increase to the applicable percentage ownership under a blanket authorization, for the purposes of sell-side transactions by us or Pattern Development 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, 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 $1 million per day per violation 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 common shares in 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 common shares that are electric holding companies 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, 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 will:

• 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 if Pattern Development and its affiliates (other than our company) collectively cease to own more than 50% of our shares;

• prohibit stockholder action by written consent, which requires all stockholder actions to be taken at a meeting of our stockholders if Pattern Development and its affiliates (other than our company) collectively cease to own more than 50% of our shares;

• 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.

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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.

We may issue and Pattern Development may sell additional shares in subsequent public offerings. We may also issue additional shares, convertible debt securities or other types of securities which are convertible or exchangeable into our shares to finance future acquisitions. We have 500,000,000 Class A shares authorized and 35,548,051 Class A shares outstanding. The number of outstanding shares includes 18,400,000 Class A shares that are held by the public, which may be resold immediately in the public market. All of the remaining Class A shares, or approximately 17,148,051, or 48.2% of our total outstanding shares, are restricted from immediate resale under the lock-up agreements between our current stockholders and our underwriters, but may be sold into the market in the near future. 16,964,050 of these Class A shares will become available for sale following the expiration of the lock-up agreements, which, without the prior consent of the underwriters, is 180 days after the date of the closing of our initial public offering, or March 31, 2014, subject to compliance with the applicable requirements under Rule 144 of the U.S. Securities Act and under Canadian securities laws relating to sales by a control person.

We cannot predict the size of future issuances of our Class A shares or the effect, if any, that future issuances and sales of our shares will have on the market price of our shares. Sales of substantial amounts of our shares (including sales pursuant to Pattern Development’s registration rights and shares issued in connection with an acquisition), 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.

Our Projects

Including the Panhandle 2 project which we have agreed to acquire from Pattern Development, and which we expect to acquire before the end of 2014, we own interests in ten wind power projects, consisting of six operating projects and four construction projects. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price power sale agreement with a creditworthy counterparty. We expect any project we acquire in the future will be party to a similar agreement, but we may acquire projects with greater levels of uncontracted capacity.

Operating Projects

Gulf Wind

Gulf Wind is a 283 MW project located on the Gulf Coast in Kenedy County, Texas. The project consists of 118 2.4 MW Mitsubishi MWT95/2.4 turbines and commenced commercial operations in 2009. Pattern Development acquired this operational project in March 2010. Gulf Wind is held by a tax equity partnership with MetLife. We, Pattern Development and MetLife currently own approximately 40%, 27% and 33% of Gulf Wind, respectively.

The project is located in the South Zone of the ERCOT market and sells 100% of its power output into the ERCOT market, receiving the locational marginal price, or “LMP.” Approximately 58% of the project’s expected annual electricity generation has been hedged under a 10-year fixed-for-floating swap with Credit Suisse Energy LLC. This financial hedging agreement settles using the South Trading Hub hourly LMP weighted by the settlement volume in each hour. The hourly notional settlement volume varies to match the project’s hourly average production profile. Gulf Wind’s obligations under the hedge are secured by a first priority lien on substantially all of the assets of Gulf Wind and a first priority lien on the membership interests in the operating project entity up to approximately $73 million, both of which are first in priority relative to the second priority liens associated with the debt financing up to approximately $250 million and which are second in priority over the third-priority liens in favor of Credit Suisse Energy LLC in excess of the first and second lien caps.

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The project is connected to the Electric Transmission Texas 345 kV transmission system and is located on approximately 9,600 acres in Kenedy County, TX and is entirely on land owned by a single private landowner. Gulf Wind entered into an easement agreement with a single landowner on May 9, 2007 for an initial term of 30 years and with an option to extend for an additional 10 years. The land, which is primarily grassland and dunes, is part of a very large ranch. In addition to our wind operations, the ranch is also used for cattle raising, oil & gas production, and private hunting outings. Due to the afternoon sea breeze effect along the coast, Gulf Wind benefits from an average daily wind production profile that generally follows the typical electricity demand load profile, which is heaviest during the daytime.

Hatchet Ridge

Hatchet Ridge is a 101 MW project located in Burney, California. The project consists of 44 2.3 MW Siemens turbines and commenced commercial operations in December 2010. The project is connected to the PG&E transmission system.

The project sells 100% of its electricity generation, including environmental attributes, to PG&E under a 15-year PPA that expires in 2025. The price under the PPA is a stated price per MWh, adjusted by seasonal time of day multipliers, with no escalation. Hatchet Ridge is required to post performance security in the amount of $21.2 million to secure damages under the PPA. The PPA also contains customary termination and event of default provisions. Under the terms of the PPA, Hatchet Ridge is required to pay liquidated damages for failure to produce a certain amount of energy in each of two consecutive years.

The project, located along a gentle ridge top, spans an area of roughly 2,700 acres in Shasta County, CA and is entirely on land owned by two private landowners, subject to 30-year wind power ground lease agreements.

St. Joseph

St. Joseph is a 138 MW project located near St. Joseph, Manitoba, just north of the U.S. border. The project consists of 60 2.3 MW Siemens turbines and commenced commercial operations in April 2011. The project is connected to the Manitoba Hydro transmission system. St. Joseph was the second commercial wind power project, and is the largest, in Manitoba.

The project sells 100% of its electricity generation, including environmental attributes, to Manitoba Hydro under a 27-year PPA that expires in 2039. The price under the PPA is a stated price per MWh at inception of the PPA, with approximately 20% of the stated price escalating annually at the consumer price index for Canada, or “Canadian CPI.” The project will additionally receive the ecoEnergy federal incentive of C$10/MWh for approximately ten years for up to 423,108 MWh of production per year. Under the PPA, if there is a sale of the project, Manitoba Hydro has a right of first offer to purchase the St. Joseph project for a fixed minimum purchase price on terms specified by us. In addition to customary termination and event of default provisions, the PPA will terminate upon the exercise by Manitoba Hydro of its right of first offer to purchase the St. Joseph project, and St. Joseph will trigger an event of default, if after the first three contract years, it fails to supply at least 80% of certain minimal energy obligations for two consecutive years.

The project is located on approximately 125 square kilometers of agricultural land in the Rural Municipalities of Montcalm and Rhineland, Province of Manitoba. The project is constructed on privately owned lands pursuant to right-of-way agreements with 64 private landowners, with 40-year terms and all on substantially the same form of agreement covering all of turbine sites, collection lines, roads and an operations and maintenance building for the project. In addition, the project purchased a small parcel of property for the project substation.

Spring Valley

Spring Valley is a 152 MW project located in White Pine County, Nevada. The project consists of 66 2.3 MW Siemens turbines and commenced commercial operations in August 2012. The project is connected to the NV Energy transmission system. Spring Valley was Nevada’s first commercial wind power project.

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The project sells 100% of its electricity generation, including environmental attributes, to NV Energy, under a 20-year PPA that expires in 2032. The price under the PPA is a stated price per MWh escalating at 1.0% per year. Spring Valley is required to reimburse NV Energy for replacement costs for any annual energy shortfall and post operating security in the amount of $6.3 million for the performance of its obligations under the PPA. The PPA also contains customary termination and event of default provisions. In connection with the PPA and subject to certain pricing conditions, NV Energy was granted an option to acquire up to 50% of the equity membership interests in Spring Valley held by our project-level operating subsidiary, which option expires in August 2014. NV Energy’s right to acquire the equity membership interests is subject to negotiation of terms and conditions that are acceptable to us. If we fail to agree on terms within 120 days of commencing negotiations, we have the right to terminate the option. In any event, if the option is exercised, the exercise price for the option is up to 50% of the fair market value of the Spring Valley project based on its assets and liabilities at the time of exercise and assuming a 25-year life of the Spring Valley project, provided that in no event will the agreed price result in a book loss to us.

The project is located on approximately 7,680 acres in White Pine County, NV on federal land administered by the Bureau of Land Management. Spring Valley was granted a right-of-way from the Bureau of Land Management with a 30-year term, which terminates on December 31, 2040.

Santa Isabel

Santa Isabel is a 101 MW project located on the south coast of Puerto Rico. The project consists of 44 2.3 MW Siemens turbines and commenced commercial operations during the fourth quarter of 2012. The project is connected to the Puerto Rico Electric Power Authority, or “PREPA,” transmission system. Santa Isabel is Puerto Rico’s first commercial wind power project and is reflective of the Puerto Rican government’s efforts to diversify its energy sources away from fossil fuels by fostering local renewable energy projects.

The project sells 100% of its electricity generation including environmental attributes to PREPA under a 20-year PPA, expiring in 2030, with automatic 5-year extensions unless terminated at the end of any term or extension by us, and PREPA may terminate after year 25 if there is a liquid spot market for electricity or the agreement has been in effect for 30 years. Under the PPA, PREPA has agreed to purchase electricity from us subject to a 75 MW per hour cap, with such cap increasing to 95 MW during certain hours of certain months. If the project is capable of generating electricity in excess of the applicable cap, PREPA has the option, but not the obligation, to purchase any such surplus electricity actually generated at the PPA price. The price for energy under the PPA and the price for RECs under a separate purchase agreement are both a stated price per MWh. Each price escalates at 1.5% per year. In the case that project electricity generation exceeds a threshold multiple of contractual electricity generation in a given year, the price for energy under the PPA reduces until output drops below contractual output for such year. Santa Isabel is required to post operating security in the amount of $3.0 million for the performance of its obligations under the PPA. In addition to customary termination and event of default provisions, the PPA may terminate if Santa Isabel fails to generate a threshold energy output during any 12 consecutive months.

The project is located on approximately 5,500 acres of land owned by the Puerto Rico Land Authority, or “PRLA,” which is actively farmed by private operations under land leases with the PRLA. The project entered into a deed of lease, easements and restrictive covenants with the PRLA on October 6, 2011, with a 30-year initial term, together with up to 45 years in renewal options, comprising substantially all project infrastructure, including all turbine sites, collection lines, roads, substation and operations and maintenance buildings for the project. The project also has entered into transmission line leases for the transmission line corridor from the project substation to the point of interconnection with PREPA with four private landowners.

Ocotillo

Ocotillo is a 265 MW project located in western Imperial County, California. The project consists of 112 2.37 MW Siemens turbines. We initially commenced commercial operations on 223 MW of Ocotillo’s electricity

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generating capacity during the fourth quarter of 2012 and commenced commercial operations on the remaining 42 MW of electricity generating capacity from Ocotillo’s additional 18 turbines in July 2013. The project connects to the San Diego Gas & Electric, or “SDG&E,” 500 kV transmission system and has a large generator interconnection agreement with SDG&E and CAISO.

The project sells 100% of its electricity generation, including capacity and environmental attributes, to SDG&E under a 20-year PPA. The PPA has a stated price per MWh with no escalation. Ocotillo is required to post performance security in the amount of $26.7 million to secure damages. The PPA also contains customary termination and event of default provisions. Under the PPA, Ocotillo is required to pay liquidated damages for failure to produce a certain amount of energy in the two previous years.

Ocotillo is the subject of active lawsuits brought by a variety of project opponents. See Item 3 “Legal Proceedings.”

The project is located on approximately 12,500 acres in Imperial County, CA and is almost entirely on federal land administered by Bureau of Land Management. The project was granted a right-of-way from the Bureau of Land Management with a 30-year term, which terminates on December 31, 2041. All the project’s turbine sites, a substation and an operations and maintenance building are located on land administered by the Bureau of Land Management. The project has entered into collection and distribution line easements with two private landowners for a portion of the underground collection system. In addition, the project has purchased a small parcel of land for a portion of the underground collection system. The project also has a lease agreement in place with a private landowner for an additional 26 acres of private land.

Construction Projects

South Kent

South Kent is a 270 MW project located in the municipality of Chatham-Kent in southern Ontario. The project will consist of 124 2.3 MW Siemens turbines that have been de-rated to a range from 1.903 MW to 2.221 MW in order to facilitate permitting compliance. The project will connect to the Hydro One Networks, Inc., or “HONI,” 230 kV transmission system at the existing Chatham switching station. The South Kent project commenced construction in the first quarter of 2013 and is expected to commence commercial operations in the second quarter of 2014. Project construction is being performed by an affiliate of RES-Americas, a leading wind power construction provider with whom we have worked in the past.

The project will sell 100% of its electricity generation, including environmental attributes, to the OPA under a 20-year PPA. The PPA has a stated price, which indexes at Canadian CPI from September 2009 until the December 31 of the year prior to commencement of commercial operations; thereafter 20% of the PPA price escalates at Canadian CPI. The PPA was granted in connection with the Green Energy Investment Agreement, an agreement among Samsung, Korea Electric Power Corporation and the Province of Ontario. This agreement supports growth in domestic renewable energy through both jobs creation and support of wind power and solar power projects.

The project is a 50/50 joint venture between us and Samsung, with shared development and financing responsibilities. Samsung has customary rights to purchase our interest in South Kent upon any subsequent sale of the project by us.

The project is located on approximately 165 distinct private land parcels and includes a conglomeration of multiple acquired wind power projects and greenfield acquired lands. The project has renegotiated and standardized each of the land agreements that were assumed along with the acquired projects. All land parcels containing project infrastructure are contracted under registered right-of-way agreements, providing for real estate interests in favor of the project in the form of easements-in-gross in respect of each land parcel, enforceable for a term of not less than 40 years.

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The project’s generation tie to the HONI transmission system is being constructed on real estate comprised primarily of 26 kilometers of an abandoned railway corridor running across the project area, together with additional private land transmission easements and ancillary interests.

El Arrayán

El Arrayán is a 115 MW project located on the coast of Chile, near Ovalle in the Fourth Region. The project consists of 50 2.3 MW Siemens turbines and is presently under construction, with commercial operations scheduled for the second quarter of 2014. The project will connect to the Sistema Interconectado Central’s, or “SIC,” 220kV transmission system. El Arrayán will be Chile’s largest commercial wind power project and is reflective of the Chilean government’s efforts to diversify its energy sources away from fossil fuels by fostering local renewable energy projects.

The project will sell its electricity generation into the Chilean spot market at the prevailing market price at the time of sale. Approximately 75% of the project’s expected output has been hedged under a 20-year fixed-for-floating swap escalating at 1.5% annually with Minera Los Pelambres, or “MLP,” one of the world’s largest copper mines. The hedge includes the transfer of environmental attributes to MLP. The project has also entered into a 20-year PPA with MLP to acquire from the market and supply MLP with up to 40 MW of capacity and related energy. This PPA is a purely cost pass-through arrangement intended to firm the power supplied to MLP, under which MLP will reimburse the project for amounts incurred.

Project construction is being performed by Skanska Chile SA, a subsidiary of Skanska AB and one of the leading wind-focused construction firms in Chile, having recently built two projects over 35 MW. As of December 2013, construction efforts remain on schedule and on budget.

We are a minority owner of El Arrayán. The project is owned 30% by Antofagasta Minerals SA, or “AMSA,” and 70% by a joint venture between us and AEI El Arrayán Chile SpA. We own 45% of the joint venture such that our net ownership in the project is 31.5%. AEI El Arrayán Chile SpA holds the other 55% of the joint venture. The other equity owners of El Arrayán have customary rights to purchase our interest in the project upon any subsequent sale of the project by us.

The project is located on approximately 15,320 acres of coastal land and is leased from a single landowner. The land is not presently used for any residential or other commercial purposes. The project entered into the lease agreement with Sociedad Inmobiliaria Correa y Compańía Limitada on January 4, 2012, with a 30-year term covering the project site and comprising all of the turbine sites, collection lines, roads, a project substation and an operations and maintenance building for the project. The project has entered into easement agreements with three private landowners and a usufruct agreement with another landowner, together for the approximately 22 kilometer transmission line corridor from the project substation to the point of interconnection with Transelec S.A.

Mining rights are entirely separate from surface rights in Chile and must be controlled in order to prevent interference by a third party. The project has mining rights for all of its planned infrastructure including the turbines and operational facilities, the interconnecting transmission line and all main roads which are not public.

Grand

Grand is a 148.6 MW project located in Haldimand County in southern Ontario. The project will consist of 67 2.3 MW Siemens turbines that have been de-rated to a range from 2.126 MW to 2.221 MW in order to facilitate permitting compliance. The project will connect to the Hydro One Networks, Inc., or “HONI,” transmission system via a shared transmission line that is co-owned with an adjacent solar facility. The Project has executed a co-ownership agreement that ensures unimpeded access across the shared transmission line to the HONI system. The Grand project commenced construction in the third quarter of 2013 and is expected to commence commercial operations in the fourth quarter of 2014. Project construction is being performed by an affiliate of Samsung C&T Corporation, an experienced global infrastructure construction provider.

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The project will sell 100% of its electricity generation, including environmental attributes, to the OPA under a 20-year PPA. The PPA has a stated price, which indexes at Canadian CPI from September 2009 until the December 31 of the year prior to commencement of commercial operations; thereafter 20% of the PPA price escalates at Canadian CPI. The PPA was granted in connection with the Green Energy Investment Agreement, an agreement among Samsung, Korea Electric Power Corporation and the Province of Ontario. This agreement supports growth in domestic renewable energy through both jobs creation and support of wind power and solar power projects.

The project is a 45/45/10 joint venture between us, Samsung and the Six Nations. Samsung has customary rights to purchase our interest in South Kent upon any subsequent sale of the project by us.

All real estate rights needed for the construction and operation of the project have been secured. The Project is being constructed on a combination of leased privately owned farm properties (as to 58 turbines) and leased lands owned and managed by Ontario Infrastructure and Lands Corporation (“OILC”) (as to 9 turbines). All parcels containing Project infrastructure are governed by the terms of standardized leases and easements with terms of a minimum of 45 years (including all renewal periods). The Project’s transmission line is to be constructed primarily on a major public road allowance pursuant to a Road Use Agreement (with a registered easement).

The transmission facilities also include a collector substation located on OILC lands, underground transition stations located on two private properties and an interconnection station located on lands controlled by a local aggregate producer. Collector lines and ancillary project infrastructure will be located within public road allowance throughout Haldimand County pursuant to a Road Use Agreement with the municipality.

Panhandle 2

Panhandle 2 is a 181.7 MW project located in the Texas Panhandle in Carson County, Texas. The project will consist of 79 2.3 MW Siemens SWT 2.3-108 turbines and is expected to commence commercial operations in the fourth quarter of 2014. We have entered into a commitment to acquire Panhandle 2, together with three institutional tax equity investors, from Pattern Development upon completion of construction. We expect to hold an approximately 80% ownership interest and receive the majority of cash flow throughout the project’s life.

The project is located in the West Zone of the ERCOT market and will sell 100% of its power output into the ERCOT market, receiving the locational marginal price, or “LMP.” Approximately 80% of the project’s expected annual electricity generation has been hedged under a physical power hedge with an affiliate of Morgan Stanley with a tenor in excess of ten years. This hedging agreement settles using the North Trading Hub hourly LMP weighted by the settlement volume in each hour. The hourly notional settlement volume varies to match the project’s hourly average production profile. Panhandle 2’s obligations under the hedge will be secured by a first priority lien on substantially all of the assets of Panhandle 2 and a first priority lien on the membership interests in the project entity.

The project will be connected to the ERCOT grid via a new 345kV transmission line owned by Cross Texas Transmission, LLC, which is part of the Texas Competitive Renewable Energy Zone (“CREZ”) program. The project is located on approximately 11,840 acres of private land pursuant to 40-year easement agreements with approximately 20 private landowners, all of which agreements are in substantially the same form. The project’s operations and maintenance building will be shared with Pattern Development’s neighboring Panhandle 1 project.

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Item 3. Legal Proceedings.

Ocotillo

On April 25, 2012, the County of Imperial certified a Final Environmental Impact Report and Environmental Impact Statement, and entered into a project implementation agreement, or “County Agreement,” regarding the Ocotillo project. On May 11, 2012, the Bureau of Land Management issued a Record of Decision, or “ROD,” and granted a right-of-way relating to the Ocotillo project. The ROD, right-of-way and County Agreement, which we collectively refer to as the “Approvals,�� allow Ocotillo to construct the project. Following issuance of the Approvals, a total of six lawsuits were filed in court by various local opposition groups alleging that the Approvals were not appropriately issued. While initially one of the six lawsuits was filed in state court, the state lawsuit was removed to the U.S. District Court for the Southern District of California and was later remanded back to the state court. In three lawsuits, the plaintiffs sought preliminary equitable relief to enjoin the construction of the project while the court decided the claims, and in each instance, the court rejected such request and allowed project construction to continue. The project has since been completed and has achieved commercial operations. In addition, the courts have subsequently dismissed all of the lawsuits. At present, three of the dismissals were appealed to the U.S. Court of Appeals for the Ninth Circuit. The time to appeal two of the dismissed cases has lapsed. The state lawsuit that was removed to the federal district court was remanded to state court following a motion by the plaintiff, was dismissed on January 28, 2014, and plaintiffs have 60 days to appeal.

We do not believe these proceedings will have a material adverse effect on our business, financial position or liquidity based on the information currently available to us, principally because attempts to enjoin the construction of the project have failed, and, subject to the pending appeals and the one remaining potential appeal described above, the actively adjudicated lawsuits have all been dismissed. We initially commenced commercial operations on 223 MW of Ocotillo’s electricity generating capacity during the fourth quarter of 2012 and commenced commercial operations on the remaining 42 MW of electricity generating capacity from Ocotillo’s additional 18 turbines in July 2013. We believe, but can give no assurance, that the remaining litigation will ultimately be resolved favorably to the project.

Other Proceedings

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.

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PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters.

Our Class A common stock began trading on the NASDAQ Global Market under the symbol “PEGI” and on the Toronto Stock Exchange under the symbol “PEG” on September 27, 2013. Prior to that time, there was no public market for our stock. Our Class B common stock is held by Pattern Development and certain of our executive officers and is neither listed nor traded.

As of February 25, 2014, we had issued and outstanding 35,548,051 shares of Class A common stock, which were held of record by approximately 18 stockholders. Our low number of record holders is because all of the shares issued in our initial public offering are held through the Depository Trust Company. The closing price of our Class A common stock was $27.01 per share as reported by the NASDAQ Global Market. 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.

The following table sets forth the range of high and low sales prices of the Class A common stock on the NASDAQ Global Market and the Toronto Stock Exchange.

	Class A Common Stock Price Ranges
Quarter Ended	High		Low
December 31, 2013	$	30.31	$	22.25

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 (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 under the Securities Act of 1933, as amended, or the Exchange Act.

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The following graph shows a comparison from September 27, 2013 (the date our Class A common stock commenced trading on the NASDAQ Global Select Market) through December 31, 2013 of the cumulative total stockholder return for our Class A common stock, the NASDAQ Composite Index (“NASDAQ Composite”) and the Bloomberg Global Wind 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, the NASDAQ Composite and the Bloomberg Global Wind Index and also assumes reinvestments of dividends. The stock price performance of the following graph is not necessarily indicative of future stock price performance.

Cash Dividend Policy

We intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A shares. Our quarterly dividend has been initially set at $0.3125 per Class A share, or $1.25 per Class A share on an annualized basis, and the amount may be changed in the future without advance notice. We have established our initial quarterly dividend level based on a targeted cash available for distribution payout ratio of 80% both prior to and following the Conversion Event, after considering the annual cash available for distribution that we expect our projects will be able to generate following the commencement of commercial operations at all of our construction projects 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 Class A share over time. However, the determination of the amount of cash dividends to be paid to holders of our Class A shares will be made by our Board of Directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant. See Item 1A “Risk Factors—Risks 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 30^th day following each fiscal quarter to holders of record of our Class A shares on the last day of such quarter. We paid our first dividend on January 30, 2014 to holders of record on December 31, 2013.

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 shares in quarters in which we do not generate sufficient

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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.

Cash Available for Distribution

Our management team considers various financial performance and liquidity measures, including net income, Adjusted EBITDA and cash available for distribution, in assessing the amount of cash that we expect our projects will be able to generate during a given period. Adjusted EBITDA and cash available for distribution are non-U.S. GAAP financial measures that we intend to use to assist us in determining whether we are generating cash flow at a level that can sustain, or support an increase in, our dividend.

We believe that an understanding of cash available for distribution is useful to investors in evaluating our ability to pay dividends pursuant to our stated cash dividend policy. We define “cash available for distribution” as net cash provided by operating activities, determined in accordance with U.S. GAAP, as adjusted by:

• adding or subtracting changes in operating assets and liabilities;

• subtracting 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;

• subtracting cash distributions paid to noncontrolling interests, which currently reflects the cash distributions to our joint venture partners in our Gulf Wind project in accordance with the provisions of its governing partnership agreement and will in the future reflect distribution to other joint venture partners;

• subtracting 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;

• subtracting non-expansionary capital expenditures, to the extent they are paid from operating cash flows during a period; and

• adding or subtracting other items as necessary to present the cash flows we deem representative of our core business operations.

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Repurchase of Equity Securities

The table below sets forth the information with respect to purchases made by the Company of its common stock during the fourth quarter of the year ended December 31, 2013. All shares were purchased from employees and represent shares withheld under the terms of grants under the Pattern Energy Group Inc. 2013 Equity Incentive Award Plan to offset tax withholding obligations that occur upon the release of restricted shares.

Repurchase Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Repurchased as Part of Publicly Announced Repurchase Plan		Dollar Value of Maximum Number of Shares to Purchased under the Plan
10/2/13 - 10/31/13		312	$	22.98		N/A	$	—
11/1/13 - 11/30/13		311		24.39		N/A		—
12/1/13 - 12/31/13		311		30.37		N/A		—
		934	$	25.91			$	—

Unregistered Sales of equity Securities and Use of Proceeds

In connection with the contribution of certain projects to the Company by Pattern Development at the time of our initial public offering, the Company issued to the selling stockholder 19,445,000 Class A shares and 15,555,000 Class B shares as consideration for the assets that were contributed to the Company.

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Item 6. Selected Financial Data.

Set forth below is our summary historical consolidated financial data. The consolidated statements of operations data for the years ended December 31, 2013, 2012 and 2011 and the consolidated balance sheet data as of December 31, 2013 and 2012 are derived from our audited consolidated financial statements included in this Form 10-K. The consolidated balance sheet data as of December 31, 2011 is derived from our audited consolidated financial statements not included in this Form 10-K. 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 7 “Management’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,
	2013			2012			2011
	(in thousands)
Statement of Operations Data:
Revenue:
Electricity sales	$	173,270		$	101,835		$	108,770
Energy derivative settlements		16,798			19,644			9,512
Unrealized (loss) gain on energy derivative		(11,272	)		(6,951	)		17,577
Related party revenue		911			—			—
Other revenue		21,866			—			—
Total revenue		201,573			114,528			135,859
Cost of revenue:
Project expenses		57,677			34,843			31,343
Depreciation and accretion		83,180			49,027			39,424
Total cost of revenue		140,857			83,870			70,767
Gross profit		60,716			30,658			65,092
Total operating expenses		12,988			11,636			9,668
Operating income		47,728			19,022			55,424
Total other income (expense)		(33,110	)		(36,002	)		(28,829	)
Net income (loss) before income tax		14,618			(16,980	)		26,595
Tax (benefit) provision		4,546			(3,604	)		689
Net income (loss)		10,072			(13,376	)		25,906
Net (loss) income attributable to noncontrolling interest		(6,887	)		(7,089	)		16,981
Net income (loss) attributable to controlling interest	$	16,959		$	(6,287	)	$	8,925
Unaudited pro forma net income (loss) after tax:
Net loss before income tax				$	(16,980	)
Pro forma tax provision					818
Pro forma net loss				$	(17,798	)

	December 31,
	2013		2012		2011
	(in thousands)
Balance Sheet Data:
Cash	$	103,569	$	17,574	$	47,672
Construction in progress		—		6,081		201,245
Property, plant and equipment , net		1,476,142		1,668,302		784,859
Total assets		1,903,631		2,035,730		1,390,426
Long-term debt		1,249,218		1,290,570		867,548
Total liabilities		1,335,627		1,446,318		943,728
Total equity before noncontrolling interest		468,210		514,111		362,226
Noncontrolling interest		99,794		75,301		84,472
Total equity		568,004		589,412		446,698

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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 Note 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. Including the Panhandle 2 project, which we have agreed to acquire from Pattern Development, and which we expect to acquire before the end of 2014, we hold interests in ten wind power projects located in the United States, Canada and Chile that use proven, best-in-class technology and have a total owned capacity of 1,255 MW, consisting of six operating projects and four projects under construction that are all scheduled to commence commercial operations prior to the end of 2014. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price power sale agreement with a creditworthy counterparty. Ninety-three percent of the electricity to be generated by our projects, including the Panhandle 2 project to be acquired from Pattern Development in late 2014, will be sold under these power sale agreements, which have a weighted average remaining contract life of approximately 18 years.

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 the core values of creating a safe, high-integrity and exciting work environment; applying rigorous analysis to all aspects of our business; and proactively working with our stakeholders in addressing 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 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 Pattern Development and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per share over time. We expect our continuing relationship with Pattern Development, a leading developer of renewable energy and transmission projects, will be an important source of growth for our business.

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 those affecting our industry generally and those that could specifically affect our existing projects and our ability to grow.

Recent Transactions

On October 2, 2013, we issued 16,000,000 shares of Class A common stock in an initial public offering generating net proceeds of approximately $317 million. Concurrently with the completion of the initial public offering, we issued 19,445,000 shares of Class A common stock and 15,555,000 shares of Class B common stock to Pattern Development and utilized approximately $233 million of the net proceeds of the initial public offering as the cash portion of the consideration paid to Pattern Development for the Contribution Transactions and repaid

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a $56.0 million outstanding balance of our revolving credit facility. On October 8, 2013, our underwriters exercised in full their overallotment option to purchase 2,400,000 shares of Class A common stock from Pattern Development, the selling stockholder, pursuant to the overallotment option granted by Pattern Development in connection with the initial public offering.

In connection with the contribution of certain projects to the Company by Pattern Development at the time of our initial public offering, Pattern Development retained a 40% portion of the interest in Gulf Wind previously held by it (equivalent to a 27% interest in the project) such that, following the completion of the initial public offering, we, Pattern Development and our joint venture partner hold interests of approximately 40%, 27% and 33%, respectively, of the distributable cash flow of Gulf Wind, together with certain allocated tax items. On December 20, 2013, we entered into agreements with Pattern Development to acquire its ownership interests in the Grand and Panhandle 2 wind projects. On that date, we acquired a 67 MW interest in the 149 MW Grand project for a cash purchase price of $79.5 million and we agreed to acquire a 147 MW interest in the 182 MW Panhandle 2 project upon the completion of its construction (the “Panhandle 2 closing date”) for a cash purchase price of $122.9 million, subject to certain price adjustments based on final project size, design and modeling assumptions, to be funded on the Panhandle 2 closing date. Both projects are currently under construction, are expected to commence commercial operations in the fourth quarter of 2014, and upon completion of the Panhandle 2 acquisition, will increase our total owned capacity to 1,255 MW.

These two project interests represent a portion of the Initial ROFO Projects and are the first two acquisitions that Pattern Energy expects to make from Pattern Development in connection with its project purchase rights. Panhandle 2, with a rated capacity of approximately 182 MW, is a larger project than we expected at the time of the initial public offering. The status of the remaining Initial ROFO Projects is summarized in the table below:

								Capacity (MW)
Remaining Initial ROFO Projects	Status	Location	Construction Start(1)		Commercial Operations(2)		Contract Type	Rated(3)		Pattern Development- Owned(4)
Gulf Wind	Operational	Ontario		2008		2009	Hedge		283		76
Panhandle 1	In Construction	Texas		2013		2014	Hedge		218		179
K2	Financing in process	Ontario		2014		2015	PPA		270		90
Armow	Ready for financing	Ontario		2014		2015	PPA		180		90
Meikle	Pre-Construction	British Columbia		2015		2016	PPA		175		175
									1,126		610

⁽¹⁾  Represents date of actual or anticipated commencement of construction.

⁽²⁾ Represents date 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 wind and other conditions, a project or a turbine will not operate at its rated capacity at all times and the amount of electricity generated will be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors discussed elsewhere in this Form 10K.

⁽⁴⁾  Pattern Development-owned capacity represents the maximum, or rated, electricity generating capacity of the project multiplied by Pattern Development’s percentage ownership interest in the distributable cash flow of the project.

The project entity which owns the Grand project is fully financed with equity contributions from its owners, which were funded prior to our acquisition, and loan commitments from a consortium of commercial banks, which provided construction and term financing for the project. The project will sell all of its electrical output to the Ontario Power Authority.

The project entity which owns the Panhandle 2 project is fully financed with equity contributions from its owners, which were funded prior to our acquisition, and loan commitments from a commercial bank, which

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provided construction financing for the project. Three institutional tax equity investors have agreed, subject to certain customary conditions precedent, which we expect will be satisfied, to provide equity contributions to the project holding company upon completion of construction; these contributions from us and from the institutional tax equity investors will be used to repay in full the then outstanding construction loan balances and the project entity will accordingly not have any term debt when it commences commercial operations. The project will sell approximately 80% of its expected annual average electrical output to an affiliate of Morgan Stanley under a fixed-for-floating energy swap with a term of over ten years, and the balance of its electrical output in the ERCOT spot market and will market its RECs separately.

Trends Affecting our Industry

Wind and solar power have been among the fastest growing sources of electricity generation in North America and globally over the past decade. This rapid growth is largely attributable to wind and solar power’s increasing cost competitiveness with other electricity generation sources, the advantages of wind and solar power over many other renewable energy sources and growing public support for renewable energy driven by concerns about security of energy supply and the environment. We expect these trends to continue to drive future growth in the wind power industry.

We believe that the key drivers for the long-term growth of wind power in North America include:

• overall and regional demand for new power plants resulting from regulatory or policy initiatives, such as state or provincial RPS programs, motivating utilities to procure electricity supply from renewable resources;

• 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;

• governmental incentives, including PTCs, which improve the cost competitiveness of renewable energy compared to traditional sources;

• environmental and social factors supporting increasing levels of wind, solar and other renewable technologies in the generation mix:

• regulatory barriers 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;

• policy initiatives to include the cost of carbon pollution in conventional fossil fuel-fired electricity generation will increase costs of conventional generation; and

• price volatility for natural gas used for electricity generation.

Uncertainty related to the demand for power, generally, and thus the need for new power projects, and the expiration of U.S. federal incentives resulted in a reduction in the build rate of wind and solar power and other renewable energy projects in 2013, compared to 2012, and these trends may continue to dampen that build rate in 2014 and beyond. We expect these adverse effects to be partially or fully offset in certain markets by regional requirements for new power projects due to older power project retirements, passage of an extension or modification of the U.S. federal tax incentives or other government actions in support of new wind power projects, a potential return to higher natural gas prices, desire, on the part of regulatory commissions and ratepayers, for more stable power sale agreements such as those which wind and solar power projects are ideally suited to provide, and increased difficulty in permitting conventional power projects. In the long term, we believe that substantial growth potential remains in the U.S. market.

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In addition, we continue to see more opportunities to acquire wind and solar projects in the North America market than has been typical for the past decade. Three factors are driving this accelerated activity level:

• We believe that many project developers have scaled back their wind project development teams and investment activity in reaction to the prior or anticipated potential expirations of PTC and ITC cash grant programs and continued uncertainty about federal, state and provincial energy policies and as a result of perceptions about slower market growth in the near term;

• A number of large European utilities that have been major participants in the U.S. wind power market appear to be strengthening their consolidated balance sheets due to their own home market issues by selling portions of their U.S. investment portfolios;

• The emergence of “yieldcos” has provided a new class of investors with an appetite for investment in contract-based renewable power projects.

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 resume following the determination of federal government policy. We have seen this occur in previous periods when tax credit extensions were uncertain, and we consider it likely to happen again in the coming years. We are a relatively small company involved in a large and somewhat fragmented market in which we believe our fully integrated approach to the business allows us to assess and execute on market opportunities quickly.

Our Outlook

Our projects are generally unaffected by the short-term trends discussed above, given that 93% of the electricity to be generated by our projects will be sold under our fixed-price power sale agreements, which have a weighted average remaining life of approximately 18 years, the geographic diversity of our projects and the limited impact that expiring U.S. federal incentives will have upon completion of our construction projects in the United States, Canada and Chile.

Our near-term growth strategy will focus on wind power projects, but will also include evaluation of solar power opportunities, and is largely insulated from the short-term trends. We expect that most of our short-term growth will come from opportunities to acquire the Initial ROFO Projects, including those located in Ontario, which have executed power sale agreements with terms substantially similar to our South Kent and Grand PPAs, Pattern Development’s Panhandle projects, which have already qualified for PTCs and which have long-term power sales agreements in the form of energy hedge contracts, pursuant to our Project Purchase Right and the Pattern Development retained Gulf Wind interest pursuant to our Gulf Wind Call Right.

Factors Affecting Our Operational Results

The primary factors that will affect our financial results are (i) the timing of commencement of commercial operations at our construction projects, (ii) the amount and price of electricity sales by our operating projects, (iii) accounting for derivative instruments, (iv) acquisitions of new projects, (v) achievement of efficient project operations, and (v) interest expense on our corporate- and project-level debt.

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Timing of Commencement of Commercial Operations at Our Construction Projects

Including the Panhandle 2 project which we have agreed to acquire from Pattern Development, and which we expect to acquire before the end of 2014, our construction projects include interests in four projects that we expect will contribute an additional operating capacity of 385 MW in 2014, for an aggregate owned capacity of 1,255 MW together with our operating projects. Our near-term operating results will, in part, depend upon our ability to transition these projects into commercial operations in accordance with our existing construction budgets and schedules. The following table sets forth each of our construction projects as well as their respective power capacities and our anticipated date of their commencement of commercial operations.

Projects	Location	Construction Start	Commercial Operations	MW
				Rated		Owned
South Kent	Ontario	Q1 2013	Q2 2014		270		135
El Arrayán	Chile	Q3 2012	Q2 2014		115		36
Panhandle 2(1)	Texas	Q4 2013	Q4 2014		182		147
Grand	Ontario	Q3 2013	Q4 2014		149		67
					716		385

⁽¹⁾  Acquisition scheduled to occur in the fourth quarter of 2014

We are constructing our projects under fixed-price and fixed-schedule contracts with major equipment suppliers and experienced balance-of-plant constructors. Under our management team’s supervision, Pattern Development completed the construction of our Hatchet Ridge, St. Joseph, Spring Valley, Santa Isabel and Ocotillo projects on time and within budget. Including their time together before forming Pattern Development, our management team has constructed and placed into service 25 wind power projects with an aggregate generating capacity of over 2,600 MW. In 2014, we expect that our four joint-venture projects, South Kent, El Arrayán, Grand and Panhandle 2, will commence commercial operations and add an additional 385 MW of owned capacity to our operating project portfolio.

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. Ninety-three percent of the electricity to be generated across our projects is currently committed under long-term, fixed-price power sale agreements with creditworthy counterparties, which have a weighted average remaining contract life of approximately 18 years.

Wind conditions and equipment performance represent the primary factors affecting our near-term operating results because these variables impact the volume of the electricity that we are able to generate from our operating projects.

Our revenue from electricity sales and energy derivative settlements during a period is primarily a function of the amount of electricity generated by our projects. The electricity generated from our power projects depends primarily on wind and weather conditions at each specific site 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 includes 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 performance of our equipment over time. Although wind conditions in 2013 were below the assumptions that drive our long-term production expectations, the longer term data continues to support our production forecast and we have not changed our expected annual average output from our existing projects.

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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 exceedance 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 improvement 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 92% 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 95% of our aggregate P50 output level. On a portfolio basis, our P90 and P95 production estimates for the annual electricity generation of our ten projects, once they are all fully operational, are approximately 90% and 87%, 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). This is demonstrated in the following diagram:

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. We employ (or will employ) the Siemens 2.3 MW turbine at nine of our ten project sites and the Mitsubishi MWT95/2.4 at the tenth. With a combination of high-quality equipment and scale, 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 maintain a shared spare parts inventory 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.

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In May 2013, a blade separated from the turbine hub on one of the wind turbines at our Ocotillo project following which we shut down all of the SWT-2.3-108 turbines utilized only at Ocotillo and Santa Isabel projects, pending determination of the cause. Siemens completed, and we accepted, a root cause analysis, a remediation plan, including inspection, repair or replacement, and a return to service program for all of the SWT-2.3-108 blades. Our warranty arrangements with Siemens required that Siemens complete the remediation plan at its cost and pay liquidated damages to us in the event that turbine availability falls below specified thresholds. During 2013,we received warranty liquidated damages from Siemens with respect to our availability warranties. Depending on future performance of the equipment, we may receive additional liquidated damages from Siemens in 2014.

Accounting for Derivative Instruments

We have, and expect to continue to enter into, contracts to hedge against risks related to fluctuations in energy prices and interest rates on our project loans and foreign currency exchange rates. Except with respect to contracts for which we do not elect or do not qualify for hedge accounting, we recognize derivative instruments as assets or liabilities at fair value in our consolidated balance sheets. Our method of accounting for a change in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated as part of a hedging relationship and, if so, on the type of hedging relationship. For derivative instruments that are not so designated, such as our energy derivatives and certain of our interest rate derivatives, changes in fair value are recorded as a component of net income on our consolidated statement of operations. For derivative instruments that are designated as cash flow hedges, the effective portion of the change in the fair value of the instrument is recorded as a component of other comprehensive income. Changes in the fair value of derivative instruments designated as cash flow hedges are subsequently reclassified into net income in the period that the hedged transaction affects earnings. The ineffective portion of changes in the fair value of designated hedges is also recorded as a component of current net income.

The fair value of a derivative is a function of a number of factors, including the duration and notional volume of the derivative and forward price curve for the product to which the derivative applies. In general, there is more volatility in the fair value of derivative instruments that are designed to protect long-dated risks, such as an 18-year loan amortization profile, than those with short durations, such as a two-year foreign currency fixed-for-floating swap. 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 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 stockholders 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 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.

Project Operations

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, 2012 and 2011, our turbine availability across our

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projects was 97.6% and 96.2%, respectively, which is in line with industry standards for original investment projections reviewed by independent engineering firms. For the year ended 2013, our turbine availability across our projects was 88.3%, which was lower than our and industry standards due primarily to the blade issue at our Santa Isabel and Ocotillo projects. It was also affected by certain equipment issues at our Spring Valley project which are covered under manufacturer warranty, which may result in certain liquidated damages being received in 2014, and which are not expected to have a long-term impact on our project operating results. More importantly, we operate our projects to maximize our revenues rather than solely focusing on time-based availability or electricity generation volume. See Item 1 “Business—Organization of Our Business—Operations and Maintenance.” To accomplish this, we provide forward-looking wind forecasts to each of our sites twice a day. Our site managers use this information to plan the maintenance activities for those days, in order to schedule maintenance during low wind periods, where impact to revenues is minimized. In addition, for sites with power prices that vary during different periods, we schedule work to avoid known or anticipated high price periods. For example, on the Hatchet Ridge project in the summer of 2012, we scheduled summer maintenance crews to start work at 5:00 AM and finish by 1:00 PM, in order to have all available turbines operating when peak PPA pricing started at 2:00 PM.

In addition, as a result of the importance we place on safety and implementation of a safety management program, our operating business has experienced no significant lost time events, worksite accidents, or other significant environmental, health or safety, or “EHS,” issues in 2013 or 2012. Certain contractors or subcontractors at our construction sites have had worksite accidents, and we continue to work with these third parties to improve their safety performance.

In 2013 and 2012, we took following steps that should enable us to continue to improve our operating performance at our operating projects:

• We hired site management personnel six months prior to achieving commercial operations at our Spring Valley, Santa Isabel and Ocotillo projects. This allows these individuals to go through an organized training program, which includes time in our Houston office to meet with the operations team, training at one of our existing operating projects, vendor and third-party external training, and focused time setting up project operational and compliance programs before arrival at site. After arrival at site, this time also allows the site management to be intimately involved in the project commissioning process and operational preparations. We also include regular visits from our management, safety, and turbine specialists during this pre-operational period to ensure smooth coordination of start-up.

• At our projects nearing the end of their original turbine manufacturer warranty periods, which includes Hatchet Ridge in October 2012 and St. Joseph in early 2013, we conduct extensive third-party end-of-warranty inspections to identify any potential equipment or service issues that can be remedied by the manufacturer pursuant to their warranty contractual obligations and ensure the sites start their post-warranty periods with reliably functioning equipment. We believe these thorough inspections also provide a solid baseline for equipment condition to drive future maintenance planning. These same end-of-warranty dates on most projects also mark the end of the manufacturer’s service contracts, and we conduct competitive solicitations between both the manufacturers as well as top-tier third-party independent service providers for conducting the turbine service and maintenance in the post-warranty period. At Hatchet Ridge, this solicitation resulted in the selection of leading independent service provider Duke Energy Services, LLC at a significant cost savings, while still ensuring quality of service.

• We implemented a robust NERC compliance program consisting of a suite of policies and procedures, employee training and record keeping systems. This program is run by a full-time in-house regulatory compliance specialist. In August 2012, we completed our first full NERC audit for the Gulf Wind project. The audit was successful, with no findings of any violations, and we were commended by the auditors for our strong regulatory compliance culture.

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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. In the near-term, 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 at our other operating projects and (iii) 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 1.7 to 1.0.

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 revenue, cost of revenue, net income and cash provided by (used in) operating activities, we also consider MWh sold, average realized electricity price and Adjusted EBITDA in evaluating our operating performance and cash available for distribution as supplemental liquidity measures. Each of these key metrics is discussed below.

MWh Sold and Average Realized Electricity Price

The number of MWh sold and the average realized price per MWh sold are the operating metrics that determine our revenue. For any period presented, average realized electricity price represents total revenue from electricity sales and energy derivative settlements divided by the aggregate number of MWh sold.

Adjusted EBITDA

We define Adjusted EBITDA as net income before net interest expense, income taxes and depreciation and accretion, including our proportionate share of net interest expense, income taxes and depreciation and accretion of joint venture investments that are accounted for under the equity method, and excluding the effect of certain other items that the Company does not consider to be indicative of its ongoing operating performance such as mark-to-market adjustments and infrequent items not related to normal or ongoing operations, such as early payment of debt and realized derivative gain or loss from refinancing transactions, and gain or loss related to acquisitions or divestitures. 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 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. Adjusted EBITDA is a non-U.S. GAAP measure.

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The following table reconciles net income (loss) to Adjusted EBITDA for the periods presented and is unaudited (in thousands):

	Pattern Energy Group Inc.
	Year ended December 31,
	2013			2012			2011
	(U.S. dollars in thousands)
Net income (loss)	$	10,072		$	(13,376	)	$	25,906
Plus:
Interest expense, net of interest income		61,118			35,457			28,285
Tax provision (benefit)		4,546			(3,604	)		689
Depreciation and accretion		83,180			49,027			39,424
EBITDA	$	158,916		$	67,504		$	94,304
Unrealized loss (gain) on energy derivative		11,272			6,951			(17,577	)
Unrealized (gain) loss on interest rate derivatives		(15,601	)		4,953			345
Interest rate derivative settlements		2,099			—			—
Gain on transactions		(5,995	)		(4,173	)		—
Plus,our proportionate share in the following from our equity accounted investments:
Interest expense, net of interest income		267			44			—
Tax benefit		(172	)		(65	)		—
Depreciation and accretion		20			—			186
Unrealized (gain) loss on interest rate and currency derivatives		(9,076	)		27			—
Realized loss on interest rate and currency derivatives		39			—			—
Adjusted EBITDA	$	141,769		$	75,241		$	77,258

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 (used in) 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, which currently reflects the cash distributions to our joint venture partners in our Gulf Wind project in accordance with the provisions of its governing partnership agreement and will in the future reflect distribution to other joint venture partners, (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, and (vi) 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 following table presents cash available for distribution for the periods presented and is unaudited (in thousands):

	Pattern Energy Group Inc.
	Year ended December 31,
	2013			2012			2011
Net cash provided by operating activities	$	78,152		$	35,051		$	46,930
Changes in current operating assets and liabilities		8,237			6,885			3,237
Network upgrade reimbursement		1,854			6,263			—
Use of operating cash to fund maintenance and debt reserves		—			(1,047	)		(1,048	)
Release of restricted cash to fund general and administrative costs		318			—			—
Operations and maintenance capital expenditures		(819	)		(623	)		(1,101	)
Less:
Distributions to noncontrolling interests		(2,292	)		(1,298	)		(7,158	)
Principal payments paid from operating cash flows(1)		(42,829	)		(27,546	)		(22,330	)
Cash available for distribution	$	42,621		$	17,685		$	18,530

⁽¹⁾ Excludes $7,495 of principal pre-payments on our Ocotillo project which were paid from ITC cash grant proceeds in 2013

Results of Operations

The following discussion and analysis of financial condition and results of operations relate to the Company and its predecessor presented as a single entity from the beginning of the earliest period presented. For periods prior to October 2, 2013, the Contribution Transaction date, the Company was a shell company, with expenses of less than $10,000 for 2013 and 2012.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

The following table provides selected financial information for the periods presented (in thousands, except percentages):

	Year ended December 31,
	2013			2012			$ Change			% Change
Revenue	$	201,573		$	114,528		$	87,045			76	%
Project expense		57,677			34,843			22,834			66	%
Depreciation and accretion		83,180			49,027			34,153			70	%
Total cost of revenue		140,857			83,870			56,987			68	%
Gross profit		60,716			30,658			30,058			98	%
Development expense		—			174			(174	)		(100	)%
General and administrative		4,819			858			3,961			462	%
Related party general and administrative		8,169			10,604			(2,435	)		(23	)%
Total operating expenses		12,988			11,636			1,352			12	%
Operating income		47,728			19,022			28,706			151	%
Total other expense		(33,110	)		(36,002	)		2,892			8	%
Net income (loss) before income tax		14,618			(16,980	)		31,598			186	%
Tax provision (benefit)		4,546			(3,604	)		8,150			(226	)%
Net income (loss)		10,072			(13,376	)		23,448			175	%
Net loss attributable to noncontrolling interest		(6,887	)		(7,089	)		202			3	%
Net income (loss) attributable to controlling interest	$	16,959		$	(6,287	)	$	23,246			370	%

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MWh sold and average realized electricity price. We sold 2,258,811 MWh of electricity in the year ended December 31, 2013 as compared to 1,673,413 MWh sold in the year ended December 31, 2012. This increase in MWh sold during 2013 as compared to 2012 was primarily attributable to the commencement of commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012. Our average realized electricity price was approximately $84 per MWh in the year ended December 31, 2013 as compared to approximately $73 per MWh in the year ended December 31, 2012. The average realized electricity price in 2013 was higher than the comparable period in 2012 because the pricing terms under the Spring Valley, Santa Isabel and Ocotillo project PPAs are each higher than our overall average realized price applicable in 2012. Although our electricity production was up 35% over the same period last year, it was lower than our expected long term average in 2013. After adjusting for equipment downtime which is reimbursable by the vendor, our electricity production was about 9% below the expected production based on long-term average wind conditions. The 2013 wind conditions are, however, within the range of variability that has been measured in our six operating wind regions over the last 35 years and, after considering these measured results, we have not changed our long-term wind forecast. Particularly noteworthy was the low average wind in the western United States in 2013 which was partly the result of a high pressure zone towards the end of 2013.

Revenue. Revenue for the year ended December 31, 2013 was $201.6 million compared to $114.5 million for the year ended December 31, 2012, an increase of $87.1 million, or approximately 76%. This increase in revenue during 2013 as compared to 2012 was the result of an increase of $71.5 million in electricity sales primarily attributable to the commencement of commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012. Also during the year ended December 31, 2013 we recorded other revenue of $21.9 million related to warranty settlement payments we received from a turbine supplier during the period as a result of the turbines at the Ocotillo and Santa Isabel projects being off line for a portion of the period. The increase in electricity sales in 2013 as compared to 2012 was offset by a decrease of $4.3 million in period-over-period revenue due to energy derivative valuation. In 2013, we recorded a $11.3 million unrealized loss on energy derivative compared to a $7.0 million unrealized loss in 2012. The value of our energy derivative, and the amount of unrealized gain or loss we record, increases and decreases due to our monthly derivative settlements and changes in forward electricity prices, which are derived from and impacted by changes in forward natural gas prices.

Cost of revenue.Cost of revenue for the year ended December 31, 2013 was $140.9 million compared to $83.9 million for the year ended December 31, 2012, an increase of $57.0 million, or approximately 68%. The increase in cost of revenue during 2013 as compared to 2012 was primarily attributable to the commencement of commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012 with depreciation and accretion contributing $34.2 million of the $57.0 million increase in 2013 as compared to 2012. As each new project commences commercial operations, we incur new incremental and ongoing costs for maintenance and services agreements, property taxes, insurance, land lease and other costs associated with managing, operating and maintaining the facility, including adding site employees and operations center staff.

General and administrative expense. General and administrative expense for the year ended December 31, 2013 was $4.8 million compared to $0.9 million for the year ended December 31, 2012, an increase of $3.9 million, or approximately 462%. After the Contribution Transactions and the initial public offering, the Company has direct payroll costs and employee-related, audit and consulting expenses costs, and other administrative costs that were previously allocated to the Company from Pattern Development and which were reflected in Related party general and administrative expense. In addition, the Company has additional general and administrative costs related to being a public company, such as directors fees.

Related party general and administrative expense. Related party general and administrative expense for the year ended December 31, 2013 was $8.2 million compared to $10.6 million for the year ended December 31, 2012, a decrease of $2.4 million, or approximately 23%, resulting primarily from lower cash bonus expense in 2013, as compared to 2012, offset by the increased staffing and overhead costs related to commercial operations commencing at Spring Valley, Santa Isabel and Ocotillo as well as our ownership in El Arrayán and South Kent as construction on these projects advanced in 2013.

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Other expense. Other expense for the year ended December 31, 2013 was $33.1 million compared to $36.0 million for the year ended December 31, 2012. The decrease of $2.9 million in other expense during 2013, as compared to 2012, was primarily related to a $7.9 million increase in equity in earnings in unconsolidated investments, which was primarily attributable to interest rate swaps that were entered into during 2013, which were deemed to be derivatives and not designated as hedges. The gain on these interest rate swaps was attributable to an increase in the forward interest rate curve after these interest rate swaps were entered into. In addition, there was a $20.6 million increase in unrealized gain on derivatives as a portion of our interest rate swaps on the Ocotillo project are not designated as hedges and there was an increase in the forward interest rate curve, which decreases our liability under these interest rate swaps and increases our unrealized gain on derivatives. During the year ended December 31, 2013 we also recorded a $7.2 million gain on the sale of Puerto Rico tax credits at the Santa Isabel project and $1.2 million of transaction expense related to our acquisition of Grand and Panhandle 2 projects as compared to a $4.2 million gain on the sale of a portion of the El Arrayán project in 2012. Offsetting these gains was a $27.1 million increase in interest expense in 2013 attributable to the commencement of commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012 and the resultant cessation of interest capitalization and treatment of interest as expense under the related facilities.

Tax provision. The tax provision was $4.5 million for the year ended December 31, 2013 compared to a $3.6 million benefit for the year ended December 31, 2012. The 2012 benefit was principally the result of the Santa Isabel project holding company being subject to U.S. income taxes and the impact of receipt of a U.S. Treasury cash grant by the Santa Isabel project on a stand-alone basis in 2012 which then required a valuation allowance in 2013 as the Santa Isabel project is included in the Company’s consolidated U.S. income tax return as a result of the Contribution Transactions

Noncontrolling interest. The allocation to noncontrolling interest was a $6.9 million loss for the year ended December 31, 2013 compared to $7.1 million of loss for the year ended December 31, 2012. The noncontrolling interest income or loss calculation is based on the hypothetical liquidation at book value method of accounting for the earnings attributable to the noncontrolling interests’ ownership in Gulf Wind.

Adjusted EBITDA. Adjusted EBITDA for the year ended December 31, 2013 was $141.8 million compared to $75.2 million for the year ended December 31, 2012, an increase of $66.6 million. The increase in Adjusted EBITDA during 2013 as compared to 2012 was primarily attributable to the commencement of operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012. For a reconciliation of net income to Adjusted EBITDA, see “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Metrics—Adjusted EBITDA”

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

The following table provides selected financial information for the periods presented (in thousands, except percentages):

	Year ended December 31,
	2012			2011			$ Change			% Change
Revenue	$	114,528		$	135,859		$	(21,331	)		(16	)%
Project expense		34,843			31,343			3,500			11	%
Depreciation and accretion		49,027			39,424			9,603			24	%
Total cost of revenue		83,870			70,767			13,103			19	%
Gross profit		30,658			65,092			(34,434	)		(53	)%
Development expense		174			704			(530	)		(75	)%
General and administrative		858			866			(8	)		(1	)%
Related party general and administrative		10,604			8,098			2,506			31	%
Total operating expense		11,636			9,668			1,968			20	%
Operating income		19,022			55,424			(36,402	)		(66	)%
Total other expenses		(36,002	)		(28,829	)		(7,173	)		25	%
Net (loss) income before income tax		(16,980	)		26,595			(43,575	)		(164	)%
Tax (benefit) provision		(3,604	)		689			(4,293	)		623	%
Net (loss) income		(13,376	)		25,906			(39,282	)		(152	)%
Net (loss) income attributable to noncontrolling interest		(7,089	)		16,981			(24,070	)		(142	)%
Net (loss) income attributable to controlling interest	$	(6,287	)	$	8,925		$	(15,212	)		(170	)%

MWh sold and average realized electricity price. We sold 1,673,413 MWh of electricity in the year ended December 31, 2012 as compared to 1,568,022 MWh in the year ended December 31, 2011. This increase in MWh sold during 2012 as compared to 2011 was primarily attributable to a full year of operations at St. Joseph as compared to a partial year in 2011 as St. Joseph commenced commercial operations in April 2011. In 2012, we also began commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012. These increases were offset by lower production at our Gulf Wind and Hatchet Ridge projects primarily due to lower winds in 2012 compared to 2011. Our average realized electricity price was approximately $73 per MWh in the year ended December 31, 2012 as compared to approximately $75 per MWh in the year ended December 31, 2011.

Revenue. Revenue for the year ended December 31, 2012 was $114.5 million compared to $135.9 million for the year ended December 31, 2011, a decrease of $21.4 million, or approximately 16%. The decrease in revenue during 2012 as compared to 2011 was attributable to a net decrease of $16.8 million due to lower spot electricity prices applicable to Gulf Wind and a decrease of $24.6 million due to energy derivative valuation, offset by an increase of approximately $20.0 million in revenue from other projects. The Gulf Wind project received higher spot market electricity prices in 2011 than in 2012, including unusually high prices which exceeded $2,000 per MWh for a total of approximately 24 hours during 2011. The lower spot prices in 2012 reduced our electricity sales at the Gulf Wind project by approximately $26.9 million and increased our energy derivative settlements by approximately $10.1 million, for a net reduction of approximately $16.8 million in 2012. In addition, in 2012, we recorded a $7.0 million unrealized loss on energy derivative compared to a $17.6 million unrealized gain in 2011, resulting in a decrease in year-over-year revenue of $24.6 million in 2012. The value of our energy derivative, and the amount of unrealized gain or loss we record, increases and decreases due to our monthly derivative settlements and changes in forward electricity prices, which are derived from and impacted by changes in forward natural gas prices. These revenue decreases in 2012 were partially offset by increased electricity sales of approximately $20.0 million resulting from a full year of electricity sales at

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St. Joseph in 2012, which commenced commercial operations in April 2011, and electricity sales at Spring Valley, which commenced commercial operations in August 2012, and at Santa Isabel and Ocotillo, which both commenced commercial operations in December 2012.

Cost of revenue. Cost of revenue for the year ended December 31, 2012 was $83.9 million compared to $70.8 million for the year ended December 31, 2011, an increase of $13.1 million, or approximately 19%. The increase in cost of revenue during 2012 as compared to 2011 was attributable to a full year of costs at St. Joseph following the commencement of commercial operations in April 2011 and costs attributable to the commencement of commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012. As each new project commences commercial operations, we incur new incremental and ongoing costs for maintenance and services agreements, property taxes, insurance, land lease and other costs associated with managing, operating and maintaining the facility, including adding site employees and operations center staff.

Development expenses. Development expenses for the year ended December 31, 2012 were $0.2 million compared to $0.7 million for the year ended December 31, 2011, a decrease of $0.5 million, or approximately 71%. The decrease in development expenses was primarily attributable to our determination that development expenses related to El Arrayán should be capitalized starting in the first quarter of 2012.

Related party general and administrative expense. Related party general and administrative expense for the year ended December 31, 2012 was $10.6 million compared to $8.1 million for the year ended December 31, 2011, an increase of $2.5 million, or approximately 31%, resulting primarily from the increased staffing and overhead costs related to commercial operations commencing at Spring Valley, Santa Isabel and Ocotillo as well as our ownership in El Arrayán and South Kent as construction and development, respectively, on the projects advanced in 2012.

Other expense. Other expense for the year ended December 31, 2012 was $36.0 million compared to $28.8 million for the year ended December 31, 2011. The increase in other expense during 2012 as compared to 2011 was primarily attributable to a $7.1 million, or approximately 25%, increase in interest expense in 2012 reflecting a full year of interest expense at St. Joseph following the commencement of commercial operations in April 2011 and interest expense attributable to the commencement of commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012. In 2012, we also had a $4.6 million increase in unrealized loss on derivatives as a portion of our interest rate swaps on the Ocotillo project are not designated as hedges and, during the period after the closing of the Ocotillo financing and entering into these interest rate swaps in October 2012, there was a decrease in the forward interest rate curve which increases our liability under these interest rate swaps and increases our unrealized loss on derivatives. These increased costs in 2012 were offset by a $4.2 million gain on the sale of a portion of our investment in El Arrayán in 2012.

Tax provision. The tax provision was a $3.6 million benefit for the year ended December 31, 2012 compared to $0.7 million for the year ended December 31, 2011. This was principally the result of the Santa Isabel project holding company being subject to U.S. income taxes at the end of 2012 but not during 2011.

Noncontrolling interest. The net loss attributable to noncontrolling interest was a $7.1 million for the year ended December 31, 2012 compared to a $17.0 million of income for the year ended December 31, 2011. The noncontrolling interest income or loss calculation is based on the hypothetical liquidation at book value method of accounting for the earnings attributable to the noncontrolling interest’s ownership in Gulf Wind, and 2011 was favorably impacted by unusually high power prices during the year.

Adjusted EBITDA. Adjusted EBITDA for the year ended December 31, 2012 was $75.2 million compared to $77.3 million for the year ended December 31, 2011, a decrease of $2.1 million. The decrease in Adjusted EBITDA during 2012 as compared to 2011 was primarily attributable to higher spot electricity prices at our Gulf Wind project in 2011, including unusually high prices which exceeded $2,000 per MWh for approximately 24

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hours during 2011 (contrasted with an average spot-market electricity price of $25.31/MWh received at Gulf Wind in 2012) and which were not repeated in 2012; the absence of this unexpected incremental electricity revenue in 2012 was partially offset by additional revenue, net of project expense, that was earned following commencement of operations at our Spring Valley, Santa Isabel and Ocotillo projects in 2012 and from a full year of operations at our St. Joseph project. For a reconciliation of net income to Adjusted EBITDA, see “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Metrics—Adjusted EBITDA”

Liquidity and Capital Resources

Our business requires substantial capital to fund (i) equity investments in our construction projects, (ii) current operational costs, (iii) debt service payments, (iv) dividends to our stockholders, (v) potential investments in new acquisitions (vi) modifications to our projects, (vii) unforeseen events and (viii) other business expenses. As a part of our liquidity strategy, we plan to retain a portion of our cash flows in above-average wind years in order to have additional liquidity in below-average wind years. Our sources of liquidity include cash generated by our operations, ITC cash grants, cash reserves, borrowings under our corporate and project-level credit agreements and further issuances of equity and debt securities.

The principal indicators of our liquidity are our restricted and unrestricted cash balances and availability under our credit agreements. As of December 31, 2013, our available liquidity was $301.9 million, including restricted cash on hand of $32.6 million, unrestricted cash on hand of $103.6 million, $75.2 million available under our revolving credit agreements and $90.5 million available under project financings for post construction use.

We believe that throughout 2014, we will have sufficient liquid assets, cash flows from operations, and borrowings available under our revolving credit facility to meet our financial commitments, debt service obligations, contingencies and anticipated required capital expenditures for at least the next 24 months, without taking into account capital required for additional project acquisitions. Additionally, we believe that our construction projects have been sufficiently capitalized such that we will not need to seek additional financing arrangements in order to complete construction and achieve commercial operations at these projects. Our acquisition of Panhandle 2 is contingent on funding by the tax equity investors so no further project financing is required. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corresponding adverse effect on our borrowing capacity. In connection with our future capital expenditures and other investments, including any project acquisitions that we may make in addition to our acquisition of Grand and Panhandle 2, we may, from time to time, issue debt or equity securities.

Cash Flows

We use traditional measures of cash flow, including net cash provided by operating activities, net cash used in investing activities and net cash provided by financing activities as well as cash available for distribution to evaluate our periodic cash flow results.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Net cash provided by operating activities was $78.2 million for the year ended December 31, 2013 as compared to $35.1 million for the year ended December 31, 2012. Electricity sales were $71.5 million higher during 2013 as compared to 2012, which was primarily attributable to the commencement of commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012. Also during the year ended December 31, 2013 we recorded other revenue of $21.9 million related to non-refundable warranty settlement payments we received from a turbine supplier during the period as a result of the turbines at the Ocotillo and Santa Isabel projects being off line for a portion of the period. Offsetting these increases in

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electricity sales and other revenue is an $8.7 million increase in the period-over-period reduction of cash flow provided by operations related to an increase in trade receivables consistent with our terms under the power sales agreements, a period-over-period increase of $19.4 million in project expenses, and a period-over-period increase in cash interest expense of $22.8 million.

Net cash provided by investing activities was $72.4 million for the year ended December 31, 2013, which consisted of $173.4 million of ITC grant proceeds at Ocotillo and Santa Isabel, $14.3 million of proceeds from the sale of investments and tax credits, and a net reduction in our reimbursable interconnection receivable of $49.7 million, offset by $123.5 million of capital expenditures primarily at Ocotillo and Santa Isabel and a funding of restricted cash primarily at Ocotillo under the credit agreement. Net cash used in investing activities was $639.0 million for the year ended December 31, 2012 which consisted of $641.4 million of capital expenditures at Spring Valley, Santa Isabel and Ocotillo, $22.4 million of investments in our unconsolidated investments, and $47.1 million in net payments for interconnection network upgrades primarily at our Ocotillo project offset by ITC cash grant proceeds of $79.9 million.

Net cash used in financing activities for the year ended December 31, 2013 was $63.4 million, which was attributable to $317.9 million of net initial public offering proceeds, $138.6 million of loan proceeds primarily at Santa Isabel and Ocotillo and $32.7 million of capital contributions prior to the initial public offering offset by $232.6 million of distributions to Pattern Development in conjunction with the Contribution Transactions, $49.4 million related to the acquisition of Grand from Pattern Development, repayment of $114.1 million of construction and bridge loans at Santa Isabel and Ocotillo, $98.9 million of capital distributions prior to our initial public offering, and $50.3 million of long-term debt repayments. Net cash provided by financing activities for the year ended December 31, 2012 was $573.2 million which was primarily attributable to $281.5 million of capital contributions, $497.2 million of loan borrowings at Spring Valley, Santa Isabel and Ocotillo, offset by $80.9 million of loan repayments and $114.2 million of capital distributions.

Cash available for distribution was $42.6 million for the year ended December 31, 2013 as compared to $17.7 million for the year ended December 31, 2012, an increase of $24.9 million. This increase in cash available for distribution was the result of higher electricity sales of $71.5 million, which was primarily attributable to the commencement of commercial operations at Spring Valley in August 2012, and at Santa Isabel and Ocotillo in December 2012. Also, during the year ended December 31, 2013, we recorded other revenue of $21.9 million related to warranty settlement payments we received from a turbine supplier during the period as a result of the turbines at the Ocotillo and Santa Isabel projects being off line for a portion of the period. Offsetting these increases in electricity sales and other revenue is a period-over-period increase of $19.4 million in project expenses, a period-over-period increase in cash interest expense of $22.8 million, a $15.3 million increase in principal payments from operating cash flows as the additional projects commenced operations in late 2012 and a $4.4 million increase in network upgrade reimbursements.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Net cash provided by operating activities was $35.1 million for the year ended December 31, 2012 as compared to $46.9 million for the year ended December 31, 2011. This decrease in cash provided by operating activities was primarily the result of lower revenue in 2012 at our Gulf Wind project as a result of receiving higher spot market electricity prices in 2011 than in 2012, including unusually high prices which exceeded $2,000 per MWh for approximately 24 hours during 2011. The lower revenue at Gulf Wind during 2012 as compared to 2011 was partially offset by increased electricity sales from a full year of operations at St. Joseph following its commencement of commercial operations in April 2011 and electricity sales following the commencement of commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012.

Net cash used in investing activities was $639.0 million for the year ended December 31, 2012, which consisted of $641.4 million of capital expenditures at Spring Valley, Santa Isabel and Ocotillo, $22.4 million of

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investments in our unconsolidated investments, and $47.1 million in net payments for interconnection network upgrades primarily at our Ocotillo project offset by ITC cash grant proceeds of $79.9 million. Net cash used in investing activities was $341.0 million for the year ended December 31, 2011, which consisted of $392.2 million of capital expenditures at St. Joseph, Spring Valley, Santa Isabel and Ocotillo and offset by the collection on our $80.3 million notes receivable at Hatchet Ridge.

Net cash provided by financing activities for the year ended December 31, 2012 was $573.2 million, which was primarily attributable to $281.5 million of capital contributions, $497.2 million of loan borrowings at Spring Valley, Santa Isabel and Ocotillo, offset by $80.9 million of loan repayments and $114.2 million of capital distributions. Net cash provided by financing activities for the year ended December 31, 2011 was $331.3 million, which was primarily attributable to $260.8 million of loan proceeds related to construction of St. Joseph, Spring Valley and Santa Isabel and $232.3 million of capital contribution, offset by $121.4 million of capital distributions.

Cash available for distribution was $17.7 million for the year ended December 31, 2012 as compared to $18.5 million for the year ended December 31, 2011. This decrease in cash available for distribution was primarily the result of higher spot electricity prices at our Gulf Wind project in 2011, including unusually high prices which exceeded $2,000 per MWh for approximately 24 hours during 2011 and which were not repeated in 2012; the loss of this unexpected incremental electricity revenue was partially offset by additional revenue, net of project expense, that was earned following commencement of operations at our Spring Valley, Santa Isabel and Ocotillo projects in 2012 and from a full year of operations at our St. Joseph project, $6.3 million of network upgrade reimbursements in 2012 and a decrease of $5.9 million in distributions to our noncontrolling interest in 2012 as compared to 2011.

Capital Expenditures and Investments

We currently own only those projects that we acquired through the Contribution Transactions and those which we additionally agreed to acquire from Pattern Development in December 2013. Each of the acquired project entities has secured all of the required project equity needed to complete the construction and achieve commercial operations at our construction projects and funding for all remaining planned construction costs, including contingency allowances, is available under financing commitments from project lenders. All capital expenditures and investments in 2013 have either been funded by Pattern Development or are available from project finance lenders under project-level credit facilities. For 2013, total capital expenditures were $123.5 million. For 2014, we do not expect to make capital expenditures at our construction projects as these projects are held in joint ventures for which we use the equity method of accounting.

We expect to make investments in additional projects. Although we have no commitments to make any such acquisitions, other than the acquisition of Panhandle 2, we consider it reasonably likely that we may have the opportunity to acquire certain Pattern Development near-term projects under our purchase rights within the 24 month period following December 31, 2013. We have agreed to make a cash payment to Pattern Development in the amount of $122.9 million, subject to certain price adjustments based on final project size, design and modeling assumptions, at the time of the Panhandle 2 acquisition, which we expect to occur in the fourth quarter of 2014. We believe that we will have sufficient cash and revolving credit facility capacity to complete the Panhandle 2 acquisition, but this may be affected by any other acquisitions or investments that we make prior to the Panhandle 2 acquisition. To the extent that we make any such investments or acquisitions, we will evaluate capital markets and other corporate financing sources available to us at the time.

In addition, we will make investments from time to time at our operating projects. Operational capital expenditures are those capital expenditures required to maintain our long-term operating capacity. Capital expenditures for the projects are generally made at the project level using project cash flows and project reserves, although funding for major capital expenditures may be provided by additional project debt or equity. Therefore, the distributions that we receive from the projects may be made net of certain capital expenditures needed at the projects.

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For the year ending December 31, 2014, we have budgeted $0.9 million for operational capital expenditures and $1.9 million for expansion capital expenditures.

Description of Credit Agreements

On November 15, 2012, certain of our subsidiaries entered into a $120.0 million revolving working capital facility with a four-year term, comprised of a revolving loan facility and a letter of credit facility, which we refer to collectively as our “revolving credit facility.” The revolving credit facility has an “accordion feature” under which we have the right to increase available borrowings by up to $35.0 million if our lenders or other additional lenders are willing to lend on the same terms and meet certain other conditions. As of December 31, 2013, letters of credit of $44.8 million have been issued and we have no outstanding drawn loan balance under the revolving credit facility.

Interest Rate and Fees

The loans under our revolving credit facility are either base rate loans or Eurodollar rate loans. The base rate loans accrue interest at the fluctuating rate per annum equal to 2.5% plus the greatest of the (i) the prime rate, (ii) the federal funds rate plus 0.50% and (iii) the Eurodollar rate that would be in effect for a Eurodollar rate loan with an interest period of one month plus 1.00%. The Eurodollar rate loans accrue interest at a rate per annum equal to LIBOR, as published by Reuters plus 3.50%.

Distribution Conditions

Certain of our project subsidiaries are subject to usual and customary affirmative and negative covenants under our revolving credit facility. Specifically, such project subsidiaries are prohibited from distributing funds to us unless the following conditions are met: (i) no default or event of default has occurred and is continuing or would be caused by such distribution, (ii) after giving effect to such distribution, an amount equal to at least 7.50% of the revolving commitment remains available to be drawn; and (iii) the borrowers are in compliance with the leverage ratio test and the interest coverage ratio test, both before and after giving effect to such declaration.

Prepayments, Certain Covenants and Events of Default

Our revolving credit facility also has customary covenants, prepayment provisions and events of default.

Gulf Wind Senior Secured Credit Agreement

In February 2010, Pattern Gulf Wind LLC, or “Gulf Wind LLC,” entered into a first lien senior secured credit agreement, or the “Gulf Wind Credit Agreement.” The Gulf Wind Credit Agreement provides up to $195.4 million in term loan borrowings, or the “Gulf Wind Term Loan,” and will mature in March 2020. Borrowings under the Gulf Wind Term Loan were used to refinance the construction financing for the Gulf Wind project.

The Gulf Wind Credit Agreement also provides for an operations and maintenance reserve loan facility in an amount up to $8.1 million and a debt service reserve loan facility in an amount up to $12.5 million. The reactive power upgrade loan is a commitment to fund up to 50% of works necessary for the Gulf Wind project to comply with Protocol Revision Request (PRR) 830. As of December 31, 2013 approximately $166.4 million of indebtedness was outstanding under the Gulf Wind Credit Agreement, all of which was outstanding under the term loan. In connection with the facility, Gulf Wind LLC entered into interest rate swaps and cap agreements to reduce its exposure to variable interest rates during the term of the facility and to hedge its exposure to refinancing rate risk.

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Interest Rate and Fees

Base rate loans accrue interest at the greater of (i) the base rate, which is (a) the greater of the prime rate and (b) the federal funds rate plus 0.50%, plus the applicable margin under the Gulf Wind Credit Agreement and (ii) LIBOR plus 3.00% per annum, the base rate floor. The base rate floor for term loans and debt service reserve loans is 3% plus LIBOR with an interest period of three months. The base rate floor for reactive power upgrade loans and operations and maintenance reserve loans is 3% plus LIBOR with an interest period of one month. LIBOR loans accrue interest at LIBOR plus the applicable margin under the Gulf Wind Credit Agreement. Gulf Wind LLC is also required to pay quarterly commitment fees on the operations and maintenance loan commitment, the debt service reserve loan commitment and the reactive power upgrade loan commitment. Our current annual interest rate, after taking into account our fixed-for-floating LIBOR rate swaps, is approximately 6.6%.

Distribution Conditions

Gulf Wind LLC may distribute excess cash flows to its owners provided that specified distribution requirements are met. The distribution requirements include that: (i) there are no operations and maintenance or debt service reserve loans outstanding; (ii) no event of default or inchoate default has occurred and is continuing; (iii) the debt service coverage ratio is equal to or greater than 1.20:1.00; and (iv) no adverse pre-existing condition remains unremedied after certain trigger dates set for each respective pre-existing condition that when taken together with the other adverse pre-existing conditions, could reasonably be expected to have a material adverse effect.

Prepayments, Certain Covenants and Events of Default

The Gulf Wind Credit Agreement contains a broad range of covenants that, subject to certain exceptions, restrict Gulf Wind’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay dividends and change its business. Gulf Wind LLC may voluntarily prepay the facility, in whole or in part, at any time without premium or penalty (except for liquidation costs and interest fix fees, if applicable), and in certain circumstances, must make mandatory prepayments of loans under the facility. From March 16, 2018 until March 16, 2020, the maturity date, all distributable cash is required to be applied as a mandatory prepayment of the loans.

Hatchet Ridge Wind Lease Financing

In December 2010, Hatchet Ridge Wind, LLC, or “Hatchet Ridge LLC,” as lessee, entered into two participation agreements, each for a 50% undivided interest in the Hatchet Ridge project, to implement a first lien lease financing, or the “Hatchet Ridge Leveraged Lease Financing,” with each of Hatchet Ridge Wind 2010-A and Hatchet Ridge Wind 2010-B, each an owner lessor, Wells Fargo Delaware Trust Company National Association, as the owner trustee, MetLife Renewables Holding, LLC, as owner participant, and Wilmington Trust Company, as trustee under each lease indenture, and Credit Agricole Corporate and Investment Bank, as PPA letter of credit provider.

The financing was structured as two sale-leaseback transactions, each for a 50% undivided interest in the Hatchet Ridge project. Borrowings under each lease financing were used to refinance the construction financing for the Hatchet Ridge wind project. Pursuant to the sale-leaseback financings (i) MetLife Renewables Holding, LLC funded an equity investment in the Hatchet Ridge wind project, (ii) Hatchet Ridge LLC sold an undivided interest in the Hatchet Ridge wind project to Hatchet Ridge Wind 2010-A and Hatchet Ridge Wind 2010-B, each a “Hatchet Ridge Undivided Interest,” for a purchase price and Hatchet Ridge Wind 2010-A and Hatchet Ridge Wind 2010-B each leased their respective undivided interest back to Hatchet Ridge LLC, (iii) Hatchet Ridge Wind 2010-A and Hatchet Ridge Wind 2010-B each sold lease notes to Wilmington Trust Company, as pass-through trustee, and (iv) Wilmington Trust Company entered into a pass-through trust agreement with Hatchet

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Ridge LLC, pursuant to which Wilmington Trust Company used the proceeds of the sale of certificates to MetLife Renewables Holding, LLC to purchase the lease notes from Hatchet Ridge Wind 2010-A and Hatchet Ridge Wind 2010-B, respectively.

In addition, Credit Agricole Corporate and Investment Bank and Hatchet Ridge LLC entered into a letter of credit and reimbursement agreement, or the “Hatchet Ridge LC Agreement,” pursuant to which Credit Agricole Corporate and Investment Bank issued a PPA letter of credit to the power purchaser as payment security for Hatchet Ridge LLC’s obligations under the PPA. In the event of a draw under the PPA letter of credit that is not reimbursed by Hatchet Ridge LLC, such amount becomes a PPA letter of credit loan. Each of Hatchet Ridge Wind 2010-A and Hatchet Ridge Wind 2010-B entered into a PPA letter of credit guarantee pursuant to which Hatchet Ridge Wind 2010-A and Hatchet Ridge Wind 2010-B, respectively, guarantee Hatchet Ridge LLC’s obligations to repay any draws under the PPA letter of credit and any amounts owed to Credit Agricole Corporate and Investment Bank under the Hatchet Ridge LC Agreement.

In addition, as partial consideration for the purchase price, Hatchet Ridge Wind 2010-A and Hatchet Ridge 2010-B each issued a note in favor of Hatchet Ridge LLC in an amount of $40.1 million secured by a right to receive Hatchet Ridge Wind 2010-A and Hatchet Ridge Wind 2010-B’s respective cash grant from the U.S. Treasury. The cash grant notes were fully paid once the cash grant proceeds were received from the U.S. Treasury. The financing is non-recourse to us.

Interest Rate

Our effective annual interest rate under the Hatchet Ridge Leveraged Lease Financing is approximately 1.4%.

Distribution Conditions

Hatchet Ridge LLC may distribute excess cash flows to its owner provided that specified distribution requirements are met. The distribution requirements include that: (i) the reserves and other accounts are fully funded; (ii) that there are no PPA letter of credit loans outstanding; (iii) that no lease event of default has occurred and is continuing and (iv) the rent service coverage ratio is equal to or greater than 1.20:1.00.

Prepayments, Certain Covenants and Events of Default

The financing documents contain a broad range of covenants that, subject to certain exceptions, restrict Hatchet Ridge LLC’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay dividends and change its business. Hatchet Ridge LLC may redeem the lease notes, in whole, at its option, at any time on or after December 14, 2015, and, in certain circumstances, must redeem the lease notes, in whole, at a price that includes a make whole premium. In addition, in certain circumstances, the note securing the PPA letter of credit loan is subject to mandatory redemption, in whole.

St. Joseph Amended Credit and Security Agreement

In April 2011, St. Joseph Wind Farm Inc., or “St. Joseph Inc.,” entered into an amended credit and security agreement or the “St. Joseph Credit Agreement.” The St. Joseph Credit Agreement provides up to C$250.0 million in construction loan borrowings. Construction loan borrowings under the St. Joseph Credit Agreement were used to finance the construction of the St. Joseph wind power project and converted upon completion of construction of the St. Joseph wind power project to a term loan, which will mature in May 2031. The St. Joseph Credit Agreement also provides for a revolving reserve loan facility in an amount up to C$10.0 million. As of December 31, 2013, C$228.7 million of indebtedness was outstanding under the St. Joseph Credit Agreement, all of which was outstanding under the term loan. The financing is limited recourse to us.

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Interest Rate and Fees

The term loan accrues interest at a rate of approximately 5.9% per annum, compounded monthly; our effective annual interest rate is approximately 5.95%. The reserve loan advances accrue interest at 4% plus the Canadian Dealer Offered Rate, or “CDOR,” with the interest payable monthly. St. Joseph Inc. is also required to pay a consent fee where a permitted change of control or permitted assignment occurs within three years of April 1, 2011, the interim commercial operation date.

Distribution Conditions

St. Joseph Inc. may distribute excess cash flows to its owner six months after the interim commercial operations date, which was April 1, 2011, provided that specified distribution requirements are met. The distribution requirements include that: (i) no reserve loans are outstanding; (ii) payment of the distribution would not violate any law or terms of any agreement to which St. Joseph Inc. or the collateral are subject; (iii) the debt service coverage ratio is greater than or equal to 1.20:1.00 for the immediately preceding 12-month period and is projected to be greater than or equal to 1.00:1.00 with electricity production based on the relevant monthly value of the estimated annual electricity such that no advance under any reserve loan is anticipated; and (iv) no cash sweep is then in effect.

Prepayments, Certain Covenants and Events of Default

The St. Joseph Credit Agreement contains standard covenants that, among other things and subject to certain exceptions, restrict St. Joseph Inc.’s ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests, dissolve, make distributions and change its business. St. Joseph Inc. may voluntarily prepay the term loan, in whole or in part, and the reserve loans at any time without premium or penalty, and, in certain circumstances, must make mandatory prepayments of the reserve loans.

Spring Valley Credit Facilities

In August 2011, Spring Valley Wind LLC, or “Spring Valley LLC,” entered into a financing agreement, or the “Spring Valley Financing Agreement.” The Spring Valley Financing Agreement currently provides for up to approximately $199.7 million in borrowings and is expected to mature in March 2031. Borrowings under the Spring Valley Financing Agreement were used to finance the construction of the Spring Valley wind project and consisted of a cash grant bridge loan of up to $53.3 million, a construction loan of up to $178.9 million, an operations and maintenance reserve letter of credit facility in an amount up to $5.4 million, a debt service reserve letter of credit facility in an amount up to $9.1 million and a PPA letter of credit facility in an amount up to $6.3 million. Additionally, the $53.3 million cash grant bridge loan that was borrowed under the Spring Valley Financing Agreement was repaid from an ITC cash grant Spring Valley LLC received following the commencement of commercial operations. The construction loan converted into the term loan upon completion of construction of the Spring Valley wind project and satisfaction of certain other specified conditions.

As of December 31, 2013, approximately $173.1 million of indebtedness was outstanding under the Spring Valley Financing Agreement, all of which was outstanding under the term loan. We have agreed to indemnify Spring Valley LLC in the event of disallowance of the ITC cash grant. Other than the indemnification, the financing is non-recourse to us.

Interest Rate and Fees

The reserve loans are either base rate loans or LIBOR loans. Reserve loans that are LIBOR loans accrue interest at LIBOR plus 2.00% per annum and reserve loans that are base rate loans accrue interest at the base rate plus 1.00% per annum. Construction loans, term loans and letter of credit loans that are LIBOR loans accrue interest at LIBOR plus 2.375% per annum, and those that are base rate loans accrue interest at the base rate plus

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1.375% per annum. Other than with respect to the construction loans, the amount of interest payable on base rate loans is increased by 25 basis points every four years after the conversion of the construction loan to a term loan. Our current effective annual interest rate, after taking into account our fixed-for-floating LIBOR rate swaps, is approximately 5.5%.

Spring Valley LLC is also required to pay quarterly commitment fees on the operations and maintenance reserve letter of credit commitment, the debt service reserve letter of credit loan commitment and the PPA letter of credit loan commitment.

Distribution Conditions

Spring Valley LLC may distribute excess cash flows to its owner provided that specified distribution requirements are met. The distribution requirements include that distributions may be made only if: (i) the initial repayment date and the term conversion of the construction loan have occurred; (ii) the reserve and other accounts are fully funded; (iii) all outstanding cash grant bridge loans, letter of credit loans and other letter of credit reimbursement obligations have been repaid; (iv) any mandatory prepayment required as a result of the occurrence of an upwind array event has been made; (v) no default or event of default has occurred; (vi) the annual debt service coverage ratio is equal to or greater than 1.20:1.00; and (vii) a satisfactory ruling or settlement has occurred in connection with the litigation challenging the Bureau of Land Management Rights-of-Way.

Prepayments, Certain Covenants and Events of Default

The Spring Valley Financing Agreement contains a broad range of covenants that, subject to certain exceptions, restrict Spring Valley LLC’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay dividends and change its business. Spring Valley LLC may voluntarily prepay the facility, in whole or in part, at any time without premium or penalty (except for liquidation costs and interest fix fees, if applicable) and, in certain circumstances, must make mandatory prepayments of loans under the facility.

Santa Isabel Senior Financing Agreement

In October 2011, Pattern Santa Isabel LLC, or “Santa Isabel LLC,” entered into a first lien senior secured financing agreement, or the “Santa Isabel Financing Agreement.” The Santa Isabel Financing Agreement provides up to approximately $192.4 million in borrowings. Current borrowings under the Santa Isabel Financing Agreement were used to finance the construction of the Santa Isabel wind project and include a cash grant bridge loan of up to $57.4 million and a construction loan of up to $119.0 million. The cash grant bridge loan was repaid from an ITC cash grant that Santa Isabel LLC received in June 2013. The construction loan converted into a term loan in May 2013.

The Santa Isabel Financing Agreement also provides for an operations and maintenance reserve loan facility in an amount up to $6.7 million, debt service reserve loan facility in an amount up to $6.2 million and a PPA collateral facility in an amount up to $3.0 million. As of December 31, 2013, approximately $115.7 million of indebtedness was outstanding under the Santa Isabel Financing Agreement. We agreed to indemnify Santa Isabel LLC in the event of disallowance of the ITC cash grant. Other than the indemnification, the financing is non-recourse to us.

Interest Rate and Fees

The operations and maintenance reserve loans, debt service reserve loans and PPA collateral loans are either base rate loans or LIBOR loans. Reserve loans that are LIBOR loans accrue interest at LIBOR plus 2.00% per annum, and reserve loans that are base rate loans accrue interest at the greater of (i) the prime rate and (ii) the

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federal funds rate plus 0.50%, plus 1.00% per annum, but increase by 12.5 basis points every three years after the earlier of March 31, 2013 and term conversion. Construction loans and term loans are fixed rate loans and accrue interest at 1.94% per annum plus a margin of 2.625%, for a total annual interest rate of 4.565%.

Santa Isabel LLC is also required to pay quarterly commitment fees on the operations and maintenance reserve loan commitment the debt service reserve loan commitment, the PPA collateral commitment and PPA collateral advance fees.

Distribution Conditions

Santa Isabel LLC may distribute excess cash flows to its owner provided that specified distribution requirements are met. The distribution requirements include that: (i) distributions may be made only following the last banking day of 2012; (ii) the occurrence of the term conversion of the construction loan; (iii) the reserve and other accounts are fully funded; (iv) all outstanding operations and maintenance reserve loans, debt service reserve loans and PPA collateral loans have been repaid and all PPA collateral reimbursement obligations have been paid; (v) any mandatory prepayment required as a result of the occurrence of an upwind array event has been made; (vi) no default or event of default has occurred; and (vii) the annual debt service coverage ratio is equal to or greater than 1.20:1.00.

Prepayments, Certain Covenants and Events of Default

The Santa Isabel Financing Agreement contains a broad range of covenants that, subject to certain exceptions, restrict Santa Isabel LLC’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay dividends and change its business. Santa Isabel LLC may, with certain exceptions, voluntarily prepay the facility, in whole or in part, at any time without premium or penalty except for liquidation costs and make-whole payments with respect to the fixed rate loans, and, in certain circumstances, must make mandatory prepayments of loans under the facility.

Ocotillo Senior Financing Agreement

Ocotillo Express LLC, or “Ocotillo LLC,” entered into a first lien senior secured financing agreement, or the “Ocotillo Financing Agreement,” with a group of commercial banks and a development bank in October 2012. The Ocotillo Financing Agreement provides up to approximately $467.3 million in borrowings. Borrowings under the Ocotillo Financing Agreement were used to finance the construction of the Ocotillo wind project and is comprised of a network upgrade bridge loan of up to approximately $56.6 million and two construction loans of up to approximately $351.5 million. The two construction loans consist of a development bank tranche of $110 million and a commercial bank tranche of up to approximately $241.5 million and mature 20 years and 7 years after the occurrence of term conversion, respectively. The network upgrade bridge loan was repaid from reimbursements by the interconnecting utility of reimbursable network upgrade costs. The construction loans converted into term loans upon completion of construction of the Ocotillo wind project.

The Ocotillo Financing Agreement also provides for an operations and maintenance reserve letter of credit facility in an amount up to $10.5 million, a debt service reserve letter of credit facility in an amount up to $22.0 million and a PPA letter of credit facility in an amount up to $26.7 million. We have agreed to indemnify Ocotillo in the event of disallowance of the ITC cash grant and for certain legal expenses in connection with certain pending legal proceedings at the project level. See Item 3 “Legal Proceedings.” Other than these indemnifications, the financing is non-recourse to us.

Interest Rate and Fees

The commercial bank tranche construction loans and the term loans are either base rate loans or LIBOR loans, and accrue interest at the base rate or LIBOR rate (as applicable), plus the applicable margin. Base rate loans accrue interest at the greatest of (i) the prime rate, (ii) the federal funds rate plus 0.50% and (iii) the LIBOR

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rate plus 1.00%. The applicable margin for commercial bank tranche construction loans is 3.00%. The applicable margin for development bank tranche construction and term loans is 2.10%; after taking into consideration our fixed-for-floating rate swaps on 90% of the loan commitment, our estimated effective annual interest rate on the development bank tranche is approximately 4.6%. The applicable margin for commercial bank tranche term loans and for operations and maintenance and debt service reserve loans is initially 2.75% and increases by 0.25% on the fourth anniversary of the term conversion date; after taking into consideration our fixed-for-floating rate swaps on 90% of the loan commitment, our initial estimated effective annual interest rate on the commercial bank tranche is approximately 5.0%. The applicable margin for PPA letter of credit loans is 2.50% until term conversion, 2.25% from term conversion until the 4th anniversary of the term conversion date, and 2.50% thereafter. As of December 31, 2013, approximately $338.7 million of indebtedness was outstanding under the Ocotillo Financing Agreement.

Ocotillo is also required to pay quarterly commitment fees on the commercial bank tranche construction loan commitment, the development bank tranche construction loan commitment, and each of the LC commitments.

Distribution Conditions

Ocotillo LLC may distribute excess cash flows to its owner provided that specified distribution requirements are met. The distribution requirements include, among other things, that: (i) there are no letter of credit loans or network upgrade bridge loans outstanding; (ii) the term conversion of the construction loans has occurred; (iii) the multipurpose reserve account is fully funded; (iv) no default or inchoate default has occurred and such distribution will not result in an event of default; and (v) the annual debt service coverage ratio is equal to or greater than 1.20:1.00.

Prepayments, Certain Covenants and Events of Default

The Ocotillo Financing Agreement contains a broad range of covenants that, subject to certain exceptions, limit Ocotillo LLC’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay dividends and change its business. Ocotillo LLC may voluntarily prepay the facility, in whole or in part, at any time without premium or penalty except for liquidation costs or interest fix fees, as applicable, and, in certain circumstances, must make mandatory prepayments of loans under the facility.

Currently, Ocotillo LLC’s right of way grant to utilize federal land is the subject of litigation. We do not believe this matter will have a material adverse effect on our business, but the Ocotillo Financing Agreement contains provisions that provide lender protection to the extent that the litigation causes or would reasonably be expected to cause a material degradation in Ocotillo LLC’s prospects, either though reduced revenues or increased costs. Such provisions include limited cash traps and mandatory pre-payments, if needed.

El Arrayán Senior Financing Agreement

In May 2012, Parque Eólico El Arrayán SPA, or “El Arrayán SPA,” entered into a first lien senior secured credit agreement, or the “El Arrayán Credit Agreement.” The El Arrayán Credit Agreement provides up to approximately $225.5 million in borrowings. Current borrowings under the El Arrayán Credit Agreement are being used to finance the construction of the El Arrayán wind project and are comprised of a commercial tranche of up to $100 million and an export credit agency tranche provided by Eksport Kredit Fonden of Denmark, or the “EKF Tranche,” of up to $110.0 million, and letter of credit facility in an amount of up to $15 million. The construction loan converts into a term loan upon completion of construction of El Arrayán and certain other specified conditions.

As of December 31, 2013, approximately $196.6 million of indebtedness was outstanding under the El Arrayán Credit Agreement. The financing is non-recourse to us.

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Interest Rate and Fees

The commercial tranche construction and term loans are, with certain exceptions, LIBOR loans and accrue interest at LIBOR plus 2.75% per annum from the closing until the sixth anniversary of closing, 3.00% from the sixth anniversary to the tenth anniversary of closing, 3.25% from the tenth anniversary to the fourteenth anniversary of closing, and 3.50% after the fourteenth anniversary of closing. The EKF Tranche construction loans accrue interest at a fixed rate of 3.30% and the EKF Tranche term loans accrue interest at a fixed rate of 5.56%, in each case, plus a margin of 0.25% from the sixth anniversary to the tenth anniversary of the closing, 0.50% from the tenth anniversary to the fourteenth anniversary of closing, and 0.75% after the fourteenth anniversary of closing.

El Arrayán SPA is also required to pay semi-annual commitment fees on the construction loan commitments and the letter of credit commitments. El Arrayán SPA also pays arranger fees and agency fees.

Distribution Conditions

El Arrayán SPA may distribute excess cash flows to its owner provided that specified distribution requirements are met. The distribution requirements include that: (i) the date is six months after term conversion or September 30, 2014 has occurred; (ii) the first repayment date has occurred, (iii) no default or event of default has occurred and is continuing; (iv) the reserve accounts are fully funded or the applicable letters of credit have been issued and are available for drawing; and (v) the debt service coverage ratio for the two preceding semi-annual periods is not less than 1.20:1:00.

Prepayments, Certain Covenants and Events of Default

The El Arrayán Credit Agreement contains a broad range of covenants that, subject to certain exceptions, restrict El Arrayán SPA’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay dividends and change its business. El Arrayán SPA may, with certain exceptions, voluntarily prepay the facility at any time without premium or penalty except for breakage costs, and, in certain circumstances, must make mandatory prepayments of loans under the facility.

Value Added Tax Facility

In May 2012, El Arrayán SPA also entered into a $20 million value added tax facility with Corpbanca. Under the value added tax facility El Arrayán SPA may borrow funds to pay for value added tax payments due from the project. The value added tax facility has an interest rate of Chilean Interbank Rate plus 1.00% and will mature in 2016. As of December 31, 2013, the outstanding balance under the value added tax facility was $1.5 million.

South Kent Senior Financing Agreement

In March 2013, South Kent Wind LP entered into a first lien senior secured financing agreement, or the “South Kent Financing Agreement.” The South Kent Financing Agreement provides up to approximately C$683.8 million in borrowings. Borrowings under the South Kent Financing Agreement will be used to finance the construction of the South Kent project and will be comprised of a construction loan of up to approximately C$683.8 million. The construction loan converts into a term loan upon completion of construction of the South Kent project and certain other specified conditions. The term loan matures seven years after the occurrence of the term conversion. The financing is non-recourse to us. As of December 31, 2013, the outstanding balance of the loan was approximately C$544.6 million.

The South Kent Financing Agreement also provides for an operations and maintenance reserve letter of credit facility in an amount up to C$12.0 million and a debt service reserve letter of credit facility in an amount up to C$40.6 million, which we collectively refer to as the “letter of credit loans.”

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Interest Rate and Fees

The construction loan, the letter of credit loans, and, after the term conversion, the term loans are either prime rate loans or CDOR loans, and accrue interest at the prime rate or CDOR rate (as applicable), plus the applicable margin. Prime rate loans accrue interest at a rate per annum equal to the sum of the Canadian Prime Rate in effect from time to time plus 1.50% (increasing to 1.75% after the fourth anniversary of term conversion). CDOR rate loans accrue interest at a rate per annum equal to the sum of CDOR for the applicable interest period plus 2.50% (increasing to 2.75% after the fourth anniversary of term conversion). After taking into consideration our fixed-for-floating rate swaps on 90% of the loan commitment, our initial estimated effective annual interest rate on the term loan is approximately 5.54%.

South Kent Wind LP is also required to pay quarterly commitment fees on the construction loan commitment and each of the letter of credit loan commitments.

Distribution Conditions

South Kent Wind LP may distribute excess cash flows to its owners provided that specified distribution requirements are met. The distribution requirements include, among other things, that: (i) there are no letter of credit loans outstanding; (ii) the term conversion of the construction loan has occurred; (iii) no default or inchoate default has occurred and such distribution will not result in an event of default; and (iv) the annual debt service coverage ratio is equal to or greater than 1.20:1.00.

Prepayments, Certain Covenants and Events of Default

The South Kent Financing Agreement contains a broad range of covenants that, subject to certain exceptions, limit South Kent Wind LP’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay dividends and change its business. South Kent Wind LP may voluntarily prepay the facility, in whole or in part, at any time without premium or penalty except for liquidation costs or interest fix fees, as applicable, and, in certain circumstances, must make mandatory prepayments of loans under the facility.

Gulf Wind Tax Equity Partnership Transaction

Gulf Wind LLC is owned 100% by Pattern Gulf Wind Holdings LLC, or “Pattern Gulf Holdings.” On August 25, 2010, a subsidiary of Pattern Development assigned its interest in Pattern Gulf Holdings to a newly formed subsidiary, Pattern Gulf Wind Equity LLC. On September 3, 2010, Pattern Gulf Wind Equity LLC, or “Pattern Equity,” sold an interest, or the “Class A Member interest,” in Pattern Gulf Holdings to MetLife Capital, Limited Partnership, or the “Class A Member,” in a tax equity partnership transaction, pursuant to which the Class A Member is entitled to receive allocations of cash distributions and tax items of Pattern Gulf Holdings that vary over time as described below. Pattern Equity and the Class A Member agreed that the fair value of Class A Member interest was approximately 46% of the aggregate fair value of the sum of all equity interests in Pattern Gulf Holdings. We currently own 60% of the existing Class B member interests in Pattern Gulf Holdings and one of our subsidiaries is the managing member of Pattern Gulf Holdings. Throughout the remainder of this description, we and Pattern Development (as a result of its ownership of the Pattern Development retained Gulf Wind interest) together are collectively referred to as the “Class B Members.”

Allocation of Distributions

In accordance with the terms of the operating agreement of Pattern Gulf Holdings, prior to the earlier of the flip point (the point at which the Class A Member has realized a specified internal rate of return) or December 31, 2015, the Class A Member shall receive approximately 33% of all distributions from Pattern Gulf Holdings. If the flip point has not been reached by December 31, 2015, the Class A Member shall begin receiving approximately 66% of the Pattern Gulf Holdings’ cash distributions from January 1, 2016 until the flip

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point has been reached. After the flip point, the Class A Member will receive 7.25% of the distributions, but not less than the amount that will offset certain Class A Member tax liabilities, or the “Tax Make-Whole Payment.” In each case, the Class B Members will receive the remainder of all distributable cash.

Allocation of Tax Items

Prior to the flip point, Pattern Gulf Holdings’ tax items consisting of income, gain, loss and deductions, or the “Tax Items,” are allocated as follows: prior to the earlier of the flip point and December 31, 2015, 99% of the Tax Items are allocated to the Class A Member and 1% to Pattern Equity. If the flip point has not occurred by December 31, 2015, the Class A Member shall begin receiving approximately 66% of the Tax Items from January 1, 2016 until the flip point has been reached and the balance to the Class B Members. After the flip point, the Class A Member receives the greater of (i) 7.25% of the Tax Items and (ii) an amount of income or gain equal to the Tax Make-Whole Payment, and the balance, to the Class B Members.

The Class A Member’s Right to Escrow Distributions

If the Class A Member suffers any losses or damages as the result of a breach of representation by Pattern Equity or breach of covenant or other obligations by Pattern Equity, in its capacity as managing member of Pattern Gulf Holdings, the Class A Member may provide notice to Pattern Equity and require that any distributions otherwise required to be paid to the Class B Member shall, instead, be paid to the Class A Member to cover any damages caused to the Class A Member. Any distributions that Pattern Equity agrees to pay to the Class A Member are paid to the Class A Member to satisfy their damages. To the extent the parties do not agree on the damages caused to the Class A Member, the Class B Members’ distributions are required to be paid into escrow with a third party commercial bank. Such escrowed amounts will be released from escrow upon the joint instruction of both parties, or, following a judgment or court order settling the dispute between the parties.

Management of Pattern Gulf Holdings

Pattern Gulf Holdings and the project are managed by one of our subsidiaries. The Class A Member is not involved in the day-to-day management of Pattern Gulf Holdings or the project. As is customary for transactions of this type, the managing member of Pattern Gulf Holdings is required to obtain the Class A Member’s consent for certain major decisions concerning the project and set forth in the operating agreement of Pattern Gulf Holdings. Such major decisions include, for example, incurring indebtedness other than permitted indebtedness, encumbering project assets, sale of project assets, terminating material principal project documents, certain changes in method of accounting, merging and consolidating the project and such other major actions. In the event that Pattern Equity becomes insolvent, dissolves or encounters a regulatory impediment preventing its ownership of the project, the Class A Member has an option to buy out Pattern Equity’s interests in the project.

Grand Credit Agreement

In September 2013, Grand entered into a credit agreement or the “Grand Credit Agreement.” The Grand Credit Agreement provides up to C$395.4 million in construction loan borrowings and up to C$37.0 million of letters of credit under a letter of credit facility. Construction loan borrowings are being used to finance the construction of the Grand wind power project and will be converted upon completion of construction of the project to a term loan, which will mature seven years after the term conversion date of the construction loan. The outside maturity date of the term loan and the letter of credit facility is no later than June 30, 2022. Letters of credit under the letter of credit facility can be issued in connection with debt service reserve requirements, O&M reserve requirements, and decommissioning requirements. As of December 31, 2013, C$82.9 million of indebtedness was outstanding under the Grand Credit Agreement, all of which was outstanding under the construction loan and zero was outstanding under the letter of credit facility. The financing is non-recourse to us.

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Interest Rate and Fees

Loans are either prime rate loans or Canadian Dealer Offered Rate, or “CDOR” loans. If the construction loan is a prime rate loan it accrues interest at the greater of (i) lenders prime rate, or (ii) 30-day CDOR plus 1%, plus an applicable margin of 1.25%; If the construction loan is a CDOR loan it accrues interest at the applicable CDOR rate per interest period plus 2.25%. The construction loan is currently a CDOR loan and accrues interest at an average rate of 3.47%. After conversion, if the term loan is a prime rate loan it will accrue interest at the greater of (i) lenders prime rate, or (ii) 30-day CDOR plus 1%, plus an applicable margin of 1.25%; If the term loan is a CDOR loan it will accrue interest at the applicable CDOR rate per interest period plus 2.25%. The letter of credit loans are drawn as prime rate borrowings that subsequently convert to CDOR loans and accrue the same interest as the construction or term loans, as the case may be.

Grand is also required to pay quarterly commitment fees on and undrawn amount of the construction loan commitment and the letter of credit loan commitment.

Distribution Conditions

Grand may distribute excess cash flows to its owner provided that specified distribution requirements are met. The distribution requirements include that: (i) term conversion shall have occurred, (ii) the first payment of scheduled principal shall have been paid by Grand, (iii) the debt service coverage ratio at the end of Grand’s immediately preceding fiscal quarter is 1.2:1.00 or greater, (iv) all outstanding letter of credit loans shall have been paid; and (vi) no default or event of default shall have occurred and is continuing or would result from the distribution.

Prepayments, Certain Covenants and Events of Default

The Grand Credit Agreement contains standard covenants that, among other things and subject to certain exceptions, restrict Grand’s ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests, dissolve, make distributions and change its business. Grand may voluntarily prepay the construction or term loan, in whole or in part, at any time without premium or penalty, provided it shall have fist prepaid any outstanding letter of credit loans, and, in certain circumstances, must make mandatory prepayments of the loans.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2013 (in thousands):

Contractual Obligations	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Long term debt principal payments	$	1,249,218	$	48,851	$	119,330	$	128,118	$	952,919
Long term debt interest payments		532,719		57,236		106,949		96,811		271,722
Purchase commitments		4,128		4,128		—		—		—
Land leases		110,500		3,713		7,442		7,469		91,876
Turbine operations and maintenance		25,109		16,465		6,033		2,020		591
Asset retirement obligations		20,834		—		—		—		20,834
Panhandle 2 acquisition commitment		122,900		122,900		—		—		—
Total	$	2,065,408	$	253,293	$	239,754	$	234,418	$	1,337,942

Off-Balance Sheet Arrangements

We are not a party to any off-balance sheet arrangements.

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Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on our consolidated historical financial statements that are included elsewhere in this Form 10K, which have been prepared in accordance with U.S. GAAP. In applying the critical accounting policies set forth below, our management uses its judgment to determine the appropriate assumptions to be used in making certain estimates. These estimates are based on management’s experience, the terms of existing contracts, management’s observance of trends in the wind power industry, information provided by our power purchasers and information available to management from other outside sources, as appropriate. These estimates are subject to an inherent degree of uncertainty.

We use estimates, assumptions and judgments for certain items, including the depreciable lives of property, plant and equipment, impairment of long-lived assets, asset retirement obligations, derivatives, income taxes, revenue recognition, certain components of cost of revenue and exemptions, stock-based compensation and reduced reporting requirements provided by the JOBS Act. These estimates, assumptions and judgments are derived and continually evaluated based on available information, experience and various assumptions we believe to be reasonable under the circumstances. To the extent these estimates are materially incorrect and need to be revised, our operating results may be materially adversely affected.

Property, Plant and Equipment

Property, plant and equipment represents the costs of completed and operational projects transferred from construction in progress as well as land, computer equipment and software, furniture and fixtures, leasehold improvements and other equipment. Property, plant and equipment are stated at cost, less accumulated depreciation. Depreciation is calculated using the straight-line method over the assets’ useful lives. Wind power projects are depreciated over 20 years and the remaining assets are depreciated over three to five years. Land is not depreciated. Improvements to Property, plant and equipment represents the costs of completed and operational projects transferred from construction in property, plant and equipment deemed to extend the useful economic life of an asset are capitalized. Repair and maintenance costs are expensed as incurred.

Derivatives

We have, and we intend to, enter into derivative transactions for the purpose of reducing exposure to fluctuations in interest rates, electricity prices and foreign currency exchange rates. We entered into fixed for floating interest rate swap agreements and have designated these derivatives as qualified cash flow hedges of its expected interest payments on variable rate debt. We have also entered into interest rate caps.

We recognize our derivative instruments at fair value in the consolidated balance sheet. Accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether the derivative instrument has been designated as part of a hedging relationship and on the type of hedging relationship.

For derivative instruments that are designated as cash flow hedges the effective portion of change in fair value of the derivative is reported as a component of other comprehensive income. The ineffective portion of change in fair value is recorded as a component of net income on the consolidated statement of operations.

For undesignated derivative instruments their change in fair value is reported as a component of net income on the consolidated statement of operations.

An interest rate cap is an instrument used to reduce exposure to future variable interest rates when the related debt is expected to be refinanced. We entered into an interest rate cap in 2010. The cap remains in place as of December 31, 2013.

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We entered into an electricity price arrangement, which qualifies as a derivative, that fixes the price of approximately 58% of the electricity generation expected to be produced and sold by Gulf Wind through April 2019, and which reduces our exposure to spot electricity prices.

Our interest rate cap and energy derivative agreement do not qualify for hedge accounting.

Income Taxes

Prior to October 2, 2013, our predecessor did not provide for income taxes as it was treated as a pass-through entity for U.S. federal and state income tax purposes, except for several specific circumstances involving its Canadian entities, which are subject to Canadian income taxes, its Chilean entities, which are subject to Chilean income taxes, a U.S. entity that is subject to Puerto Rican taxes and a U.S. entity which became subject to U.S. income taxes in 2012. Federal and state income taxes were assessed at the owner level and each owner was liable for its own tax payments. Certain consolidated entities are corporations or have elected to be taxed as corporations. In these circumstances, income tax was accounted for under the asset and liability method.

Subsequent to October 2, 2013, following the Contribution Transactions, we account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning and results of recent operations. If we determine that we would be able to realize deferred tax assets in the future in excess of their net recorded amount, we would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes. We record uncertain tax positions in accordance with ASC 740 on the basis of a two-step process whereby (1) we determine whether it is more likely than not that the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, we recognize the largest amount of tax benefit that is more than 50 percent likely to be realized upon ultimate settlement with the related tax authority. We have a policy to classify interest and penalties associated with uncertain tax positions together with the related liability, and the expenses incurred related to such accruals, if any are included in the provision for income taxes.

Revenue Recognition

We sell the electricity we generate under the terms of our power sale agreements or at spot market prices. Revenue is recognized based upon the amount of electricity delivered at rates specified under the contracts, assuming all other revenue recognition criteria are met. We evaluate our PPAs to determine whether they are in substance leases or derivatives and, if applicable, recognize revenue pursuant to Accounting Standards Codification (“ASC”) 840Leases and ASC 815Derivatives and Hedging, respectively. As of December 31, 2012, there were no PPAs that are accounted for as leases or derivatives.

We also generate renewable energy credits as we produce electricity. Certain of these energy credits are sold independently in an open market and revenue is recognized at the time title to the energy credits is transferred to the buyer.

We acquired a ten-year energy derivative instrument under the terms of our acquisition of Gulf Wind, which fixes approximately 58% of our expected electricity sales at Gulf Wind through April 2019. The energy

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derivative instrument reduces exposure to changes in commodity prices by allowing us to lock in a fixed price per MWh for a specified amount of annual electricity production. The monthly settlement amounts under the energy hedge are accounted for as energy derivative settlements in the consolidated statements of operations. The change in the fair value of the energy hedge is classified as energy derivative revenue in the consolidated statements of operations.

Cost of Revenue

Our cost of revenue is comprised of direct costs of operating and maintaining our power projects, including labor, turbine service arrangements, land lease royalties, depreciation, amortization, property taxes and insurance.

Stock-Based Compensation

We account forstock-based compensation related to stock options granted to employees by estimating the fair value of thestock-based awards using theBlack-Scholesoption-pricing model. The fair value of the stock options granted are amortized over the applicable vesting period. TheBlack-Scholes option pricing model includes assumptions regarding dividend yields, expected volatility, expected option term, expected forfeiture rate and risk-free interest rates. We estimate expected volatility based on the historical volatility of comparable publicly traded companies for a period that is equal to the expected term of the options. The risk-free interest rate is based on the U.S. treasury yield curve in effect at the time of grant for a period commensurate with the estimated expected life. The expected term of options granted is derived using the “simplified” method as allowed under the provisions of the ASC 718Compensation—Stock Compensation, and represents the period of time that options granted are expected to be outstanding.

We account forstock-based compensation related to restricted stock award grants by amortizing the fair value of the restricted stock award grants, which is the grant date market price, over the applicable vesting period.

JOBS Act

In April 2012, the JOBS Act was enacted. Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the U.S. Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are electing to delay such adoption of new or revised accounting standards, and as a result, we may not comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for other companies.

Additionally, we regularly evaluate the benefits of relying on other exemptions and reduced reporting requirements provided by the JOBS Act. We may choose to take advantage of some but not all of these reduced burdens. For so long as we are an SEC foreign issuer under Canadian securities laws, we will be exempt from the continuous disclosure requirements of Canadian securities laws, subject to limited exceptions, if we comply with the reporting requirements applicable in the United States, including certain provisions of the JOBS Act.

Subject to certain conditions set forth in the JOBS Act and Canadian securities laws, as an emerging growth company, we intend to rely on certain of these exemptions, including, without limitation, providing an auditor’s attestation report on our system of internal controls over financial reporting pursuant to Section 404 and complying with any requirement that may be adopted regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements (auditor discussion and analysis). These exemptions will apply for a period of five years following our initial public offering; although, if the market value of our shares that are held by non-affiliates exceeds $700 million as of any December 31 before that time, we would cease to be an emerging growth company as of the following December 31.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We have significant exposure to commodity prices, interest rates and foreign currency exchange rates, as described below. To mitigate these market risks, we have entered into multiple derivatives. We have not applied hedge accounting treatment to all of our derivatives, therefore we are required to mark some of our derivatives to market through earnings on a periodic basis, which will result in non-cash adjustments to our earnings and may result in volatility in our earnings, in addition to potential cash settlements for any losses.

Commodity Price Risk

We manage our commodity price risk for electricity sales through the use of long-term power sale agreements with creditworthy counterparties. Our financial results reflect approximately 308,000 MWh of electricity sales in the year ended December 31, 2013 that were not subject to power sale agreements and were subject to spot market pricing. A hypothetical increase or decrease of $3.04 per MWh (or an approximately 10% change) in these spot market prices would have increased or decreased earnings by $0.9 million, respectively, for the year ended December 31, 2013.

Interest Rate Risk

We use a variety of derivative instruments to manage our exposure to fluctuations in interest rates, including interest rate swaps and interest rate caps, primarily in the context of our project-level indebtedness. We generally match the tenor and amount of these instruments to the tenor and amount, respectively, of the related debt financing. We also will have exposure to changes in interest rates with respect to our revolving credit agreement to the extent that we make draws under that facility. A hypothetical increase or decrease in short-term interest rates by 1% would not have changed our earnings for the year ended December 31, 2013.

Foreign Currency Risk

We manage our foreign currency risk through the consideration of forward exchange rate derivatives. Certain of our power sale agreements are U.S. dollar denominated and others are Canadian dollar denominated. We did not enter into forward exchange rate derivatives to manage our exposure to Canadian dollar denominated revenues at our St. Joseph contract in the past. Our financial results include approximately $40.3 million of revenue that was earned pursuant to Canadian dollar denominated power sale agreements. A hypothetical increase of US$0.10 per Canadian dollar would have increased our earnings by $0.3 million for the year ended December 31, 2013, and a hypothetical decrease of US$0.10 per Canadian dollar would have decreased our earnings by $0.3 million for the year ended December 31, 2013.

Item 8. Financial Statements and Supplementary Data.

The financial statements and schedules are listed in Part IV, Item 15 of this Form 10-K, beginning at page F-1, Index to Consolidated Financial Statements, and are incorporated by reference herein.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Exchange Act. In designing and evaluating the disclosure controls and procedures, management recognizes that any disclosure controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

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Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2013.

Attestation Report of the Registered Public Accounting Firm

This report does not include an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.

Change in Internal Control Over Financial Reporting

There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B. Other Information.

None.

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PART III

Certain information required by Part III is omitted from this Form 10-K because the registrant will file with the U.S. Securities and Exchange Commission a definitive proxy statement pursuant to Regulation 14A in connection with the solicitation of proxies for the Company’s Annual Meeting of Stockholders, or the 2014 Proxy Statement, within 120 days after the end of the fiscal year covered by this Form 10-K, and certain information included therein is incorporated herein by reference.

Item 10. Directors, Executive Officers and Corporate Governance.

The information required under this Item 10 is incorporated by reference to our 2014 Proxy Statement.

Item 11. Executive Compensation.

The information required under this Item 11 is incorporated by reference to our 2014 Proxy Statement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related StockholderMatters

The information required under this Item 12 is incorporated by reference to our 2014 Proxy Statement.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required under this Item 13 is incorporated by reference to our 2014 Proxy Statement.

Item 14. Principal Accounting Fees and Services.

We have engaged Ernst and Young LLP as our independent registered public accounting firm. The following table presents fees for the audit of the Company’s annual consolidated financial statements for the last two fiscal years and for other services provided by Ernst and Young LLP (in thousands):

	Year ended December 31,
	2013		2012
Audit fees(1)	$	1,961	$	2,865
All other fees		—		—
Total	$	1,961	$	2,865

⁽¹⁾ “Audit fees” in 2012 relate to (a) the audit of the combined financial statements of our predecessor as at December 31, 2012 and 2011 and the related combined statements of operations, comprehensive income, equity and cash flows for the years ended December 31, 2012, 2011, 2010 and 2009 and (b) procedures performed in connection with our initial public offering.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)	Documents filed as part of this report
(1)	Financial statements—Pattern Energy Group Inc.
	Report of Independent Registered Public Accounting Firm	F-2
	Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012	F-3
	Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011	F-4
	Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011	F-5
	Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2013, 2012 and  2011	F-6
	Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	F-7
	Notes to Consolidated Financial Statements	F-9
(2)	Financial Statement Schedules
	a)Schedule I—Condensed Parent-Company Financial Statements	S-1
	b)Schedule II—South Kent Wind LP Financial Statements	S-4
(3)	Exhibits

The following documents are filed or furnished as part of this Form 10-K. The Company will furnish a copy of any exhibit listed to requesting stockholders upon payment of the Company’s reasonable expenses in furnishing those materials.

Exhibit No.	Description Of Exhibit
3.1	Amended and Restated Certificate of Incorporation of Pattern Energy Group Inc. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1/A dated September 20, 2013 (Registration No. 333-190538)).
3.2	Amended and Restated Bylaws of Pattern Energy Group Inc. (Incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).
4.1	Form of Class A Stock Certificate (Incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).
10.1	Credit and Guaranty Agreement, among Pattern US Finance Company LLC, Pattern Canada Finance Company ULC, as borrowers, certain subsidiaries of the borrowers, the lenders party thereto from time to time, Royal Bank of Canada, as Administrative Agent and Collateral Agent, Bank of Montreal, as Syndication Agent, and Morgan Stanley Bank, N.A., as Documentation Agent, dated as of November 15, 2012. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).
10.2	Pattern Energy Group Inc. 2013 Equity Incentive Award Plan (Incorporated by reference to Exhibit 10.2 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).
10.3	Form of Pattern Energy Group Inc. 2013 Incentive Bonus Plan. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).

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Exhibit No.	Description Of Exhibit
10.4	Form of Stock Option Agreement under 2013 Equity Incentive Award Plan. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).
10.5	Form of Restricted Stock Agreement under 2013 Equity Incentive Award Plan. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Registration Statement on Form S-1/A dated September 20, 2013 (Registration No. 333-190538)).
10.6	Form of Restricted Stock Unit Agreement under 2013 Equity Incentive Award Plan. (Incorporated by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).
10.7	Form of Indemnification Agreement between the Registrant and each of its Executive Officers and Directors. (Incorporated by reference to Exhibit 10.7 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).
10.8	Registration Rights Agreement between the Company and Pattern Energy Group LP, dated as of October 2, 2013. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Registration Statement on Form 8-K dated September 26, 2013 (Registration No. 333-190538)).
10.9	Contribution Agreement among the Company, Pattern Renewables LP, Pattern Energy Group LP, and Pattern Renewable Holdings Canada ULC, dated as of October 2, 2013. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Registration Statement on Form 8-K dated September 26, 2013 (Registration No. 333-190538)).
10.10	Purchase Rights Agreement among the Company, Pattern Energy Group LP, Pattern Energy Group Holdings LP and Pattern Energy GP LLC, dated as of October 2, 2013. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Registration Statement on Form 8-K dated September 26, 2013 (Registration No. 333-190538)).
10.11	Bilateral Management Services Agreement between the Company and Pattern Energy Group LP, dated as of October 2, 2013. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Registration Statement on Form 8-K dated September 26, 2013 (Registration No. 333-190538)).
10.12	Non-Competition Agreement between the Company and Pattern Energy Group LP, dated October 2, 2013. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Registration Statement on Form 8-K dated September 26, 2013 (Registration No. 333-190538)).
10.13	Shareholder Approval Rights Agreement between the Company and Pattern Energy Group LP, dated as of October 2, 2013. (Incorporated by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form 8-K dated September 26, 2013 (Registration No. 333-190538)).
10.15	Purchase and Sale Agreement, dated as of December 20, 2013, by and between Pattern Canada Operations Holdings ULC and Pattern Energy Group LP (Grand PSA) . (Incorporated by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form 8-K dated December 20, 2013 (Registration No. 333-190538)).
10.16	Purchase and Sale Agreement, dated as of December 20, 2013, by and among Pattern Energy Group Inc., Panhandle B Holdco 2 LLC and Pattern Energy Group LP (PH2 PSA) ((Incorporated by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form 8-K dated December 20, 2013 (Registration No. 333-190538)).
10.17	Management, Operation and Maintenance Agreement, dated as of December 20, 2013, by and between Pattern Panhandle Wind 2 LLC and Pattern Operators LP (PH2 MOMA) (Incorporated by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form 8-K dated December 20, 2013 (Registration No. 333-190538)).

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Exhibit No.	Description Of Exhibit
10.18	Project Administration Agreement, dated as of December 20, 2013, by and between Pattern Panhandle Wind 2 LLC and Pattern Operators LP (PH2 PAA) (Incorporated by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form 8-K dated December 20, 2013 (Registration No. 333-190538)).
10.19	Employment Agreement between Pattern Energy Group Inc. and Michael M. Garland dated October 2, 2013
10.20	Employment Agreement between Pattern Energy Group Inc. and Hunter H. Armistead dated October 2, 2013
10.21	Employment Agreement between Pattern Energy Group Inc. and Daniel M. Elkort dated October 2, 2013
21.1	List of Subsidiaries
23.1	Consent of Ernst & Young LLP
23.2	Consent of PricewaterhouseCoopers LLP
24.1	Powers of Attorney (included in the signature pages to this filing).
31.1	Certification of the Company’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of the Company’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certifications of the Company’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document

* This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed “filed” by the Company for purposes of Section 18 of the Exchange Act.

** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act and are deemed not filed for purposes of Section 18 of the Exchange Act and otherwise are not subject to liability under these sections.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: February 28, 2014	Pattern Energy Group Inc.
	By	/S/ Michael M. Garland
	Michael M. Garland
	President and Chief Executive Officer

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Dyann Blaine and Michael Lyon, and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming that all said attorneys-in-fact and agents, or any of them or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/S/ MICHAEL M. GARLAND Michael M. Garland	President, Chief Executive Officer and Director of Pattern Energy Group Inc. (Principal Executive Officer)	February 28, 2014
/S/ ALAN R. BATKIN Alan R. Batkin	Director and Chairman of Pattern Energy Group Inc.	February 28, 2014
/S/ PATRICIA S. BELLINGER Patricia S. Bellinger	Director of Pattern Energy Group Inc.	February 28, 2014
/S/ THE LORD BROWNE OF MADINGLEY The Lord Browne of Madingley	Director of Pattern Energy Group Inc.	February 28, 2014
/S/ DOUGLAS G. HALL Douglas G. Hall	Director of Pattern Energy Group Inc.	February 28, 2014
/S/ MICHAEL B. HOFFMAN Michael B. Hoffman	Director of Pattern Energy Group Inc.	February 28, 2014

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Signature	Title	Date
/S/ PATRICIA M. NEWSON Patricia M. Newson	Director of Pattern Energy Group Inc.	February 28, 2014
/S/ MICHAEL J. LYON Michael J. Lyon	Chief Financial Officer of Pattern Energy Group Inc. (Principal Financial Officer)	February 28, 2014
/S/ ERIC S. LILLYBECK Eric S. Lillybeck	Senior Vice President, Fiscal and Administrative Services of Pattern Energy Group Inc. (Principal Accounting Officer)	February 28, 2014

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012	F-3
Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011	F-4
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011	F-5
Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2013, 2012 and 2011	F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	F-7
Notes to Consolidated Financial Statements	F-9

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Pattern Energy Group Inc. and Subsidiaries

We have audited the accompanying consolidated balance sheets of Pattern Energy Group Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We did not audit the financial statements of South Kent Wind LP and Grand Renewable Wind LP, partnerships in which the Company has a 50% and 45% interest, respectively. In the consolidated financial statements, the Company’s investment in South Kent Wind LP and Grand Renewable Wind LP is stated at $85,952,000 at December 31, 2013 and the Company’s equity in the net income of South Kent Wind LP and Grand Renewable Wind LP is stated at $8,212,000 for the year ended December 31, 2013. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for South Kent Wind LP and Grand Renewable Wind LP, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the reports of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pattern Energy Group Inc. and subsidiaries at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

San Francisco, California

February 28, 2014

F-2

Pattern Energy Group Inc.

Consolidated Balance Sheets

(In thousands of U.S. Dollars, except share data)

	December 31,
	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	103,569		$	17,574
Trade receivables		20,951			13,715
Related party receivable		167			—
Reimbursable interconnection costs		1,455			51,307
Derivative assets, current		13,937			17,177
Current deferred tax assets		573			—
Prepaid expenses and other current assets		13,927			13,794
Total current assets		154,579			113,567
Restricted cash		32,636			13,904
Turbine advances		—			44,150
Deferred development costs		—			26,544
Construction in progress		—			6,081
Property, plant and equipment, net of accumulated depreciation of $179,778 and $100,247 in 2013 and 2012, respectively		1,476,142			1,668,302
Unconsolidated investments		107,055			36,218
Derivative assets		82,167			62,895
Deferred financing costs, net of accumulated amortization of $16,225 and $9,311 in 2013 and 2012, respectively		35,792			42,654
Net deferred tax assets		2,017			4,940
Other assets		13,243			16,475
Total assets	$	1,903,631		$	2,035,730
Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities	$	15,550		$	7,750
Accrued construction costs		3,204			67,206
Related party payable		1,245			198
Accrued interest		495			559
Dividend payable		11,103			—
Contingent liabilities		—			8,001
Derivative liabilities, current		16,171			13,462
Current portion of long-term debt		48,851			137,258
Total current liabilities		96,619			234,434
Long-term debt		1,200,367			1,153,312
Derivative liabilities		7,439			35,326
Asset retirement obligations		20,834			19,056
Net deferred tax liabilities		9,930			3,662
Other long-term liabilities		438			528
Total liabilities		1,335,627			1,446,318
Equity:
Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 35,530,786 and 100 shares issued and outstanding as of December 31, 2013 and 2012, respectively		355			—
Class B common stock, $0.01 par value per share: 20,000,000 shares authorized; 15,555,000 shares issued and outstanding at December 31, 2013		156			—
Additional paid-in capital		489,388			1
Capital		—			545,471
Accumulated (loss) income		(13,336	)		2,903
Accumulated other comprehensive loss		(8,353	)		(34,264	)
Total equity before noncontrolling interest		468,210			514,111
Noncontrolling interest		99,794			75,301
Total equity		568,004			589,412
Total liabilities and equity	$	1,903,631		$	2,035,730

See accompanying notes to consolidated financial statements.

F-3

Pattern Energy Group Inc.

Consolidated Statements of Operations

(In thousands of U.S. Dollars, except share data)

	Year ended December 31,
	2013			2012			2011
Revenue:
Electricity sales	$	173,270		$	101,835		$	108,770
Energy derivative settlements		16,798			19,644			9,512
Unrealized (loss) gain on energy derivative		(11,272	)		(6,951	)		17,577
Related party revenue		911			—			—
Other revenue		21,866			—			—
Total revenue		201,573			114,528			135,859
Cost of revenue:
Project expense		57,677			34,843			31,343
Depreciation and accretion		83,180			49,027			39,424
Total cost of revenue		140,857			83,870			70,767
Gross profit		60,716			30,658			65,092
Operating expenses:
Development expense		—			174			704
General and administrative		4,819			858			866
Related party general and administrative		8,169			10,604			8,098
Total operating expenses		12,988			11,636			9,668
Operating income		47,728			19,022			55,424
Other income (expense):
Interest expense		(63,614	)		(36,502	)		(29,404	)
Equity in earnings (losses) in unconsolidated investments		7,846			(40	)		(205	)
Interest rate derivative settlements		(2,099	)		—			—
Unrealized gain (loss) on derivatives		15,601			(4,953	)		(345	)
Net gain on transactions		5,995			4,173			—
Related party income		665			—			—
Other income, net		2,496			1,320			1,125
Total other expense		(33,110	)		(36,002	)		(28,829	)
Net income (loss) before income tax		14,618			(16,980	)		26,595
Tax provision (benefit)		4,546			(3,604	)		689
Net income (loss)		10,072			(13,376	)		25,906
Net (loss) income attributable to noncontrolling interest		(6,887	)		(7,089	)		16,981
Net income (loss) attributable to controlling interest	$	16,959		$	(6,287	)	$	8,925
Earnings per share information:
Less: Net income attributable to controlling interest prior to the IPO on October 2, 2013		(30,295	)
Net loss attributable to controlling interest subsequent to the IPO	$	(13,336	)
Weighted average number of shares:
Basic and diluted—Class A common stock		35,448,056
Basic and diluted—Class B common stock		15,555,000
Earnings per share for period subsequent to the IPO
Class A common stock:
Basic and diluted loss per share	$	(0.17	)
Class B common stock:
Basic and diluted loss per share	$	(0.48	)
2012 pro forma information:
Unaudited pro forma net loss after tax:
Net loss before income tax				$	(16,980	)
Pro forma tax provision					818
Pro forma net loss				$	(17,798	)

See accompanying notes to consolidated financial statements.

F-4

Pattern Energy Group Inc.

Consolidated Statements of Comprehensive Income (Loss)

(In thousands of U.S. Dollars)

	Year ended December 31,
	2013			2012			2011
Net income (loss)	$	10,072		$	(13,376	)	$	25,906
Other comprehensive income (loss):
Foreign currency translation, net of tax		(8,309	)		2,749			(2,406	)
Effective portion of change in fair market value of derivatives, net of tax		36,875			(11,170	)		(23,667	)
Proportionate share of equity investee’s other comprehensive income (loss), net of tax		2,473			(1,475	)		—
Total other comprehensive income (loss), net of tax		31,039			(9,896	)		(26,073	)
Comprehensive income (loss)		41,111			(23,272	)		(167	)
Less comprehensive income attributable to noncontrolling interest:
Net (loss) income attributable to noncontrolling interest		(6,887	)		(7,089	)		16,981
Effective portion of change in fair market value of derivatives, net of tax		5,088			(784	)		(6,135	)
Comprehensive (loss) income attributable to noncontrolling interest		(1,799	)		(7,873	)		10,846
Comprehensive income (loss) attributable to controlling interest	$	42,910		$	(15,399	)	$	(11,013	)

See accompanying notes to consolidated financial statements.

F-5

Pattern Energy Group Inc.

Consolidated Statement of Stockholders’ Equity

(In thousands of U.S. Dollars, except share data)

	Controlling Interest																									Noncontrolling Interest												Total Equity
	Class A Common Stock					Class B Common Stock					Additional Paid-in Capital			Capital			Accumulated Income (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total			Capital			Accumulated Income (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	Shares			Amount		Shares		Amount
Balances at January 1, 2011		—		$	—		—	$	—		$	—		$	260,109		$	265		$	(5,214	)	$	255,160		$	82,633		$	2,474		$	(4,323	)	$	80,784		$	335,944
Contribution		—			—		—		—			—			232,277			—			—			232,277			—			—			—			—			232,277
Distribution		—			—		—		—			—			(114,198	)		—			—			(114,198	)		(7,158	)		—			—			(7,158	)		(121,356	)
Net income		—			—		—		—			—			—			8,925			—			8,925			—			16,981			—			16,981			25,906
Other comprehensive loss, net of tax		—			—		—		—			—			—			—			(19,938	)		(19,938	)		—			—			(6,135	)		(6,135	)		(26,073	)
Balances at December 31, 2011		—			—		—		—			—			378,188			9,190			(25,152	)		362,226			75,475			19,455			(10,458	)		84,472			446,698
Contribution		—			—		—		—			—			281,519			—			—			281,519			—			—			—			—			281,519
Distribution		—			—		—		—			—			(114,236	)		—			—			(114,236	)		(1,298	)		—			—			(1,298	)		(115,534	)
Issuance of common stock		100			—		—		—	��		1			—			—			—			1			—			—			—			—			1
Net loss		—			—		—		—			—			—			(6,287	)		—			(6,287	)		—			(7,089	)		—			(7,089	)		(13,376	)
Other comprehensive loss, net of tax		—			—		—		—			—			—			—			(9,112	)		(9,112	)		—			—			(784	)		(784	)		(9,896	)
Balances at December 31, 2012		100			—		—		—			1			545,471			2,903			(34,264	)		514,111			74,177			12,366			(11,242	)		75,301			589,412
Contribution		—			—		—		—			—			32,677			—			—			32,677			—			—			—			—			32,677
Distribution		—			—		—		—			—			(104,634	)		—			—			(104,634	)		(1,426	)		—			—			(1,426	)		(106,060	)
Additional paid-in capital		—			—		—		—			2			—			—			—			2												—			2
Net income (loss)		—			—		—		—			—			—			30,295			—			30,295			—			(690	)		—			(690	)		29,605
Other comprehensive income, net of tax		—			—		—		—			—			—			—			20,633			20,633			—			—			3,559			3,559			24,192
Balances at October 1, 2013		100			—		—		—			3			473,514			33,198			(13,631	)		493,084			72,751			11,676			(7,683	)		76,744			569,828
Interest in Gulf Wind retained by Pattern Development		—			—		—		—			—			(18,332	)		(13,122	)		2,870			(28,584	)		18,332			13,122			(2,870	)		28,584			—
Assumption of liabilities related to Contribution Transactions		—			—		—		—			—			(4,207	)		—			—			(4,207	)		—			—			—			—			(4,207	)
Issuance of common stock for Contribution Transactions		19,445,000			194		15,555,000		156			470,701			(450,975	)		(20,076	)		—			—			—			—			—			—			—
Deemed distribution for Contribution Transactions		—			—		—		—			(232,640	)		—			—			—			(232,640	)											—			(232,640	)
Issuance of Class A common stock related to the IPO, net of issuance costs		16,000,000			160		—		—			316,882			—			—			—			317,042			—			—			—			—			317,042
Issuance of Class A restricted common stock		83,183			1		—		—			155			—			—			—			156			—			—			—			—			156
Issuance of Class A common stock		3,437			—		—		—			93			—			—			—			93						—			—			—			93
Repurchase of shares for employee tax withholding		(934	)		—		—		—			(24	)		—			—			—			(24	)		—			—			—			—			(24	)
Stock-based compensation		—			—		—		—			263			—			—			—			263			—			—			—			—			263
Dividends declared on Class A common stock		—			—		—		—			(11,103	)		—			—			—			(11,103	)		—			—			—			—			(11,103	)
Acquisition from Pattern Development		—			—		—		—			(54,942	)		—			—			(2,910	)		(57,852	)		—			—			—			—			(57,852	)
Distribution to noncontrolling interest		—			—		—		—			—			—			—			—			—			(866	)		—			—			(866	)		(866	)
Net loss		—			—		—		—			—			—			(13,336	)		—			(13,336	)		—			(6,197	)		—			(6,197	)		(19,533	)
Other comprehensive income, net of tax		—			—		—		—			—			—			—			5,318			5,318			—			—			1,529			1,529			6,847
Balances at December 31, 2013		35,530,786		$	355		15,555,000	$	156		$	489,388		$	—		$	(13,336	)	$	(8,353	)	$	468,210		$	90,217		$	18,601		$	(9,024	)	$	99,794		$	568,004

See accompanying notes to consolidated financial statements.

F-6

Pattern Energy Group Inc.

Consolidated Statement of Cash Flows

(In thousands of U.S. Dollars)

	Year ended December 31,
	2013			2012			2011
Operating activities
Net income (loss)	$	10,072		$	(13,376	)	$	25,906
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and accretion		83,180			49,027			39,424
Amortization of financing costs		6,816			2,546			1,477
Unrealized (gain) loss on derivatives		(4,329	)		11,904			(17,232	)
Stock-based compensation		511			—			—
Net gain on transactions		(5,995	)		(4,173	)		—
Deferred taxes		4,546			(3,604	)		809
Equity in (earnings) loss in unconsolidated investments		(7,846	)		40			205
Changes in operating assets and liabilities:
Trade receivables		(8,721	)		(298	)		(6,438	)
Reimbursable interconnection receivable		(11	)		—			—
Prepaid expenses and other current assets		(2,698	)		(5,842	)		2,793
Other assets (non current)		(566	)		(428	)		(422	)
Accounts payable and other accrued liabilities		3,036			(379	)		167
Income taxes payable		—			—			(259	)
Related party receivable/payable		190			(100	)		54
Accrued interest payable		(33	)		(78	)		446
Contingent liabilities		—			(188	)		—
Net cash provided by operating activities		78,152			35,051			46,930
Investing activities
Receipt of ITC Cash Grant		173,446			79,910			—
Payment for acquisition from Pattern Development		(30,070	)		—			—
Proceeds from sale of investments and tax credits		14,254			4,173			—
Decrease in restricted cash —interconnect and PPA security		66,517			28,431			9,988
Increase in restricted cash —interconnect and PPA security		(80,569	)		(36,576	)		(1,889	)
Capital expenditures		(123,517	)		(641,422	)		(392,212	)
Deferred development costs		(528	)		(7,093	)		(17,777	)
Distribution from unconsolidated investments		10,463			—			—
Contribution to unconsolidated investments		(9,678	)		(22,387	)		(13,173	)
Short-term notes receivable		—			—			80,311
Reimbursable interconnection receivable		49,715			(47,055	)		—
Other assets (non current)		2,358			3,066			(6,225	)
Net cash provided by (used in) investing activities		72,391			(638,953	)		(340,977	)

See accompanying notes to consolidated financial statements.

F-7

Pattern Energy Group Inc.

Consolidated Statement of Cash Flows

(In U.S. Dollars)

	Year ended December 31,
	2013			2012			2011
Financing activities
Proceeds from IPO, net of expenses	$	317,926		$	—		$	—
Repurchase of shares for employee tax withholding		(24	)		—			—
Capital distributions—Contribution Transactions		(232,640	)		—			—
Payment for acquisition from Pattern Development		(49,430	)		—			—
Capital contributions—controlling interest		32,679			281,519			232,277
Capital distributions—controlling interest		(98,886	)		(114,236	)		(114,198	)
Capital distributions—noncontrolling interest		(2,292	)		(1,298	)		(7,158	)
Decrease in restricted cash—debt service reserves		122,689			26,669			13,048
Increase in restricted cash—debt service reserves		(127,369	)		(15,850	)		(14,096	)
Payment for deferred financing costs		(294	)		(19,989	)		(17,001	)
Proceeds from revolving credit facility		56,000			—			—
Proceeds from long-term debt		138,620			497,226			260,794
Repayment of revolving credit facility		(56,000	)		—			—
Repayment of long-term debt		(50,324	)		(27,546	)		(22,330	)
Repayment of construction and grant loans		(114,056	)		(53,328	)		—
Net cash (used in) provided by financing activities		(63,401	)		573,167			331,336
Effect of exchange rate changes on cash and cash equivalents		(1,147	)		637			1,455
Net change in cash and cash equivalents		85,995			(30,098	)		38,744
Cash and cash equivalents at beginning of period		17,574			47,672			8,928
Cash and cash equivalents at end of period	$	103,569		$	17,574		$	47,672
Supplemental disclosure
Cash payments for interest and commitment fees	$	57,505		$	43,474		$	30,648
Cash payments for income taxes		—			—			141
Schedule of non-cash activities
Change in fair value of interest rate swaps		52,244			(11,173	)		(23,667	)
Change in fair value of contingent liabilities		—			(2,015	)		(486	)
Amortization of deferred financing costs—included as construction in progress		175			3,824			595
Capitalized interest		4,171			9,386			3,621
Capitalized commitment fee		39			873			599
Change in property, plant and equipment		(192,461	)		30,154			(61,338	)
Transfer of capitalized assets to South Kent joint venture		49,275			—			—
Non-cash distribution to Pattern Development		(5,748	)		—			—
Assumption of liabilities related to Contribution Transactions		(4,207	)		—			—
Accrued IPO stock issuance costs		(884	)		—			—

See accompanying notes to consolidated financial statements.

F-8

Pattern Energy Group Inc.

Notes to Consolidated Financial Statements

1. Organization

Pattern Energy Group Inc. (“Pattern Energy” or the “Company”) was organized in the state of Delaware on October 2, 2012. Pattern Energy issued 100 shares on October 17, 2012 to Pattern Renewables LP, a 100% owned subsidiary of Pattern Energy Group LP (“Pattern Development”). On September 24, 2013, Pattern Energy’s charter was amended, and the number of shares that Pattern Energy is authorized to issue was increased to 620,000,000 total shares; 500,000,000 of which are designated Class A Common Stock, 20,000,000 of which are designated Class B Common Stock, and 100,000,000 of which are designated Preferred Stock.

Pattern Energy is an independent energy generation company focused on constructing, owning and operating energy projects with long-term energy sales contracts located in the United States, Canada and Chile. The Company consists of the consolidated operations of certain entities and assets contributed by Pattern Development. The Company owns 100% of Hatchet Ridge Wind, LLC (Hatchet Ridge), St. Joseph Windfarm Inc. (St. Joseph), Spring Valley Wind LLC (Spring Valley), Pattern Santa Isabel LLC (Santa Isabel) and Ocotillo Express LLC (Ocotillo). The Company owns a controlling interest in Pattern Gulf Wind Holdings LLC (Gulf Wind) and noncontrolling interests in South Kent Wind LP (South Kent), Grand Renewable Wind LP (Grand) and AEI-Pattern Holding Limitada (El Arrayán). The principal business objective of the Company is to produce stable and sustainable cash flows through the generation and sale of energy.

Initial Public Offering and Contribution Transactions

On October 2, 2013, Pattern Energy issued 16,000,000 shares of Class A common stock in an initial public offering (“IPO”) generating net proceeds of approximately $317.0 million. Concurrent with the IPO, Pattern Energy issued 19,445,000 shares of Class A common stock and 15,555,000 shares of Class B common stock to Pattern Development and utilized approximately $232.6 million of the net proceeds of the IPO as a portion of the consideration to Pattern Development for certain entities and assets contributed to Pattern Energy (“Contribution Transactions”) consisting of interests in eight wind power projects, including six projects in operation (Gulf Wind, Hatchet Ridge, St. Joseph, Spring Valley, Santa Isabel and Ocotillo), and two projects under construction (El Arrayán and South Kent). In accordance with ASC 805-50-30-5,Transactions between Entities under Common Control, Pattern Energy recognized the assets and liabilities contributed by Pattern Development at their historical carrying amounts at the date of the Contribution Transactions. On October 8, 2013, Pattern Energy’s underwriters exercised in full their overallotment option to purchase 2,400,000 shares of Class A common stock from Pattern Development, the selling stockholder, pursuant to the overallotment option granted by Pattern Development.

In connection with the Contribution Transactions, Pattern Development retained a 40% portion of the interest in Gulf Wind previously held by it such that, at the completion of the IPO, Pattern Energy, Pattern Development and the joint venture partner held interests of approximately 40%, 27% and 33%, respectively, of the distributable cash flow of Gulf Wind, together with certain allocated tax items.

Effective with Pattern Energy’s IPO, Pattern Development’s project operations and maintenance personnel and certain of its executive officers became Pattern Energy employees and their employment with Pattern Development was terminated. Pattern Development retained those employees whose primary responsibilities relate to project development, legal, financial or other administrative functions. Pattern Energy entered into a bilateral services agreement with Pattern Development, or the “Management Services Agreement”, that provides for Pattern Energy and Pattern Development to benefit, primarily on a cost-reimbursement basis, from the respective management and other professional, technical and administrative personnel of the respective companies, all of whom report to and are managed by Pattern Energy’s executive officers.

F-9

Basis of Presentation

Pattern Energy was formed by Pattern Development for the purpose of an IPO and does not have any historical financial operating results. For periods prior to October 2, 2013, Pattern Energy was a shell company, with expenses of less than $10,000 for 2013 and 2012. In accordance with ASC 805-50-30-6, the historical financial statements of Pattern Energy’s predecessor, which consist of the combined financial statements of a combination of entities and assets contributed by Pattern Development to Pattern Energy, are consolidated with Pattern Energy (the “Company”) from the beginning of the earliest period presented.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP). They include the results of wholly-owned and partially-owned subsidiaries in which the Company has a controlling interest with all significant intercompany accounts and transactions eliminated.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates, and such differences may be material to the consolidated financial statements.

Unaudited Pro Forma Income Tax

In order to present the tax effect of the Contribution Transactions, the Company has presented a 2012 pro forma income tax provision as if the Contribution Transactions occurred effective January 1, 2012 and as if the Company were under control of a Subchapter C-Corporation for U.S. federal income tax purposes.

Variable Interest Entities

ASC 810,Consolidation of Variable Interest Entities, defines the criteria for determining the existence of Variable Interest Entities (VIEs) and provides guidance for consolidation. The Company consolidates VIEs where the Company is the primary beneficiary. The primary beneficiary of a VIE is the party that has the power to direct the activities that most significantly impact the performance of the entity and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the entity.

Investments or joint ventures in which the Company does not have a majority ownership interest and are not VIEs for which the Company is considered the primary beneficiary are accounted for using the equity method. These amounts are included in unconsolidated investments in the consolidated balance sheets.

Noncontrolling Interests

Noncontrolling interests represent third-party interests in Gulf Wind which resulted from the sale of a noncontrolling interest to an unrelated third party on September 3, 2010 and the interest retained by Pattern Development in connection with the Contribution Transactions on October 2, 2013. The Company has determined that the operating partnership agreement for Gulf Wind does not allocate economic benefits pro rata to its two classes of investors and the appropriate methodology for calculating the noncontrolling interest balance that reflects the substantive profit sharing arrangement is a balance sheet approach using the hypothetical liquidation at book value (HLBV) method.

F-10

Under the HLBV method, the amounts reported as noncontrolling interest in the consolidated balance sheets and consolidated statements of operations represent the amounts the third party would hypothetically receive at each balance sheet reporting date under the liquidation provisions of the operating partnership agreement assuming the net assets of Gulf Wind were liquidated at recorded amounts determined in accordance with U.S. GAAP and distributed to the investors. The third-party interest in the results of operations of Gulf Wind and the Company’s net income and comprehensive income is determined as the difference in noncontrolling interests in the consolidated balance sheets at the start and end of each reporting period, after taking into account any capital transactions between Gulf Wind and the third party. The noncontrolling interest balance in Gulf Wind is reported as a component of equity in the consolidated balance sheets.

Foreign Currency Translation

The assets and liabilities of foreign subsidiaries, where the local currency is the functional currency, are translated from their respective functional currencies into U.S. dollars at the rates in effect at the balance sheet date, with resulting foreign currency translation adjustments recorded in other comprehensive income (loss), net of tax in the accompanying consolidated statements of stockholders’ equity and comprehensive income (loss). Revenue and expense amounts are translated at average rates during the period. Where the U.S. dollar is the functional currency, translation adjustments are recorded in other income, net in the accompanying consolidated statements of operations.

Gains and losses realized from transactions, including related party balances not considered permanent investments, denominated in currencies other than an entity’s functional currency are included in other income, net in the accompanying consolidated statements of operations.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents, trade receivables and derivative assets. The Company places its cash and cash equivalents with high quality institutions.

The Company sells electricity and environmental attributes, including renewable energy credits, primarily to creditworthy utilities under long-term, fixed-priced PPAs. The table below presents significant customers who accounted for the following percentages of total revenues:

	Year ended December 31,
	2013			2012			2011
Manitoba Hydro		17.62	%		32.06	%		20.91	%
San Diego Gas & Electric		17.23	%		0.18	%		0.00	%
Pacific Gas & Electric Company		14.54	%		23.12	%		20.67	%
Electric Reliability Council of Texas		12.24	%		18.28	%		35.23	%

The Company’s derivative assets are placed with counterparties that are creditworthy institutions. A derivative asset was generated from Credit Suisse Energy LLC, the counterparty to a 10-year fixed-for-floating swap related to annual electricity generation at the Company’s Gulf Wind project. The Company’s reimbursements for prepaid interconnect network upgrades are with large creditworthy utility companies.

Fair Value of Financial Instruments

ASC 820,Fair Value Measurements, defines fair value as the price at which an asset could be exchanged or a liability transferred in an orderly transaction between knowledgeable, willing parties in the principal or most advantageous market for the asset or liability. Where available, fair value is based on observable market prices or derived from such prices. Where observable prices or inputs are not available, valuation models are applied.

F-11

These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity. See Note 12 on Fair Value Measurements.

U.S. Treasury Grants

The Company received U.S. Treasury grants on certain wind power projects as defined under Section 1603 of the American Recovery and Reinvestment Act of 2009, as amended by the Tax Relief Unemployment Insurance Reauthorization and Job Creation Act of December 2010, upon approval by the U.S. Treasury Department. The Company records the U.S. Treasury grant proceeds as a deduction from the carrying amount of the related asset which results in a reduction of depreciation expense over the life of the asset. The Company records a catch-up adjustment in the period in which the grant is approved to recognize the portion of the grant that proportionally matches the depreciation for the period between the date of placement in service of the wind power project and approval by the U.S. Treasury Department. See Note 5 on Property, Plant and Equipment.

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly-liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents, which consist principally of demand deposits with high credit quality financial institutions. The Company has exposure to credit risk to the extent cash and cash equivalent balances, including restricted cash, exceed amounts covered by federal deposit insurance. The Company believes that its credit risk is immaterial.

Restricted Cash

Restricted cash consists of cash balances which are restricted as to withdrawal or usage and include cash to collateralize bank letters of credit related primarily to interconnection rights and power purchase agreements (“PPAs”) and for certain reserves required under the Company’s loan agreements.

Trade Receivables

The Company’s trade receivables are generated by selling energy and renewable energy credits in the California, Texas, Nevada, Manitoba (Canada) and Puerto Rico energy markets. The Company believes that all amounts are collectible and an allowance for doubtful accounts is not required as of December 31, 2013 and 2012.

Reimbursable Interconnect Costs

During 2013 and 2012, the Company paid to construct interconnect network upgrades for one of its utility customers. The utility owns the interconnect upgrades and reimbursed the Company with interest when the project reached commercial operations in 2013.

Turbine Advances

Turbine advances represent amounts advanced to turbine suppliers for the manufacture of wind turbines in accordance with turbine supply agreements for the Company���s wind power projects and for which the Company has not taken title. Turbine advances are reclassified to construction in progress when the Company takes legal title to the related turbines and are reclassified to property, plant and equipment when the project achieves commercial operation. Depreciation does not commence until projects enter commercial operation and assets are placed in service.

Deferred Development Costs

Deferred development costs consist primarily of initial permitting, environmental reviews, land rights and obligations and preliminary design and engineering work. The Company expenses all project development costs

F-12

until a project is determined to be technically feasible and likely to achieve commercial success. Capitalized deferred project development costs are reclassified to construction in progress upon start of construction and recorded to property, plant and equipment upon commercial operation.

Construction in Progress

Construction in progress represents the accumulated costs of projects in construction. Construction costs include turbines for which the Company has taken legal title, civil engineering, electrical and other related costs. Other capitalized costs include reclassified deferred development costs, amortization of intangible assets, amortization of deferred financing costs, capitalized interest and other costs required to place a project into commercial operation. Construction in progress is reclassified to property, plant and equipment when the project begins commercial operation.

Property, Plant and Equipment

Property, plant and equipment represents the costs of completed and operational projects transferred from construction in progress as well as land, computer equipment and software, furniture and fixtures, leasehold improvements and other equipment. Property, plant and equipment are stated at cost, less accumulated depreciation. Depreciation is calculated using the straight-line method over the assets’ useful lives. Wind farms are depreciated over twenty years and the remaining assets are depreciated over three to five years. Land is not depreciated. Improvements to property, plant and equipment deemed to extend the useful economic life of an asset are capitalized. Repair and maintenance costs are expensed as incurred.

Accounting for Impairment of Long-Lived Assets

The Company periodically evaluates whether events have occurred that would require revision of the remaining useful life of equipment and improvements and purchased intangible assets or render them not recoverable. If such circumstances arise, the Company uses an estimate of the undiscounted value of expected future operating cash flows to determine whether the long-lived assets are impaired. If the aggregate undiscounted cash flows are less than the carrying amount of the assets, the resulting impairment charge to be recorded is calculated based on the excess of the carrying value of the assets over the fair value of such assets, with the fair value determined based on an estimate of discounted future cash flows. Through December 31, 2013, no impairment charges have been recorded.

Derivatives

The Company recognizes its derivative instruments as assets or liabilities at fair value in the consolidated balance sheets. Accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated as part of a hedging relationship and on the type of hedging relationship.

For derivative instruments that are designated as cash flow hedges the effective portion of change in fair value of the derivative is reported as a component of other comprehensive income (loss) (“OCI”). Changes in the fair value of these derivatives are subsequently reclassified into earnings in the period that the hedged transaction affects earnings. The ineffective portion of change in fair value is recorded as a component of net income (loss) on the consolidated statement of operations.

For undesignated derivative instruments their change in fair value is reported as a component of net income on the consolidated statement of operations.

The Company enters into derivative transactions for the purpose of reducing exposure to fluctuations in interest rates and electricity prices. The Company has entered into interest rate swaps, an interest rate cap and an electricity price derivative.

F-13

Interest rate swaps are instruments used to fix the interest rate on variable interest rate debt. The Company entered into interest rate swaps in 2013, 2012 and 2011.

An interest rate cap is an instrument that is used to reduce exposure to future variable interest rates when the related debt is expected to be refinanced. The Company entered into an interest rate cap in 2010. The cap remains in place as of December 31, 2013.

The Company entered into an electricity price arrangement, which qualifies as a derivative, that fixes the price of approximately 58% of the electricity expected to be produced and sold by Gulf Wind through April 2019, and which reduces the Company’s exposure to spot electricity prices.

Deferred Financing Costs

Financing costs incurred in connection with obtaining construction and term financing are deferred and amortized over the lives of the respective loans using the effective-interest method. Amortization of deferred financing costs is capitalized during construction and recorded as interest expense in the consolidated statements of operations following commencement of commercial operation.

Income Taxes

Prior to October 2, 2013, the Company’s predecessor did not provide for income taxes as it was treated as a pass-through entity for U.S. federal and state income tax purposes, except for several specific circumstances involving its Canadian entities, which are subject to Canadian income taxes, its Chilean entities, which are subject to Chilean income taxes, a U.S. entity that is subject to Puerto Rican taxes and a U.S. entity which became subject to U.S. income taxes in 2012. Federal and state income taxes were assessed at the owner level and each owner was liable for its own tax payments. Certain consolidated entities are corporations or have elected to be taxed as corporations. In these circumstances, income tax was accounted for under the asset and liability method.

Subsequent to October 2, 2013, following the Contribution Transactions, the Company accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The Company recognizes deferred tax assets to the extent that it believes these assets are more likely than not to be realized. In making such a determination, the Company considers all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning and results of recent operations. If the Company determines that it would be able to realize its deferred tax assets in the future in excess of their net recorded amount, it would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes. The Company records uncertain tax positions in accordance with ASC 740 on the basis of a two-step process whereby (1) it determines whether it is more likely than not that the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, it recognizes the largest amount of tax benefit that is more than 50 percent likely to be realized upon ultimate settlement with the related tax authority. The Company has a policy to classify interest and penalties associated with uncertain tax positions together with the related liability, and the expenses incurred related to such accruals, if any, are included in the provision for income taxes.

Contingent Liabilities

The Company’s contingent liabilities represent deferred and contingent purchase price obligations related to projects acquired through business combinations and are recorded at fair value at each reporting date.

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Asset Retirement Obligation

The Company records asset retirement obligations for the estimated costs of decommissioning turbines, removing above-ground installations and restoring sites, at the time when a contractual decommissioning obligation materializes. The Company records accretion expense, which represents the increase in the asset retirement obligations, over the remaining or operational life of the associated wind project. Accretion expense is recorded as cost of revenue in the statement of operations using accretion rates based on credit adjusted risk free interest rates.

Revenue Recognition

The Company sells the electricity it generates under the terms of PPAs or at spot market prices. Revenue is recognized based upon the amount of electricity delivered at rates specified under the contracts, assuming all other revenue recognition criteria are met. The Company evaluates its PPAs to determine whether they are in substance leases or derivatives and, if applicable, recognizes revenue pursuant to ASC 840Leasesand ASC 815Derivatives and Hedging, respectively. As of December 31, 2013, there were no PPAs that are accounted for as leases or derivatives and revenue is recognized on an accrual basis.

The Company also generates renewable energy credits as it produces electricity. Certain of these energy credits are sold independently in an open market and revenue is recognized at the time title to the energy credits is transferred to the buyer.

The Company acquired a ten-year energy derivative instrument as part of its acquisition of Gulf Wind in 2010, which fixes approximately 58% of the Project’s expected electricity generation through April 2019. The energy derivative instrument reduces exposure to changes in commodity prices by allowing the Company to lock in a fixed price per MWh for a specified amount of annual electricity generation. The monthly settlement amounts under the energy hedge are accounted for as energy derivative settlements in the consolidated statements of operations. The change in the fair value of the energy hedge is classified as unrealized (loss) gain on energy derivative revenue in the consolidated statements of operations.

The Company recognizes revenue for warranty settlements and liquidated damages from turbine manufacturers in other revenue upon resolution of outstanding contingencies. Any cash receipts for amounts subject to future adjustment or repayment are deferred in other liabilities until the final settlement amount is considered fixed and determinable.

Cost of Revenue

The Company’s cost of revenue is comprised of direct costs of operating and maintaining its wind project facilities, including labor, turbine service arrangements, land lease royalties, depreciation, accretion, property taxes and insurance.

Stock-Based Compensation

The Company accounts forstock-based compensation related to stock options granted to employees by estimating the fair value of thestock-based awards using theBlack-Scholesoption-pricing model. The fair value of the stock options granted are amortized over the applicable vesting period. TheBlack-Scholes option pricing model includes assumptions regarding dividend yields, expected volatility, expected option term, expected forfeiture rate and risk-free interest rates. The Company estimates expected volatility based on the historical volatility of comparable publicly traded companies for a period that is equal to the expected term of the options. The risk-free interest rate is based on the U.S. treasury yield curve in effect at the time of grant for a period commensurate with the estimated expected life. The expected term of options granted is derived using the “simplified” method as allowed under the provisions of the ASC 718,Compensation—Stock Compensation, and represents the period of time that options granted are expected to be outstanding.

F-15

The Company accounts forstock-based compensation related to restricted stock award grants by amortizing the fair value of the restricted stock award grants, which is the grant date market price, over the applicable vesting period.

Stock-based compensation expense is recorded as a component of general and administrative expenses in the Company’s consolidated statements of operations.

Comprehensive Income (Loss)

Comprehensive income (loss) consists of net income (loss) and other comprehensive income (loss), net of tax. Other comprehensive income (loss), net of tax included in accumulated other comprehensive income (loss) in the accompanying consolidated statements of stockholders’ equity, is comprised of changes in foreign currency translation adjustments and changes in the fair value of derivatives designated as hedges.

Segment Data

Operating segments are defined as components of a company about which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is the chief executive officer. Based on the financial information presented to and reviewed by the chief operating decision maker in deciding how to allocate the resources and in assessing the Company’s performance, the Company has determined its wind projects represent individual operating segments with similar economic characteristics that meet the criteria for aggregation into a single reporting segment for financial statement purposes.

3. Acquisition from Pattern Development

On December 20, 2013, the Company acquired from Pattern Development a 45% equity interest in Grand for $79.5 million, paid in 2013, plus a contingent payment of up to $4.7 million, payable in 2014. Grand is a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. The project has a 20-year PPA and commenced construction in September 2013. The Company’s investment in Grand was paid from general corporate funds. Grand is accounted for under the equity method of accounting. In accordance with ASC 805-50-30-5,Transactions between Entities under Common Control, the Company recognized the investment at the historical carrying amount at the date of acquisition.

4. Prepaid expenses and other current assets

The following table presents the components of prepaid expenses and other current assets (in thousands):

	December 31,
	2013		2012
Prepaid expenses	$	10,132	$	7,202
Sales tax		50		3,275
Interconnection network upgrade receivable		2,512		1,854
Other current assets		1,233		1,463
Prepaid expenses and other current assets	$	13,927	$	13,794

F-16

5. Property, Plant and Equipment

The following presents the categories within property, plant and equipment (in thousands):

	December 31,
	2013			2012
Operating wind farms	$	1,652,119		$	1,765,200
Furniture, fixtures and equipment		3,785			3,333
Land		16			16
Subtotal		1,655,920			1,768,549
Less: accumulated depreciation		(179,778	)		(100,247	)
	$	1,476,142		$	1,668,302

The Company recorded depreciation expense related to property, plant and equipment of $82.0 million, $48.3 million and $38.9 million for the years ended December 31, 2013, 2012 and 2011, respectively.

In June 2013, the Company received $115.9 million and $57.6 million for Ocotillo and Santa Isabel, respectively, under a cash grant in lieu of investment tax credit (Cash Grant) from the U.S. Department of the Treasury. In December 2012, the Company received $79.9 million for Spring Valley under a Cash Grant from the U.S. Department of the Treasury. The Company recorded the cash proceeds as a deduction from the carrying amount of the related wind farm assets which resulted in the assets being recorded at lower amounts.

The Cash Grants received for Ocotillo, Santa Isabel, and Spring Valley reduced depreciation expense recorded in the consolidated statements of operations by approximately $13.0 million and $1.5 million for the years ended December 31, 2013 and 2012, respectively.

6. Unconsolidated Investments

The following presents projects that are accounted for under the equity method of accounting (in thousands):

					Percentage of Ownership
	December 31,				December 31,
	2013		2012		2013			2012
South Kent	$	59,488	$	17,895		50.0	%		50.0	%
El Arrayán		21,103		18,323		31.5	%		31.5	%
Grand		26,464		—		45.0	%		N/A
Unconsolidated investments	$	107,055	$	36,218

South Kent

The Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. The project has a 20-year PPA. Construction commenced in March 2013.

El Arrayán

The Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Chile. The project has a 20-year PPA and commenced construction in May 2012.

F-17

Grand

On December 20, 2013, the Company acquired from Pattern Development a 45% equity interest in Grand for $79.5 million, paid in 2013, plus a contingent payment of up to $4.7 million, payable in 2014. Grand is a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. The project has a 20-year PPA and commenced construction in September 2013. The Company’s investment in Grand was paid from general corporate funds. The Company is a noncontrolling investor in Grand and the investment is accounted for under the equity method of accounting.

The following summarizes the aggregated balance sheets as of December 31, 2013 and 2012, and operating results of the unconsolidated joint ventures for the years ended December 31, 2013, 2012 and 2011, respectively (in thousands):

	December 31,
	2013		2012
Current assets	$	78,906	$	33,578
Non-current assets		1,097,018		142,522
Total assets	$	1,175,924	$	176,100
Current liabilities	$	128,076	$	5,153
Non-current liabilities		810,936		71,709
Total liabilities	$	939,012	$	76,862
Total equity	$	236,912	$	99,238
Total liabilities and equity	$	1,175,924	$	176,100

	Year ended December 31,
	2013			2012		2011
Revenue	$	—		$	—	$	—
Other (income) expense		(13,322	)		275		455
Net income (loss)	$	13,322			$  (275)		$  (455)

7. Accounts payable and other accrued liabilities

The following table presents the components of accounts payable and other accrued liabilities (in thousands):

	December 31,
	2013		2012
Accounts payable	$	168	$	331
Other accrued liabilities		7,282		3,847
Warranty settlement payments		2,187		—
Payroll liabilities		2,162		—
Property tax payable		3,490		3,444
Sales tax payable		261		128
Accounts payable and other accrued liabilities	$	15,550	$	7,750

F-18

8. Long term debt

The Company’s long term debt as of December 31, 2013 and 2012 is presented below (in thousands):

	December 31,						Interest Rate as of December 31,						Interest Type
	2013			2012			2013			2012				Maturity
Santa Isabel bridge loan	$	—		$	38,337			N/A			2.31	%	Variable	N/A
Ocotillo bridge loan		—			56,586			N/A			3.31	%	Variable	N/A
Hatchet Ridge term loan		239,865			251,119			1.43	%		1.43	%	Imputed	December 2032
Gulf Wind term loan		166,448			174,969			3.25	%		3.36	%	Variable	March 2020
St. Joseph term loan		215,330			238,737			5.88	%		5.88	%	Fixed	May 2031
Spring Valley term loan		173,110			178,900			2.63	%		2.62	%	Variable	June 2030
Santa Isabel term loan		115,721			119,035			4.57	%		4.57	%	Fixed	September 2033
Ocotillo commercial term loan		230,944			160,299			3.00	%		3.31	%	Variable	August 2020
Ocotillo development term loan		107,800			72,588			2.35	%		2.41	%	Variable	August 2033
		1,249,218			1,290,570
Less: current portion		(48,851	)		(137,258	)
	$	1,200,367		$	1,153,312

The following are amounts due for long-term debt as of December 31, 2013 (in thousands):

For the year ending December 31,
2014	$	48,851
2015		58,888
2016		60,442
2017		61,571
2018		66,547
Thereafter		952,919
	$	1,249,218

Interest and commitment fees incurred, and interest expense recorded in the Company’s consolidated statements of operations are as follows (in thousands):

	Year ended December 31,
	2013			2012			2011
Interest and commitment fees incurred	$	57,478		$	43,496		$	31,610
Capitalized interest, commitment fees, and letter of credit fees		(4,210	)		(10,259	)		(4,220	)
Letter of credit fees		3,530			720			537
Amortization of financing costs		6,816			2,545			1,477
Interest expense	$	63,614		$	36,502		$	29,404

Hatchet Ridge

In December 2010, Hatchet Ridge entered into sale-leaseback transactions to finance the facility for 22 years. In accordance with ASC 840, Leases, Hatchet Ridge accounts for the sale-leaseback as a financing transaction.

Collateral for the sale-leaseback financing includes Hatchet Ridge’s tangible assets and contractual rights and cash on deposit with the depository agent. Its loan agreement contains a broad range of covenants that, subject to certain exceptions, restrict Hatchet Ridge’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business.

F-19

Gulf Wind

The Company acquired Gulf Wind in March 2010. Concurrent with its acquisition, Gulf Wind entered into a $195.4 million credit facility. The Gulf Wind credit facility has a term of ten years. In connection with the facility, Gulf Wind entered into interest rate swaps and cap agreements to reduce its exposure to variable interest rates of the term of the facility and to hedge its exposure to re-financing rate risk.

Collateral for the Gulf Wind credit facility includes Gulf Wind’s tangible assets and contractual rights and cash on deposit with the depository agent. Its loan agreement contains a broad range of covenants that, subject to certain exceptions, restrict Gulf Wind’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business.

St. Joseph

In March 2010, St. Joseph entered into a $259.5 million construction and term loan facility that was converted to a 20-year term loan in May 2011.

Collateral for the St. Joseph facility includes St. Joseph’s tangible assets and contractual rights and cash on deposit with the depository agent. Its loan agreement contains a broad range of covenants that, subject to certain exceptions, restrict St. Joseph’s ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests, dissolve, make distributions and change its business.

Spring Valley

In August 2011, Spring Valley entered into a $178.9 million construction loan facility and a $53.3 million cash grant bridge loan. Spring Valley reached commercial operations on August 16, 2012 and the construction loan was converted to a term loan on November 16, 2012. The cash grant bridge loan was repaid in December 2012 from funds the Company received under a Cash Grant from the U.S. Department of Treasury following the wind project being placed in service. In connection with the term loan, Spring Valley entered into interest rate swaps for the term of the loan to hedge its exposure to variable interest rates following term conversion of the facility.

Collateral for the loan consists of Spring Valley’s tangible assets and contractual rights, and cash on deposit with the depository agent. Its loan agreement contains a broad range of covenants that, subject to certain exceptions, restrict Spring Valley’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business.

Santa Isabel

In October 2011, Santa Isabel entered into a $119.0 million construction loan facility and a $57.5 million cash grant bridge loan facility. On December 5, 2012, Santa Isabel achieved commercial operations under the terms of its PPA. The construction loan converted to a term loan on May 15, 2013 and matures on September 30, 2033. The cash grant bridge loan was repaid from funds the Company received under a Cash Grant in May 2013.

Collateral for the Santa Isabel facility consists of Santa Isabel’s tangible assets and contractual rights, and cash on deposit with the depository agent. Its loan agreement contains a broad range of covenants that, subject to certain exceptions, restrict Santa Isabel’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business.

Ocotillo

In October 2012, Ocotillo entered into a $467.3 million financing agreement comprised of two construction loan facilities totaling $351.5 million, a network upgrade bridge loan facility of $56.6 million and a letter of credit facility of $59.2 million. The two loan facilities consist of a development bank tranche of $110.0 million and a

F-20

commercial bank tranche of $241.5 million. Ocotillo reached full commercial operations in July 2013, and the two construction loans converted to term loans on September 20, 2013 and mature 20 years and 7 years after the term loan conversion, respectively. The network upgrade bridge loan was repaid in August 2013 from reimbursements received from the utility related to the construction of network upgrade costs. In connection with the financing agreement, the Company entered into interest rate swaps on 90% of the loan commitment. In addition, in September 2013, Ocotillo prepaid $2.2 million of the development bank loan and $5.3 million of the commercial bank loan pursuant to a proposal initiated by Ocotillo and accepted by the lenders.

Collateral under the Ocotillo financing agreement consists of Ocotillo’s tangible assets and contractual rights, and cash on deposit with the depository agent. Its loan agreement contains a broad range of covenants that, subject to certain exceptions, restrict Ocotillo’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business.

Revolving Credit Facility

On November 15, 2012, the Company entered into a $120.0 million revolving credit agreement for working capital with a four-year term comprised of a revolving loan facility and a letter of credit facility. The revolving credit agreement has an “accordion feature” under which the Company has the right to increase available borrowings by up to $35.0 million if its lenders or other additional lenders are willing to lend on the same terms and meet certain other conditions. As of December 31, 2013 and 2012, letters of credit of $44.8 million and $39.1 million, respectively, have been issued and loans of $56.0 million and zero were drawn and repaid in 2013 and 2012, respectively. As of December 31, 2013 and 2012, there was no outstanding balance on the revolving credit facility.

Loans, when and if drawn, are either base rate loans or Eurodollar rate loans. The base rate loans accrue interest at 2.5% plus the greatest of the (i) the prime rate, (ii) the federal funds rate plus 0.5% and (iii) the Eurodollar rate that would be in effect for a Eurodollar rate loan with an interest period of one month plus 1.0%. The Eurodollar rate loans will accrue interest at a rate per annum equal to LIBOR, as published by Reuters plus 3.5%. Collateral for the revolving credit facility consists of the Company’s membership interests in certain of the Company’s holding company subsidiaries. The revolving credit facility contains a broad range of covenants that, subject to certain exceptions, restrict the Company’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business.

9. Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated cost of decommissioning the turbines, removing above-ground installations and restoring the sites at a date that is 20 years from the commencement of commercial operation of the facility.

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligations as of December 31, 2013, 2012 and 2011 (in thousands):

	December 31,
	2013			2012		2011
Beginning asset retirement obligations	$	19,056		$	10,342	$	9,365
Additions during the year		767			7,971		467
Foreign currency translation adjustment		(172	)		59		(43	)
Accretion expense		1,183			684		553
Ending asset retirement obligations	$	20,834		$	19,056	$	10,342

F-21

10. Derivative Instruments

The Company employs a variety of derivative instruments to manage its exposure to fluctuations in interest rates and electricity prices. The following tables present the amounts that are recorded in the Company’s consolidated balance sheets as of December 31, 2013, 2012 and 2011 (in thousands):

Undesignated Derivative Instruments Classified as Assets (Liabilities):

			As of						Year ended
			Fair Market Value						YTD Gain (Loss)
Derivative Type	Quantity	Maturity Dates	Current Portion			Long-Term Portion			Recognized into Income
December 31, 2013
Interest rate swaps	6	6/30/2030	$	(3,899	)	$	14,358		$	15,367
Interest rate cap	1	12/31/2024		—			681			234
Energy derivative	1	4/30/2019		13,937			54,416			(11,272	)
			$	10,038		$	69,455		$	4,329
December 31, 2012
Interest rate swaps	6	6/30/2030	$	(1,980	)	$	(2,931	)	$	(4,909	)
Interest rate cap	1	12/31/2024		—			447			(44	)
Energy derivative	1	4/30/2019		17,177			62,448			(6,951	)
			$	15,197		$	59,964		$	(11,904	)
December 31, 2011
Interest rate cap	1	12/31/2024	$	—		$	491		$	(345	)
Energy derivative	1	4/30/2019		18,687			67,890			17,577
			$	18,687		$	68,381		$	17,232

Designated Derivative Instruments Classified as Assets ( Liabilities):

			As of						Year ended
			Fair Market Value						YTD Gain (Loss)
Derivative Type	Quantity	Maturity Dates	Current Portion			Long-Term Portion			Recognized in OCI
December 31, 2013
Interest rate swaps	6	6/30/2033	$	(2,105	)	$	9,625		$	10,434
Interest rate swaps	7	3/15/2020		(5,289	)		(7,439	)		9,398
Interest rate swaps	2	6/28/2030		(4,878	)		3,087			17,043
			$	(12,272	)	$	5,273		$	36,875
December 31, 2012
Interest rate swaps	6	6/30/2033	$	(952	)	$	(1,962	)	$	(2,914	)
Interest rate swaps	7	3/15/2020		(5,558	)		(16,568	)		(1,835	)
Interest rate swaps	2	6/28/2030		(4,972	)		(13,865	)		(6,421	)
			$	(11,482	)	$	(32,395	)	$	(11,170	)
December 31, 2011
Interest rate swaps	7	3/15/2020	$	(4,929	)	$	(15,362	)	$	(11,251	)
Interest rate swaps	2	6/28/2030		—			(12,416	)		(12,416	)
			$	(4,929	)	$	(27,778	)	$	(23,667	)

F-22

Gulf Wind

In 2010, Gulf Wind entered into interest rate swaps with each of its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments that were approximately 6.6% for the years ended December 31, 2013, 2012 and 2011. The fixed interest rate is set at 6.6% for years two through eight and 7.1% and 7.6% for the last two years of the loan term, respectively. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the years ended December 31, 2013, 2012 and 2011. The Company expects to reclassify $5.3 million into earnings from accumulated other comprehensive income (loss) during 2014 as quarterly hedge payments occur.

In 2010, Gulf Wind also entered into an interest rate cap to manage exposure to future interest rates when its long-term debt is expected to be refinanced at the end of the ten-year term. The cap protects the Company if future interest rates exceed approximately 6.0%. The cap has an effective date of March 31, 2020, terminates on December 31, 2024, and has a notional amount of $42.1 million which reduced quarterly during its term. The cap is a derivative but does not qualify for hedge accounting and has not been designated. The Company recognized unrealized gains (losses) of $0.2 million, zero and ($0.3) million for the years ended December 31, 2013, 2012 and 2011, respectively, in unrealized gain (loss) on derivatives in the consolidated statements of operations. The derivative instrument’s asset value as of December 31, 2013, 2012 and 2011, was approximately $0.7 million, $0.4 million and $0.5 million, respectively.

In 2010, Gulf Wind acquired an energy derivative instrument to manage its exposure to variable electricity prices. The energy price swap fixes the price of approximately 58% of its electricity generation through April 2019. The energy derivative instrument is a derivative but did not meet the criteria required to adopt hedge accounting. The energy derivative instrument’s fair value as of December 31, 2013, 2012 and 2011 was $68.4 million, $79.6 million and $86.6 million, respectively. Gulf Wind recognized unrealized (losses) gain of ($11.3) million, ($7.0) million, and $17.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, in unrealized (loss) gain on energy derivative in the consolidated statements of operations.

Spring Valley

In 2011, Spring Valley entered into interest rate swaps with its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 5.5% for the first four years of its term debt and increases by 0.25% every four years, thereafter. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the years ended December 31, 2013, 2012 and 2011. The Company expects to reclassify $4.9 million into earnings from accumulated other comprehensive income (loss) during 2014 as quarterly swap settlement payments occur.

Ocotillo

In October 2012, Ocotillo entered into interest rate swaps with its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 2.5% and 2.2% for the development bank term loans and the commercial bank term loans, respectively. The interest rate swaps for the development bank loans qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the years ended December 31, 2013, 2012 and 2011. The Company expects to reclassify $2.1 million into earnings from accumulated other comprehensive income (loss) during 2014 as quarterly hedge payments occur. The interest rate swaps for the commercial bank loans are undesignated derivatives that are used to mitigate exposure to variable interest rate debt.

F-23

11. Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the accumulated other comprehensive income (loss) balance by component:

	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI			Total
Balances at January 1, 2011	$	(497	)	$	(9,040	)	$	—		$	(9,537	)
Current period other comprehensive loss		(2,406	)		(23,667	)		—			(26,073	)
Income tax benefit (expense)		—			—			—			—
Balances at December 31, 2011		(2,903	)		(32,707	)		—			(35,610	)
Current period other comprehensive income (loss)		2,749			(11,170	)		(1,475	)		(9,896	)
Income tax benefit (expense)		—			—			—			—
Balances at December 31, 2012		(154	)		(43,877	)		(1,475	)		(45,506	)
Current period other comprehensive income (loss)		(8,309	)		36,875			2,621			31,187
Income tax expense		—			—			(148	)		(148	)
Grand acquisition		—			—			(4,217	)		(4,217	)
Income tax benefit—Grand acquisition		—			—			1,307			1,307
Balances at December 31, 2013	$	(8,463	)	$	(7,002	)	$	(1,912	)	$	(17,377	)

12. Fair Value Measurements

The Company’s fair value measurements incorporate various factors, including the credit standing and performance risk of the counterparties, the applicable exit market, and specific risks inherent in the instrument. Nonperformance and credit risk adjustments on risk management instruments are based on current market inputs when available, such as credit default hedge spreads. When such information is not available, internal models may be used.

Assets and liabilities recorded at fair value in the consolidated financial statements are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to valuation of these assets or liabilities are as follows:

Level 1—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2—Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities and which reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuations technique and the risk inherent in the inputs to the model.

Short-term financial instruments consist principally of cash, cash equivalents, accounts receivable, notes receivable, accounts payable and other accrued liabilities. Based on the nature and short maturity of these instruments their fair value is approximated using carrying cost and they are presented in the Company’s financial statements at carrying cost. The fair values of cash, cash equivalents and restricted cash are a Level 1 hierarchy. The fair values of accounts receivable, notes receivable, accounts payable and other accrued liabilities are Level 2 hierarchy.

F-24

Long term debt is presented on the consolidated balance sheet at amortized cost. The fair value of variable interest rate long-term debt is approximated by its carrying cost. The fair value of fixed interest rate long-term debt is estimated based on observable market prices or parameters or derived from such prices or parameters (Level 2). Where observable prices or inputs are not available, valuation models are applied, using the net present value of cash flow streams over the term using estimated market rates for similar instruments and remaining terms (Level 3).

Derivatives and contingent liabilities subject to re-measurement are presented in the financial statements at fair value. The interest rate swaps and interest rate cap were valued by discounting the net cash flows using the forward LIBOR curve with the valuations adjusted by the counterparties’ credit default hedge rate (Level 2). The fair value of contingent liabilities is based upon the time of realization and the probability of the contingent event (Level 3). The energy derivative instrument was valued by discounting the projected net cash flows over the remaining life of the derivative using forward energy curves adjusted by a nonperformance risk factor (Level 3).

The following tables present the fair values according to each defined level (in thousands):

Financial assets and (liabilities) measured on a recurring basis:

	Fair Value Measurements Using
	Level 1		Level 2			Level 3
December 31, 2013
Interest rate swaps	$	—	$	3,460		$	—
Interest rate cap		—		681			—
Energy derivative		—		—			68,353
	$	—	$	4,141		$	68,353
December 31, 2012
Interest rate swaps	$	—	$	(48,788	)	$	—
Interest rate cap		—		447			—
Energy derivative		—		—			79,625
Contingent liabilities		—		—			(8,001	)
	$	—	$	(48,341	)	$	71,624

Reconciliation of energy derivative and contingent liabilities measured at fair value using unobservable inputs (Level 3):

	Contingent Liabilities			Energy Derivative			Total
Balances at January 1, 2012	$	(5,986	)	$	86,577		$	80,591
Settlements		—			(19,644	)		(19,644	)
Change in fair value, net of settlements		(2,015	)		12,692			10,677
Balances at December 31, 2012		(8,001	)		79,625			71,624
Settlements		8,001			(16,798	)		(8,797	)
Change in fair value, net of settlements		—			5,526			5,526
Balances at December 31, 2013	$	—		$	68,353		$	68,353

The change in fair value for the years ended December 31, 2013, 2012 and 2011 related to assets and liabilities still held at the end of the respective period, except for contingent liabilities which were settled during the year ended December 31, 2013.

F-25

The following table presents the carrying amounts and fair values of the Company’s long term debt (in thousands):

	December 31, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total long term debt	$	1,249,218	$	1,165,119	$	1,290,570	$	1,247,449

13. Income Taxes

The following table presents significant components of the provision for income taxes (in thousands):

	Year ended December 31,
	2013		2012			2011
Current
U.S. federal	$	—	$	—		$	—
State		—		—			—
Foreign		—		—			—
		—		—			—
Deferred
U.S. federal		2,961		—			—
State		—		—			—
Foreign		1,585		(3,604	)		689
		4,546		(3,604	)		689
Total income tax (benefit) provision	$	4,546	$	(3,604	)	$	689

The following table presents the domestic and foreign components of net income (loss) before income tax (benefit) expense (in thousands):

	Year ended December 31,
	2013		2012			2011
U.S.	$	4,022	$	(17,810	)	$	25,957
Foreign		10,596		830			638
Total	$	14,618	$	(16,980	)	$	26,595

The following table presents a reconciliation of the statutory U.S federal income tax rate to the Company’s effective tax rate, as a percentage of income before taxes for the years ended December 31, 2013, 2012 and 2011:

	Year ended December 31,
	2013			2012			2011
Statutory U.S. federal tax rate		35.0	%		35.0	%		35.0	%
Book/tax basis difference		—			27.2	%		—
Partnership income not subject to taxes		—			(40.9	)%		(32.4	)%
Adjustment for income in non-taxable entities allocable to noncontrolling interest		16.5	%		—			—
Foreign rate difference
Tax rate differential on pre-tax book income, other		2.1	%		—			—
Local tax on branch profits/(losses)—Puerto Rico		13.1	%		—			—
Permanent book/tax differences (domestic only)		(2.2	)%		—			—
Valuation allowance		187.2	%		—			—
Other		3.1	%		—			—
ARRA Section 1603 grant-basis reduction deferred tax assets		(223.7	)%		—			—
Effective income tax rate		31.1	%		21.3	%		2.6	%

F-26

The following table presents significant components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2013 and 2012 (in thousands):

	December 31,
	2013			2012
Deferred tax assets/liabilities—current
Other current deferred tax assets and liabilities	$	2,399		$	—
Basis difference in derivatives		2,835			—
Total gross deferred tax assets/(liabilities)		5,234			—
Less: valuation allowance		(4,661	)		—
Total net deferred tax assets/(liabilities)—current		573			—
Deferred tax assets/(liabilities)—non-current:
Property, plant and equipment		(36,548	)		(47,894	)
Basis difference in foreign subsidiaries		40,097			—
Partnership interest		(4,917	)		—
Lease Hatchet Ridge		29,314			—
Asset retirement obligation		4,649			—
Equity method		3,794			—
Unrealized loss on derivatives		(5,830	)		—
Net operating loss carryforwards		61,441			45,302
Other non current deferred tax assets and liabilities		(4,595	)		(690	)
Change in tax status		—			4,599
Accruals not currently deductible		—			443
Total gross deferred tax assets/(liabilities)—non-current		87,405			1,760
Less: valuation allowance		(95,318	)		(482	)
Total net deferred tax assets/(liabilities)—non-current		(7,913	)		1,278
Total net deferred tax assets/(liabilities)	$	(7,340	)	$	1,278

The deferred tax assets and deferred tax liabilities resulted primarily from temporary differences between book and tax basis of assets and liabilities. The Company regularly assesses the likelihood that future taxable income levels will be sufficient to ultimately realize the tax benefits of the deferred tax assets. Should the Company determine that future realization of the tax benefits is not more likely than not, additional valuation allowance would be established which would increase the Company’s tax provision in the period of such determination. The net deferred tax assets and net deferred tax liabilities as of December 31, 2013 and 2012 are attributed primarily to the Company’s Canadian and Puerto Rico entities. The net change in valuation allowance increased by $99.5 million during year ended December 31, 2013. The net increase is attributable to the contribution transactions of $79.3 million and the three month activity ended December 31, 2013 in the U.S. consolidated filing group of $20.2 million.

As of December 31, 2013, the Company had U.S federal and state net operating loss carryforwards of approximately $77.6 million and $77.8 million, respectively. These net operating loss carryforwards are available to reduce future taxable income and will begin to expire commencing in 2033 for federal and state purposes.

Internal Revenue Code Section 382 places a limitation ( the “Section 382 Limitation”) on the amount of taxable income that can be offset by net operating loss (“NOL”) carryforwards after a change in control (generally greater than 50% change in ownership) of a loss corporation. California has similar rules. The Company did not have any historic US net operating losses prior to October 2, 2013 except for net operating losses from its Puerto Rico entity which may be subject to Section 382 limitation.

F-27

The Company is required to recognize in the financial statements the impact of a tax position, if that position is more likely than not of being sustained on audit, based on the technical merits of the position. As of December 31, 2013, the Company does not have any unrecognized tax benefits and does not have any tax positions for which it is reasonably possible that the amount of gross unrecognized tax benefits will increase or decrease within 12 months after the year ended December 31, 2013.

The Company files income tax returns in the U.S federal jurisdiction, various state jurisdictions and foreign jurisdictions for its Canadian and Chilean operations. The Company’s U.S and foreign income tax returns for 2009 and forward are subject to examination.

The Company has a policy to classify accrued interest and penalties associated with uncertain tax positions together with the related liability, and the expenses incurred related to such accruals are included in the provision for income taxes. The Company did not incur any interest expense or penalties associated with unrecognized tax benefits for the years ended December 31, 2013, 2012 and 2011.

The Company operates under a tax holiday in Puerto Rico which enacted a special tax rate of 4% for business dedicated to the production of energy for consumption through the use of renewal sources. Pursuant to Act 83 as of July 19, 2010, the Green Energy Incentives Act (“GEIA”), promotes the development of green energy projects through economic incentives so as to reduce the island’s dependency on oil. The GEIA provides for a 4% flat income tax rate on green energy income (“GEI”) in lieu of any income tax imposed by the Puerto Rico Code for a 25 year period and is scheduled to terminate on December 31, 2036. The impact of the tax holiday decreased foreign deferred tax benefit by $0.2 million for 2013. The impact of the tax holiday on net income per diluted share was $0.006.

14. Stockholders’ Equity

Common Stock

A summary of the rights and preferences of the Company’s Class A and Class B common stock as of December 31, 2013 is as follows:

Voting Rights

The rights of the holders of the Company’s Class A and Class B shares are identical other than in respect of dividends and the conversion rights of the Class B shares. While each Class A and Class B share have one vote on all matters submitted to a vote of the Company’s stockholders, Class B shares have no rights to dividends or distributions (other than upon liquidation). In the case of a proposed amendment to the Company’s amended and restated certificate of incorporation affecting its Class A shares and/or its Class B shares, holders of Class A shares and holders of Class B shares will each be entitled to vote separately as a class to approve such amendment. Upon the later of December 31, 2014 and the date on which its South Kent project has achieved commercial operations (“Conversion Event”), all of the outstanding Class B shares will automatically convert, on a one-for-one basis, into Class A shares. Other than upon occurrence of the Conversion Event, there are no conversion rights attaching to the Class B shares. Other than in certain circumstances involving a take-over bid, tender offer or merger or similar business combination in respect of the Company, in which circumstance a transfer of Class B shares to the acquirer, and subsequently among the acquirer and its officers, employees and affiliates, would be permitted, the Company’s Class B shares will not be transferrable except to and among Pattern Development, the Company and its respective officers, employees and affiliates. No subdivision or consolidation of Class B shares can be made unless the same subdivision or consolidation of the Class A shares is made concurrently.

F-28

Dividend Rights

Holders of Class A stock are eligible to receive dividends on common stock held when funds are available and as approved by the Board of Directors. Holders of Class B common stock are not entitled to dividends. In November 2013, the Company’s Board of Directors declared a quarterly cash dividend of $0.3125 per Class A share for the fourth quarter, which represents $1.25 on an annualized basis. The dividend was paid on January 30, 2014 to stockholders of record as of December 31, 2013.

Liquidation Rights

In the event of any liquidation, dissolution or winding-up of the Company, holders of Class A shares will be entitled to share ratably, together with holders of Class B shares, in the Company’s assets that remain after payment or provision for payment of all of its debts and obligations and after liquidation payments to holders of outstanding shares of preferred stock, if any.

Preferred Stock

The Company has 100,000,000 shares of authorized preferred stock issuable in one or more series. The Company’s Board of Directors is authorized to determine the designation, powers, preferences and relative, participating, optional or other special rights of any such series. As of December 31, 2013 and 2012, there was no preferred stock issued and outstanding.

15. Equity Incentive Award Plan

In September 2013, the Company adopted the 2013 Equity Incentive Award Plan (“2013 Plan”) , which permits the Company to issue 3,000,000 aggregate number of Class A common shares for equity awards including incentive and nonqualified stock options, restricted stock awards (“RSAs”) and restricted stock units to employees, directors and consultants. RSAs provide the holder with immediate voting rights, but are restricted in all other respects until released. Upon cessation of services to the Company, any unreleased RSAs will be cancelled. All unreleased RSAs accrue dividends and distributions, and are paid in cash upon release. In 2013, the Company made an initial grant of 444,823 stock options and 83,183 RSAs to certain employees in connection with the IPO and additional grants of 3,437 RSAs to certain directors. As of December 31, 2013, 2,468,557 aggregate number of Class A shares were available for issuance under the 2013 Plan.

Restricted Stock Awards

The following table summarizes restricted stock awards activity under the 2013 Plan for the year ended December 31, 2013:

	Number of RSAs Outstanding			Weighted Average Grant Date Fair Value		Aggregate Intrinsic Value
Balance at October 2, 2013		—		$	—
Granted		86,620			22.71
Released		(9,424	)		24.15
Repurchased for employee tax withholding		(934	)		22.53
Balance at December 31, 2013		76,262		$	22.53	$	2,311,501

For the year ended December 31, 2013, the total fair value of restricted stock awards released was $0.2 million, based on the weighted average grant date fair value.

F-29

Stock Options

The following table summarizes stock option activity under the 2013 Plan for the year ended December 31, 2013:

	Number of Options Outstanding			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (in years)		Aggregate Instrinsic Value
Balance at October 2, 2013		—		$	—
Granted		444,823			22.00
Vested		(37,069	)		22.00
Exercised		—			—
Expired		—			—
Forfeited		—			—
Balance at December 31, 2013		407,754		$	22.00		9.8	$	3,388,436
Exercisable at December 31, 2013		37,069		$	22.00		9.8	$	308,043

Aggregate intrinsic value represents the value of the Company’s closing stock price of $30.31 on the last trading day of the period in excess of the weighted-average exercise price multiplied by the number of options outstanding or exercisable.

Stock-Based Compensation

The Company accounts forstock-based compensation related to stock options granted to employees by estimating the fair value of thestock-based awards using theBlack-Scholesoption-pricing model. The fair value of the stock options granted are amortized over the applicable vesting period. TheBlack-Scholes option pricing model includes assumptions regarding dividend yields, expected volatility, expected option term, expected forfeiture rate and risk-free interest rates. The Company estimates expected volatility based on the historical volatility of comparable publicly traded companies for a period that is equal to the expected term of the options. The risk-free interest rate is based on the U.S. treasury yield curve in effect at the time of grant for a period commensurate with the estimated expected life. The expected term of options granted is derived using the “simplified” method as allowed under the provisions of the ASC 718,Compensation—Stock Compensation, due to insufficient historical exercise history data to provide a reasonable basis upon which to estimate expected term due to the limited period of time its equity shares have been publicly traded. As such, expected term of options represents the period of time that options granted are expected to be outstanding.

As of December 31, 2013, the fair value of employee stock options was estimated using the Black-Scholes option pricing model. The following weighted average assumptions were used:

	Year ended December 31, 2013
Stock options:
Risk-free interest rate		1.68	%
Expected life (in years)		5.8
Expected volatility		36	%
Expected dividend yield		5.7

The Company measures the fair value of RSAs at the grant date and accounts forstock-based compensation by amortizing the fair value on a straight line basis over the related vesting period.

The stock-based compensation expense related to stock options and RSAs is recorded as a component of general and administrative expenses in the Company’s consolidated statements of operations and totaled $0.5 million for the year ended December 31, 2013.

F-30

As of December 31, 2013, the total unrecorded stock-based compensation expense for unvested restricted stock awards was $1.7 million, which is expected to be amortized over a weighted-average period of 2.8 years. As of December 31, 2013 the total unrecorded stock-based compensation expense for unvested stock options shares was $1.7 million, which is expected to be amortized over a weighted-average period of 2.8 years.

16. Earnings Per Share

The Company computes earnings per share (EPS) for Class A and Class B common stock using the two-class method for participating securities. The rights, including voting and liquidation rights, of the holders of the Class A and Class B common stock are identical, except with respect to dividends, as the Class B common stock is not entitled to dividends.

Basic EPS is computed by dividing the net income attributable to common stockholders by the weighted-average number of common shares outstanding, for each respective class of stock. Net income attributable to common stockholders is allocated to each class of common stock considering dividends declared or accumulated during the current period that must be paid for the current period and the allocation of undistributed earnings to the extent that each class of stock may share in earnings as if all of the earnings for the period had been distributed. Because our Class B shares are not entitled to dividends, undistributed earnings, if any, would be allocated entirely to the Class A shares.

Diluted EPS is computed by dividing net income attributable to common stockholders by the weighted-average number of common shares and potentially dilutive common shares outstanding, for each respective class of stock. Potentially dilutive common stock includes the dilutive effect of the common stock underlying in-the-money stock options and is calculated based on the average share price for each period using the treasury stock method. Potentially dilutive common stock also reflects the dilutive effect of unvested restricted stock awards.

Class B common stock is a contingently convertible security which is convertible to Class A common stock on a one-to-one basis on the later of December 31, 2014 or commencement of commercial operations of the South Kent wind project. The computation of diluted EPS of Class A common stock would include the impact of the conversion of the Class B common stock, if dilutive for Class A, using the if-converted method once the contingency surrounding the conversion has been met.

In periods of net loss, the loss is allocated by first considering any dividends declared or accumulated to Class A common stock. While Class B is not entitled to dividends, because it has the same voting, liquidation and residual rights as Class A, the remaining undistributed loss is allocated equally per share to weighted average Class A and Class B common stock outstanding during the year. For the period from October 2, 2013 to December 31, 2013, potentially dilutive securities were excluded from the diluted EPS calculation as their effect is anti-dilutive.

F-31

The following table provides a disaggregated presentation of the Company’s consolidated statements of operations before and after its IPO on October 2, 2103:

Pattern Energy Group Inc.

Consolidated Statements of Operations

(In thousands of U.S. dollars, except share data)

	From October 2, 2013 to December 31, 2013			From January 1, 2013 to October 1, 2013			For Year Ended December 31, 2013
Revenue:
Electricity sales	$	41,836		$	131,434		$	173,270
Energy derivative settlements		4,035			12,763			16,798
Unrealized loss on energy derivative		(4,916	)		(6,356	)		(11,272	)
Related party revenue		446			465			911
Other revenue		701			21,165			21,866
Total revenue		42,102			159,471			201,573
Cost of revenue:
Project expense		15,455			42,222			57,677
Depreciation and accretion		21,193			61,987			83,180
Total cost of revenue		36,648			104,209			140,857
Gross profit		5,454			55,262			60,716
Total operating expenses		3,456			9,532			12,988
Operating income		1,998			45,730			47,728
Other expense		(10,217	)		(22,893	)		(33,110	)
Net (loss) income before income tax		(8,219	)		22,837			14,618
Tax provision (benefit)		11,314			(6,768	)		4,546
Net (loss) income		(19,533	)		29,605			10,072
Net loss attributable to noncontrolling interest		(6,197	)		(690	)		(6,887	)
Net (loss) income attributable to controlling interest	$	(13,336	)	$	30,295		$	16,959
Earnings per share information:
Less: Net income attributable to controlling interest prior to the IPO on October 2, 2013								(30,295	)
Net loss attributable to controlling interest subsequent to the IPO							$	(13,336	)
Numerator for basic and diluted earnings (loss) per share:
Net earnings (loss)							$	(13,336	)
Less: dividends declared
Class A common stock								(11,103	)
Class B common stock								—
							$	(24,439	)
Undistributed earnings (loss)
Denominator for basic and diluted earnings (loss) per share:
Weighted average number of shares:
Class A common stock								35,448,056
Class B common stock								15,555,000
Total								51,003,056
Calculation of basic and diluted earnings (loss) per share:
Class A common stock:
Dividends							$	0.31
Undistributed loss								(0.48	)
Basic and diluted loss per share							$	(0.17	)
Class B common stock:
Dividends							$	—
Undistributed loss								(0.48	)
Basic and diluted loss per share							$	(0.48	)

F-32

17. Geographic Information

The table below provides information, by country, about the Company’s consolidated operations. 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,
	2013		2012		2011		2013		2012
United States	$	161,505	$	73,089	$	103,773	$	1,210,319	$	1,367,149
Canada		40,068		41,439		32,086		265,823		301,153
Total	$	201,573	$	114,528	$	135,859	$	1,476,142	$	1,668,302

18. Commitments, Contingencies and Warranties

From time to time, the Company has become involved in claims and legal matters arising in the ordinary course of business. Management is not currently aware of any matters that will have a material adverse effect on the financial position, results of operations, or cash flows of the Company.

Power Purchase Agreements

The Company has various PPAs that terminate from 2025 to 2039. The terms of the PPAs generally provide for the annual delivery of a minimum amount of electricity at fixed prices and in some cases include price escalation over the term of the respective PPAs. As of December 31, 2013, under the terms of the PPAs, the Company issued irrevocable letters of credit totaling $57.2 million to ensure its performance for the duration of the PPAs.

Project Finance Agreements

The Company has various project finance agreements which obligate the Company to provide certain reserves to enhance its credit worthiness and facilitate the availability of credit. As of December 31, 2013, the Company issued irrevocable letters of credit totaling $91.8 million, of which $44.8 million was from the Company’s revolving credit facility, to ensure performance under these various project finance agreements.

Turbine Operations and Maintenance

The following table presents turbine operations and maintenance commitments over the next five years (in thousands):

For the year ending December 31,
2014	$	16,465
2015		3,845
2016		2,188
2017		1,965
2018		55
Thereafter		591
Total	$	25,109

The Company has six operating projects that have entered into turbine service and maintenance agreements with the turbine supplier or a third party to provide turbine maintenance for terms between two to five years from the in-service date for each of the project’s turbines. Total annualized base fees at December 31, 2013, are approximately $19.4 million, adjusted for inflation.

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Contingent Liabilities

The Company has recorded contingent purchase price payment obligations related to acquired assets that were recorded at fair value and re-measured at each reporting date. The amount of recorded contingent purchase price obligations was zero and $8.0 million as of December 31, 2013 and 2012, respectively.

In addition, the Company has unrecorded purchase price payment obligations related to asset acquisitions that are contingent on future events. The amount of unrecorded contingent purchase price obligations was $4.7 million and $2.8 million as of December 31, 2013 and 2012, respectively.

Land Leases

The Company has entered into various long-term land leases. Rent expense, included in project expense in the consolidated statements of operations, was $6.1 million, $4.2 million and $4.6 million for the years ended December 31, 2013, 2012 and 2011, respectively.

The future minimum payments related to these leases as of December 31, 2013, are as follows (in thousands):

For the year ending December 31,
2014	$	3,713
2015		3,717
2016		3,725
2017		3,731
2018		3,738
Thereafter		91,876
Total	$	110,500

Purchase Commitments

The Company has entered into various commitments with service providers related to the Company’s projects and operations of its business. Outstanding commitments with these vendors, excluding turbine operations and maintenance commitments were $4.1 million and $5.1 million as of December 31, 2013 and 2012, respectively. The Company has open commitments for the purchase of new wind turbines of zero and $1.7 million, as of December 31, 2013 and 2012, respectively, and for construction of zero and $22.3 million as of December 31, 2013 and 2012, respectively.

Purchase and Sales Agreement

On December 20, 2013, the Company entered into an agreement with Pattern Development to acquire approximately 80% of the ownership interest in Panhandle 2, a 182 MW wind project being built in Carson County, Texas, for approximately $122.9 million in cash. The acquisition, which includes assumption by the Company of certain tax indemnities, is expected to close in fourth quarter of 2014 upon completion of construction, and the Company expects to fund the purchase with available cash and credit facilities.

Indemnity

The Company provides a variety of indemnities in the ordinary course of business to contractual counterparties and to our lenders and other financial partners. Hatchet Ridge agreed to indemnify the lender that provided financing for Hatchet Ridge against certain tax losses in connection with its sale-leaseback financing transaction in December 2010. The indemnity agreement is effective for the duration of the sale-leaseback financing.

The Company is party to certain indemnities for the benefit of the Spring Valley, Santa Isabel and Ocotillo project finance lenders. These indemnity obligations consist principally of indemnities that protect the project

F-34

finance lenders from the potential effect of any recapture by the U.S. Department of the Treasury, or “U.S. Treasury,” of any amount of the ITC cash grants previously received by the projects. The ITC cash grant indemnity obligations guarantee amounts of any cash grant made to each of the respective projects that may subsequently be recaptured. In addition, the Company is also party to an indemnity of our Ocotillo project finance lenders in connection with certain legal matters, which is limited to the amount of certain related costs and expenses.

Santa Isabel agreed to indemnify unrelated third parties against certain tax losses in connection with monetization of tax credits under the Economic Incentives for the Development of Puerto Rico Act of May 28, 2008 for $7.2 million.

Turbine Availability Warranties

The Company has various turbine availability warranties from its turbine manufacturers. Pursuant to these warranties, if a turbine operates at less than minimum availability during the warranty period, the turbine manufacturer is obligated to pay as liquidated damages a fee for each percent that the turbine operates below the minimum availability threshold. In addition, also pursuant to certain of these warranties, if a turbine operates at more than a specified availability during the warranty period, the Company has an obligation to pay a bonus to the turbine manufacturer. During 2012 and 2011, no liquidating damages or bonus were recorded by the Company.

In 2013, the Company entered into warranty settlements with a turbine manufacturer for blade related wind turbine outages. The warranty settlements provide for total liquidated damage payments of approximately $21.9 million for the year ended December 31, 2013. During the year ended December 31, 2013, the Company received payments of $24.1 million in connection with these warranty settlements. The Company estimates the maximum future refund of liquidated damage payments to the turbine manufacturer to be $2.2 million and has recorded an accrued liability for this amount as of December 31, 2013. The warranty settlements received, net of the maximum potential future refund to the wind turbine manufacturer, have been recorded as other revenue in the consolidated statements of operations.

19. Related Party Transactions

From inception to October 1, 2013, the Company’s project management and administrative activities were provided by Pattern Development. Costs associated with these activities were allocated to the Company and recorded in its consolidated statements of operations. Allocated costs include cash and non-cash compensation, other direct, general and administrative costs, and non-operating costs deemed allocable to the Company. Measurement of allocated costs is based principally on time devoted to the Company by officers and employees of Pattern Development. The Company believes the allocated costs presented in its consolidated statements of operations are a reasonable estimate of actual costs incurred to operate the business. The allocated costs are not the result of arms-length, free-market dealings.

Management Services Agreement and Shared Management

Effective October 2, 2013, the Company entered into a bilateral Management Services Agreement with Pattern Development which provides for the Company and Pattern Development to benefit, primarily on a cost-reimbursement basis, plus a 5% fee on certain direct costs, from the parties’ respective management and other professional, technical and administrative personnel, all of whom will report to and be managed by the Company’s executive officers. Pursuant to the Management Services Agreement, certain of the Company’s executive officers, including its Chief Executive Officer, will also serve as executive officers of Pattern Development and devote their time to both the Company and Pattern Development as is prudent in carrying out their executive responsibilities and fiduciary duties. The Company refers to the employees who will serve as executive officers of both the Company and Pattern Development as the “shared PEG executives.” The shared

F-35

PEG executives will have responsibilities for both the Company and Pattern Development and, as a result, these individuals will not devote all of their time to the Company’s business. Under the terms of the Management Services Agreement, Pattern Development is required to reimburse the Company for an allocation of the compensation paid to such shared PEG executives reflecting the percentage of time spent providing services to Pattern Development.

The table below presents allocated costs prior to October 2, 2013 and net bilateral management service cost reimbursements on and after October 2, 2013 included in the consolidated statements of operations (in thousands):

	December 31,
	2013			2012			2011
Project expense	$	1,995		$	1,998		$	1,139
General and administrative		7,318			10,604			8,098
Management Services Agreement expense		851			—			—
Management Services Agreement income		(665	)		—			—
Other income		(551	)		(210	)		(199	)
Total	$	8,948		$	12,392		$	9,038

Prior to the Contribution Transactions, the Company had purchase arrangements with Pattern Development under which the latter purchased various services and supplies on behalf of the Company and received reimbursement for these purchases. As of December 31, 2013 and 2012, the amounts payable to Pattern Development for these purchases were $1.2 million and $0.2 million, respectively.

Letters of credit, indemnities and guarantees

Pattern Development provided letters of credit that secure the Company’s obligations under PPAs and interconnection agreements. There were no letters of credit outstanding as of December 31, 2013 and 2012, respectively.

Pattern Development agreed to guarantee $14.0 million of El Arrayán’s payment obligations to a lender that has provided a $20 million credit facility for financing of El Arrayán’s recoverable, construction-period value added tax payments. The remaining $6.0 million of the credit facility has been guaranteed by another investor in El Arrayán.

Purchase and Sales Agreements

On December 20, 2013, the Company entered into an agreement with Pattern Development to acquire approximately 80% of the ownership interest in Panhandle 2, a 182 MW wind project being built in Carson County, Texas, for approximately $122.9 million in cash. The acquisition is expected to close in fourth quarter of 2014 upon completion of construction, and the Company expects to fund the purchase with available cash and credit facilities.

On December 20, 2013, the Company acquired a 45.0% equity interest in Grand from Pattern Development. Subject to the terms of this agreement, the Company may make an additional contingent payment of up to $4.7 million to Pattern Development in 2014.

Puerto Rico Electric Power Authority (PREPA)

The Company’s Santa Isabel project was in a dispute with PREPA over the appropriate rate being charged to the project for the electric services it uses. During the year ended December 31, 2013, the difference between what the Company believes is the appropriate monthly charge and PREPA’s bill was resolved in principle, and billing is now per the understanding between the parties. Pattern Development provided the Company with an indemnity to mitigate the economic impact on the Company of this dispute.

F-36

Management fees

The Company provides operations and management services and receives a fee for such services under agreements with South Kent, Grand and El Arrayán, its joint venture investees. Management fees of $0.9 million were recorded as related party revenue in the consolidated statements of operations for the year ended December 31, 2013 and a related party receivable of $0.2 million was recorded in the consolidated balance sheet as of December 31, 2013. The Company eliminates the intercompany profit from management fees related to its ownership interest in South Kent.

Employee Savings Plan

The Company participates in a 401(k) plan sponsored and maintained by Pattern Development, established on August 3, 2009 and restated on October 3, 2013. The Company also sponsors a Canadian Registered Retirement Savings Plan (“RRSP”), established on October 2, 2013. Participants in the plans are allowed to defer a portion of their compensation, not to exceed the respective Internal Revenue Service (IRS) or Canada Revenue Agency (CRA) annual allowance contribution guidelines, and are 100% vested in their respective deferrals and earnings. Participants may choose from a variety of investment options. The Company contributes 5% of base compensation to each employee’s 401(k) or RRSP account, up to the annual compensation limit. For the year ended December 31, 2013, the Company contributed $0.1 million which was recorded in the consolidated statements of operations as either general and administrative expense or cost of revenue. No such contributions were made during the years ended December 31, 2012 and 2011.

20. Selected Quarterly Financial Data (Unaudited)

The following tables summarize the Company’s unaudited quarterly consolidated statements of operations for each of the eight quarters in the period ended December 31, 2013. The quarterly consolidated statements of operations data were prepared on a basis consistent with the audited consolidated financial statements included in Part III, Item 14, “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.

Quarterly financial data in thousands, except for share data:

	Three months ended
	December 31, 2013			September 30, 2013		June 30, 2013			March 31, 2013
Revenue	$	41,767		$	57,257	$	58,712		$	43,837
Gross profit		4,729			21,471		26,222			8,294
Net (loss) income		(19,376	)		4,244		43,988			(18,784	)
Net (loss) income attributable to noncontrolling interest		(6,197	)		3,248		(359	)		(3,579	)
Net (loss) income attributable to controlling interest		(13,179	)		996		44,347			(15,205	)
Basic and diluted loss per share—Class A	$	(0.17	)		N/A		N/A			N/A
Basic and diluted loss per share—Class B	$	(0.48	)		N/A		N/A			N/A

	Three months ended
	December 31, 2012			September 30, 2012			June 30, 2012			March 31, 2012
Revenue	$	34,345		$	16,903		$	24,939		$	38,341
Gross profit (loss)		10,086			(5,213	)		6,175			19,610
Net (loss) income		(4,455	)		(16,913	)		(575	)		8,567
Net (loss) income attributable to noncontrolling interest		(1,147	)		(7,494	)		(2,928	)		4,480
Net (loss) income attributable to controlling interest		(3,308	)		(9,419	)		2,353			4,087
Basic and diluted loss per share—Class A		N/A			N/A			N/A			N/A
Basic and diluted loss per share—Class B		N/A			N/A			N/A			N/A

21. Subsequent Events

None.

F-37

Schedule I—Condensed Parent-Company Financial Statements

Pattern Energy Group Inc.

Condensed Financial Information of Parent

Balance Sheets

(In thousands of U.S. dollars, except share data)

	December 31, 2013			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	75,776		$	1
Related party receivable		1,000			—
Prepaid expenses and other current assets		446			—
Total current assets		77,222			1
Investments in subsidiaries		407,271			514,117
Net deferred tax assets		573			—
Total assets	$	485,066		$	514,118
Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities	$	4,513		$	7
Related party payable		667			—
Dividend payable		11,103			—
Total current liabilities		16,283			7
Net deferred tax liabilities		573			—
Total liabilities		16,856			7
Equity:
Class A common stock, $0.01 par value per share:
500,000,000 shares authorized; 35,530,786 and 100 shares issued and outstanding as of December 31, 2013 and 2012, respectively		355			—
Class B common stock, $0.01 par value per share:
20,000,000 shares authorized; 15,555,000 shares issued and outstanding at December 31, 2013		156			—
Additional paid-in capital		461,828			1
Capital		—			551,109
Accumulated income (loss)		14,224			(2,735	)
Accumulated other comprehensive loss		(8,353	)		(34,264	)
Total equity		468,210			514,111
Total liabilities and equity	$	485,066		$	514,118

S-1

Pattern Energy Group Inc.

Condensed Financial Information of Parent

Statements of Operations and Comprehensive Income (Loss)

(In thousands of U.S. dollars)

	Year ended December 31, 2013			October 17, 2012 (initial capitalization) to December 31, 2012
Revenue	$	—		$	—
Expenses		3,630			7
Operating loss		(3,630	)		(7	)
Other income (expense):
Equity in earnings (loss) from subsidiaries		20,487			(2,728	)
Related party income		665			—
Other expense, net		(563	)		—
Other income (expense)		20,589			(2,728	)
Net income (loss) before income tax		16,959			(2,735	)
Tax (benefit) provision		—			—
Net income (loss)		16,959			(2,735	)
Other comprehensive income (loss), net of tax
Foreign currency translation, net of tax		(8,309	)		777
Effective portion of change in fair market value of derivatives, net of tax		31,787			1,099
Proportionate share of equity investee’s other comprehensive loss, net of tax		2,473			—
Total other comprehensive income (loss), net of tax		25,951			1,876
Comprehensive income (loss)	$	42,910		$	(859	)

S-2

Pattern Energy Group Inc.

Condensed Financial Information of Parent

Condensed Statements of Cash Flows

(In thousands of U.S. dollars)

	Year ended December 31, 2013			October 17, 2012 (initial capitalization) to December 31, 2012
Operating activities
Net income (loss)	$	16,959		$	(2,735	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Stock-based compensation		511			—
Equity in (earnings) loss from subsidiaries		(20,487	)		2,728
Changes in operating assets and liabilities:
Prepaid expenses and other current assets		(446	)		—
Accounts payable and other accrued liabilities		93			7
Related party receivable/payable		(1,007	)		—
Net cash used in operating activities		(4,377	)		—
Investing activities
Distributions from subsidiaries		233,226			—
Contributions to subsidiaries		(172,130	)		—
Net cash provided by investing activities		61,096			—
Financing activities
Repurchase of shares for employee tax withholding		(24	)
Capital contributions		32,678			1
Proceeds from IPO, net of expenses		317,926			—
Capital distributions		(98,884	)		—
Capital distributions—Contribution Transactions		(232,640	)		—
Net cash provided by financing activities		19,056			1
Net change in cash and cash equivalents		75,775			1
Cash and cash equivalents at beginning of period		1			—
Cash and cash equivalents at end of period	$	75,776		$	1
Schedule of non-cash activities
Investments in subsidiaries	$	—		$	514,117

S-3

Schedule II—South Kent Wind LP Financial Statements

South Kent Wind LP

Financial Statements

December 31, 2013

(expressed in Canadian dollars)

S-4

February 21,2014

Independent Auditor’s Report

To the Partners of

South Kent Wind LP

We have audited the accompanying statement of financial position of South Kent Wind LP as of December 31, 2013 and the related statement of operations and comprehensive income, changes in partners’ capital and cash flows for the year then ended. Management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Our audit of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We were not engaged to perform an audit of the company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provide a reasonable basis for our opinions.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of South Kent Wind LP as of December 31, 2013 and the results of its operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants, Licensed Public Accountants

S-5

March 14, 2013

Independent Auditor’s Report

To the Partners of

South Kent Wind LP

We have audited the accompanying financial statements of South Kent Wind LP, which comprise the balance sheets as at December 31, 2012 and December 31, 2011 and the statements of income, changes in partners’ capital and cash flows for the years then ended, and the related notes, which comprise a summary of significant accounting policies and other explanatory information.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of South Kent Wind LP as at December 31, 2012 and December 31, 2011 and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants, Licensed Public Accountants

S-6

South Kent Wind LP

Statement of Financial Position

As at December 31, 2013

(expressed in Canadian dollars)

	2013		2012
Assets
Current assets
Cash and cash equivalents	$	139,346	$	415,032
Restricted cash (note 3)		26,888,466		—
Sales tax recoverable		13,590,640		260,784
Other current assets (note 4)		1,515,511		54,527
		42,133,963		730,343
Non-current assets
Restricted cash (note 3)		—		5,400,000
Advance payment		19,520,025		—
Deferred development costs (note 5)		—		32,334,346
Construction-in-progress (note 5)		625,636,458		—
Property, plant and equipment - net of accumulated depreciation of $86,934 (2012 - $47,582) (note 6)		115,915		82,188
Intangible assets - net of accumulated amortization of $592,315 (2012 - $385,980) (note 7)		430,584		82,388
Deferred financing costs - net of accumulated amortization of $1,056,079 (2012 - $nil)		19,361,860		—
Derivative assets (note 12)		26,757,264		—
	$	733,956,069	$	38,629,265
Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	43,155,372	$	712,771
Current portion of construction facility loan (note 9)		1,914,367		—
Current portion of long-term contingent liabilities (note 14)		1,564,600		1,346,000
Derivative liability - current portion (note 12)		7,814,992		—
Other current liabilities (note 8)		1,030,657		—
		55,479,988		2,058,771
Non-current liabilities
Construction facility loan (note 9)		542,717,827		—
Long-term contingent liabilities (note 14)		9,500,000		1,064,600
Asset retirement obligation (note 11)		5,833,484		—
		613,531,299		3,123,371
Partners’ capital
Contributions (note 10)		103,164,191		35,440,000
Accumulated net income		17,260,579		65,894
		120,424,770		35,505,894
	$	733,956,069	$	38,629,265

S-7

South Kent Wind LP

Statement of Operations and Comprehensive Income

For the year ended December 31, 2013

(expressed in Canadian dollars)

	2013			2012			2011
Revenue	$	—		$	—		$	—
Operating expenses
Professional fees		(341,110	)		—			—
General and administrative		(320,281	)		(27,048	)		—
General and administrative - related party		(555,588	)		—			—
Depreciation and amortization		(32,863	)		—			—
Operating loss		(1,249,842	)		(27,048	)		—
Unrealized gain on derivatives(note 12)		18,942,272			—			—
Other (expenses) income		(497,745	)		92,942			—
Net income and comprehensive income	$	17,194,685		$	65,894		$	—

S-8

South Kent Wind LP

Statement of Changes in Partners’ Capital

For the year ended December 31, 2013

(expressed in Canadian dollars)

	Partners’ capital			Accumulated net income		Total
Balance at January 1, 2011	$	—		$	—	$	—
Cash initial contribution		10,000			—		10,000
Cash contribution		22,410,000			—		22,410,000
Net income		—			—		—
Balance at December 31, 2011	$	22,420,000		$	—	$	22,420,000
Cash contribution		13,020,000			—		13,020,000
Net income		—			65,894		65,894
Balance at December 31, 2012	$	35,440,000		$	65,894	$	35,505,894
Cash contribution		9,016,022			—		9,016,022
Cash distribution		(21,393,091	)		—		(21,393,091	)
Non-cash contribution		80,101,260			—		80,101,260
Net income		—			17,194,685		17,194,685
Balance at December 31, 2013	$	103,164,191		$	17,260,579	$	120,424,770

S-9

South Kent Wind LP

Statements of Cash Flows

For the year ended December 31, 2013

(expressed in Canadian dollars)

	2013			2012			2011
Operating activities
Net income (loss) for the period	$	17,194,685		$	65,894		$	—
Adjustment to reconcile net income (loss) to net cash used in operating activities
Unrealized gain on derivatives		(18,942,272	)		—			—
Non-cash activities		100,879			(38,984	)		—
Bad debt expense		300,000			—			—
		(1,346,708	)		26,910			—
Investing activities
Consideration paid for the acquisition of project assets		(1,346,000	)		—			(15,215,910	)
Construction costs paid		(478,425,665	)		—			—
Purchase of property, plant and equipment and intangible assets		(627,610	)		(178,184	)		(162,482	)
Deferred development costs paid		—			(12,748,484	)		(1,346,818	)
Payment for restricted cash		(21,488,466	)		—			(5,400,000	)
		(501,887,741	)		(12,926,668	)		(22,125,210	)
Financing activities
Partner contribution		9,016,022			—			—
Construction facility loan proceeds		535,753,771			—			—
Deferred financing costs paid		(20,417,939	)		—			—
Distribution to partners		(21,393,091	)		13,020,000			22,420,000
		502,958,763			13,020,000			22,420,000
Increase (decrease) in cash and cash equivalents during the period		(275,686	)		120,242			294,790
Cash and cash equivalents - Beginning of period		415,032			294,790			—
Cash and cash equivalents - End of period	$	139,346		$	415,032		$	294,790
Supplemental non-cash activities disclosure
Transfer to Construction-in-progress from deferred development costs	$	32,334,346		$	—		$	—
Accrued construction costs	$	42,442,601		$	—		$	—
Non-monetary contribution from partners	$	80,101,260		$	—		$	—
Construction loan - capitalized interest	$	8,878,422		$	—		$	—
Depreciation and amortization	$	1,200,887		$	257,093		$	176,469
Community fund commitment	$	10,000,000		$	—		$	—

S-10

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

1 General information

The Partnership

South Kent Wind LP (the Partnership), a limited partnership under the laws of the Province of Ontario, was formed on January 10, 2011, as a joint venture project between Samsung Renewable Energy Inc. (Samsung) and Pattern South Kent LP Holdings LP, a subsidiary of Pattern Renewable Holdings Canada ULC (PRHC), each as 49.99% limited partners of the Partnership, and South Kent Wind GP Inc. (the GP), as the 0.02% general partner of the Partnership. The terms of the Partnership initially were governed by the Limited Partnership Agreement of the Partnership, dated January 10, 2011, which was subsequently superseded in its entirety by the Amended and Restated Limited Partnership Agreement of the Partnership, dated February 22, 2013. The Partnership was created to develop, build and operate a wind power project in the Regional Municipality of Chatham-Kent that is expected to generate 270 megawatts (MW) of power (the Project). The Project is part of Phase 1 of the Green Energy Investment Agreement that Samsung C&T Corp., a parent company of Samsung, entered into with the Government of Ontario in January 2010, subsequently amended in June 20, 2013.

On February 24, 2013, Samsung transferred its LP interest in the Partnership to SRE SKW LP Holdings LP, an affiliate of Samsung.

On October 2, 2013, in a series of transactions: (i) Pattern South Kent GP Holdings Inc., a wholly owned subsidiary of PRHC, transferred all of the general partner interests in Pattern South Kent LP Holdings LP to PRHC, causing Pattern South Kent LP Holdings LP to be dissolved by operation of law and PRHC to acquire the LP interests in the Partnership that previously were held by Pattern South Kent LP Holdings LP; (ii) PRHC transferred its LP interest in the Partnership and its ownership interest in Pattern South Kent GP Holdings Inc., which owned PRHC’s ownership interest in the GP, to Pattern Canada Operations Holdings ULC, an affiliate of Pattern Energy Group Inc. (Pattern); and (iii) Pattern South Kent GP Holdings Inc. was dissolved, so that Pattern Canada Operations Holdings ULC now holds Pattern’s (a) LP interests in the Partnership and (b) ownership interests in the GP.

The Partnership is controlled by its general partner, the GP, also a joint venture controlled by affiliates of Samsung and Pattern. The GP is governed by the Amended and Restated Unanimous Shareholder Agreement of the GP, dated March 6, 2013 (the Shareholder Agreement). As at December 31, 2013 and 2012, the Partnership’s ownership interests were distributed as follows:

	2013		2012
SRE SKW LP Holdings LP		49.99%		—  %
Pattern Canada Operations Holdings ULC		49.99%		—  %
Samsung Renewable Energy Inc.		—  %		49.99%
Pattern South Kent LP Holdings LP		—  %		49.99%
South Kent Wind GP Inc.		0.02%		0.02%
		100.00%		100.00%

The Project

The Project is a 270 MW wind project consisting of 124 Siemens wind turbine generators located in the Regional Municipality of Chatham-Kent, Ontario.

S-11

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

On August 2, 2011, the Partnership entered into a power purchase agreement (PPA) with the Ontario Power Authority (OPA) related to the sale of 100% of the electrical output of the Project at prescribed electricity rates for a period of 20 years following Commercial Operation Date (COD), which is expected to be in the second quarter of 2014 (note 14).

On June 15, 2012, the Project received the final approval in the permitting process, known as the Renewable Energy Approval process. On December 5, 2012, decisions by the Environmental Review Tribunal on all appeals were made in favour of the Project. The Partnership secured sufficient land rights and commitments to construct the Project, including turbine locations, roads, collector system, substation and the transmission line.

2 Summary of significant accounting policies

The principal accounting policies applied in the preparation of these financial statements are set out below. These policies have been consistently applied to the period presented, unless otherwise stated.

Basis of preparation

The accompanying financial statements are presented using accounting principles generally accepted in the United States of America (U.S. GAAP). The preparation of U.S. GAAP financial statements requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Because the use of estimates is inherent in the financial reporting process, actual results could differ from those estimates.

In recording transactions and balances resulting from business operations, the Partnership uses estimates based on the best information available. Estimates are used for such items as asset retirement obligation valuation of derivative contracts and acquisition contingencies.

These financial statements do not include assets, liabilities, revenue and expenses of the GP and limited partners. The financial statements of the Partnership reflect no provision or liability for income taxes because profits and losses of the Partnership are allocated to the partners and are included in the income tax returns of partners. Income and losses for tax purposes may differ from the financial statement amounts and the partners’ capital reflected in the financial statements does not necessarily reflect their tax basis.

Functional and presentation currency

Items included in the financial statements of the Partnership are measured using the currency of the primary economic environment in which the Partnership operates (the functional currency). The financial statements are presented in Canadian dollars, which is the Partnership’s functional and presentation currency.

Fair value of financial instruments

ASC 820,Fair Value Measurements, defines fair value as the price at which an asset could be exchanged or a liability transferred in an orderly transaction between knowledgeable, willing parties in the principal or most advantageous market for the asset or liability. Where available, fair value is based on observable market prices or derived from such prices. Where observable prices or inputs are not available, valuation

S-12

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

Cash and cash equivalents

Cash and cash equivalents include cash on hand, deposits held at call with banks and other short-term highly liquid investments with original maturities of three months or less.

Restricted cash

Restricted cash consists of cash balances required to collateralize commercial bank letter of credit facilities related primarily to interconnect rights and power purchase agreements (PPAs) and for reserves required under the Partnership’s loan agreements (note 3).

Concentration of credit risk

Financial instruments that potentially subject the Partnership to concentrations of credit risk consist primarily of cash and cash equivalents and restricted cash. The Partnership places its cash and cash equivalents and restricted cash with high-quality institutions.

Deferred development costs

The Partnership developed and is now constructing a wind power plant for its own use. There are two phases to the development of the wind power plant: first, a feasibility stage where all costs are expensed; and second, a construction phase where capitalization is appropriate, subject to the appropriate criteria (note 5).

Judgment needs to be exercised for each situation. The Partnership determines whether or not the wind power plant can be built to its proposed specifications and in compliance with the respective regulations. During the feasibility stage, it is uncertain whether the wind power plant will be completed and whether future economic benefits will flow to the Partnership. During the development stage, the Partnership will build the wind power plants. It can reliably measure the cost of development and it is probable that future economic benefits will flow to the Partnership. Certain costs incurred during the development stage should be recognized as an item of deferred development costs.

An evaluation of the circumstances surrounding the development of the Project and in particular the provisions of the Green Energy Investment Agreement, which provide for the issuance of a PPA and support through the permitting process, support the conclusion that the Project moved beyond the feasibility stage prior to the date of inception of the Partnership. Accordingly, all development costs have been capitalized.

Other development expenditures that do not meet the criteria are recognized as an expense when incurred. Development costs previously recognized as an expense are not recognized as an asset in a subsequent period.

Development costs of $32,334,346 incurred during the development stage including $17,369,038 of asset acquired costs through the asset purchase agreements (APA), which had been capitalized and recorded as deferred development costs in the statement of financial position, were transferred and recorded as construction-in-progress as the construction commenced on March 8, 2013.

S-13

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

Construction-in-progress

Construction-in-progress represents the accumulated costs of projects in construction. Construction costs include turbines for which the Partnership has taken legal title, civil engineering, electrical and other related costs. Other capitalized costs include reclassified deferred development costs, amortization of intangible assets, amortization of deferred financing costs, capitalized interest and other costs required to place a project into commercial operation. Construction-in-progress is reclassified to property, plant and equipment when the project begins commercial operations.

Advance payments

Advance payments represent amounts advanced to turbine and other suppliers for the manufacture of wind turbines and other plant assets in accordance with supply agreements for the Partnership’s wind power project and for which the Project has not taken title. Advance payments are reclassified to Construction-in-progress when the Partnership takes legal title to the related turbines and other plant assets and they are reclassified to property, plant and equipment when the project achieves commercial operation. Depreciation does not commence until projects enter commercial operation and assets are placed in service.

Property, plant and equipment

Property, plant and equipment are stated at historical cost, less depreciation. Historical cost includes expenditure that is directly attributable to the acquisition of the items.

Asset retirement obligations included in property, plant and equipment are stated at the present value of future cash flows of asset retirement obligations.

Subsequent costs are included in the asset’s carrying value or recognized as separate assets, as appropriate, only when it is probable the future economic benefits associated with the item will flow to the Partnership and the cost of the item can be measured reliably.

Depreciation on property, plant and equipment is calculated using the straight-line method to allocate their cost to their residual values over their estimated useful lives. The assets’ residual values and useful lives are reviewed and adjusted, if appropriate, at the end of each reporting period.

Intangible assets (lease options)

Lease options are recognized at fair value at the acquisition date and subsequently accounted for at cost. Lease options have a finite useful life and are carried at cost less accumulated amortization. Amortization is calculated using the straight-line method to allocate the cost of lease options over the period of expected future benefit (i.e., the contract period of each lease option). Separately acquired lease options are capitalized on the basis of the costs incurred to enter into the respective contract considering legal fees and service fees.

Impairment of long-lived assets

The Partnership periodically evaluates whether events have occurred that would require revision of the remaining useful life of equipment and improvements and purchased intangible assets or render them not recoverable. If such circumstances arise, the Partnership uses an estimate of the undiscounted value of expected future operating cash flows to determine whether the long-lived assets are impaired. If the aggregate undiscounted cash flows are less than the carrying amount of the assets, the resulting impairment charge to be recorded is calculated based on the excess of the carrying value of the assets over the fair value of such assets, with the fair value determined based on an estimate of discounted future cash flows.

S-14

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

Interest capitalization

The Partnership capitalizes interest and related financing fees from non-recourse debt used to finance projects in construction. Capitalization is discontinued when a project goes into commercial operation.

Derivatives

The Partnership recognizes its derivative instruments as either assets or liabilities in the statement of financial position at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it qualifies and has been designated as part of a hedging relationship and, further, on the type of hedging relationship.

For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure to variability in expected future cash flows that are attributable to a particular risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of other comprehensive income (OCI). Changes in the fair value of these derivatives are subsequently reclassified into earnings in the period the hedged transaction affects earnings. The ineffective portion of changes in fair value is recorded as a component of net income in the statement of comprehensive income.

For undesignated derivative instruments, their change in fair value is reported as a component of net income in the statement of operations and comprehensive income.

The Partnership enters into derivative transactions for the purpose of reducing exposure to fluctuations in interest rates. The Partnership entered into interest rate swaps. Interest rate swaps are instruments used to fix the interest rate on variable interest rate debt.

Deferred financing costs

Financing costs incurred in connection with obtaining construction and term financing, which include direct financing, legal and other upfront costs of borrowing, are deferred and amortized over the lives of the respective loans using the effective-interest method. Amortization of deferred financing costs is capitalized during construction or expensed following commencement of commercial operation.

Accounts payable and other accrued liabilities

Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Payables with payment terms extended beyond one year from the statement of financial position date are presented as non-current liabilities.

Contingent liabilities

Contingent liabilities for environmental restoration, restructuring costs and other legal obligations are recognized when: the Partnership has a present legal obligation as a result of past events; it is probable that an outflow of resources will be required to settle the obligation; and the amount has been reasonably estimated.

S-15

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

Asset retirement obligation

The Partnership records an asset retirement obligation for the estimated costs of decommissioning turbines, removing above-ground installations and restoring sites, at the time when a contractual decommissioning obligation materializes. The Partnership records accretion expense, which represents the increase in the asset retirement obligation, over the remaining life of the associated wind project. Accretion expense is recorded as cost of revenue in the statement of comprehensive income using accretion rates based on credit adjusted risk free interest rates of 5.54%.

Comprehensive income

Comprehensive income consists of net income and other comprehensive income.

Contributions

Contributions from joint venture partners are classified as equity.

3 Restricted cash

The following table presents the components of restricted cash:

	December 31,
	2013		2012
Security deposit for letter of guarantee to OPA	$	8,100,000	$	5,400,000
Security deposit for letter of guarantee to Municipality of Chatham-Kent		2,614,000		—
Security deposit for letter of guarantee - others		82,338		—
10% holdback account for contractors		16,092,128		—
	$	26,888,466	$	5,400,000

The Partnership maintains term deposits with Korea Exchange Bank of Canada that are restricted as security for the letter of guarantee to the OPA, and provided as the initial and incremental security under the PPA. The Partnership classifies these balances as restricted cash in current assets in the statement of financial position as the restrictions are anticipated to be released on COD of the Project, which is expected to be in the second quarter of 2014 (note 2).

4 Other current assets

The following table presents the components of other current assets:

	December 31,
	2013		2012
Mortgage debt receivable, net of bad debt provision of $300,000	$	828,386	$	—
Refundable deposit on COD		86,000		—
Prepaid expenses		484,477		15,544
Accrued interest income		116,648		38,983
	$	1,515,511	$	54,527

S-16

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

5 Deferred development costs and construction-in-progress

The following table presents the components of deferred development costs and construction-in-progress:

	December 31,
	2013		2012
Deferred development costs	$	—	$	32,334,346
Construction-in-progress	$	625,636,458	$	—

Deferred development costs of $32,334,346 incurred were transferred to construction-in-progress on March 8, 2013, the date the project commenced construction.

Construction-in-progress includes capitalized interest expense of $12,583,514 and $nil as of December 31, 2013 and 2012, respectively.

6 Property, plant and equipment

The following table reflects the categories within property, plant and equipment at historical cost:

	December 31,						Depreciable life (years)
	2013			2012
Machinery and equipment	$	202,849		$	129,770			5
Subtotal		202,849			129,770
Less: Accumulated depreciation		(86,934	)		(47,582	)
	$	115,915		$	82,188

Depreciation expense of $6,489 (2012 - $47,582) has been charged to deferred development costs in the statement of financial position and $32,863 (2012 - $nil) has been charged to the statement of operations and comprehensive income.

7 Intangible assets

	2013			2012
Beginning net book value	$	82,388		$	135,343
Additions		554,531			178,184
Amortization expense		(206,335	)		(231,139	)
Closing net book value	$	430,584		$	82,388
Cost	$	1,022,899		$	468,368
Accumulated amortization		(592,315	)		(385,980	)
Net book value	$	430,584		$	82,388

Amortization of $206,355 (2012 -$231,139) is included in deferred development costs in the statements of financial position.

S-17

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

8 Other current liabilities

The following table presents the components of accounts payable and other accrued liabilities:

	December 31,
	2013		2012
Accrued expenses	$	856,084	$	—
Accrued interest - construction facility loan		174,573		—
	$	1,030,657	$	—

9 Long-term debt

On March 8, 2013, the Partnership signed a credit facility agreement with a syndicate of lenders consisting of 15 different financial institutions for a term of construction period plus seven years at a rate of Canadian Dealer Offered Rate (CDOR) plus 2.5% per annum for the first four years and CDOR plus 2.75% per annum thereafter. The credit facilities under the agreement include a $683,817,047 construction facility, letter of credit facility and an interest rate hedge facility. The funds from these facilities will be utilized to finance the construction of the Project and to run the project operations thereafter.

For the periods ended December 31, 2013 and December 31, 2012, the credit facilities incurred capitalized interest charges of $8,878,422 and $nil, respectively. Interest payments on the construction facility are currently deferred and will be added to the loan principal on term conversion.

The terms and conditions of outstanding borrowings were as follows:

	December 31,					Interest rate as of December 31,						Interest		Loan
	2013			2012		2013			2012			type		type		Maturity
Construction facility loan	$	544,632,194		$	—		3.75	%		—	%		Variable		Project financing		March 8, 2021
Current portion		(1,914,367	)		—
	$	542,717,827		$	—

The following are the amounts due for long-term debt as of December 31, 2013:

2014	$	1,914,367
2015		23,185,104
2016		22,109,351
2017		25,773,416
2018		26,819,083
Thereafter		444,830,873
	$	544,632,194

S-18

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

10 Contributions from/distributions to joint venture partners

	2013
	SRE SKW LP Holdings LP1			Pattern Canada Operations Holdings ULC2			South Kent Wind GP Inc.			Total
Balance - Beginning of year	$	17,716,456		$	17,716,456		$	7,088		$	35,440,000
Subsequent cash contribution on
Jan. 3, 2013		1,699,660			1,699,660			680			3,400,000
Jan. 11, 2013		1,449,710			1,449,710			580			2,900,000
Feb. 5, 2013		1,349,730			1,349,730			540			2,700,000
Feb. 22, 2013		—			—			3,943			3,943
Mar. 6, 2013		—			—			11,802			11,802
Mar. 6, 2013		—			—			277			277
		4,499,100			4,499,100			17,822			9,016,022
Subsequent cash distribution
Mar. 7, 2013		(1,126,037	)		(1,126,037	)		(451	)		(2,252,525	)
Mar. 8, 2013		(9,568,369	)		(9,568,369	)		(3,828	)		(19,140,566	)
		(10,694,406	)		(10,694,406	)		(4,279	)		(21,393,091	)
Non-cash contribution - vend in
Feb. 22, 2013		9,856,843			9,856,843			—			19,713,686
Mar. 6, 2013		29,500,000			29,500,000			—			59,000,000
Mar. 7, 2013		693,787			693,787			—			1,387,574
		40,050,630			40,050,630			—			80,101,260
Balance - End of year	$	51,571,780		$	51,571,780		$	20,631		$	103,164,191

¹  On February 24, 2013, Samsung Renewable Energy Inc. transferred its ownership interest to SRE SKW LP Holdings LP at fair value, which approximates net book value.

²  On October 2, 2013, Pattern South Kent LP Holdings LP, in a series of transactions, transferred its ownership interest in South Kent Wind LP to Pattern Canada Operations Holdings ULC at fair value, which approximates net book value.

	2012
	SRE SKW LP Holdings LP1		Pattern Canada Operations Holdings ULC2		South Kent Wind GP Inc.		Total
Balance - Beginning of year	$	11,207,758	$	11,207,758	$	4,484	$	22,420,000
Subsequent contributions on
May 4, 2012		3,459,308		3,459,308		1,384		6,920,000
August 31, 2012		1,809,638		1,809,638		724		3,620,000
November 20, 2012		439,912		439,912		176		880,000
November 28, 2012		799,840		799,840		320		1,600,000
		6,508,698		6,508,698		2,604		13,020,000
Balance - End of year	$	17,716,456	$	17,716,456	$	7,088	$	35,440,000

S-19

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

Pursuant to an agreement dated February 19, 2013 between the Partnership, Samsung, PRHC and certain of their respective affiliates, certain project development costs in the amount of $19,713,686 incurred by Pattern were contributed to the Partnership. In order to maintain the equal ownership within the Partnership, Samsung acquired an additional interest in the Partnership for consideration payable to PRHC in cash and through exchange of ownership interest in another partnership entity related to both Samsung and PRHC. This transaction has no impact on the Partnership.

Pursuant to a series of Assignment and Assumption Agreements dated March 6, 2013 between and/or among Samsung, PRHC, the Partnership, and various affiliates of Samsung and PRHC, a construction deposit of $59,000,000 was placed with an affiliate of Siemens AG by Samsung and Pattern were contributed to the Partnership in accordance with a Memorandum of Understanding (MOU) signed on October 30, 2012 on behalf of the Partnership.

Pursuant to a series of Assignment and Assumption Agreements dated March 6, 2013 between and/or among Samsung, PRHC, the Partnership, and various affiliates of Samsung and PRHC, certain project development costs, which were not part of the previous contribution on February 19, 2013, in the amount of $1,387,574 incurred by Pattern were contributed to the Partnership. Afterward, Samsung acquired additional interest in the Partnership for a cash consideration payable to an affiliate of PRHC. This transaction has no impact on the Partnership.

Prior to financial close, Korea Electric Power Corporation (KEPCO), another party of Korean Consortium of the Green Energy Investment Agreement, is entitled to participate as an equity investor in the Project, where the purchase price shall be equal to the proportionate share of the Project’s fair market value. The interest of the Partnership to be held by KEPCO shall not be greater than 20%. KEPCO’s entitlement to participate in the Project shall expire on achieving financial close of the project financing for construction of the Project. On February 14, 2013, KEPCO abandoned its entitlement to participate in the Project by signing an amending agreement.

11 Asset retirement obligation

The Partnership’s asset retirement obligation represents the estimated cost of decommissioning the turbines, removing above-ground installations and restoring the sites at a date that is 20 years from the commencement of commercial operations.

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation:

	December 31,
	2013		2012
Asset retirement obligation, beginning balance	$	—	$	—
Additions during the year		5,833,484		—
Accretion expense		—		—
Asset retirement obligation, end of year	$	5,833,484	$	—

S-20

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

12 Derivatives

On March 14, 2013, the Partnership entered into interest rate swaps to manage exposure to interest rate risk on its long-term debt. The interest rate swaps are undesignated derivatives that are used to mitigate exposure to variable interest rate debt by exchanging variable interest rate payments for fixed rate payments of 5.54%.

The following table presents the amounts that are recorded in the Partnership’s statement of financial position as of December 31, 2013:

Undesignated derivative instruments classified as assets (liabilities)

					As of December 31, 2013					For the period ended
					Fair market value					Gain recognized		Gain recognized
Derivative type	Quantity		Maturity date		Current portion			Non-current portion		into earnings		into OCI
Interest rate swaps		13		March 31, 2032	$	(7,814,992	)	$	26,757,264	$	18,942,272	$	—

13 Fair value measurement

The Partnership’s fair value measurements incorporate various factors, including the credit standing and performance risk of the counterparties, the applicable exit market, and specific risks inherent in the instrument. Non-performance and credit risk adjustments on risk management instruments are based on current market inputs when available, such as credit default swap spreads. When such information is not available, internal models are used.

Assets and liabilities recorded at fair value in the financial statements are categorized based on the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to valuation of these assets or liabilities are as follows:

Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities and which reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

Short-term financial instruments consist principally of cash and cash equivalents, restricted cash, accounts payable, current derivative liability and other accrued liabilities. Based on the nature and short maturity of these instruments their fair value is approximated using carrying cost and they are presented in the financial statements at carrying cost.

Long-term debt is presented on the statement of financial position at amortized cost. The fair value of variable interest rate long-term debt is approximated by its carrying cost.

S-21

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

Derivatives are presented in the financial statements at fair value. The interest rate swaps were valued by discounting the net cash flows using the forward CDOR curve with the valuations adjusted by the counterparties’ credit default swap rate.

The following table presents the fair values according to each defined level.

Financial assets and liabilities measured on a recurring basis:

	Level 1		Level 2		Level 3
December 31, 2013
Interest rate swaps	$	—	$	18,942,272	$	—
December 31, 2012
Interest rate swaps	$	—	$	—	$	—

14 Commitments and contingencies

Power purchase agreement

The Partnership entered into a PPA with the OPA on August 2, 2011. The contract capacity of the PPA is defined as 270 MW and the term of the PPA is 20 years from the COD. Under the PPA, the electrical output

from the Project is sold at an electricity price equal to $135 per MWh (on the base date as at September 30, 2009), with 80% of the price fixed and 20% escalating at the Consumer Price Index. The Partnership obtained NTP under the PPA on January 7, 2013. The Partnership has provided to the OPA initial security of $20 per kW of contract capacity. In addition, the Partnership will deliver to the OPA the additional amount of incremental NTP security defined as $10 per kW of contract capacity after receiving the NTP. Both initial and incremental security will be returned to the Partnership after the COD. As at December 31, 2013, the Partnership provided a letter of guarantee amounting to $8,100,000 (2012—$5,400,000) to the OPA, as the initial and incremental security agreed within the PPA. Korea Exchange Bank of Canada issued the letter of guarantee due on July 31, 2014 for the Partnership, based on a restricted term deposit of $8,100,000 (2012 - $5,400,000).

On January 29, 2013 and August 22, 2013, the Partnership amended the PPA by way of an amending agreement with the OPA in connection with announced changes in the market rules governing the dispatch of certain intermittent generators, including those connected to the IESO-controlled grid. Among other provisions, the amendment will limit the amount of economic curtailment to which the Project is subject.

Contingent payment under APA

Per certain Asset Purchase Agreements between the GP, in its capacity as general partner and on behalf of the Partnership, and Northland Power Inc., dated March 4, 2011, and between the GP, in its capacity as general partner of the Partnership, and Suncor Energy Products Inc., dated March 22, 2011, the Partnership is liable to pay $675,000 and $389,600, respectively, once the Project reaches commercial operation under the PPA.

Community Fund Agreement

On April 17, 2013, the GP, in its capacity as general partner and on behalf of the Partnership, entered into a South Kent Wind Community Fund Agreement with Chatham-Kent Community Foundation, in which the

S-22

South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

Partnership committed to twenty annual contributions of $500,000 plus an initial contribution of $1,000,000 million. In April 2013, the initial $1,000,000 was paid on close of construction financing and recorded as construction-in-progress. The remaining $10,000,000 was recorded as a liability.

Operational Incentive Agreement

On March 8, 2013, an Operational Incentive Agreement was entered into between Samsung, an affiliate of PRHC and Siemens Canada Limited to define operational objectives and the terms and conditions upon which the Partnership may pay operational incentive payments to Siemens for achieving one or more of such operational objectives under the turbine supply agreements of certain projects under development by Samsung and affiliates of PRHC, including the Project. Siemens earned an initial payment of $1,078,996 for having satisfied a Peak Capacity Objective defined under the agreement.

The operational incentive payment shall not exceed any of the applicable maximums of (a) $20 per kW of the agreed de-rated capacity of wind turbines purchased under the TSA for the Project, and (b) an aggregate of $15,000,000 under all TSAs for all projects subject to the Operational Incentive Agreement, including the Project, and the South Kent, K2, and Armow wind projects.

Land Lease Agreement

The Partnership has acquired various lease option agreements with landowners through the APAs, and subsequently the Partnership exercised most of the options to execute lease agreements with landowners during the year.

The lease payment including amortization of lease option in the prior year was capitalized to Construction-in-progress and deferred development costs. The capitalized lease payments and amortization of land options are $713,605 and $177,184 for the years ended December 31, 2013 and 2012, respectively.

The future minimum payments related to these leases as of December 31, 2013 are as follows:

2014	$	1,017,943
2015		1,222,133
2016		1,295,059
2017		1,302,068
2018		1,312,842
Thereafter		39,463,763
Total	$	45,613,807

Other commitments

The Partnership has entered into an agreement to purchase turbine related consumable supplies, components, materials, equipment and items required for the Project. The purchase commitment outstanding for these items at December 31, 2013 is $50,266,877.

The Partnership also has other project related contract, and the contract commitment outstanding at December 31, 2013 is $23,967,910.

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South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

15 Related party transactions

The Partnership is controlled by the GP, which is jointly controlled by Samsung and Pattern in accordance with the terms of the Shareholder Agreement. Certain terms of the Samsung Pattern Joint Venture Wind Development Agreement, entered into between Samsung and an affiliate of PRHC on July 27, 2010, directed the responsibilities of Samsung and PRHC during the development of the Project.

The following transactions were carried out with related parties:

a) Management, Operation, and Maintenance Agreement (MOMA)

On March 8, 2013, the Partnership entered into MOMA with Pattern Operators Canada ULC, which is 100% owned by an affiliate of Pattern to operate and manage the maintenance of the wind plant and to perform certain other services pertaining to the wind plant in accordance with the terms and conditions set in the MOMA.

The fixed annual fee for the service is $855,000 pro-rated for the period from March 8, 2013 until the COD and thereafter the annual fee will be increased to $1,425,000 until the end of the term (20 years from the COD). The Partnership paid $627,252 during the year, which is capitalized and recorded to construction-in-progress in the statement of financial position.

b) Engineering Procurement and Construction Contract (EPC Contract)

On March 8, 2013, the Partnership entered into an EPC contract with SRE SKW EPC LP, which is 100% owned by Samsung, to build the balance of plant. $184,067,045 has been invoiced to the Partnership as of December 31, 2013, which was capitalized and recorded in construction-in-progress in the statements of financial position.

c) Project Administration Agreement (PAA)

On March 8, 2013, the Partnership entered into the PAA with SRE Wind PA LP (PA), which is 100% owned by Samsung to supply project administrative services.

The fixed annual fee for the service is $350,000 retroactively pro-rated for the period from June 15, 2012 until the COD and thereafter the annual fee will be increased to $500,000. The Partnership paid $555,588 during the year, which is recorded in the statement of operations and comprehensive income.

d) Deferred development costs transferred to the Project by Samsung and PRHC (note 10)

Siemens deposits paid and certain development cost incurred by Samsung and an affiliate of PRHC were transferred to the Partnership at carrying value in March 2013.

	Samsung		PRHC		Total
Siemens deposit	$	29,500,000	$	29,500,000	$	59,000,000
Development costs		—		20,950,417		20,950,417
	$	29,500,000	$	50,450,417	$	79,950,417

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South Kent Wind LP

Notes to Financial Statements

December 31, 2013

(expressed in Canadian dollars)

e) The Partnership recorded the following balances and transactions with related parties:

	2013		2012
Related party payable	$	42,811,950	$	—
Deferred development costs transferred	$	79,450,417	$	—

16 Subsequent events

On January 26, 2014, the Environmental Review Tribunal dismissed a challenge to the Project modifying the position and rated capacity of two turbines.

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