Form S-1

(Address, including zip code, and telephone number, including area code, of the registrant’s principal executive offices)

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

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 definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

This registration statement contains two forms of prospectus: one to be used in connection with the offering of the securities described herein in the United States, which we refer to as the “U.S. Prospectus,” and one to be used in connection with the offering of such securities in Canada, which we refer to as the “Canadian Prospectus.” The U.S. Prospectus and the Canadian Prospectus are identical except for the cover page, the table of contents and the back page, and except that the Canadian Prospectus includes pages 163 through 165, a “Certificate of the Company and the Promoter” and a “Certificate of the Canadian Underwriters.” The form of the U.S. Prospectus is included herein and is followed by the alternate and additional pages to be used in the Canadian Prospectus. Each of the alternate pages for the Canadian Prospectus included herein is labeled “Alternate Page for Canadian Prospectus.” Each of the additional pages for the Canadian Prospectus included herein is labeled “Additional Page for Canadian Prospectus.”

The information in this prospectus is not complete and may be changed. Neither we nor the selling shareholder may sell these securities until this registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and neither we nor the selling shareholder are soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

This is Pattern Energy Group Inc.’s initial public offering. We are selling shares of our Class A common stock.

We expect the public offering price to be between $ and $ per Class A share. Currently, no public market exists for the shares.

We are an “emerging growth company” as defined in Section 2(a)(19) of the U.S. Securities Act of 1933, as amended, and, as such, are allowed to provide in this prospectus more limited disclosures than an issuer that would not so qualify. In addition, for so long as we remain an emerging growth company, we will qualify for certain limited exceptions from investor protection laws such as the Sarbanes-Oxley Act of 2002 and the Investor Protection and Securities Reform Act of 2010, subject to the disclosure requirements under Canadian securities laws. Please read “Risk Factors” and “Business Summary—Implications of Being an Emerging Growth Company.”

Investing in our Class A common stock involves a high degree of risk. See “Risk Factors” beginning on page 25 of this prospectus for a discussion of certain risks that you should consider before investing.

The underwriters may also purchase up to an additional shares of our Class A common stock from the selling shareholder named herein at the public offering price, less the underwriters’ commissions, within 30 days from the closing date of this offering to cover overallotments, if any. We will not receive any proceeds from the exercise of the underwriters’ overallotment option.

The underwriters expect to deliver the shares of Class A common stock to purchasers on , 2013.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

A copy of this preliminary prospectus has been filed with the securities regulatory authorities in each of the provinces and territories of Canada but has not yet become final for the purpose of the sale of securities. Information contained in this preliminary prospectus may not be complete and may have to be amended. The securities may not be sold until a receipt for the prospectus is obtained from the securities regulatory authorities.

This prospectus has been filed under procedures in each of the provinces and territories of Canada that permit certain information about these securities to be determined after the prospectus has become final and that permit the omission of that information from this prospectus. The procedures require the delivery to purchasers of a supplemented PREP prospectus containing the omitted information within a specified period of time after agreeing to purchase any of these securities. All of the information contained in the supplemented PREP prospectus that is not contained in this base PREP prospectus will be incorporated by reference into this base PREP prospectus as of the date of the supplemented PREP prospectus.

No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise. This preliminary prospectus constitutes a public offering of these securities only in those jurisdictions where they may be lawfully offered for sale and only by persons permitted to sell these securities.

We have filed a registration statement on Form S-1 with the United States Securities and Exchange Commission under the United States Securities Act of 1933, as amended, with respect to these securities.

This prospectus qualifies the distribution of an aggregate of Class A common shares of Pattern Energy Group Inc., consisting of a new issue by us of Class A common shares. We expect the public offering price to be between US$ and US$ per Class A share.

The Class A common shares are being offered for sale concurrently in Canada under this prospectus and in the United States under a registration statement on Form S-1 filed with the United States Securities and Exchange Commission. Our Class A common shares are being offered in Canada by BMO Nesbitt Burns Inc., RBC Dominion Securities Inc., Morgan Stanley Canada Limited, and , or the “Canadian underwriters,” and in the United States by BMO Capital Markets Corp., RBC Capital Markets, LLC and Morgan Stanley & Co. LLC and , together with the Canadian underwriters, the “underwriters.”

There is currently no market through which our Class A common shares may be sold and purchasers may not be able to resell Class A common shares purchased under this prospectus. This may affect the pricing of our Class A common shares in the secondary market, the transparency and availability of trading prices, the liquidity of the securities and the extent of issuer regulation. See “Risk Factors”

An investment in our Class A common shares involves a high degree of risk. See “Risk Factors” beginning on page 25 of this prospectus for a discussion of certain risks that you should consider before investing.

The Canadian underwriters, as principals, conditionally offer the Class A common shares qualified under this prospectus, subject to prior sale, if, as and when issued by us and accepted by the Canadian underwriters in accordance with the conditions contained in the underwriting agreement referred to under “Underwriting” and subject to the approval of certain legal matters on our behalf by Blake, Cassels & Graydon LLP, as to matters of Canadian law, and Latham & Watkins LLP, as to matters of U.S. law, and on behalf of the underwriters by Torys LLP, as to matters of Canadian law, and Vinson & Elkins L.L.P., as to matters of U.S. law.

Certain affiliates of BMO Nesbitt Burns Inc., RBC Dominion Securities Inc. and Morgan Stanley Canada Limited act as agents and/or are lenders, as applicable, under our revolving credit facility (as defined herein). Accordingly, we may be considered a “connected issuer” of BMO Nesbitt Burns Inc., RBC Dominion Securities Inc. and Morgan Stanley Canada Limited within the meaning of applicable Canadian securities laws. See “Description of Certain Financing Arrangements—Revolving Credit Facility” and “Underwriting.”

In connection with this offering, the underwriters may, subject to applicable laws, overallot or effect transactions that stabilize, maintain or otherwise affect the market price of our Class A common shares at levels other than those which otherwise might prevail on the open market. Such transactions, if commenced, may be discontinued at any time. See “Underwriting.” The selling shareholder has granted an overallotment option to the underwriters to cover overallotments, if any. We will not receive any proceeds from the exercise of the underwriters’ overallotment option. See “Principal and Selling Shareholders” and “Use of Proceeds.” The underwriters may offer our Class A common shares at a lower price than stated above. See “Underwriting.”

Subscriptions will be received subject to rejection or allotment in whole or in part and the underwriters reserve the right to close the subscription books at any time without notice. A book entry only certificate representing the Class A common shares to be issued or sold in this offering will be issued in registered form to CDS Clearing and Depository Services Inc., or “CDS,” and deposited with CDS on the closing date of this offering which is expected to occur on or about , 2013 or such later date as we and the underwriters may agree, but in any event not later than , 2013. A purchaser of our Class A common shares in Canada will receive only a customer confirmation from a registered dealer that is a participant in CDS through which our Class A common shares are purchased, unless such purchaser requests from us the issuance of a certificate evidencing such Class A common shares.

Projects in Operation or Under Construction South Kent Location: Ontario, Canada Net MW: 135 MW Commercial Operations: Q2 2014 Hatchet Ridge Location: California, U.S. Net Capacity: 101 MW Commercial Operations: Q4 2010 El Arrayán Location: Ovalle, Chile Net Capacity: 35 MW Commercial Operations: Q2 2014 Gulf Wind (60%) Location: Texas, U.S. Net Capacity: 170 MW Commercial Operations: Q3 2009 Santa Isabel Location: Santa Isabel, Puerto Rico Net Capacity: 101 MW Commercial Operations: Q4 2012 St. Joseph Location: Manitoba, Canada Net Capacity: 138 MW Commercial Operations: Q2 2011 Spring Valley Location: Nevada, U.S. Net Capacity: 152 MW Commercial Operations: Q3 2012 Ocotillo Location: Ocotillo, California Net Capacity: 265 MW Commercial Operations: Q4 2012 In Operation Under Construction

Subscriptions will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without notice. We expect that delivery of our Class A shares will be made against payment therefor on or about the date specified on the cover page of this prospectus, which will be the business day following the date of pricing of our Class A shares (such settlement code being herein referred to as “T + ”). Pursuant to SEC Rule 15c6-1 under the Exchange Act, trades in the secondary market generally are required to settle in three business days, unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade our Class A shares on the date of pricing or the next succeeding business day will be required, by virtue of the fact that our Class A shares initially will settle T + , to specify an alternate settlement cycle at the time of any such trade to prevent a failed settlement and should consult their own advisor.

We have not authorized anyone to provide you with any information other than that contained in this prospectus or in any free writing prospectuses (in the United States) we have prepared. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. This prospectus is an offer to sell only the Class A common shares offered hereby, but only under the circumstances and in jurisdictions where it is lawful to do so. The information in this document may only be accurate on the date of this document.

Through and including (the 25th day after the date of this prospectus), under U.S. securities law, all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

We are a holding company with U.S. operating subsidiaries that are “public utilities” (as defined in the Federal Power Act, or “FPA”) and, therefore, subject to the jurisdiction of the U.S. Federal Energy Regulatory Commission, or “FERC,” under the FPA. As a result, the FPA places certain restrictions and requirements on the transfer of an amount of our voting securities sufficient to convey direct or indirect control over us. See “Risk Factors—Risks Related to this Offering and Ownership of our Class A Shares—As a result of the FPA and FERC’s regulations in respect of transfers of control, absent prior authorization by FERC, neither we nor PEG LP 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 obtained the industry, market and competitive position data used throughout this prospectus from our own internal estimates as well as from industry publications and research, surveys and studies conducted by third parties, including the Global Wind Energy Council, the World Meteorological Organization, North American Electric Reliability Corporation, National Energy Technology Laboratory, the U.S. Department of Energy, the U.S. Energy Information Administration, the Federal Energy Regulatory Commission, the Electric Reliability Council of Texas, the Public Utility Commission of Texas, the Centre for Energy, Natural Resources Canada, Ontario Power Generation, Ontario Power Authority, the Government of Manitoba, the Chilean Ministry of Energy and Puerto Rico Electric Power Authority. Industry publications, studies and surveys generally state that they have been obtained from sources believed to be reliable, although they do not guarantee the accuracy or completeness of such information. While we believe our internal company research is reliable and the market definitions are appropriate, neither such research nor these definitions have been verified by any independent source. Estimates of historical growth rates in the markets where we operate are not necessarily indicative of future growth rates in such markets.

This prospectus includes trademarks, such as the Pattern name and the Pattern logo, which are protected under applicable intellectual property laws and are our property and/or the property of our subsidiaries. This prospectus also contains trademarks, service marks, copyrights and trade names of other companies, which are the property of their respective owners. We do not intend our use or display of other companies’ trademarks, service marks, copyrights or trade names to imply a relationship with, or endorsement or sponsorship of us by, any other companies. Solely for convenience, our trademarks and tradenames referred to in this prospectus may

appear without the ® or ™ symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks and tradenames. We expect to enter into an agreement with PEG LP under which PEG LP will license us the name “Pattern” and the Pattern logo and also grant us a right to acquire the name and logo, subject to our granting PEG LP a license to use the name “Pattern” and the Pattern logo after we acquire it.

In this prospectus, references to “C$” and “Canadian dollars” are to the lawful currency of Canada and references to “$”, “US$” and “U.S. dollars” are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars, unless otherwise stated.

Our predecessor’s historical financial statements that are included elsewhere in this prospectus are presented in U.S. dollars. The following chart sets forth for each of 2010, 2011 and 2012, and each completed month to date during 2013, the high, low, period average and period end noon buying rates in the City of New York for cable transfers of Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York expressed as Canadian dollars per US$1.00.

The noon buying rate in Canadian dollars on August 2, 2013 was US$1.00 = C$1.0379.

The above rates differ from the actual rates used in our predecessor’s historical financial statements and the calculation of cash available for distribution and dividends we may declare and pay, if any, described elsewhere in this prospectus. Our inclusion of these exchange rates is not meant to suggest that the U.S. dollar amounts actually represent such Canadian dollar amounts or that such amounts could have been converted into Canadian dollars at any particular rate or at all.

For information on the impact of fluctuations in exchange rates on our operations, see “Risk Factors—Risks Related to Our Projects—Currency exchange rate fluctuations may have an impact on our financial results and condition” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk—Foreign Currency Risk.”

This prospectus contains references to Adjusted EBITDA, cash available for distribution before principal payments and cash available for distribution, which are not measures under generally accepted accounting principles in the United States, or “U.S. GAAP,” and, therefore, may differ from definitions of these measures used by other companies in our industry. We disclose Adjusted EBITDA, cash available for distribution before principal payments and cash available for distribution because we believe that these measures may assist investors in assessing our financial performance and the anticipated cash flow from our projects. None of these measures should be considered the sole measure of our performance and should not be considered in isolation from, or as a substitute for, the financial statements included elsewhere in this prospectus prepared in accordance with U.S. GAAP. For further discussion of the limitations of these non-U.S. GAAP measures and the reconciliations of net income to Adjusted EBITDA and net cash provided by (used in) operating activities to each of cash available for distribution before principal payments and cash available for distribution, see footnotes 2 and 3 to the table under the heading “Summary Historical and Pro Forma Financial Data” elsewhere in this prospectus.

BUSINESS SUMMARY

This summary highlights information contained elsewhere in this prospectus. It does not contain all the information you need to consider in making your investment decision. You should read this entire prospectus carefully and should consider, among other things, the matters set forth under “Risk Factors,” “Selected Historical Financial Data,” “Unaudited Pro Forma Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our and our predecessor’s financial statements and related notes thereto appearing elsewhere in this prospectus before making your investment decision. Unless the context provides otherwise, references herein to (i) “we,” “our,” “us,” “our company” and “Pattern” refer to Pattern Energy Group Inc., a Delaware corporation, together with its consolidated subsidiaries after giving effect to the Contribution Transactions and (ii) “PEG LP” refers to Pattern Energy Group LP and its subsidiaries. On or immediately prior to the completion of this offering, PEG LP will contribute to Pattern Energy Group Inc. all or a portion of its ownership interests in the entities that, directly or indirectly, own or lease and operate certain wind power projects, which we refer to as the “Contribution Transactions.” See “Structure and Formation of Our Company—The Contribution Transactions” and “Certain Relationships and Related Party Transactions.” The information contained in this prospectus assumes (A) the Contribution Transactions have been consummated, (B) the underwriters have not exercised their overallotment option and (C) an initial public offering price of $ per Class A share, which is the midpoint of the range set forth on the cover page of this prospectus. For an explanation of certain terms used in this prospectus see “Meaning of Certain References.” For recent and historical exchange rates between Canadian dollars and U.S. dollars, see “Currency and Exchange Rate Information.”

Our Business

We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued growth of our business. We own interests in eight 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 1,041 MW, consisting of six operating projects and two construction projects. We expect our two construction projects will commence commercial operations prior to the end of the second 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-five 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 19 years.

Upon completion of this offering, we will have two classes of authorized common stock outstanding, Class A shares and Class B shares. The rights of the holders of our Class A and Class B shares will be identical other than in respect of dividends and the conversion rights of our Class B shares. Upon the later of December 31, 2014 and the date on which our South Kent project has achieved commercial operations, which we refer to as the “Conversion Event,” all of our outstanding Class B shares will automatically convert, on a one-for-one basis, into Class A shares. Our Class B shares, all of which will be held by PEG LP and members of management, will have no rights to dividends. We are using a dual-class share structure to mitigate our Class A shareholders’ risk with respect to construction of our South Kent project. See “Description of Capital Stock.”

Based on the related assumptions included in “Cash Dividend Policy—Forecasted Cash Available for Distribution” and “—Forecast Limitations, Assumptions and Other Considerations,” we forecast that we will generate cash available for distribution and Adjusted EBITDA of $55.4 million and $217.7 million, respectively, for the year ending December 31, 2014. Additionally, to illustrate the financial effect of a fully operational project portfolio, our forecast also indicates that if our construction projects (South Kent and El Arrayán) generated revenue and cash flow throughout the year ending December 31, 2014, as opposed to only during a

portion of the year (as we currently expect), our forecasted cash available for distribution would increase from $55.4 million to $80.2 million and our forecasted Adjusted EBITDA would increase from $217.7 million to $238.2 million. We refer to these illustrative forecasted amounts as our “run-rate cash available for distribution” and our “run-rate Adjusted EBITDA,” respectively. The assumptions and estimates underlying these forecasts are inherently uncertain and our future operating results are subject to a wide variety of risks and uncertainties, any one of which could cause our actual results to differ materially from those forecasted. Prospective investors should read “Cash Dividend Policy,” including our financial forecast and related assumptions, in its entirety and are cautioned not to place undue reliance on our forecast.

The table below summarizes our projected cash available for distribution per Class A share for the year ending December 31, 2014 based on our 2014 and run-rate forecasts, as well as other related information:


(in millions, except project and per share data)	Forecast for Year Ending December 31, 2014			Run-rate
	(unaudited)
Assumed operational projects throughout period indicated		6			8
Cash available for distribution⁽¹⁾	$	55.4		$	80.2
Class A shares						⁽²⁾

Cash available for distribution per Class A Share	$			$		⁽²⁾

Annual dividend per Class A share, based on initial dividend level	$			$
Payout ratio⁽³⁾			%			%⁽²⁾

Adjusted EBITDA⁽¹⁾	$	217.7		$	238.2

(1)	For a reconciliation of these forecasted non-U.S. GAAP metrics to their closest U.S. GAAP measure, see “Cash Dividend Policy—Forecasted Cash Available for Distribution” elsewhere in this prospectus.

(2)	Assumes the Conversion Event has occurred.

(3)	Reflects forecasted annual dividend per Class A share as a percentage of forecasted cash available for distribution per Class A share.

PEG LP has granted us preferential rights to acquire projects that it owns and chooses to sell. As a result we will have preferential purchase rights in respect of various projects owned by PEG LP, including, among others, 746 MW of PEG LP-owned capacity, or the “Initial ROFO Projects,” which are predominantly operational or construction ready. See the table under “—Our Relationship with PEG LP” for more information about the Initial ROFO Projects. Based on our run-rate cash available for distribution and our initial quarterly dividend level, we believe that we will generate excess cash flow that we can use, together with our initial cash on hand and the proceeds of any potential future debt or equity issuances, to invest in accretive project acquisition opportunities, including the Initial ROFO Projects. Considering our preferential rights to acquire the Initial ROFO Projects, we have established a three-year targeted annual growth rate in our cash available for distribution per Class A share of 8% to 10%.

Our Core Values and Financial Objectives

Our financial objectives, which we believe will maximize long-term value for our shareholders, 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 Management Team

The executive officers who make up our management team have on average over 20 years of experience in all aspects of the independent power industry, including development, commercial contracting, finance, construction, operations and management, and are dedicated to protecting the long-term value of our projects. Almost all of the members of our and PEG LP’s management teams have worked together since 2002 and have a proven track record of successfully identifying new opportunities, investing, constructing projects and operating energy assets during periods of both favourable and challenging economic conditions. While working together at PEG LP 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 32% from 2003 to 2014, measured by cumulative wind MW installed), several independent transmission projects and other conventional power assets. Since the formation of PEG LP in 2009, the PEG LP management team has acquired and developed the operational and in-construction wind power projects that will comprise our owned capacity of 1,041 MW upon completion of the Contribution Transactions, representing a CAGR of 42%, and a more than 3,000 MW portfolio of development assets. We believe our management team, along with our talented staff, as well as the management team and staff at PEG LP, provide our company with the depth of experience and breadth of skills to meet our financial objectives and successfully grow our business both domestically and internationally. In addition, we believe we are among the leaders in our industry in areas such as environmental mitigation, financing and commercial management, and we have built a team of highly skilled professionals dedicated to delivering high-quality, well-structured operating power projects.

Our Projects

Upon completion of this offering, we will own interests in eight wind power projects, consisting of six operating projects and two construction projects. The following table provides an overview of our projects:

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

PPA

100%

Pacific Gas & Electric

BBB/A3

2025

St. Joseph

Manitoba

Q1 2010

Q2 2011

138

PPA

100%

Manitoba Hydro

AA/Aa1⁽⁸⁾

2039

Spring Valley

Nevada

Q3 2011

Q3 2012

152

PPA

100%

NV Energy

BBB-/Baa2

2032

Santa Isabel

Puerto Rico

Q4 2011

Q4 2012

101

PPA

100%

Puerto Rico Electric Power Authority

BBB/Baa3

2037

Ocotillo⁽⁹⁾

California

Q3 2012

Q4 2012

223

PPA

100%

San Diego Gas & Electric

A/A2

2033

Q3 2013

PPA

100%

San Diego Gas & Electric

A/A2

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

Hedge⁽¹¹⁾

~75%

Minera Los Pelambres

2034

385

171

1,425

1,041

(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 prospectus. See “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 immediately following the Contribution Transactions.

(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 the date of this prospectus.

(7)	Represents a 10-year fixed-for-floating swap. See “Business—Operating Projects—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 “Business—Construction Projects—El Arrayán.”

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; long-term contracts for our power sale, interconnection and real estate rights; fixed-price, construction contracts with specified completion dates; all necessary construction and operating permits; a comprehensive operations and maintenance service program; and safety, environmental and community programs.

For additional information regarding each of our projects, see “Business—Our Projects.” Our ability to begin commercial operation of our construction projects and to achieve anticipated power output at our projects is subject to numerous risks and uncertainties as described under “Risk Factors.”

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, 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 and by investing in our key personnel;

•

completing our construction projects on schedule and within budget, by having our highly experienced construction team closely overseeing construction-contractor and turbine-vendor activities, which are subject to fixed-price contracts with guaranteed completion dates;

•

maintaining a prudent capital structure and financial flexibility, by seeking to match our long-term assets with long-term liabilities, limiting exposure to commodity and interest rate risk and ensuring a prudent level of leverage in our business;

•

working closely with our stakeholders, including suppliers, power sale agreement counterparties and the local communities where we are located to best support our projects; and

•

selectively growing our business, by leveraging our management team’s extensive relationships, experience and highly disciplined approach to evaluating and facilitating new business opportunities, including through collaboration with PEG LP and other developers to advance their development pipelines, and by focusing on projects and regions where we believe we can add value.

For more information about our business strategy, see “Business—Our Strategy.”

Our Competitive Strengths

We believe our key competitive strengths include:

•

our high-quality projects, which we believe provide the foundation for the stable long-term cash flows required to operate our business, service our debt and achieve our financial objectives;

•

our strong reputation in the industry, which we believe is derived from our integrity, expertise, solutions-oriented approach and record of success, which attracts talented people and opportunities;

•

our approach to project selection, which aims to deliver superior financial results and minimize long-term operating risks, by employing a highly disciplined, timely and comprehensive analysis of projects using our in-house experts;

•

our relationship with PEG LP, which enhances our ability to operate our projects and provides us with access to a pipeline of acquisition opportunities, including the Initial ROFO Projects (see “—Our Relationship with PEG LP”); and

•

our proven management team, which has extensive experience in all aspects of the independent power business, a demonstrated track record of successfully developing, constructing and operating wind power projects and a history of prudent financial and technological innovation in the power industry.

For more information about our competitive strengths, see “Business—Competitive Strengths.”

Market Opportunity

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 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 PEG LP 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, non-renewable energy projects and transmission projects.

Our Relationship with PEG LP

We were incorporated as a Delaware corporation by PEG LP in October 2012 with the intent that we will own, operate and construct power projects and that PEG LP will focus on its extensive development pipeline. We and PEG LP have agreed that we will transfer PEG LP’s employees to our company, at no cost, once we reach $2.5 billion in total market capitalization, which we believe is a sufficient size to undertake development of future projects. Since it was formed, PEG LP has been very active in developing project opportunities.

Key members of our management team, together with certain other executives at PEG LP and investment funds managed by Riverstone Holdings LLC, or “Riverstone,” formed PEG LP in June 2009. Upon its formation, PEG LP acquired a portfolio of development projects, but did not own any operating or construction projects. In late 2009, PEG LP closed financing for its first construction project, Hatchet Ridge. In 2010, PEG LP acquired the Gulf Wind project, completed construction of the Hatchet Ridge project, commenced construction of the St. Joseph project and formed a joint venture with a subsidiary of Samsung C&T Corporation, or “Samsung,” to develop at least 1,000 MW of wind power projects located in Ontario. Since 2010, PEG LP also successfully completed construction and commenced operation of the St. Joseph, Spring Valley, Santa Isabel and Ocotillo projects and commenced construction of the El Arrayán and South Kent projects. Certain members of PEG LP’s management team who will not be part of our management team, including John Calaway, PEG LP’s Senior Vice President—Wind Development, and George Hardie and Colin Edwards, each a Vice President—Development, intend to continue in their current roles at PEG LP. These individuals have been key contributors to PEG LP’s success and to the more than 3,000 MW portfolio of development assets that includes the Initial ROFO Projects.

We will initially own, acquire and operate projects for which the development risks have been substantially reduced in order to generate stable long-term cash flows, and we expect that PEG LP will invest in and deploy its staff to engage in higher-risk project development activities. At the completion of this offering, PEG LP will hold a retained interest of approximately 27% in Gulf Wind, representing approximately 76 MW of PEG LP-owned capacity, which we refer to as the “PEG LP retained Gulf Wind interest” and interests in development projects with an expected total rated capacity of more than 3,000 MW, including wind power and solar power projects, as well as certain transmission development projects. Five of these development projects, together with the PEG LP retained Gulf Wind interest, constitute the Initial ROFO Projects, and are predominantly operational or construction ready.


						Capacity (MW)
Initial ROFO Projects	Status	Location	Construction Start⁽¹⁾	Commercial Operations⁽²⁾	Contract Type	Rated⁽³⁾		PEG LP- Owned⁽⁴⁾
Gulf Wind	Operational	Texas	2008	2009	Hedge		283		76
Grand Renewable	Construction financing	Ontario	2013	2014	PPA		149		67
Panhandle⁽⁵⁾	Construction financing	Texas	2013	2014	Hedge		318		248
Armow	Construction ready	Ontario	2014	2015	PPA		180		90
K2	Construction ready	Ontario	2014	2015	PPA		270		90
Meikle	Securing final permits	British Columbia	2015	2016	PPA		175		175

							1,375		746

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

(2)	Represents date of actual or anticipated commencement of commercial operations.

(3)

(4)	PEG LP-owned capacity represents the maximum, or rated, electricity generating capacity of the project multiplied by PEG LP’s percentage ownership interest in the distributable cash flow of the project immediately following the Contribution Transactions.

(5)	We expect the first phase of the Panhandle project, representing approximately 170 MW of PEG LP-owned capacity, to close financing before the completion of this offering; documentation for the balance of the project is in an early stage of discussion with financial counterparties.

Our Purchase Rights

To promote our growth strategy, concurrently with the completion of this offering, we will enter into a purchase rights agreement with PEG LP and its equity owners that will provide us with three distinct avenues to grow our business through acquisitions:

•

the right to acquire the PEG LP retained Gulf Wind interest at any time between the first and second anniversary of the completion of this offering at its then current fair market value, which we refer to as our “Gulf Wind Call Right;”

•

a right of first offer with respect to any power project that PEG LP decides to sell, including the Initial ROFO Projects, which we refer to as our “Project Purchase Right;” and

•

a right of first offer with respect to PEG LP itself, or substantially all of its assets, if the equity owners of PEG LP decide to sell PEG LP or substantially all of its assets, which we refer to as our “PEG LP Purchase Right.”

We refer to these rights as our “Purchase Rights.” Our Gulf Wind Call Right will terminate on the second anniversary of the completion of this offering. Our Project Purchase Right and PEG LP Purchase Right will terminate together upon the fifth anniversary of the completion of this offering, but are subject to automatic five-year renewals unless either party dissents at the time of renewal. In addition, PEG LP will have the right to terminate our Project Purchase Right and PEG LP Purchase Right together upon the third occasion (within any five-year initial or renewal term) on which we have elected not to exercise our Project Purchase Right with respect to an operational or construction-ready project and following which PEG LP has sold the project to an unrelated third party.

Although we have no commitments to make any such acquisitions, we consider it reasonably likely that we may have the opportunity to acquire the Initial ROFO Projects under our Purchase Rights at various times within the 18-month period following the completion of this offering. In particular, we have commenced a dialogue with PEG LP in connection with an interest in the Panhandle project, which PEG LP has notified us that it wishes to sell and which we may acquire shortly after the completion of this offering, although we have not yet determined our offer price. For more information about this potential acquisition, the Initial ROFO Projects and our Purchase Rights, see “Certain Relationships and Related Party Transactions—Our Relationship with PEG LP—Our Purchase Rights.”

Shareholder Approval Rights Agreement

We will enter into a shareholder approval rights agreement, or the “Shareholder Agreement,” with PEG LP concurrently with the consummation of this offering. Pursuant to the Shareholder Agreement, for so long as PEG LP beneficially owns at least 33 1/3% of our shares, PEG LP’s consent will be necessary for us to take certain material corporate actions, including: (i) our consolidation with or merger into an unaffiliated entity; (ii) certain acquisitions of stock or assets of a third-party; (iii) our adoption of a plan of liquidation, dissolution or winding up; (iv) certain dispositions of our or our subsidiaries’ assets; (v) the incurrence of indebtedness in excess of a specified amount, (vi) a change in the size of our board of directors (subject to certain exceptions) and (vii) issuing equity securities with preferential rights to our common shares. See “Certain Relationships and Related Party Transactions—Shareholder Agreement.”

Non-Competition Agreement

We will enter into a non-competition agreement, or the “Non-Competition Agreement,” with PEG LP concurrently with the consummation of this offering. Pursuant to the Non-Competition Agreement, PEG LP will

agree 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. In addition, PEG LP will notify us of opportunities to acquire power generation or transmission projects that it wishes to pursue and, should we be interested in acquiring all or a portion of such projects, we may direct PEG LP to forego such opportunities. We may also elect to collaborate with PEG LP to jointly pursue acquisition opportunities from time to time. Riverstone will not be subject to the Non-Competition Agreement.

Management Services Agreement and Shared Management

We intend to grow our assets until we have sufficient size and cash flow to undertake development activities. Until such time, we will contract for certain services pursuant to the terms of a bilateral services agreement with PEG LP, or the “Management Services Agreement,” that we will enter into upon the completion of this offering. However, 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, such event, the “reintegration event,” the employees of PEG LP will become our employees, which we refer to as the “employee reintegration.”

Our project operations and maintenance personnel and executive officers will be solely compensated by us and their employment with PEG LP will terminate. These executives will lead our business functions and rely on support from PEG LP employees for certain administrative functions. PEG LP will retain only those employees whose primary responsibilities relate to project development or legal, financial or other administrative functions. The Management Services Agreement will provide for us and PEG LP to benefit, primarily on a cost-reimbursement basis, from the parties’ respective management and other professional, technical and administrative personnel, all of whom will report to and be managed by our executive officers. In the event that PEG LP is, or substantially all of its assets are, acquired by an unrelated third party, we will have the unilateral right to terminate the Management Services Agreement.

Pursuant to the Management Services Agreement, certain of our executive officers, including our Chief Executive Officer, will also serve as executive officers of PEG LP and devote their time to both our company and PEG LP as is prudent in carrying out their executive responsibilities and fiduciary duties. We refer to our employees who will serve as executive officers of both our company and PEG LP as the “shared PEG executives.” The shared PEG executives will have responsibilities for both us and PEG LP and, as a result, these individuals will not devote all of their time to our business. Under the terms of the Management Services Agreement, PEG LP will be required to reimburse us for an allocation of the compensation paid to such shared PEG executives reflecting the percentage of time spent providing services to PEG LP. For more information on management and management’s relationship with PEG LP, see “Conflicts of Interest and Fiduciary Duties” and “Management.”

Upon employee reintegration, we expect that our principal focus will continue to be owning operational and under construction power projects. However, 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 PEG LP (including services from the reintegrated departments of PEG LP) to the extent required by PEG LP’s remaining development activities and the consideration for such services would continue to be paid primarily on a cost reimbursement basis. See “Certain Relationships and Related Party Transactions—Management Services Agreement and Shared Management” for a further discussion of the Management Services Agreement and the employee reintegration.

The Contribution Transactions

On or immediately prior to the completion of this offering, pursuant to the terms of a contribution agreement between us and PEG LP, which we refer to as the “Contribution Agreement,” we will enter into a series of transactions with PEG LP, or the “Contribution Transactions.” In connection with the Contribution Transactions, PEG LP will contribute to us all of our projects, including the related properties and other assets that will be used in our business, together with liabilities and obligations to which such projects are subject. PEG LP currently holds its interests in these projects through one or more holding companies, the sole purposes of which are to hold such interests or to obtain related financing.

As consideration for the assets contributed to us by PEG LP in the Contribution Transactions, we will pay approximately $ million from the proceeds of this offering to PEG LP and issue to PEG LP of our Class A shares and of our Class B shares. As a result, PEG LP will hold approximately % of our outstanding Class A shares and % of our outstanding Class B shares (or % and %, respectively, if the underwriters exercise their overallotment option in full), representing in the aggregate an approximate % voting interest in our company (or % if the underwriters exercise their overallotment option in full). The remaining % of our outstanding Class B shares will be held by members of our management. Until the Conversion Event, neither PEG LP nor the management holders of our Class B shares will be entitled to receive any dividends on their Class B shares. In connection with the Contribution Transactions, PEG LP also will receive customary resale registration rights with respect to our Class A shares. See “Shares Eligible for Future Sale—Registration Rights Agreement.”

In connection with the Contribution Transactions, we will also assume certain indemnities previously granted by PEG LP 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 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. Following the Contribution Transactions, we will have assumed ITC cash grant indemnity obligations in amounts that are up to the greater of the respective cash grant loans or the amounts of any cash grant subsequently recaptured. Such maximum indemnity amounts are currently estimated to be approximately $116 million, $80 million and $58 million for the Ocotillo, Spring Valley and Santa Isabel projects, respectively. In addition, we will also assume an indemnity that was granted by PEG LP to our Ocotillo project finance lenders in connection with certain legal matters, which is limited to the amount of certain related costs and expenses. See “Risk Factors—We are subject to various indemnity obligations,” “Business—Legal Proceedings” and “Description of Certain Financing Arrangements—Santa Isabel Senior Financing Agreement and —Ocotillo Senior Financing Agreement.”

Riverstone

PEG LP was formed in June 2009 by the executive management team of PEG LP and investment funds managed by Riverstone. Riverstone is an energy and power-focused private equity firm founded in 2000 with approximately $25 billion of equity capital raised across seven investment funds and related coinvestments, including the world’s largest renewable energy fund. Riverstone conducts buyout and growth capital investments in the midstream, exploration & production, oilfield services, power and renewable sectors of the energy industry. With offices in New York, London and Houston, the firm has committed approximately $22.8 billion to 102 investments in North America, Latin America, Europe, Africa and Asia.

Conflicts of Interest and Fiduciary Duties

While we believe our relationship with PEG LP provides us with a significant advantage, it is also a potential source of conflicts of interest. Prior to the completion of this offering, all of our executive officers were employees of PEG LP. In addition, three of our seven directors will not qualify as independent directors under applicable Canadian securities laws and stock exchange rules due to their affiliation with PEG LP. See “Management.” While all of our executive officers will terminate their employment with PEG LP prior to the completion of this offering, pursuant to the terms of the Management Services Agreement, the shared PEG executives will also serve as executive officers of PEG LP and will continue to provide services to PEG LP and, as a result, will have fiduciary or other obligations to PEG LP and its equity owners. None of our officers will receive any compensation paid by PEG LP after the completion of this offering, but some of our executive officers will continue to have economic interests in PEG LP. For example, each of Michael M. Garland, our Chief Executive Officer (and one of our directors), Hunter H. Armistead, our Executive Vice President, Business Development, Daniel M. Elkort, our Executive Vice President and General Counsel, and Dean S. Russell, our Senior Vice President, Engineering and Construction, will continue to have economic interests in PEG LP. In addition, Messrs. Garland and Armistead will continue to serve as directors of, and will therefore have certain fiduciary duties to, PEG LP. As a result of these relationships, conflicts of interest may arise in the future between us (and our shareholders other than PEG LP) and PEG LP (and its owners and affiliates).

The officers and directors of PEG LP have a fiduciary duty to manage its business in a manner beneficial to its owners and, in connection with fulfilling this duty, PEG LP’s ownership and management may compete with us for the time and focus of the shared PEG executives or for employment of other talented individuals, or may develop PEG LP’s business plan in a manner that is incompatible with our objectives, any of which might result in our failure to realize the full benefits of the relationship that we currently contemplate and jeopardize our ability to execute our growth plan. In addition, although we believe that PEG LP will continue to focus its efforts on power project development and not on our core business function of operating and constructing commercially viable power projects, other than during the term of the Non-Competition Agreement, PEG LP will not be restricted from competing with us and we cannot assure you that PEG LP’s business focus will not change over time. See “Certain Relationships and Related Party Transactions—Non-Competition Agreement.” Pursuant to the Shareholder Agreement, for so long as PEG LP beneficially owns at least 33 1/3% of our shares, PEG LP’s consent will be necessary for us to take certain material corporate actions, which could adversely affect our business. See “Certain Relationships and Related Party Transactions—Shareholder Agreement.”

these individuals may be conflicted when advising the conflicts committee or otherwise participating in the negotiation or approval of such transactions on our behalf. The conflicts committee will have the ability to consult with those of our executive officers and operating personnel who do not have economic interests in PEG LP, including Michael J. Lyon, our Chief Financial Officer, and Esben W. Pedersen, our Chief Investment Officer, as well as other external advisors that the conflicts committee deems appropriate, in connection with reviewing a transaction with PEG LP. In addition, in some cases, transactions between our company and PEG LP will be related party transactions for the purposes of Multilateral Instrument 61-101—Protection of Minority Security Holders in Special Transactions, or “MI 61-101,” of the Canadian Securities Administrators. MI 61-101 provides, among other things, that in certain circumstances a transaction between an issuer and a related party of the issuer is subject to formal valuation and minority shareholder approval requirements. See “Conflicts of Interest and Fiduciary Duties.”

Summary Risk Factors

An investment in our shares involves risks. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our shares. This list is not exhaustive. Please read the full discussion of these risks and other risks described under “Risk Factors.”

Risks Related to Our Projects, Acquisition Strategy and Financial Activities

•

Electricity generated from wind energy depends heavily on suitable wind conditions and wind turbines being available for operation. If wind conditions are unfavourable 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.

•

Our cash available for distribution may not be sufficient to pay dividends to shareholders at expected levels or at all.

•

The assumptions underlying the forecast of cash available for distribution that we include in “Cash Dividend Policy” may prove inaccurate and are subject to significant risks and uncertainties, which could cause actual results to differ materially from our forecasted results.

•

We have a limited operating history and our growth may make it difficult for us to manage our projects efficiently.

•

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.

•

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 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 cash flow. Liquidity constraints could impair our ability to execute favourable financial hedges in the future.

•

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

Risks Inherent in an Investment in Our Company

•

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

•

Certain of our executive officers will continue to have economic interests in, and provide services to, PEG LP, which could result in conflicts of interest and have a material adverse effect on our business, financial condition and results of operations.

Implications of Being an Emerging Growth Company

As a company with less than $1.0 billion in revenue during our last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the “JOBS Act,” under the rules and regulations of the U.S. Securities and Exchange Commission, or the “SEC.” An emerging growth company may take advantage of specified reduced reporting in the United States and other burdens that are otherwise applicable generally to public companies. These provisions include:

•

an election to have only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations;

•

an exemption from the auditor attestation requirement in the assessment of the emerging growth company’s internal control over financial reporting;

•

reduced disclosure about the emerging growth company’s executive compensation arrangements; and

•

no requirement for non-binding advisory votes on executive compensation or golden parachute arrangements.

We may take advantage of these provisions for up to five years if we continue to be an emerging growth company. 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. We may choose to take advantage of some but not all of these reduced burdens. We have availed ourself of the exemption from disclosing certain executive compensation information in this prospectus pursuant to Title 1, Section 102 of the JOBS Act. Additionally, we have elected to take advantage of the extended transition period provided in Section 7(a)(2)(B) of the U.S. Securities Act of 1933, as amended, or the “U.S. Securities Act,” for complying with new or revised accounting standards that have different effective dates for public and private companies until the earlier of the date we (i) are no longer an emerging growth company or (ii) affirmatively and irrevocably opt out of the extended transition period provided in U.S. Securities Act Section 7(a)(2)(B). See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” for a further discussion of this exemption.

Canadian securities laws require three years of audited financial statements to be included in this prospectus and, as a result, will not permit us to take advantage of the reduced financial statement requirements permitted under the JOBS Act. In addition, 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 the provisions of the JOBS Act described above, and file our disclosure documents with Canadian securities regulatory authorities. See “Risk Factors—Risks Related to this Offering and Ownership of our Class A Shares—We will be an SEC foreign issuer under Canadian securities laws and, therefore, be exempt from certain requirements of Canadian securities laws applicable to other Canadian reporting issuers.”

THE OFFERING

Common stock offered by us

Class A shares.

Common stock outstanding after this offering

shares.^(x)

Class A common stock to be outstanding after this offering Class B common stock to be outstanding after this offering

Class A shares.

Class B shares. The rights of the holders of our Class A and Class B shares will be identical other than in respect of dividends and the conversion rights of the Class B shares. While each Class A and Class B share will have one vote on all matters submitted to a vote of our shareholders, our Class B shares will have no rights to dividends or distributions (other than upon liquidation). Upon the Conversion Event, all of our outstanding Class B shares will automatically convert, on a one-for-one basis, into Class A shares. See “Description of Capital Stock.”

Conversion Event

Our Amended and Restated Certificate of Incorporation will provide that 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.” For the purposes of our Amended and Restated Certificate of Incorporation, “Commercial Operations” will refer to the date upon which our South Kent project has achieved commercial operations under its power purchase agreement. See “Description of Capital Stock.”

Overallotment option

PEG LP, or the “selling shareholder,” has granted the underwriters an option, exercisable within 30 days following the closing date of this offering, to purchase up to an additional Class A shares at the initial public offering price to cover overallotments, if any. We will not receive any proceeds from the exercise of the underwriters’ overallotment option. See “Use of Proceeds.”

Use of proceeds

We estimate we will receive net proceeds of approximately $ million from this offering, based on an assumed public offering price of $ per Class A share, which is the midpoint of the range set forth on the cover page of this prospectus, and after deducting underwriting commissions and estimated offering expenses payable by us. We intend to use the net proceeds from this offering (i) to provide $ million (i.e., the cash portion) of the consideration to be paid to PEG LP in connection with the Contribution Transactions and (ii) the remainder for working capital and general corporate purposes. See “Use of Proceeds” for additional information. Certain of our executive officers have an economic interest in PEG LP and, as a result, these individuals will have an interest in the proceeds from this offering received by PEG LP in proportion to their respective economic interest in PEG LP. See “Certain Relationships and Related Party Transactions.”

PEG LP retained interest

Dividends

Our ability to pay our initial and subsequent dividends, if any, is subject to various restrictions and other factors. For a detailed discussion of the basis upon which we established our initial quarterly dividend and factors that could affect our ability to pay dividends at that level or at all, see “Cash Dividend Policy.”

U.S. Taxation of Dividends to U.S. Holders and Non-U.S. Holders

The distributions that we will make to our shareholders will be treated as dividends under U.S. tax law only to the extent that they will be paid out of our current or accumulated earnings and profits computed under U.S. tax principles, which we refer to herein as “earnings and profits.” Our earnings and profits, as calculated under U.S. tax principles, may be negative at times due to various deductions, for example, depreciation. If the cash dividends paid to our shareholders exceed our current and accumulated earnings and profits for a taxable year, the excess cash dividends would not be taxable as a dividend but rather be treated as a return of capital for U.S. federal income tax purposes, which would result in a reduction in the adjusted tax basis of our shares to the extent thereof, and any balance in excess of adjusted basis would be treated as a gain for U.S. federal income tax purposes. As a result, U.S. Holders (as defined under “Material U.S. Federal Income Tax Considerations for Holders of Our Class A Common Shares”) may receive cash dividends from us that represent a non-taxable return of capital to the extent thereof (and gain thereafter), although no assurance can be given in this regard. For

Non-U.S. Holders (as defined under “Material U.S. Federal Income Tax Considerations for Holders of Our Class A Common Shares”), cash dividends that are treated as dividends would normally be subject to U.S. federal withholding tax at the rate of 30% (or at a reduced rate under an applicable income tax treaty, such as a 15% rate generally applicable under the income tax treaty between the United States and Canada). However, such U.S. withholding tax may not apply to cash dividends to the extent they are treated as a return of capital or gain with respect to the shares for U.S. federal income tax purposes. In the event there is any excess withholding, a Non-U.S. Holder should be able to obtain a refund of any over-withheld tax by filing the appropriate tax forms.

For more information, see “Material U.S. Federal Income Tax Considerations for Holders of Our Class A Common Shares.”

Canadian Taxation of Dividends to Canadian Resident Shareholders and Non-Canadian Resident Shareholders

Shareholders resident in Canada will generally be required to include in their income any dividends, including any amounts deducted for U.S. withholding tax, if any, received on the shares whether or not treated as dividends under U.S. tax law. Such shareholders may be eligible for a foreign tax credit or deduction in respect of any U.S. withholding tax in computing their Canadian tax liability.

Dividends paid in respect of our shares to shareholders not resident in Canada will not be subject to Canadian withholding tax or, generally, other Canadian income tax.

For more information, see “Material Canadian Federal Income Tax Considerations for Holders of Our Class A Common Shares.”

FERC-Related Purchase Restrictions

As a result of the FPA and FERC’s regulations in respect of transfers of control, consistent with the requirements for blanket authorizations granted under or exemptions from FERC’s regulations, absent prior authorization by FERC, no purchaser in this offering will be permitted to purchase an amount of our Class A shares that would cause such purchaser and its affiliate and associate companies in aggregate to hold 10% or more of our common shares outstanding after this offering. See “Risk Factors—Risks Related to this Offering and Ownership of our Class A Shares—As a result of the FPA and FERC’s regulations in respect of transfers of control, absent prior authorization by FERC, neither we nor PEG LP 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.”

(x)	Includes (i) (a) Class A shares offered by us to the public hereby, (b) Class A shares and Class B shares to be issued to PEG LP in connection with the Contribution Transactions and (c)

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

We were incorporated in October 2012 by PEG LP for the purpose of this offering and do not have historical financial operating results. Therefore, in this prospectus, we present the historical financial statements of our predecessor, which consist of the combined financial statements of a combination of entities and assets currently owned by PEG LP. Throughout this prospectus, we refer to these entities collectively as our “predecessor.” PEG LP will contribute to us the entities and assets that will make up our projects in connection with the Contribution Transactions, which entities and assets are the same as those of our predecessor with the exception of the PEG LP retained Gulf Wind interest.

The following table presents summary historical and pro forma combined financial data of our predecessor as of the dates and for the periods indicated. The summary historical combined financial data as of December 31, 2010, 2011 and 2012 and for the years ended December 31, 2010, 2011 and 2012 have been derived from the audited historical combined financial statements of our predecessor included elsewhere in this prospectus. The summary historical combined financial data as of June 30, 2013 and for the three and six months ended June 30, 2013 and 2012 have been derived from the unaudited historical combined financial statements of our predecessor included elsewhere in this prospectus.

In order to present the financial effect of the Contribution Transactions, the following table presents unaudited pro forma balance sheet data as of June 30, 2013, and statement of operations and other financial and operating data for the six months ended June 30, 2013 and the year ended December 31, 2012, based upon the combination of Pattern Energy Group Inc. and our predecessor’s combined historical financial statements after giving pro forma effect to (i) PEG LP’s retention of the PEG LP retained Gulf Wind interest and (ii) the estimated tax effects of the Contribution Transactions. The pro forma balance sheet, statement of operations and other financial and operating data presented are not necessarily indicative of what our actual results of operations would have been as of the date and for the periods indicated, nor does it purport to represent our future results of operations.

The historical financial statements of our predecessor, from which the summary unaudited pro forma financial data have been derived, are presented in U.S. dollars and have been prepared in accordance with U.S. GAAP, which differ in certain material respects from Canadian GAAP applicable to publicly accountable enterprises (International Financial Reporting Standards as issued by the International Accounting Standards Board, or “IFRS”). For recent and historical exchange rates between Canadian dollars and U.S. dollars, see “Currency and Exchange Rate Information.”

You should read the following table in conjunction with “Structure and Formation of Our Company,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the historical combined financial statements of our predecessor and the notes thereto included elsewhere in this prospectus.


	Predecessor																					Pro Forma Pattern
	Three Months Ended June 30,						Six Months Ended June 30,						Year Ended December 31,									Six Months Ended June 30,			Year Ended December 31,
	2013			2012			2013			2012			2012			2011			2010			2013			2012
	(U.S. dollars in thousands, except MWh sold and $/MWh)
Statement of Operations Data:
Revenue:
Electricity sales	$	47,351		$	23,015		$	92,583		$	49,874		$	101,835		$	108,770		$	24,669		$	92,583		$	101,835
Energy derivative settlements		4,809			5,918			10,217			11,659			19,644			9,512			10,905			10,217			19,644
Unrealized (loss) gain on energy derivative		(5,078	)		(3,995	)		(11,881	)		1,746			(6,951	)		17,577			14,000			(11,881	)		(6,951	)
Related party revenue		263			—			263			—			—			—			—			263			—
Other revenue		11,367			—			11,367			—			—			—			—			11,367			—

Total revenue		58,712			24,938			102,549			63,279			114,528			135,859			49,574			102,549			114,528
Cost of revenue:
Project expenses		14,492			7,910			27,469			15,758			34,843			31,343			18,530			27,469			34,843
Depreciation and accretion		17,998			10,853			40,564			21,736			49,027			39,424			12,951			40,564			49,027

Total cost of revenue		32,490			18,763			68,033			37,494			83,870			70,767			31,481			68,033			83,870

Gross profit		26,222			6,175			34,516			25,785			30,658			65,092			18,093			34,516			30,658
Total operating expenses		2,904			2,861			5,710			5,264			11,629			9,668			10,155			5,710			11,636

Operating income		23,318			3,314			28,806			20,521			19,029			55,424			7,938			28,806			19,022
Total other income (expense)		12,982			(3,665	)		(10,996	)		(11,524	)		(36,002	)		(28,829	)		(1,572	)		(10,996	)		(36,002	)

Net income (loss) before income tax		36,300			(351	)		17,810			8,997			(16,973	)		26,595			6,366			17,810			(16,980	)
Tax (benefit) provision		(7,688	)		224			(7,396	)		1,004			(3,604	)		689			(672	)		676			818

Net income (loss)		43,988			(575	)		25,206			7,993			(13,369	)		25,906			7,038			17,134			(17,798	)
Net (loss) income attributable to noncontrolling interest⁽¹⁾		(359	)		(2,928	)		(3,938	)		1,552			(7,089	)		16,981			2,474			(5,438	)		(8,244	)

Net income (loss) attributable to controlling interest⁽¹⁾	$	44,347		$	2,353		$	29,144		$	6,441		$	(6,280	)	$	8,925		$	4,564		$	22,572		$	(9,554	)

Unaudited pro forma net income (loss) after tax:
Net income (loss) before income tax							$	17,810					$	(16,973	)
Pro forma tax provision								674						818

Pro forma net income (loss)							$	17,136					$	(17,791	)

Other Financial Data:
Adjusted EBITDA⁽²⁾	$	45,965		$	18,352		$	80,404		$	40,683		$	75,248		$	77,258		$	6,899		$	80,404		$	75,241
Cash available for distribution⁽³⁾	$	16,206		$	90		$	30,676		$	10,853		$	17,692		$	18,530		$	(17,830	)	$	29,742		$	16,654
Cash available for distribution before principal payments⁽³⁾	$	31,790		$	13,823		$	52,491		$	28,025		$	45,238		$	40,860		$	(4,089	)	$	51,557		$	44,200
Net cash provided by (used in):
Operating activities	$	33,268		$	11,506		$	41,659		$	24,808		$	35,050		$	46,930		$	(3,011	)	$	41,657		$	35,050
Investing activities	$	124,130		$	(183,743	)	$	63,414		$	(241,439	)	$	(638,953	)	$	(340,977	)	$	(460,207	)	$	63,414		$	(638,953	)
Financing activities	$	(144,111	)	$	124,217		$	(79,772	)	$	217,694		$	573,167		$	331,336		$	472,321		$	(79,770	)	$	573,167
Operating Data:
MWh sold⁽⁴⁾		658,243			429,350			1,261,876			874,331			1,673,413			1,568,022			643,477			1,261,876			1,673,413
Average realized electricity price ($/MWh)⁽⁵⁾	$	79		$	67		$	81		$	70		$	73		$	75		$	55		$	81		$	73


									Pro Forma
	Predecessor								Pattern
	As of June 30,		As of December 31,						As of June 30,
	2013		2012		2011		2010		2013
	(U.S. dollars in thousands)
Balance Sheet Data:
Cash	$	41,774	$	17,573	$	47,672	$	8,928	$	41,775
Construction in progress	$	69,769	$	6,081	$	201,245	$	291,089	$	69,769
Property, plant and equipment , net	$	1,441,319	$	1,668,302	$	784,859	$	500,403	$	1,441,319
Total assets	$	2,010,053	$	2,035,729	$	1,390,426	$	1,058,493	$	1,998,315
Long-term debt	$	1,315,810	$	1,290,570	$	867,548	$	637,964	$	1,315,810
Total liabilities	$	1,445,179	$	1,446,311	$	943,728	$	722,549	$	1,445,622
Total equity before noncontrolling interest	$	491,103	$	514,117	$	362,226	$	255,160	$	450,770
Noncontrolling interest⁽¹⁾	$	73,771	$	75,301	$	84,472	$	80,784	$	101,923
Total equity	$	564,874	$	589,418	$	446,698	$	335,944	$	552,693

(1)

Prior to the completion of this offering, as reflected in the combined historical financial statements of our predecessor, our predecessor and its joint venture partner hold interests in approximately 67% and 33% of the distributable cash flow of Gulf Wind, respectively, together with certain allocated tax items. For more information about the allocation of the distributable cash flow and tax items of Gulf Wind, and their variability over time, see “Description of Certain Financing Arrangements—Gulf Wind Tax Equity Partnership Transaction.” In connection with the Contribution Transactions, PEG LP will retain a 40% portion of the interest in Gulf Wind previously held by our predecessor such that, at the completion of this offering, we, PEG LP and our joint venture partner will hold interests of approximately 40%, 27% and 33%, respectively, of the distributable cash flow of Gulf Wind, together with certain allocated tax items. The summary pro forma financial data presented above reflects the adjustment to noncontrolling interest due to the retention by PEG LP of an approximate 27% interest in Gulf Wind. Gulf Wind is consolidated in the combined historical financial statements of our predecessor and the pro forma financial data included in this prospectus and will continue to be consolidated in our financial statements following the Contribution Transactions.

(2)

Adjusted EBITDA represents 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 for joint venture investments that are accounted for under the equity method. Adjusted EBITDA also excludes the effect of certain mark-to-market adjustments and infrequent items not related to normal or ongoing operations, such as early payment of debt and realized derivative gain or loss from refinancing transactions, and gain or loss related to acquisitions or divestitures. We disclose Adjusted EBITDA, which is a non-U.S. GAAP measure, because management believes this metric assists investors and analysts in comparing our operating performance across reporting periods on a consistent basis by excluding items that our management believes are not indicative of our core operating performance. We use Adjusted EBITDA to evaluate our operating performance. You should not consider Adjusted EBITDA as an alternative to net income (loss), determined in accordance with U.S. GAAP, or as an alternative to net cash provided by operating activities, determined in accordance with U.S. GAAP, as an indicator of our cash flows.

Adjusted EBITDA has limitations as an analytical tool. Some of these limitations are:

•

Adjusted EBITDA

•

does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

•

does not reflect changes in, or cash requirements for, our working capital needs;

•

does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;

•

does not reflect our income tax expense or the cash requirement to pay our taxes; and

•

does not reflect the effect of certain mark-to-market adjustments and non-recurring items;

•

although depreciation and accretion are non-cash charges, the assets being depreciated and accreted will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and

•

other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure.

Because of these limitations, Adjusted EBITDA should not be considered in isolation or as a substitute for performance measures calculated in accordance with U.S. GAAP.

The most directly comparable U.S. GAAP measure to Adjusted EBITDA is net income (loss). The following table is a reconciliation of our net income (loss) to Adjusted EBITDA for the periods presented:


	Predecessor																					Pro forma Pattern
	Three Months Ended June 30,						Six Months Ended June 30,						Year Ended December 31,									Six Months Ended June 30,			Year Ended December 31,
	2013			2012			2013			2012			2012			2011			2010			2013			2012
	(U.S. dollars in thousands)
Net income (loss)	$	43,988		$	(575	)	$	25,206		$	7,993		$	(13,369	)	$	25,906		$	7,038		$	25,204		$	(17,798	)
Plus:
Interest expense, net of interest income		15,788			7,835			31,672			15,696			35,457			28,285			10,869			31,672			35,457
Tax provision (benefit)		(7,688	)		224			(7,396	)		1,004			(3,604	)		689			(672	)		(7,394	)		818
Depreciation and accretion		17,998			10,853			40,564			21,736			49,027			39,424			12,951			40,564			49,027

EBITDA	$	70,086		$	18,337		$	90,046		$	46,429		$	67,511		$	94,304		$	30,186		$	90,046		$	67,504

Unrealized loss (gain) on energy derivative		5,078			3,995			11,881			(1,746	)		6,951			(17,577	)		(14,000	)		11,881			6,951
Unrealized (gain) loss on interest rate derivatives		(8,202	)		115			(10,133	)		95			4,953			345			289			(10,133	)		4,953
Early extinguishment of debt		—			—			—			—			—			—			5,837			—			—
Realized loss on interest rate derivatives		—			—			—			—			—			—			6,596			—			—
Gain on transactions^(a)		(7,200	)		(4,173	)		(7,200	)		(4,173	)		(4,173	)		—			(22,009	)		(7,200	)		(4,173	)
Plus, our proportionate share in the following from our equity accounted investments:
Interest expense, net of interest income		(50	)		0			(52	)		0			44			—			—			(52	)		44
Tax (benefit) provision		(12	)		56			(48	)		56			(65	)		—			—			(48	)		(65	)
Depreciation and accretion		10			0			11			0			—			186			—			11			—
Unrealized (gain) loss on interest rate and currency derivatives		(13,731	)		18			(3,948	)		18			27			—			—			(3,948	)		27
Realized (gain) loss on interest rate and currency derivatives		(14	)		4			(153	)		4			—			—			—			(153	)		—

Adjusted EBITDA	$	45,965		$	18,352		$	80,404		$	40,683		$	75,248		$	77,258		$	6,899		$	80,404		$	75,241

(a)

Represents gains related to the sale of a portion of our investment in the El Arrayán project in 2012 and 2010 plus a gain on the acquisition of Gulf Wind in 2010.

(3)

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 may 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. Cash available for distribution before principal payments represents the sum of cash available for distribution and scheduled project-level debt repayments in accordance with the related loan amortization schedules, to the extent they are paid from operating cash flows during a period.

We disclose cash available for distribution before principal payments and cash available for distribution because management recognizes that they will be used as supplemental measures by investors and analysts to evaluate our liquidity. However, cash available for distribution before principal payments and cash available for distribution have limitations as analytical tools because they exclude depreciation and accretion, do not capture the level of capital expenditures necessary to maintain the operating performance of our projects, are not reduced for principal payments on our project indebtedness except, with respect to cash available for distribution, to the extent they are paid from operating cash flows during a period, and exclude the effect of certain other cash flow items, all of which could have a material effect on our financial condition and results from operations. Cash available for distribution before principal payments and cash available for distribution are non-U.S. GAAP measures and should not be considered alternatives to net income, net cash provided by (used in) operating activities or any other liquidity measure determined in accordance with U.S. GAAP, nor are they indicative of funds available to fund our cash needs. In addition, our calculations of cash available for distribution before principal payments and cash available for distribution are not necessarily comparable to cash available for distribution before principal payments and cash available for distribution as calculated by other companies. Investors should not rely on these measures as a substitute for any U.S. GAAP measure, including net income (loss) and net cash provided by (used in) operating activities.

The most directly comparable U.S. GAAP measure to both cash available for distribution before principal payments and cash available for distribution is net cash provided by (used in) operating activities. The following table is a reconciliation of our net cash provided by (used in) operating activities to both cash available for distribution before principal payments and cash available for distribution for the periods presented:


	Predecessor																					Pro forma Pattern
	Three Months Ended June 30,						Six Months Ended June 30,						Year Ended December 31,									Six Months Ended June 30,			Year Ended December 31,
	2013			2012			2013			2012			2012			2011			2010			2013			2012
	(U.S. dollars in thousands)
Net cash provided by (used in) operating activities	$	33,268		$	11,506		$	41,659		$	24,808		$	35,050		$	46,930		$	(3,011	)	$	41,659		$	35,050
Changes in current operating assets and liabilities		(940	)		(768	)		11,757			640			6,893			3,237			(836	)		11,757			6,893
Network upgrade reimbursement^(a)		618			4,409			618			4,409			6,263			—			—			618			6,263
Use of operating cash to fund maintenance and debt reserves		—			(525	)		—			(525	)		(1,047	)		(1,048	)		—			—			(1,047	)
Operations and maintenance capital expenditures		(156	)		(66	)		(375	)		(254	)		(623	)		(1,101	)		(20	)		(375	)		(623	)
Less:																							—
Distributions to noncontrolling interests^(b)		(1,000	)		(733	)		(1,168	)		(1,053	)		(1,298	)		(7,158	)		(222	)		(2,102	)		(2,336	)

Cash available for distribution before principal payments		31,790			13,823			52,491			28,025			45,238			40,860			(4,089	)		51,557			44,200
Principal payments paid from operating cash flows		(15,584	)		(13,733	)		(21,815	)		(17,172	)		(27,546	)		(22,330	)		(13,741	)		(21,815	)		(27,546	)

Cash available for distribution	$	16,206		$	90		$	30,676		$	10,853		$	17,692		$	18,530		$	(17,830	)	$	29,742		$	16,654

(a)

During the construction of the Hatchet Ridge project, we funded the costs to construct interconnection facilities in order to connect to the utility’s power grid and we will be reimbursed from the utility for those costs during the years 2013 to 2015. We carry a network upgrade reimbursements receivable in prepaid expenses and other current assets and other assets on our balance sheet.

(b)

$0.9 million and $1.0 million for the six months ended June 30, 2013 and the year ended December 31, 2012, respectively, on a pro forma basis after giving effect to the adjustment to non-controlling interest due to the PEG LP retained Gulf Wind interest. See “Unaudited Pro Forma Financial Data.”

(4)	For any period presented, MWh sold represents the amount of electricity measured in MWh that our projects generated and sold.

(5)	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.

An investment in our shares involves a high degree of risk. You should carefully consider the following risks, together with other information provided to you in this prospectus, in deciding whether to invest in our Class A shares. 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 revenue generated by our projects is principally dependent on the number of MWh generated in a given time period and 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 climates tends to reduce the magnitude of the deviation, but material deviations may still occur. As illustrated in the forecast presented elsewhere in this prospectus, 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 “Cash Dividend Policy—Forecasted Cash Available for Distribution.”

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:

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 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:

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.

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 favourable 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. 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.

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 5% 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 substations. 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 generator leads 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 that is a portion of the total purchase price of the turbines, 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 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. You should consider our prospects in light of the risks and uncertainties growing companies encounter in rapidly evolving industries such as ours. Also, our anticipated near-term growth could make it difficult for us to manage

our project expansion efficiently due to an inability to employ a sufficient number of skilled personnel or otherwise to effectively manage our capital expenditures and control our costs, including the requisite general and administrative costs necessary to achieve our anticipated growth. These challenges could adversely affect our ability to manage our current or future operating projects in an efficient manner and complete construction of 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 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.

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.

Following the occurrence of the reintegration event, we may be faced with increased costs associated with employing a larger number of employees. If PEG LP 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.

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, 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, the Electric Reliability Council of Texas, or “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 behaviour 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 approved 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 either

nuclear or hydroelectric 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 is scheduled to take effect in the fall of 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 12-18 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 PEG LP’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. 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 favourable 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 year ended December 31, 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 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 combined financial statements included elsewhere in this prospectus, 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 reserve,” and are recorded in “Other comprehensive income.” 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 favourable 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 you 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.

Upon the completion of this offering, we will own, and in the future may acquire, certain projects in joint ventures, and our partners’ interests may conflict with our and our shareholders’ interests.

Upon the completion of this offering, we will own, and in the future may acquire, certain projects in joint ventures, including South Kent, in which we have a 50% interest, 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 PEG LP-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 shareholders, 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 shareholders’ 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.

The growth of our business depends on locating and acquiring interests in additional attractive independent power and transmission projects at favourable 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 PEG LP pursuant to our Purchase Rights. Various factors could affect the availability of attractive projects to grow our business, including:

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.

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 shareholders 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.

Our strategy includes acquiring existing wind power projects. The acquisition of existing wind 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 wind 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 PEG LP, 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 PEG LP, 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 PEG LP or third parties on economically favourable terms.

Our goal of growing our cash available for distribution and increasing dividends to our Class A shareholders 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 favourable terms. If we are unable to make accretive acquisitions from PEG LP or third parties because we are unable to identify attractive acquisition opportunities, negotiate acceptable purchase contracts, obtain financing on economically acceptable terms (as a result of the then current market value of our Class A shares or otherwise) or are outbid by competitors, we may not be able to realize our targeted growth in cash available for distribution per Class A share.

The energy industry in 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 also currently benefit 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 are scheduled to expire 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, 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 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 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 favours other sources of renewable energy over wind power.

We have no control over where our competitors may erect wind power projects. Our competitors may erect wind power projects adjacent to our wind projects that may cause upwind array losses to occur at our wind

projects. Upwind array losses reflect the diminished wind resource available at a project resulting from interference with available wind caused by adjacent wind turbines. An adjacent wind power project that causes upwind array losses could have a material adverse effect on our revenues and results of operations.

Any change in power consumption levels could have a material adverse effect on our business, 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.

In developing certain of our projects PEG LP experienced delays in obtaining non-appealable permits and we may experience delays in the future. For example, our Ocotillo project is currently the subject of five 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 have commenced construction of, and closed project financing for, the Ocotillo project in anticipation of securing favourable rulings on these lawsuits. See “Business—Legal Proceedings.” In Ontario, an anti-wind advocacy group opposed the environmental permit granted to our South Kent project. The permit was appealed before the Environmental Review Tribunal, which dismissed the appeal on December 5, 2012. 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 the Ocotillo project or 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 PEG LP through which we expect PEG LP 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, PEG LP is generally not restricted from competing with us, other than with respect to the Non-Competition Agreement, and, in certain circumstances, PEG LP may sell its projects to third parties.

To the extent we do not exercise our Purchase Rights (or upon their expiration), PEG LP may sell its projects (including the PEG LP retained Gulf Wind interest) or PEG LP 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 PEG LP, PEG LP 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 PEG LP or its equity owners or if we decline to make an offer, PEG LP 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 this offering; and our Project Purchase Right and our PEG LP Purchase Right terminate upon the fifth anniversary of the completion of this offering, 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 PEG LP 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 PEG LP has sold the project to an unrelated third party. Following termination of our Project Purchase Right and our PEG LP Purchase Right, PEG LP 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 PEG LP will also terminate, and at such time, PEG LP will no longer be restricted from competing with us for acquisitions.

The loss of one or more of our or PEG LP’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 PEG LP’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 PEG LP’s executive officers or key employees leaves and neither we nor PEG LP 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.

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 “Business—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. See “Certain Relationships and Related Party Transactions—Other Contractual Arrangements with Related Persons.” 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 unfavourable 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.

Our substantial amount of indebtedness may adversely affect our ability to operate our business and impair our ability to pay dividends.

After giving effect to the Contribution Transactions, this offering and the use of proceeds therefrom, our pro forma consolidated indebtedness as of June 30, 2013 would have been approximately $ million, or approximately % of our total pro forma capitalization of $ million at such date. See “Capitalization” and “Use of Proceeds” for a discussion of the related pro forma adjustments and assumptions.

Of this amount, approximately $ million represents project-level debt that matures prior to . 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 favourable 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.

Our substantial indebtedness could have important consequences, including, for example:

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 favourable 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 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 the lender under

the Hatchet Ridge Wind Lease Financing against certain tax losses. In March 2013, we became aware of potential tax indemnity obligations in respect of the Hatchet Ridge indemnity triggered by an upstream owner of PEG LP and us inadvertently failing to file an election to not be treated as a tax-exempt entity under section 168(h)(6) or 168(h)(5) of the Internal Revenue Code. As a result, certain of our assets are currently subject to less favourable tax depreciation treatment than we had anticipated. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingent Tax Indemnity Obligations.”

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 have obtained construction bridge loans to finance a portion of project construction costs, and in certain cases, such loans are secured by the ITC cash grant proceeds anticipated to be received from the U.S. Treasury. We have assumed certain indemnities that were originally provided by PEG LP 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 “Description of Certain Financing Arrangements” elsewhere in this prospectus.

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 favourable 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 non-ISO markets or where we believe it is otherwise advisable. Under a PPA, we contract to sell all or a fixed proportion of the electricity generated by one of our projects, sometimes bundled with RECs and capacity or other environmental attributes, to a power purchaser, 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 credits 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.

We are a holding company with no operations of our own, and we will 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 “—Risks Related to Our Projects.” Our ability to declare and pay regular quarterly cash dividends will be subject to our obtaining sufficient cash distributions from our project subsidiaries after the payment of operating costs, debt service and other expenses. See “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.

We cannot guarantee that our forecast will prove to be accurate. Our actual results of operations for the forecast period will likely be different than the results disclosed in the forecast and the variations may be material.

The forecast presented elsewhere in this prospectus was prepared using assumptions that our management believes are reasonable. See “Cash Dividend Policy—Forecasted Cash Available for Distribution—Forecast

Limitations, Assumptions and Other Considerations.” These include assumptions regarding the future composition of our project portfolio, future operating costs of our projects, our projects’ future level of electricity generation, interest rates, foreign currency exchange rates, administrative expenses, tax treatment of income, future capital expenditure requirements and the absence of material adverse changes in economic conditions or government regulations. They also include assumptions about wind patterns (which are variable and difficult to predict) and availability of our equipment.

In particular, our cash available for distribution is most directly affected by the volume of electricity generated and sold by our projects because revenue from electricity sales and energy derivative settlements is the most significant component of our net income and net cash provided by operating activities. 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. For example, if the forecasted volume of electricity generated by our projects for the year ended December 31, 2014 decreased by 5% (corresponding to a P75 output, after taking account of the portfolio effect), we estimate that our forecasted net income, Adjusted EBITDA, net cash provided by operating activities and cash available for distribution would correspondingly decrease by approximately $11 million (or approximately 20% with respect to forecasted cash available for distribution) for each such metric during the year ending December 31, 2014. See “Cash Dividend Policy—Forecasted Cash Available for Distribution.” For an explanation of the portfolio effect on our projected output, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors that Significantly Affect our Business—Factors Affecting Our Operational Results—Electricity Sales and Energy Derivative Settlements of our Operating Projects.”

In addition, the forecast assumes that no unexpected risks materialize during the forecast period. Any one or more than one of these assumptions may prove to be incorrect, in which case our actual results of operations will be different from, and possibly materially worse than, those contemplated by the forecast. There can be no assurance that the assumptions underlying the forecast will prove to be accurate. Actual results for the forecast period will likely vary from the forecast results and those variations may be material. We make no representation that actual results achieved in the forecast period will be the same, in whole or in part, as those forecasted herein.

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.

Following completion of this offering, 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 “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 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 this offering, 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 “Description of Certain Financing Arrangements.”

Our ability to pay regular dividends on our Class A shares is subject to the discretion of our board of directors.

Our Class A shareholders will 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.

There is no existing market for our Class A shares, and we do not know if one will develop with adequate liquidity to sell our Class A shares at prices equal to or greater than the offering price.

Prior to this offering, there has not been a public market for our Class A shares. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on any stock exchanges or otherwise or how liquid that market might become. If an active trading market does not develop, you may have difficulty selling our Class A shares that you purchase in this offering. The initial public offering price for our Class A shares was determined by negotiations between us, PEG LP and the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell our Class A shares at prices equal to or greater than the price you paid in this offering or at all.

We are an emerging growth company, and we cannot be certain if the reduced reporting requirements applicable to emerging growth companies will make our Class A shares less attractive to investors.

We are an emerging growth company. For as long as we are an emerging growth company, we may take advantage of exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, or the “Sarbanes-Oxley Act,” certain 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 shareholder approval of any golden parachute payments not previously approved. We could be an emerging growth company for up to five years, although circumstances could cause us to lose that status earlier, including if the market value of our shares held by non-affiliates exceeds $700 million as of any June 30 before that time, in which case we would no longer be an emerging growth company as of the following December 31. See “Business Summary—Implications of Being an Emerging Growth Company.” We cannot predict if investors will find our Class A shares less attractive because we may rely on these exemptions. If some investors find our Class A shares less attractive as a result, there may be a less active trading market for our Class A shares and our Class A share price may be more volatile.

Under the JOBS Act, emerging growth companies can also delay adopting new or revised accounting standards until such standards apply to private companies. In addition, Section 107 of the JOBS Act also 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 that have different effective dates for public and private companies. In other words, an emerging growth company can delay the adoption of such accounting standards until those standards would otherwise apply to private companies until the first to occur of the date the subject company (i) is no longer an emerging growth company or (ii) affirmatively and irrevocably opt outs of the extended transition period provided in U.S. Securities Act Section 7(a)(2)(B). We have elected to 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 that have different effective dates for public and private companies and, as a result, our financial statements may not be comparable to the financial statements of other public companies. In addition, we have availed ourselves of the exemption from disclosing certain executive compensation information in this prospectus pursuant to Title 1, Section 102 of the JOBS Act. We cannot predict if investors will find our Class A shares less attractive because we will rely on these exemptions. If some investors find our Class A shares less attractive as a result, there may be a less active trading market for our Class A shares and our Class A share price may be more volatile.

We will be an SEC foreign issuer under Canadian securities laws and, therefore, be exempt from certain requirements of Canadian securities laws applicable to other Canadian reporting issuers.

Although we will be a reporting issuer in Canada, we will be an SEC foreign issuer and will be 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 shareholders 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.

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

Upon completion of this offering, PEG LP will hold approximately % of our outstanding Class A shares and % of our outstanding Class B shares (or % and %, respectively, if the underwriters exercise their overallotment option in full), representing in the aggregate an approximate % voting interest in our company (or % if the underwriters exercise their overallotment option in full). The remaining % of our outstanding Class B shares will be held by members of our management. Until the Conversion Event, neither PEG LP nor the management holders of our Class B shares will be entitled to receive any dividends on their Class B shares. Prior to the completion of this offering, we will enter into 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 PEG LP as needed to conduct our respective businesses. As a result, these shared PEG executives will have fiduciary and other duties to PEG LP. Conflicts of interest may arise in the future between our company (including our shareholders other than PEG LP) and PEG LP (and its owners and affiliates). Our directors and executive officers owe fiduciary duties to the holders of our shares. However, PEG LP’s general partner and certain of its officers and directors also have a fiduciary duty to act in the best interest of PEG LP’s limited partners, which interest may differ from or conflict with that of our company and our other shareholders.

The concentration of our share ownership following the offering will limit your ability to influence corporate matters.

Upon completion of this offering, PEG LP or its affiliates will hold approximately % of the combined voting power of our shares, or approximately % of the combined voting power of our shares if the underwriters exercise their overallotment option in full, and this concentration of voting power will limit your ability to

influence corporate matters, and as a result, actions may be taken that you may not view as beneficial. As a result of its ownership in our company, PEG LP will continue to have significant influence over all matters that require approval by our shareholders, including the election of directors. As a result, PEG LP or its affiliates will have the ability to exercise substantial influence over our company, including with respect to decisions relating to our capital 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 PEG LP and its affiliates may differ from or conflict with the interests of our other shareholders. Pursuant to the Shareholder Agreement, for so long as PEG LP beneficially owns at least 33 1/3% of our shares, PEG LP’s consent will be necessary for us to take certain material corporate actions. PEG LP may withhold its consent, which could adversely affect our business. See “Certain Relationships and Related Party Transactions—Share Ownership—Shareholder Agreement.”

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

Following the completion of this offering, certain of our executive officers will continue to provide services to PEG LP pursuant to the terms of the Management Services Agreement between our company and PEG LP and, as a result, will, in some instances, have fiduciary or other obligations to PEG LP. 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 will continue to have economic interests in PEG LP and, accordingly, the benefit to PEG LP from a transaction between PEG LP and our company will proportionately inure to their benefit as holders of economic interests in PEG LP. Following the completion of this offering, PEG LP 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 PEG LP (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 will continue to have economic interests in PEG LP following the completion of this offering 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 PEG LP, 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 favour.

Subject to the terms of the Non-Competition Agreement with, and our Purchase Rights granted to us by, PEG LP (see “Certain Relationships and Related Party Transactions”), 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, shareholders, 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 shareholder 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.

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. See “Description of Capital Stock—Corporate Opportunity.”

Our actual or perceived failure to deal appropriately with conflicts of interest with PEG LP 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.

Following the completion of this offering, the conflicts committee will be 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 PEG LP to determine whether the offer is fair and reasonable (including any acquisitions by us of assets of PEG LP 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 will influence 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 you could lose all or part of your investment.

Volatility in the market price of our shares may prevent you from being able to sell your Class A shares at or above the price you paid for your shares. The market price of our Class A shares could fluctuate significantly for various reasons, including:

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 you to lose all or part of your 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.

We will 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 will 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 shareholder 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. We also expect that, as a public company, it will be more expensive for us to obtain director and officer liability insurance.

The initial public offering price per Class A share is substantially higher than our net tangible book value per Class A share immediately after the offering. As a result, you will pay a price per Class A share that substantially exceeds the book value of our assets after subtracting our liabilities. At our offering price of $ per Class A share, you will incur immediate and substantial dilution in the amount of $ per Class A share. See “Dilution.”

As a result of the FPA and FERC’s regulations in respect of transfers of control, absent prior authorization by FERC, neither we nor PEG LP 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 PEG LP, 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 are purchased in this offering, subsequent offerings by us or PEG LP, 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 PEG LP 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 PEG LP, 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 this offering, or subsequent offerings of our voting securities, will be permitted to purchase an amount of our securities from us that would cause such purchaser and its affiliate and associate companies to collectively hold 10% or more of our voting securities outstanding on a post-offering basis. Additionally, purchasers in this offering 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, following the completion of this offering, 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 PEG LP, 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.

Upon the completion of this offering, we anticipate our amended and restated certificate of incorporation and amended and restated bylaws will contain provisions that could discourage, delay or prevent a change in control of our company or changes in our management that the shareholders of our company may deem advantageous. These provisions will:

These anti-takeover defences 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 you and other shareholders to elect directors of your choosing and cause us to take corporate actions other than those you desire. See “Description of Capital Stock.”

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 your ownership in us and may adversely affect the market price of our Class A shares.

We may issue and PEG LP 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. After the completion of this offering, we will have Class A shares authorized and Class A shares outstanding. The number of outstanding shares includes Class A shares that we are selling in this offering, which may be resold immediately in the public market. All of the remaining Class A shares, or approximately , or % of our total outstanding shares, are restricted from immediate resale under the lock-up agreements between our current shareholders and the underwriters described in “Underwriting,” but may be sold into the market in the near future. 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 this offering, 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 PEG LP’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. See “Certain Relationships and Related Party Transactions” and “Shares Eligible for Future Sale.”

This prospectus contains forward-looking statements. All statements other than statements of historical fact included in this prospectus are forward-looking statements. The words “believe,” “expect,” “anticipate,” “intend,” “estimate” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify forward-looking statements. You should not place undue reliance on these forward-looking statements. Although forward-looking statements reflect management’s good faith beliefs, reliance should not be placed on forward-looking statements because they involve known and unknown risks, uncertainties and other factors, which may cause the actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. Forward-looking statements in this prospectus speak only as of the date of this prospectus. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise. These forward-looking statements are subject to numerous risks and uncertainties, including, but not limited to:

We derive many of our forward-looking statements from our operating budgets and forecasts, which are based upon many detailed assumptions, including industry data referenced elsewhere in this prospectus. While we believe our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and it is impossible for us to anticipate all factors that could affect our actual results. Important factors that could cause actual results to differ materially from our expectations are disclosed under “Risk Factors”, “Cash Dividend Policy—Forecasted Cash Available for Distribution—Forecast Limitations, Assumptions and Other Considerations” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this prospectus. All written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this prospectus as well as other cautionary statements that are made from time to time in our other filings with the SEC and applicable Canadian securities regulatory authorities or public communications. You should evaluate all forward-looking statements made in this prospectus in the context of these risks and uncertainties.

We caution you that the important factors referenced above may not contain all of the factors that are important to you. In addition, we cannot assure you that we will realize the results or developments we expect or anticipate or, even if those results or developments are substantially realized, that they will result in the consequences we anticipate or affect us or our operations in the way we expect.

We estimate the net proceeds to us from this offering will be approximately $ million, based on an assumed public offering price of $ per Class A share, which is the midpoint of the price range set forth on the cover page of this prospectus and after deducting underwriting commissions and estimated offering expenses payable by us.

We intend to use the net proceeds from this offering (i) to provide $ million (i.e., the cash portion) of the consideration to be paid to PEG LP in connection with the Contribution Transactions and (ii) the remainder for working capital and general corporate purposes. Certain of our executive officers have an economic interest in PEG LP and, as a result, these individuals will have an interest in the proceeds from this offering received by PEG LP in proportion to their respective economic interest in PEG LP. See “Conflicts of Interest and Fiduciary Duties.”

In connection with the Contribution Transactions referred to in (i) above, we will also issue to PEG LP Class A shares and Class B shares as consideration for the assets it will contribute to us. See “Certain Relationships and Related Party Transactions” and “Structure and Formation of our Company.”

The underwriters may also purchase up to an additional Class A shares from the selling shareholder at the public offering price, less the underwriting commissions, within 30 days from the closing date of this offering to cover overallotments, if any. We estimate that the net proceeds to the selling shareholder will be approximately $ million, based on an assumed public offering price of $ per Class A share, which is the midpoint of the price range set forth on the cover page of this prospectus, after deducting underwriting commissions and assuming the exercise in full of the underwriters’ overallotment option. We will not receive any proceeds from the exercise of the underwriters’ overallotment option. The selling shareholder will pay the underwriters’ commissions and the expenses of the offering applicable to the sale of shares pursuant to the exercise of the underwriters’ overallotment option.

Each $1.00 increase (decrease) in the assumed public offering price would increase (decrease) the net proceeds to us by approximately $ million, after deducting underwriting commissions and estimated offering expenses payable by us, assuming the number of Class A shares offered by us, as set forth on the cover page of this prospectus, remains the same. Each increase (decrease) of 1.0 million in the number of Class A shares offered by us would increase (decrease) the net proceeds to us by approximately $ million, after deducting underwriting commissions and estimated offering expenses payable by us, assuming the assumed public offering price of $ per Class A share, which is the midpoint of the price range set forth on the cover page of this prospectus.

The following table sets forth the cash and cash equivalents and the capitalization as of June 30, 2013 on (i) a historical basis from our predecessor’s financial statements, (ii) a pro forma basis to reflect the Contribution Transactions and other pro forma adjustments and assumptions set forth under the heading “Unaudited Pro Forma Financial Data” as if each has occurred on such date and (iii) the pro forma basis described in the immediately preceding (ii), as adjusted to give effect to the filing of our amended and restated certificate of incorporation, this offering and the use of the proceeds therefrom as set forth under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our predecessor’s historical financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Structure and Formation of Our Company,” “Use of Proceeds,” “Selected Historical Financial Data,” “Unaudited Pro Forma Financial Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Dilution is the amount by which the offering price paid by the purchasers of our Class A shares sold in this offering will exceed the pro forma net tangible book value per share of our Class A shares after the offering. Prior to the Contribution Transactions, PEG LP will not own any of our Class A shares or Class B shares and, accordingly, in order to more meaningfully present the dilutive impact on the purchasers in this offering, we have presented dilution in net tangible book value per Class A share to investors in this offering assuming that the issuance of our shares in connection with the Contribution Transactions has occurred and all Class B shares issued in connection therewith have been exchanged for Class A shares on a one-for-one basis. At June 30, 2013, our predecessor would have had a net tangible book value of approximately $ million, or $ per Class A share to be held by PEG LP after giving effect to the Contribution Transactions (but not this offering), and assuming all of the Class B shares issued in connection therewith are exchanged for our Class A shares a one-for-one basis. After giving further effect to this offering and the use of proceeds therefrom, the pro forma net tangible book value at June 30, 2013 attributable to our Class A shares would have been $ million, or $ per Class A share. Purchasers of our Class A shares in this offering will experience substantial and immediate dilution in net tangible book value per Class A share for financial accounting purposes, as illustrated in the following table:

The following discussion includes forward-looking statements relating to our cash dividend policy as well as an illustrative forecast of our possible future operating results for each of the years ending December 31, 2013 and 2014. This forecast of future operating results and cash available for distribution in future periods is based on the assumptions described below and other assumptions believed by us to be reasonable as of the date of this prospectus. However, we cannot assure you that any or all of these assumptions will be realized. These forward-looking statements are based upon estimates and assumptions about circumstances and events that have not yet occurred and are subject to all of the uncertainties inherent in making projections. This forecast should not be relied upon as fact or as an accurate representation of future results. Future results will be different from this forecast and the differences may be materially less favourable. Our operations are subject to numerous risks and uncertainties, including those discussed above under the caption “Risk Factors” and “Forward-Looking Statements.” You should not place undue emphasis on these forward-looking statements.

Our actual results in future periods may also be materially different than our predecessor’s historical financial results. For additional information regarding our predecessor’s historical financial results, you should refer to our predecessor’s audited historical combined financial statements as of December 31, 2011 and 2012 and for the years ended December 31, 2010, 2011 and 2012, included elsewhere in this prospectus.

We intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A shares. Our quarterly dividend will initially be set at $ per Class A share, or $ 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 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.

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. With respect to our first dividend payable on or about January 30, 2014 to holders of record on December 31, 2013, we intend to pay a pro-rated dividend covering the period from the completion of this offering through December 31, 2013, based on our initial dividend level and the actual length of that period.

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 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.

Our management team considered 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 the forecast 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:

For a further discussion of Adjusted EBITDA and cash available for distribution and their limitations as analytical tools, please see “Summary Historical and Pro Forma Financial Data”.

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 years ending December 31, 2013 and 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 following the completion of this offering 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:

Based upon the assumptions described below and other assumptions that we believe to be reasonable as of the date of this prospectus, the forecast indicates that we will generate cash available for distribution during the years ending December 31, 2013 and 2014 of $44.5 million and $55.4 million, respectively.

Our forecast for the year ending December 31, 2013 indicates that we expect to generate cash available for distribution during the period of $44.5 million. We received approximately $173 million in cash proceeds from ITC cash grants during the second quarter of 2013 as a result of commencing commercial operations of our Santa Isabel project and a portion of our Ocotillo project during the year ended December 31, 2012 and approximately $7 million from the sale of certain local tax credits at our Santa Isabel project in the second quarter of 2013, and we expect to receive an approximately $59 million network upgrade reimbursement at our Ocotillo project in the third quarter of 2013. We expect that these cash proceeds will be reduced to a net amount of approximately $115 million after using approximately $125 million to repay or otherwise service our project-level indebtedness at these two projects. We intend to use this net amount for general corporate purposes and, if necessary, to supplement any shortfall in cash available for distribution to pay our dividends in 2014. We have excluded the impact of the ITC cash grants, local tax credit sale and the Ocotillo network upgrade reimbursement from our forecast of cash available for distribution because we do not consider these items to be representative of the cash generating ability of our business. See “Risk Factors—Risks Related to Our Financial Activities—We are subject to indemnity obligations.”

During the year ending December 31, 2014, the forecast indicates that we expect to generate cash available for distribution of $55.4 million as compared to our aggregate annual dividends payable for the period of $ million. To the extent that there is a shortfall in cash available for distribution generated by our operations during any quarter in the year ending December 31, 2014, we expect to fund any shortfall from other sources of available cash, which could include cash on hand and borrowings under our $120 million revolving credit facility. We also expect to receive a special distribution of approximately $13 million from our South Kent project in the third quarter of 2014 in part as a result of certain local tax refunds. We have excluded the impact of this distribution from our forecast of cash available for distribution because we do not consider this item to be representative of the cash generating ability of our business.

The following table reconciles our estimated net income to estimated Adjusted EBITDA for the forecast periods presented.

While we believe that the assumptions underlying the forecast are reasonable in light of management’s current expectations concerning future events, we can give you no assurance that our assumptions will be realized or that we will generate cash available for distribution during the forecast periods at the levels forecasted, in which event we may not be able to pay cash dividends on our Class A shares at our initial dividend level or at all. Assumptions and estimates underlying the forecast are inherently uncertain and our future operating results are subject to a wide variety of risks and uncertainties, including significant business, economic, and competitive risks and uncertainties described under the headings “Risk Factors” and “Forward-Looking Statements” elsewhere in this prospectus. Any one of these risks or uncertainties could cause our actual results to differ materially from those contained in the forecast. Accordingly, we cannot assure you that the prospective results in the forecast above are indicative of our future performance. Our actual results will differ from those presented, and the differences could be material. Investors in our Class A shares should not regard inclusion of the forecast in this prospectus as a representation by any person that the results contained in the forecast will be achieved.

We do not undertake any obligation to release publicly the results of any future revisions we may make to our forecast or to update this forecast to reflect events or circumstances after the date of this prospectus, except as required by applicable law. In light of the above, the statement that we believe that we will have sufficient cash available for distribution, together with other sources of cash available to us, to allow us to pay our initial quarterly dividend on all of our outstanding Class A shares for the years ending December 31, 2013 and 2014 should not be regarded as a representation by us, the underwriters or any other person that we will actually generate such amount of cash available for distribution or pay such dividends.

The accompanying forecast was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information. The forecast included in this prospectus has been prepared by, and is the responsibility of, our management. No independent registered public accounting firm, has examined, compiled or performed any procedures with respect to the forecast, and accordingly, no independent registered public accounting firm has expressed an opinion or any other form of assurance with respect thereto.

The forecast has been prepared using assumptions that we believe to be reasonable and that are consistent with our intended course of action for the periods presented, except that they exclude any acquisitions, and all other non-recurring or unexpected charges or events. The key assumptions upon which the forecast is based are as follows:

Our business is exposed to numerous risks that could have a material adverse effect on our business, financial condition, results of operations or cash available for distribution. However, we have assumed that no such risks will materialize for the purposes of preparing the forecast. For a discussion of the important factors that could cause actual results to differ materially from our forecast, see “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” elsewhere in this prospectus.

The forecast assumes that on , 2013, our company will raise net proceeds of $ million in this offering through the issuance of of our Class A shares at a price of $ per Class A share (these proceeds and share amounts are based on the midpoint of the range set forth on the cover of this prospectus). The forecast also assumes that the proceeds of this offering will be used as described in “Use of Proceeds” elsewhere in this prospectus and that in connection with the completion of this offering, we will enter into the Contribution Transactions with PEG LP. See “Structure and Formation of Our Company.”

The forecast assumes that our projects will be comprised, during the relevant periods, of the projects set forth in the table below. We have assumed that each of our construction projects will be completed on schedule for the budgeted construction costs. Although making acquisitions is part of our strategy, we have assumed we will not make any acquisitions during the forecast period.

Our ability to generate sufficient cash available for distribution to pay dividends to holders of our Class A shares is primarily a function of the volume of electricity generated and sold by our projects, which, in turn, is impacted by wind levels and the availability of our equipment to generate and transmit electricity. The volume of electricity generated and sold by our projects during a particular period is also impacted by the number of projects that have commenced commercial operations. Ninety-five percent of the electricity to be generated across our projects is committed for sale pursuant to long-term, fixed-price power sale agreements.

The forecast above for each of the years ending December 31, 2013 and 2014 is based on an assumption as to the annual electricity generation from our projects, which we refer to as the “P50 output.” The P50 output assumption reflects our management’s estimate that during the forecast periods presented, there is a 50% probability that the electricity generated across our projects will exceed the amount of MWh set forth opposite the line item “MWh sold” for each of the periods in the table above. We have adjusted our 2013 P50 output estimate to reflect actual production in the first two quarters of the year and a reduction of output with respect to certain turbine outages. In the third quarter of 2013, we are receiving payments for warranty liquidated damages

with respect to turbine outages at our Ocotillo and Santa Isabel projects (see “Management Discussion and Analysis—Factors that Significantly Affect our Business—Factors Affecting Our Operational Results—Electricity Sales and Energy Derivative Settlements of Our Operating Projects”), which we have included in our forecast as other revenue.

The P50 output assumption is based on our management’s estimates of likely electricity generation during extended periods of time, including the forecast period, which is based on internal and third-party long-term wind and other meteorological studies, and the further assumption that there will be no unusual or unexpected business interruptions. Wind conditions are variable, and we have, from time to time, experienced unexpected outages. We have assumed availability level of 96.5% for wind turbine equipment across our projects, which level is consistent with and based upon our availability levels since the commencement of operations across our operating projects. We have also made allowance for a ramp-up of each project’s operation by reducing output in its first year of operations by 0.5%.

The following tables indicate our estimates of the volume of electricity that we would expect to sell at each of our projects during a typical year after all of our projects have commenced commercial operations, based upon the P50 output assumption described above.

Our cash available for distribution is most directly affected by the volume of electricity generated and sold by our projects because revenue from electricity sales and energy derivative settlements is the most significant component of our net income and net cash provided by operating activities. 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, increases or decreases in the volume of electricity generated and sold by our projects typically result in a proportionately greater increase or decrease, respectively, in our cash available for distribution. For example, if the forecasted volume of electricity generated by our projects for the year ending December 31, 2014 increased by 5% or decreased by 5% (a 5% decrease corresponds to a P75 output, after taking account of the portfolio effect), we estimate that our forecasted net income, Adjusted EBITDA, net cash provided by operating activities and cash available for distribution would correspondingly increase or decrease by approximately $12 million (or approximately 20% with respect to forecasted cash available for distribution) for each such metric during the year ending December 31, 2014. For an explanation of the portfolio effect on our projected output, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors that Significantly Affect our Business—Factors Affecting Our Operational Results—Electricity Sales and Energy Derivative Settlements of our Operating Projects.”

The electricity pricing used in the forecast is based on our expected annual electricity generation and four revenue sources:

The forecast assumes long-term, contracted revenues will be determined pursuant to the pricing terms of the PPAs and hedging agreements that are currently in place, that our power purchasers and hedge counterparties will fulfil their obligations under such agreements and that the exchange rate between U.S. dollars and Canadian dollars will not materially change after the date of this prospectus. With respect to an operating project’s power output not covered by PPAs or hedging agreements, the forecast assumes that such power will be sold in the spot electricity market or in REC contract sales at future spot market and REC prices, respectively, determined by reference to third-party industry forecasts, which are considered by management to be reasonable.

Project expense is comprised of the direct costs of operating and maintaining our projects, including labour, turbine service arrangements, land lease royalty payments, property taxes, insurance, power scheduling and forecasting, environmental costs and contractual administration. Expenses are forecast based on historical experience, land contracts, contracted service arrangements and other management estimates.

The forecast assumes our operating projects will operate within budgeted operating costs, including with respect to repair and maintenance costs, and that there will be no unusual, non-recurring or unexpected operating, repair or maintenance charges.

To mitigate our market risks, we have entered into, and expect to enter into, derivatives to hedge against risks related to fluctuations in energy prices at Gulf Wind and El Arrayán, interest rates on our project loans and foreign currency exchange rates. U.S. GAAP requires that, in certain circumstances, we make mark-to-market

adjustments related to these derivatives. The forecast assumes that the market value of our energy derivatives will decline, and our interest rate derivatives will change, throughout the forecast period in a manner that is consistent with the forward electricity price curve and forward interest rate curves, respectively, used in our most recent month-end derivative valuation.

The depreciation and accretion expense reflected in the forecast is based on the carried historical cost basis of our individual projects as reduced, where applicable, by related ITC cash grants. Depreciation is calculated using the straight-line method and an estimated useful life of 20 years. Accretion is calculated for the asset retirement or decommissioning obligation over an estimated operational life of 20 years.

Total operating expenses consist principally of related party general and administrative and other general and administrative expenses which reflect an estimate prepared by our management in a manner that is consistent with the historical allocations of shared costs between PEG LP and our predecessor and in accordance with the Management Services Agreement. We have also included an estimate of the incremental costs of being a public company of approximately $2 million per year.

The forecast assumes that interest expense is based on the expected level of interest paid on our project-level debt facilities, fees on approximately $45 million of issued letters of credit and only limited short-term borrowings under our $120 million revolving credit facility. For each of our projects, project-level debt facilities include a fixed-loan amortization schedule, such that loan balances at any point in time are known. The project-level financings are either based on fixed interest rates or floating London Interbank Offered Rate, or “LIBOR,”—based interest rates. In the case of LIBOR-based interest rates, we have entered into interest rate swap agreements to hedge the risk of fluctuations in LIBOR.

The forecast makes the following assumptions regarding our revolving credit facility and project-level debt facilities:

See “Description of Certain Financing Arrangements” for a description of our project-level financing arrangements, including applicable interest rates.

Our estimate of interest expense during the forecast periods and thereafter, including our proportional share of interest expense reflected in our equity in earnings in unconsolidated investments, is based on the estimated scheduled amortization for project-level indebtedness shown in the following tables:

Equity in Earnings in Unconsolidated Investments. Our projected equity in earnings in unconsolidated investments consists of our proportional share of the earnings of each of our unconsolidated joint-venture investments, El Arrayán and South Kent. Our estimate of our proportional interest in the components of the earnings of El Arrayán and South Kent in 2013 and 2014 consists of the following:

Distributions From Unconsolidated Investments. The forecast adjusts our projected equity in earnings in unconsolidated investments by adding back our proportional share of depreciation and accretion and subtracting our proportional share of projected principal payments on project-level indebtedness and other working capital adjustments, including an estimated two-month lag in the timing of receipt of electricity sales and energy derivative settlements due to the billing cycles and payment schedules of our power sale agreement counterparties. After taking into consideration the distribution timing permitted under their respective financing arrangements, our forecast includes only one distribution from each of our unconsolidated investments in 2014.

Timing Related to Commercial Operations of Construction Projects. Our equity in earnings in unconsolidated investments is directly affected by the timing of our construction projects achieving commercial operations because the date of commencement of commercial operations is the date on which the project also commences the generation and sale of electricity. Consistent with our expectations expressed elsewhere in this prospectus, our forecast for the year ending December 31, 2014 presented above assumes that our final two construction projects, South Kent and El Arrayán, will commence commercial operations during April and June of 2014, respectively.

Our estimated proportional interest in electricity generation used in estimating the forecasted equity in earnings in unconsolidated investments above is 176,125 MWh less than the P50 electricity generation at our unconsolidated subsidiaries shown above under “Forecast Limitations, Assumptions and Other Considerations—MWh Sold.” If the projects held in our unconsolidated investments were fully operational for a full 12-month period, and additionally not subject to our assumed initial two-month working capital lag, for illustrative purposes, our equity in earnings in unconsolidated investments for a 12-month period of full project operations would consist of the following:

Illustrative Impact on Equity in Earnings in Unconsolidated Investments⁽¹⁾

In addition, the illustrative impact on our equity in earnings in unconsolidated investments shown in the table above would result in an increase in combined net income, Adjusted EBITDA, and cash available for distribution in a 12-month period during which all of our projects were fully operational (and based upon all the other assumptions used in the preparation of the forecast) of $5.2 million, $20.6 million and $24.8 million, respectively. The effect of this illustrative adjustment on our 2014 forecast results is shown in the table below.

The forecast assumes that, following the completion of this offering, we will be subject to federal and state income taxes as a U.S. corporation, that certain of our subsidiaries will be subject to Canadian federal and provincial income taxes and that valuation allowances will be established and maintained with respect to certain net operating losses.

The forecast of working capital increase is based on the projected difference between cash receipts and accrued revenue.

The forecast assumes we will have limited capital expenditures other than in connection with the construction of our projects pursuant to the budgets for our construction projects. Operational capital expenditure items, other than non-recurring items, for which cash reserves have been provided, are estimated to be approximately $500,000 in each of 2013 and 2014, respectively, for minor improvements and capital outlays associated with our operating assets.

The forecast assumes that the average exchange rate between the U.S. dollar and Canadian dollar will be approximately C$1.01:US$1.00 and C$1.02: US$1.00 for the years ending December 31, 2013 and 2014, respectively. The assumed average exchange rates were determined by reference to actual exchange rates from January 1, 2013 to April 30, 2013 and forward exchange rates for the balance of 2013 and year ending December 31, 2014.

In preparing the forecast, we have applied the accounting policies used in the preparation of our predecessor’s financial statements shown elsewhere in this prospectus. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” and the notes to our predecessor’s financial statements included elsewhere in this prospectus.

The following table presents selected historical combined financial data of our predecessor as of the dates and for the periods indicated. The selected historical financial data as of December 31, 2010, 2011 and 2012 and the years ended December 31, 2010, 2011 and 2012 have been derived from the audited historical combined financial statements of our predecessor that are included elsewhere in this prospectus. The selected historical financial data as of June 30, 2013 and for the three and six months ended June 30, 2013 and 2012 have been derived from the unaudited historical combined financial statements of our predecessor included elsewhere in this prospectus.

The historical financial statements of our predecessor, from which the summary historical financial data have been derived, are presented in U.S. dollars and have been prepared in accordance with U.S. GAAP, which differs in certain material respects from IFRS. For recent and historical exchange rates between Canadian dollars and U.S. dollars, see “Currency and Exchange Rate Information.”

You should read the following table in conjunction with “Structure and Formation of Our Company,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical combined financial statements of our predecessor and the notes thereto that are included elsewhere in this prospectus.

We were incorporated in October 2012 by PEG LP for the purpose of this offering and do not have historical financial operating results. Therefore, in this prospectus, we present the historical financial statements of our predecessor. In order to present the financial effect of the Contribution Transactions, the following tables present unaudited pro forma balance sheet data as of June 30, 2013, pro forma statement of operations and other financial and operating data for the six months ended June 30, 2013 and the year ended December 31, 2012, based upon the combination of Pattern Energy Group Inc. and our predecessor’s combined historical financial statements after giving pro forma effect to (i) PEG LP’s retention of the PEG LP retained Gulf Wind interest and (ii) the estimated tax effects of the Contribution Transactions. The pro forma balance sheet, statement of operations and other financial and operating data presented are not necessarily indicative of what our actual results of operations would have been as of the date and for the periods indicated, nor does it purport to represent our future results of operations.

The Contribution Transactions are treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in the accounts of our predecessor at the date of transfer. The pro forma data presented reflect events directly attributable to the Contribution Transactions and certain assumptions we believe are reasonable. The Contribution Transactions will be completed on or immediately prior to the completion of this offering.

The unaudited pro forma combined balance sheet assumes that the Contribution Transactions occurred on June 30, 2013. The unaudited pro forma combined statement of operations for the six months ended June 30, 2013 and the year ended December 31, 2012 assumes that the Contribution Transactions occurred on January 1, 2012.

The historical financial statements of Pattern Energy Group Inc. and our predecessor, from which the unaudited pro forma financial data have been derived, are presented in U.S. dollars and have been prepared in accordance with U.S. GAAP, which differ in certain material respects from IFRS. For recent and historical exchange rates between Canadian dollars and U.S. dollars, see “Currency and Exchange Rate Information.”

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including, without limitation, those set forth in “Risk Factors,” “Forward-Looking Statements” and other matters included elsewhere in this prospectus. The following discussion of our financial condition and results of operations should be read in conjunction with our predecessor’s historical financial statements and the notes thereto included elsewhere in this prospectus and our unaudited pro forma financial data, as well as the information presented under “Summary Historical and Pro Forma Financial Data,” “Selected Historical Financial Data,” “Unaudited Pro Forma Financial Data,” “Material U.S. Federal Income Tax Considerations for Holders of Our Class A Shares” and “Material Canadian Federal Income Tax Considerations for Holders of Our Class A Shares.” As a result of the Contribution Transactions, we believe that our predecessor’s historical financial statements are representative of our financial position following the completion of this offering, with the exception of PEG LP’s approximate 27% retained interest in Gulf Wind.

We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued growth of our business. We own interests in eight 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 1,041 MW, consisting of six operating projects and two projects under construction. We expect that our two construction projects will commence commercial operations prior to the end of the second 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-five 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 19 years.

We intend to maximize long-term value for our shareholders 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 shareholders, 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.

We intend to use a portion of the cash available for distribution generated from our projects to pay regular quarterly dividends in U.S. dollars to holders of our Class A shares. Our quarterly dividend will initially be set at $ per Class A share, or $ per Class A share on an annualized basis. We have established our initial quarterly dividend level 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 consideration given to retaining a portion of the cash available for distribution to grow our business. 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. See “Cash Dividend Policy.”

Based on our run-rate cash available for distribution and our initial quarterly dividend level, we believe that we will generate excess cash flow that we can use, together with our initial cash on hand and the proceeds of any potential future debt or equity issuances, to invest in accretive project acquisition opportunities, including the Initial ROFO Projects. Considering our preferential rights to acquire the Initial ROFO Projects, we have established a three-year targeted annual growth rate in our cash available for distribution per Class A share of 8% to 10%.

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.

Wind power has been one of the fastest growing sources of electricity generation in North America and globally over the past decade. This rapid growth is largely attributable to wind power’s increasing competitiveness with other electricity generation sources, the advantages of wind 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:

Uncertainty related to the demand for new power projects in general and the expiration of U.S. federal incentives are likely to result in a reduction in the build rate of wind power and other renewable energy projects in 2013 and 2014. These adverse effects may be partially or fully offset by regional requirements for new power projects due to older power project retirements, passage of an extension of the U.S. federal tax incentives or other government actions in support of new wind power projects, a return to higher natural gas prices, desire for more stable power sale agreements, and increased difficulty in permitting conventional power projects. In the long term, we believe that substantial growth potential remains in the U.S. market.

Our projects are generally unaffected by the short-term trends discussed above, given that 95% 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 19 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 and is also 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 PPA, pursuant to our Project Purchase Right and the PEG LP retained Gulf Wind interest pursuant to our Gulf Wind Call Right.

In addition, we expect that the recent increase in renewable energy development activity that has resulted in part from the anticipation of the potential expiration of PTC and ITC cash grant programs, when combined with a coming temporary slow-down in new project development, could create significant investment opportunities for us. We believe that there will be additional acquisition opportunities in the United States in the short term as some of our competitors react to slower growth by selling existing projects, 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 throughout 2013. 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.

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) the achievement of efficient project operations, (v) interest expense on our corporate- and project-level debt and (vi) expenses associated with becoming a public company.

Our construction projects include interests in two projects that we expect will contribute an additional operating capacity of 171 MW in 2014, for an aggregate owned capacity of 1,041 MW together with our operating projects, including the portion of our Ocotillo project expected to commence commercial operations prior to the completion of this offering. 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.

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, PEG LP completed the construction of our Hatchet Ridge, St. Joseph, Spring Valley and Santa Isabel projects and the first portion of our Ocotillo project on time and within budget. Including their time together before forming PEG LP, our management team has constructed and placed into service 25 wind power projects with an aggregate generating capacity of over 2,600 MW. In the first half of 2014, we expect that our two joint-venture projects, South Kent and El Arrayán, will commence commercial operations and add an additional 171 MW of owned capacity to our project portfolio. See “Business—Our 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-five 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 19 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 generation 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.

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 analysed 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 eight 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:

We and many of our project lenders also use annual electricity generation forecasts, including probability of exceedance, to evaluate the ability of a project to make scheduled debt service payments and to determine the nature and size of project-level liquidity features such as debt service reserves or letter of credit facilities. In general, our operating projects have performed within our expectations to date. While electricity generation has been slightly below projected long-term estimates, we have been able to offset any production shortfalls by achieving operating and financing costs that were under budget. To date, none of our projects have been blocked from making distributions by the terms of our project-level credit agreements or as a result of a failure to meet distribution conditions.

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 seven of our eight project sites and the Mitsubishi MWT95/2.4 at the eighth. 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.

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 employed only by our Ocotillo and Santa Isabel projects, pending determination of the cause. Siemens has completed, and we have 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 require 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. We have received and expect to receive additional warranty liquidated damages from Siemens with respect to our availability warranties.

We have, and expect to continue to enter into, derivatives to hedge against risks related to fluctuations in energy prices and interest rates on our project loans and foreign currency exchange rates. We recognize derivative instruments as assets or liabilities at fair value in our combined 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 combined 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 shareholders reflected in these derivative instruments, outweighs the risk of volatility in net income that we expect to report. Accordingly, we believe it is useful to investors to consider supplemental financial measures that we report, such as Adjusted 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.

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, 2011 and 2012, our turbine availability across our projects was 96.2% and 97.6%, respectively, which is in line with industry standards for original investment projections reviewed by independent engineering firms. More importantly, we operate our projects to maximize our revenues rather than solely focusing on time-based availability or electricity generation volume. See “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 business has experienced no significant lost time events, worksite accidents, except one construction related injury to a subcontractor’s employee that occurred in late November 2012, or other significant environmental, health or safety, or “EHS,” issues in 2011 or 2012.

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

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 closed project financing for the South Kent project in March 2013. See “Description of Certain Financing Arrangements.”

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 1.70 to 1.0.

We believe that our annual general and administrative expenses will increase by approximately $2 million as a result of becoming a publicly traded company following this offering. This increase will be due to increased accounting support services, filing annual and quarterly reports with the SEC and the Canadian Securities Administrators, increased audit fees, investor relations, directors’ fees, directors’ and officers’ insurance, legal fees, stock exchange listing fees, and registrar and transfer agent fees. Our financial statements following this offering will reflect the impact of these increased expenses which will affect the comparability of our predecessor’s historical financial statements for periods prior to the completion of this offering.

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 before principal payments and cash available for distribution as supplemental liquidity measures. Each of these key metrics is discussed below.

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.

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 we do not consider to be indicative of our ongoing operating performance such as mark-to-market adjustments and other non-recurring items. 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. For a further discussion of Adjusted EBITDA, including a reconciliation of net income (loss) to Adjusted EBITDA and discussion of its limitations, see “Cautionary Statement Regarding the Use of Non-GAAP Measures” and footnote 2 under the heading “Summary Historical and Pro Forma Financial Data” elsewhere in this prospectus.

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. As calculated in this prospectus, 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 may 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. For a further discussion of cash available for distribution, including a reconciliation of net cash provided by (used in) operating activities to cash available for distribution and discussion of its limitations, see “Cautionary Statement Regarding the Use of Non-GAAP Measures” and footnote 3 under the heading “Summary Historical and Pro Forma Financial Data” elsewhere in this prospectus.

We define cash available for distribution before principal payments as the sum of cash available for distribution and 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.

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

MWh sold and average realized electricity price. We sold 658,243 MWh of electricity in the three months ended June 30, 2013 as compared to 429,350 MWh sold in the three months ended June 30, 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 and higher production at Gulf Wind, Hatchet Ridge and St. Joseph primarily as a result of higher winds during 2013. Our average realized electricity price was approximately $79 per MWh in the three months ended June 30, 2013 as compared to approximately $67 per MWh in the three months ended June 30, 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.

Revenue. Revenue for the three months ended June 30, 2013 was $58.7 million compared to $24.9 million for the three months ended June 30, 2012, an increase of $33.8 million, or approximately 136%. This increase in revenue during 2013 as compared to 2012 was the result of an increase of $24.3 million in electricity sales attributable to the commencement of commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012 and higher production at Gulf Wind, Hatchet Ridge and St. Joseph during 2013 as compared to 2012 primarily due to stronger winds. Also during the three months ended June 30, 2013 we recorded other revenue of $11.4 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 $1.1 million in quarter-over-quarter revenue due to a change in energy derivative valuation. In 2013, we recorded a $5.1 million unrealized loss on energy derivative compared to a $4.0 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 three months ended June 30, 2013 was $32.5 million compared to $18.8 million for the three months ended June 30, 2012, an increase of $13.7 million, or approximately 73%. The increase in cost of revenue during 2013 as compared to 2012 was 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 $7.1 million of the $13.7 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.

Related party general and administrative expense. Related party general and administrative expense for the three months ended June 30, 2013 was $2.7 million compared to $2.6 million for the three months ended June 30, 2012, an increase of $0.1 million, or approximately 4%, 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 on these projects advanced in 2013.

Other income and expense. Other income for the three months ended June 30, 2013 was $13.0 million compared to $3.7 million of other expense for the three months ended June 30, 2012. The increase of $16.7 million in other income during 2013 as compared to 2012 was primarily related to a $13.5 million increase in equity in earnings in unconsolidated investments, which was primarily attributable to interest rate swaps that were entered into in 2013 and which are 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 an $8.3 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 three months ended June 30, 2013 we also recorded a $7.2 million gain on the sale of Puerto Rico tax credits at the Santa Isabel project. Offsetting these gains was an $8.7 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.

Adjusted EBITDA. Adjusted EBITDA for the three months ended June 30, 2013 was $46.0 million compared to $18.4 million for the three months ended June 30, 2012, an increase of $27.6 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 footnote 2 to the table under the heading “Summary Historical and Pro Forma Financial Data” elsewhere in this prospectus.

MWh sold and average realized electricity price. We sold 1,261,876 MWh of electricity in the six months ended June 30, 2013 as compared to 874,331 MWh sold in the six months ended June 30, 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 $81 per MWh in the six months ended June 30, 2013 as compared to approximately $70 per MWh in the six months ended June 30, 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.

Revenue. Revenue for the six months ended June 30, 2013 was $102.5 million compared to $63.3 million for the six months ended June 30, 2012, an increase of $39.2 million, or approximately 62%. This increase in revenue during 2013 as compared to 2012 was the result of an increase of $42.7 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 six months ended June 30, 2013 we recorded other revenue of $11.4 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 $13.6 million in period-over-period revenue due to energy derivative valuation. In 2013, we recorded a $11.9 million unrealized loss on energy derivative compared to a $1.7 million unrealized gain 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 six months ended June 30, 2013 was $68.0 million compared to $37.5 million for the six months ended June 30, 2012, an increase of $30.5 million, or approximately 81%. The increase in cost of revenue during 2013 as compared to 2012 was 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 $18.9 million of the $30.5 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.

Related party general and administrative expense. Related party general and administrative expense for the six months ended June 30, 2013 was $5.4 million compared to $4.8 million for the six months ended June 30, 2012, an increase of $0.6 million, or approximately 13%, 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 on these projects advanced in 2013.

Other expense. Other expense for the six months ended June 30, 2013 was $11.0 million compared to $11.5 million for the six months ended June 30, 2012. The decrease of $0.5 million in other expense during 2013 as compared to 2012 was primarily related to an $3.4 million increase in equity in earnings in unconsolidated investments, which was primarily attributable to interest rate swaps that were entered into in 2013 and which are 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 $10.2 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 six months ended June 30, 2013 we also recorded a $7.2 million gain on the sale of Puerto Rico tax credits at the Santa Isabel project 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 $17.3 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.

Adjusted EBITDA. Adjusted EBITDA for the six months ended June 30, 2013 was $80.4 million compared to $40.7 million for the six months ended June 30, 2012, an increase of $39.7 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 footnote 2 to the table under the heading “Summary Historical and Pro Forma Financial Data” elsewhere in this prospectus.

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 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.

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 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 footnote 2 to the table under the heading “Summary Historical and Pro Forma Financial Data” elsewhere in this prospectus.

MWh Sold and average realized electricity price. We sold 1,568,022 MWh of electricity in the year ended December 31, 2011 as compared to 643,478 MWh in the year ended December 31, 2010. This increase in MWh sold during 2011 as compared to 2010 was primarily attributable to a full year of operations at Gulf Wind in 2011 as compared to a partial year in 2010 following our acquisition of Gulf Wind in March of 2010, the commencement of commercial operations at Hatchet Ridge in December 2010 and at St. Joseph in April 2011. Our average realized electricity price was approximately $75 per MWh in the year ended December 31, 2011 as compared to approximately $55 per MWh in the year ended December 31, 2010. This increase in average realized electricity price during 2011 as compared to 2010 was primarily attributable to unusually high spot electricity prices at our Gulf Wind project in 2011 when prices exceeded $2,000 per MWh for approximately 24 hours during 2011 and the additional contributions from Hatchet Ridge and St. Joseph in 2011, following commencement of operations in December 2010 and April 2011, respectively, as the pricing terms under the Hatchet Wind and St. Joseph project PPAs are each higher than our overall average.

Revenue. Revenue for the year ended December 31, 2011 was $135.9 million compared to $49.6 million for the year ended December 31, 2010, an increase of $86.3 million, or approximately 174%. The increase in revenue during 2011 as compared to 2010 was attributable to a full year of electricity sales and higher spot electricity prices at our Gulf Wind project in 2011 as compared to a partial year of revenue in 2010 following our acquisition of Gulf Wind in March of 2010, a full year of electricity sales from Hatchet Ridge following the commencement of commercial operations in December 2010 and a partial year of electricity sales from St. Joseph in 2011 following the commencement of commercial operations in April 2011. In addition, for the year ended December 31, 2011 we recorded a $17.6 million unrealized gain on energy derivative for the period compared to a $14.0 million gain for the year ended December 31, 2010 due to changing forward electricity prices, which are impacted by changes in forward natural gas prices. During the years ended December 31, 2011 and 2010, forward natural gas and electricity price curves decreased which increased the value of our energy derivative and increased revenue.

Cost of Revenue. Cost of revenue for the year ended December 31, 2011 was $70.8 million compared to $31.5 million for the year ended December 31, 2010, an increase of $39.3 million, or approximately 125%. The increase in cost of revenue during 2011 as compared to 2010 was attributable to a full year of costs at Gulf Wind in 2011 as compared to a partial year of costs in 2010 following our acquisition of Gulf Wind in March 2010 and costs related to Hatchet Ridge and St. Joseph following the commencement of commercial operations in December 2010 and April 2011, respectively. As our projects commence commercial operations, we begin incurring 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, 2011 were $0.7 million compared to $3.1 million for the year ended December 31, 2010, a decrease of $2.4 million, or approximately 77%. The decrease in development expenses were primarily attributable to our determination that development expenses related to Ocotillo should be capitalized starting in the first quarter of 2011, and offset by an increase in development expenses related to El Arrayán.

Related party general and administrative expense. Related party general and administrative expense for the year ended December 31, 2011 was $8.1 million compared to $6.7 million for the year ended December 31, 2010,

an increase of $1.4 million, or approximately 21% resulting primarily from the increased staffing and overhead costs related to commercial operations commencing at Hatchet Ridge and St Joseph in December 2010 and April 2011, respectively, and the incremental construction activities at Spring Valley, Santa Isabel and Ocotillo as well as our ownership in El Arrayán and South Kent as development on those projects advanced in 2011.

Other expense. Other expense for the year ended December 31, 2011 was $28.8 million compared to $1.6 million for the year ended December 31, 2010. The increase in other expense during 2011 as compared to 2010 was primarily attributable to a $18.0 million, or approximately 154%, increase in interest expense in 2011, offset by a $20.2 million gain on our acquisition of Gulf Wind in 2010 and a $2.0 million gain on the sale of a portion of our investment in El Arrayán in 2010. The gains in 2010 were partially offset by a $6.6 million realized loss on derivatives and a $5.8 million loss on early extinguishment of indebtedness in connection with the closing of a sale-leaseback financing transaction following the commencement of operations at Hatchet Ridge in 2010. The increase in interest expense in 2011 is primarily attributable to a discontinuation of the capitalization of interest following the commencement of commercial operations at Hatchet Ridge and St. Joseph in December 2010 and April 2011, respectively.

Adjusted EBITDA. Adjusted EBITDA for the year ended December 31, 2011 was $77.3 million compared to $6.9 million for the year ended December 31, 2010, an increase of $70.4 million. The increase in Adjusted EBITDA during 2011 as compared to 2010 was primarily attributable to a full year of operations at Gulf Wind in 2011 as compared to a partial year in 2010 following our acquisition of Gulf Wind in March of 2010, a full year of electricity sales following the commencement of commercial operations at Hatchet Ridge in the fourth quarter of 2010 and a partial year of electricity sales from St. Joseph in 2011 following the commencement of commercial operations in April 2011. The increase was also affected by 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 did not occur in 2010. For a reconciliation of net income to Adjusted EBITDA, see footnote 2 to the table under the heading “Summary Historical and Pro Forma Financial Data” elsewhere in this prospectus.

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 holders of our Class A shares, (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 cash flow years in order to have additional liquidity in below-average cash flow years. Our sources of liquidity include cash generated by our operations, cash reserves, borrowings under our corporate and project-level credit agreements and further issuances of equity and debt securities.

Like other companies in the independent power industry, we hold our projects through special purpose project entities and sometimes through holding companies that own interests in the project entities, including joint ventures. Distributions from these project entities are our primary source of cash flow, and investments in these entities are our primary use of capital. Once operational, our projects are capitalized in order to fund their own operating activities, debt service, taxes and other capital and operating expenses. Prior to becoming operational, our project entities rely on equity that we and any project partners invest, together with non- or limited-recourse project indebtedness, to build or acquire our projects. Our project entities and joint ventures typically employ project debt from lenders who require that we provide a commitment for all of the required project equity before the lenders will make any loans available. The amount of project debt that we can raise is usually determined by reference to targeted minimum expected debt service coverage ratios under both an expected (i.e., P50) production case and a lower production case or minimum equity investment levels.

Our project entities hold cash reserves that are, in certain cases, held for specifically designated uses, including working capital, operations and maintenance and debt service reserves, and are generally subject to

“waterfall” provisions that allocate project revenues to specified priorities of use (such as operating expenses, scheduled debt service, targeted debt service reserves, and any other reserves) and the remaining cash is distributable to us only on certain dates and subject to satisfaction of certain conditions. As of December 31, 2012, and throughout the period during which we had an ownership interest, none of our operating project entities were subject to blocks on the distribution of cash flow to us as a result of a failure to meet distribution conditions. Our project entities are generally allowed to distribute excess cash flow on or shortly after the regularly scheduled debt service payment dates, which are quarterly for Gulf Wind, Spring Valley, Santa Isabel and Ocotillo, semiannually for Hatchet Ridge and monthly for St. Joseph.

The principal indicators of our liquidity are our restricted and unrestricted cash balances and availability under our credit agreements. As of June 30, 2013, our available liquidity was $312.7 million, including restricted cash on hand of $132.9 million, unrestricted cash on hand of $41.8 million, and $138.0 million available under our credit agreements.

We believe that following the completion of this offering 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. 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. 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, we may, from time to time, issue debt or equity securities.

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.

Net cash provided by operating activities was $41.7 million for the six months ended June 30, 2013 as compared to $24.8 million for the six months ended June 30, 2012. Electricity sales were $42.7 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 six months ended June 30, 2013 we recorded other revenue of $11.4 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 electricity sales and other revenue is an $8.2 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 $11.7 million in project expenses, and a period-over-period increase in cash interest expense of $13.9 million.

Net cash provided by investing activities was $63.4 million for the six months ended June 30, 2013, which consisted of $173.4 million of ITC grant proceeds at Ocotillo and Santa Isabel and $14.3 million of proceeds from the sale of investments and tax credits, offset by $111.1 million of capital expenditures primarily at Ocotillo and Santa Isabel and $6.6 million for interconnection network upgrades primarily at our Ocotillo project. Net cash used in investing activities was $241.4 million for the six months ended June 30, 2012 consisting primarily of capital expenditures at Spring Valley, Santa Isabel and Ocotillo, $37.4 million for interconnection network upgrades primarily at our Ocotillo project and an $18.5 million investment in our El Arrayán project.

Net cash used in financing activities for the six months ended June 30, 2013 was $79.8 million, which was attributable to $118.0 million of loan borrowings primarily at Santa Isabel and Ocotillo, a $56.0 million loan draw under our revolving credit facility offset by the $57.5 million repayment of our Santa Isabel grant loan, $21.8 million of long-term debt repayments, $116.7 million increase in restricted cash balances primarily at Ocotillo and distributions to controlling interests. Net cash provided by financing activities for the six months ended June 30, 2012 was $217.7 million, which was primarily attributable to $98.5 million of capital contributions, $163.4 million of loan borrowings at Spring Valley and Santa Isabel, offset by loan repayments and capital distributions.

Cash available for distribution was $30.7 million for the six months ended June 30, 2013 as compared to $10.9 million for the six months ended June 30, 2012, an increase of $19.8 million. This increase in cash available for distribution was the result of higher electricity sales of $42.7 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 six months ended June 30, 2013, we recorded other revenue of $11.4 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 this increase in electricity sales were period-over-period increases of $11.7 million in project expenses, $13.9 million in cash interest expense, and $4.6 million in principal payments from operating cash flows as the additional projects commenced operations in late 2012.

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 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.

Net cash provided by operating activities was $46.9 million for the year ended December 31, 2011 as compared to $3.0 million net cash used in operating activities for the year ended December 31, 2010. This increase in cash provided by operating activities was primarily the result of an increase in net income due to a full year of operations and unusually high spot electricity prices at Gulf Wind in 2011, a full year of operations at Hatchet Ridge and nine months of operations at St. Joseph following commencement of commercial operations in December 2010 and April 2011, respectively.

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 used in investing activities was $460.2 million for the year ended December 31, 2010, which consisted of $386.3 million of capital expenditures at Hatchet Ridge and St. Joseph, and $80.3 million investment in our Hatchet Ridge note receivable, and was partially offset by proceeds from the sale of interests in our Gulf Wind and El Arrayán projects.

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. Net cash provided by financing activities for the year ended December 31, 2010 was $472.3 million, which was primarily attributable to $271.1 million of net borrowings related to construction of St. Joseph and Hatchet Ridge and the acquisition of Gulf Wind, and $297.1 million of capital contributions, and $79.0 million of capital distributions.

Cash available for distribution was $18.5 million for the year ended December 31, 2011 as compared to $(17.8) million for the year ended December 31, 2010. This increase in cash available for distribution was primarily the result of a full year of operations at Gulf Wind which we acquired in March 2010, a full year of operations at Hatchet Ridge and nine months of operations at St. Joseph following commencement of commercial operations in December 2010 and April 2011, respectively, and was partially offset by a $6.9 million increase in distributions to noncontrolling interests and an $8.6 million increase in principal payments in 2011 as compared to 2010. The increase was also affected by higher spot electricity prices at our Gulf Wind project in 2011, including unusually high prices that exceeded $2,000 per MWh for approximately 24 hours during 2011 and did not occur in 2010.

We will initially own only those projects that we acquire through the Contribution Transactions. Each of the acquired project entities have 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. In 2012, we incurred approximately $641.4 million in capital expenditures to complete the construction of our Spring Valley and Santa Isabel projects and a portion of our Ocotillo project. In 2013, we expect to incur approximately $132.8 million in capital expenditures primarily related to completing construction of the Ocotillo project and to invest a de minimis amount of equity in our joint venture projects, El Arrayán and South Kent. All of these capital expenditures and investments in 2013 have either been funded by PEG LP or are available from project finance lenders under project-level credit facilities. See “—Credit Agreements.”

Following the completion of this offering, we expect to make investments in additional projects. Although we have no commitments to make any such acquisitions, we consider it reasonably likely that we may have the opportunity to acquire the Initial ROFO Projects under our Purchase Rights at various times within the 18-month period following the completion of this offering. We do not expect to have sufficient amounts of cash on hand to fund the acquisition costs of all of the Initial ROFO Projects. As a result, in order to acquire the Initial ROFO Projects, we will need to either finance a portion of such acquisitions by raising additional equity or issuing new debt. We believe that we will have the financing capacity to pursue such opportunities, but we are subject to business, operational and macroeconomic risks that could adversely affect our cash flows and ability to raise capital. A material decrease in our cash flows or downturn in the equity or debt capital markets would likely produce a corresponding adverse effect on our capacity to make such investments.

In addition, we will make investments from time to time at our operating projects. The operating projects that we own consist of large capital assets that have achieved commercial operations. Ongoing capital expenditures for assets of this nature are generally not significant because most expenditures relate to repairs and maintenance and are expensed when incurred. Operational capital expenditures are those capital expenditures required to maintain our long-term operating capacity. For example, operational capital expenditures include expenditures associated with the upgrade of existing equipment and structures to improve project availability or the installation of new equipment required by electricity grid operators. Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity over the long term, such as expansion capital expenditures include blade retrofits to improve wind utilization. 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.

For the year ending December 31, 2013, we have budgeted $0.7 million for operational capital expenditures and $2.1 million for expansion capital expenditures. We have established a cash reserve to fund these expansion capital expenditures.

Following the Contribution Transactions, certain of our subsidiaries will continue to be party to our revolving credit facility.

Following the Contribution Transactions, our project subsidiaries will continue to be party to their current project-level credit facilities.

See “Description of Certain Financing Arrangements” for a further discussion of the terms of our credit agreements.

The following table summarizes the contractual obligations of our predecessor as of December 31, 2012 (in thousands):

In March 2013, we became aware that an upstream owner of PEG LP and us, a “tax-exempt controlled entity” formed in 2009 to hold certain domestic tax-exempt investors’ interests in PEG LP and indirectly hold approximately a 27% ownership interest in PEG LP, inadvertently failed upon its formation and thereafter to file an election to not be treated as a tax-exempt entity under section 168(h)(6) or 168(h)(5) of the Internal Revenue Code. As a result, certain of our assets are deemed to be tax-exempt use property and are subject to less favorable tax depreciation treatment than we had anticipated prior to such determination. As a result of the discovery of this inadvertent failure to file the required election, the upstream owner filed such an election in April 2013, which is effective as of January 1, 2012, and requested from the IRS a further retroactive application of the election beginning upon the formation of the upstream owner, the outcome of which will not be known until later in 2013.

Until the IRS grants the upstream owner’s request for retroactive application of the election, we are technically in breach of certain affirmative representations made to certain financing counterparties and are subject to indemnity and damage claims with respect to a resulting deferral of tax benefits which we intended to make available to those counterparties. We estimate that the potential aggregate exposure to these counterparties is approximately $1.7 million. Based on our review of the facts related to the upstream owner’s request for retroactive relief, we believe it is likely that relief will be granted to the upstream owner, and that no indemnity or damages will be payable to affected counterparties, and accordingly have made no accrual of the contingent liability.

Our discussion and analysis of our financial condition and results of operations are based on our predecessor’s combined historical financial statements that are included elsewhere in this prospectus, 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, derivatives, income tax, revenue recognition, certain components of cost of revenue and exemptions 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 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 deemed to extend the useful economic life of an asset are capitalized. Repair and maintenance costs are expensed as incurred.

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

We recognize our derivative instruments at fair value in the combined 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 undesignated derivative instruments their change in fair value is reported as a component of net income on the combined statement of operations.

Interest rate swaptions are instruments used to fix the terms of prospective interest rate derivatives that may be required when the related debt is refinanced. 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.

Our predecessor entered into interest rate swaptions in 2009. The swaptions were terminated in 2010. Our predecessor entered into an interest rate cap in 2010. The cap remains in place as of June 30, 2013.

Our predecessor 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 predecessor’s swaptions, interest rate cap and energy derivative agreement do not qualify for hedge accounting.

Income taxes have not been provided for because our predecessor 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. U.S. federal and state income taxes are assessed at the owner level and each owner is liable for its own tax payments. Certain combined entities are corporations or have elected to be taxed as corporations. In these circumstances, income tax is accounted for under the asset and liability method.

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 840, or “ASC 840,” Leases and Accounting Standards Codification 815, or “ASC 815,” Derivatives 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.

Our predecessor acquired a ten-year energy derivative instrument under the terms of its acquisition of Gulf Wind, which fixes approximately 58% of our expected electricity sales at Gulf Wind through April 2019. The energy 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 combined statements of operations. The change in the fair value of the energy hedge is classified as energy derivative revenue in the combined statements of operations.

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

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 are in the process of evaluating 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 instance, Canadian securities laws require three years of audited financial statements to be included in this prospectus, and as a result, will not permit us to take advantage of the reduced financial statement requirements permitted under the JOBS Act. 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 the completion of this offering; although, if the market value of our shares that are 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.

We have evaluated recent accounting pronouncements and their adoption has not had or is not expected to have a material impact on our financial statements.

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.

We manage our commodity price risk for electricity sales through the use of long-term power sale agreements with creditworthy counterparties. Our predecessor’s financial results reflect approximately 323,000 MWh of electricity sales in the year ended December 31, 2012 that were not subject to power sale agreements and were subject to spot market pricing. A hypothetical increase or decrease of $3.00 per MWh (or an approximately 12% change) in these spot market prices would have increased or decreased earnings by $1.0 million, respectively, for the year ended December 31, 2012.

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 predecessor’s earnings for the year ended December 31, 2012.

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. Our predecessor 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 predecessor’s financial results include approximately $41.4 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 predecessor’s earnings by $0.2 million for the year ended December 31, 2012, and a hypothetical decrease of US$0.10 per Canadian dollar would have decreased our predecessor’s earnings by $0.2 million for the year ended December 31, 2012.

According to the U.S. Energy Information Administration, or “EIA,” International Energy Outlook 2011, global net electricity generation is expected to grow at a CAGR of 2.4% from 2008 to 2020. Although the 2008-2009 global economic recession slowed the rate of growth in global demand for electricity, demand returned in 2010, led by strong recoveries in non-Organisation for Economic Co-operation and Development, or “OECD,” countries. The EIA expects net electricity generation in non-OECD countries to grow at a CAGR of 3.8% from 2008 to 2020, led by non-OECD Asia (including China and India), which is expected to grow at a CAGR of 5.0%. In contrast, total net electricity generation in OECD countries is expected to grow at a CAGR of 1.1% over the same period. In all of these markets, transmission infrastructure expansion will be required to transmit electricity from new power generation projects to areas of customer demand.

Renewable energy is generated using naturally-replenishing resources such as water, wind, sunlight, plant and wood waste, and geothermal energy. In many parts of the world, increasing concerns regarding manufacturing jobs, security of energy supply and the environmental consequences of greenhouse gas emissions as well as the outlook for fossil-fuel prices have resulted in governmental policies that support an increase in electricity generation from renewable energy. Over the period from 2008 to 2020, the EIA expects net electricity generation from renewable energy to be the fastest growing source of net electricity generation at a CAGR of 4.6%. The significant growth in electricity generation from renewable energy is principally the result of an improvement in the cost competitiveness of renewable energy technologies and support from governments to increase the contribution of electricity generation from renewable energy. According to the EIA, net electricity generation from renewable energy accounted for 19.1% of global net electricity generation in 2008, making it the third largest contributor after coal and natural gas. By 2020, net electricity generation from renewable energy is projected to account for 24.6% of global net electricity generation. While wind and solar resources are intermittent, depending on the time of day and climatic conditions, improving storage technology and the dispersing of wind power and solar power projects over wide geographic areas can mitigate these concerns.

Natural gas is expected to be the third fastest growing source of electricity generation. An increase in unconventional natural gas resources, in particular, in North America, is expected to result in growth in net electricity generation from natural gas at a CAGR of 2.6% from 2008 to 2020.

The EIA expects net electricity generation from nuclear power to increase at a CAGR of 3.0% from 2008 to 2020. However, there is still considerable uncertainty regarding the future of nuclear power, which suggests that the EIA’s expectations for the addition of new nuclear power generating capacity may not be fully realized. Further, the EIA expects approximately 72% of the increase in net electricity generating capacity from nuclear power to occur in non-OECD countries, with China, Russia and India accounting for the largest growth through 2020.

Future net electricity generation from renewable energy, natural gas, and, to a lesser extent, nuclear power is largely expected to displace net electricity generation from coal, although coal is expected to remain the largest source of global net electricity generation through 2020.

Source: International Energy Outlook 2011—U.S. Energy Information Administration

Over the period from 2008 to 2020, the EIA expects 52% and 32% of the increase in net electricity generation from renewable energy to be from hydro power and wind power, respectively. While hydro power represented 85.2% of global net electricity generation from renewable energy in 2008, its contribution is expected to decline to approximately 71.4% by 2020 as projects utilizing other renewable energy technologies, including wind power and solar power, come online. Net electricity generation from wind power is expected to increase at a CAGR of 14.2% from 2008 to 2020, increasing its contribution to global net electricity generation from renewable energy from 5.7% in 2008 to 16.5% in 2020.

Source: International Energy Outlook 2011—U.S. Energy Information Administration

The regulatory frameworks applicable to the electricity industry vary between regions.

Electricity markets in the United States are subject to regulation at both the federal and state levels. Federal law provides for the exclusive jurisdiction over the sale of electricity at wholesale and the transmission of electricity in interstate commerce, while state regulators review individual utilities’ electricity supply requirements and have oversight over the ability of public utilities to pass through to their ratepayers the costs associated with power purchases from IPPs. Federal regulatory filings are required for renewable energy projects in the United States that sell energy at wholesale, but state and local approvals (such as siting and permitting approvals) typically require more time to secure.

FERC regulates the sale of electricity at wholesale and the transmission of electricity pursuant to its regulatory authority under the Federal Power Act. FERC’s jurisdiction includes, among other things, authority over the rates, charges and other terms for the sale of electricity at wholesale by public utilities (entities that own or operate projects subject to FERC jurisdiction) and for transmission services. In most cases, FERC does not set specific rates for the sale of electricity at wholesale by generating companies (such as our U.S. project companies) that qualify for market-based rate authority, enabling companies to price based upon negotiated rates reflecting market conditions. In order to be eligible for market-based rate authority, and to maintain exemptions from certain FERC regulations, our projects must request market based rate authorization from FERC. With respect to its regulation of the transmission of electricity, FERC requires transmission providers to provide open access transmission services, which supports the development of non-utility power generators and competitive power markets by assuring non-discriminatory access of non-utility generators to the transmission grid. FERC has also encouraged the formation of regional transmission operators, or “RTOs,” to allow non-utility generators greater access to transmission services and certain competitive wholesale markets administered by RTOs.

In 2005, the U.S. federal government enacted the Energy Policy Act of 2005, or “EPACT 2005,” conferring new authority for FERC to act to limit wholesale market power if required and strengthening FERC’s criminal and civil penalty authority (including the power to assess fines of up to $1 million per day per violation), and adding certain disclosure requirements. EPACT 2005 also directed FERC to develop regulations to promote the development of transmission infrastructure, which provides incentives for transmitting utilities to serve renewable energy projects and expanded and extended the availability of U.S. federal tax credits to a variety of renewable energy technologies, including wind power.

In addition, PUHCA provides FERC and state regulatory commissions with access to the books and records of holding companies and other companies in holding company systems, and it also provides for the review of certain costs. Companies that are holding companies under PUHCA solely with respect to one or more EWGs, “qualifying facilities”, or foreign utilities are exempt from these books and records requirements. Each of our U.S. projects must request EWG or qualifying facility status, as applicable, and file updates to ensure they maintain the applicable status and are not treated as a holding company under PUHCA. Given that our operating projects in the U.S. are all EWGs, we are exempt from regulation under PUHCA.

While federal law provides the utility regulatory framework for our sales of electricity at wholesale in interstate commerce, there are also important areas in which state regulatory actions over traditional public utilities that fall under state jurisdiction may have an effect on our U.S. projects. For example, the regulated electric utility buyers of electricity from our projects are generally required to seek state public utility commission approval for the pass through in retail rates of costs associated with PPAs entered into with a wholesale seller, such as one of our U.S. projects. Certain states, such as New York, regulate to some extent the transfer of wholesale power projects and financing activities by the owners of such projects. California, one of our markets, requires compliance with certain operations and maintenance reporting requirements for wholesale generators. In addition, states and other local agencies require a variety of environmental and other permits.

In Canada, provincial governments have jurisdiction over their respective intra-provincial electricity markets and the Canadian federal government has jurisdiction over inter-provincial and international transmission and export permitting. Significant regional diversity of the sources of supply and market structures exists among provinces. In addition, the pace and extent of electricity market deregulation varies among, and reflects the unique circumstances and challenges faced by, each province. In recent years there has been a shift to retail and wholesale competition in Alberta and to a much lesser extent in Ontario, and some other provinces have undertaken varying degrees of sector unbundling through the granting of PPAs to IPPs and greater access to transmission and distribution networks. As a result, the number of IPPs active across Canada has increased. Some provinces are experiencing supply adequacy challenges during demand peaks and are focused on immediate generation and transmission investments for both short-term reliability and long-term security of supply, while surplus baseload generation is presently occurring in Ontario.

Energy policy in Chile is founded on the principles of free market competition between private companies, the regulation of natural monopolies and the limited role of the state. Chile has two major electricity grids, the Central Interconnected System, or the “SIC,” and the Northern Interconnected System, or the “SING.” Each of these two main grids has its own independent system operator and market administrator, a Centro de Despacho Económico de Carga, or “CDEC,” and is subject to the oversight of La Comisión Nacional de Energía, or “CNE.” The CDECs’ functions include ensuring an adequate supply of electricity into the system and providing efficient and economical dispatch of power projects.

In the United States, power prices vary across regions and states. The price of electricity varies based on supply and demand dynamics, generation mix, fuel-supply costs and other inputs required to generate electricity and relevant environmental laws and regulations.

California ranked second in the United States in terms of electricity generating capacity, which stood at approximately 68 GW as of the end of 2011. Electricity in California is principally sold by load-serving utilities which buy the majority of their required electricity supply from IPPs. Load-serving entities within the state include investor-owned utilities, including Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric, and municipal utilities, including Los Angeles Department of Water and Power, Sacramento Municipal Utilities District, and the Imperial Irrigation District. The market clearing price of electricity in California is highly correlated with the price of natural gas as natural gas-fired projects are the marginal cost electricity generators. The average retail electricity price in California was approximately 13.1 cents/kWh in 2011. Much of the California power grid is operated by the CAISO, which operates and controls the bulk transmission grid and also administers a competitive bulk power market. Approximately 80% of California’s load falls within the footprint of the CAISO, with the remaining 20% served by irrigation districts and municipal utilities, which have chosen not to join the CAISO.

Texas had approximately 109 GW of electricity generating capacity as of the end of 2011, ranking first nationally. The provision of transmission and distribution service in Texas remains regulated by the Public Utility Commission of Texas, or “PUCT.” Population growth, an improving economy and extreme temperatures have resulted in record electricity demand during the past two summer seasons and two of the past four winter seasons in ERCOT. The market clearing, real-time settlement-point price of electricity within ERCOT is highly correlated with the price of natural gas as natural gas-fired projects are the marginal cost electricity generators in Texas for most of the on-peak hours. The average retail electricity price in Texas was approximately 9.0 cents/kWh in 2011.

The Texas power market is deregulated, with competition in wholesale electricity generation and retail electricity sales. Most of Texas is within the ERCOT NERC region, with the balance included in the Southwest Power Pool, or “SPP,” and SERC Reliability Council regions. ERCOT is an ISO that serves approximately 85% of Texas’ electricity load and is subject to oversight by the PUCT. ERCOT is a self-contained market on a standalone grid with only approximately 1,100 MW of transfer capability through direct current ties with the SPP and the Comision Federal de Electricidad in Mexico. Nearly 95% of ERCOT transactions are bilateral, with only 5% of market operations conducted in the real-time energy market. In December 2010, ERCOT replaced its zonal market design with a nodal market. The nodal system was designed to mitigate congestion costs with a greater number of settlement points and improve wind power dispatch efficiency, given more frequent and specific instructions to controllable generation. The nodal market continues to support bilateral agreements, such as long-term power sale agreements, designated at settlement points.

In order to address curtailment issues that have historically impacted wind power projects in the western and northwestern areas of the State of Texas, the PUCT over the past several years has implemented a project to construct over $6 billion of new transmission facilities to serve those installations, or the “CREZ Transmission Lines.” The primary CREZ Transmission Lines have all been certificated, and construction on most of the CREZ Transmission Lines is expected to be completed during 2013.

Nevada had approximately 11,646 MW of electricity generating capacity as of the end of 2011. In 1997, Nevada began to deregulate its power markets, but this plan was suspended in 2001. Electricity is regulated in the state by the Public Utility Commission of Nevada. The Nevada market is primarily served by NV Energy, Inc., or “NV Energy,” an integrated utility holding company, with natural gas as its primary fuel for electricity generation. The average retail electricity price in Nevada was approximately 9.0 cents/kWh in 2011.

PREPA is a public corporation and governmental instrumentality of Puerto Rico. PREPA transmits and distributes virtually all of the electricity consumed in Puerto Rico. As of June 30, 2011, PREPA owned and had entered into power sale agreements for approximately 4,878 MW and 961 MW of electricity generating capacity, respectively. Imported heavy distillate oil and residual oil are the primary fuels utilized for electricity generation in Puerto Rico. The average retail electricity price in Puerto Rico was approximately 23.8 cents/kWh in the 12–month period ended June 30, 2011.

Similar to the United States, power prices in Canada vary across regions and provinces. The price of electricity varies based on supply and demand dynamics, generation mix, fuel supply costs and other inputs required to generate electricity and relevant environmental laws and regulations.

Ontario ranks second in Canada in terms of electricity generating capacity, which stood at approximately 37 GW as of the end of 2012. Ontario’s electricity market is structured around the five entities that resulted from the break-up of Ontario Hydro in 1999, namely: the Ontario Electricity Financial Corporation, Ontario Hydro’s legal successor with the mandate to manage and retire Ontario Hydro debt and contractual obligations with certain IPPs; Ontario Power Generation, or “OPG,” the electricity generating company, which generated approximately 60% of the electricity in Ontario in 2012; Hydro One Inc., the transmission and rural distribution company; the IESO, the grid operator that ensures security of supply, operates the spot market providing open access to regulated transmission systems; and the OPA, which awards and enters into PPAs for the supply of new electricity generation in Ontario.

Manitoba had approximately 5,927 MW of electricity generating capacity as of the end of 2012, which consists predominantly of hydro power. Manitoba Hydro is a Crown Corporation of the Province of Manitoba and generates, transmits and distributes virtually all of the electricity consumed in the province. Manitoba is a net exporter of electricity, mainly to Saskatchewan, Ontario and certain midwestern states of the United States. To date, the province has successfully utilized its large hydro power resources to satisfy its internal demand for electricity while exporting the balance.

Chile had approximately 18.3 GW of electricity generating capacity as of November 2012. Chile’s Ministry of Energy expects electricity consumption in Chile to increase at an annual rate of approximately 6% to 7% from 2011 to 2020. According to the Ministry of Energy, 63% of Chile’s electricity generation is generated from fossil fuel-fired sources, the majority of which is imported, 34% from domestic hydro power and only 3% from renewable energy, including wind power, small-scale hydro power and biomass. According to figures published by the OECD, electricity prices in Chile posted a four-fold increase between 1998 and 2011 due in large part to its dependence on foreign energy sources and a reduction in natural gas supply from Argentina. To satisfy this expected increase in demand, Chile’s Ministry of Energy estimates that approximately 8,000 MW of additional electricity generating capacity would be required.

Wind power has been one of the fastest growing sources of electricity generation in North America and globally over the past decade. According to GWEC, from 2001 to 2012, net electricity generation from wind power in the United States and Canada grew at a CAGR of 27% and 37%, respectively. According to AWEA, wind was the number one source of new U.S. generating capacity in 2012. However, uncertainty related to the demand for new power projects in general and the potential expiration of U.S. federal incentives on December 31, 2012 resulted in a reduction in the build rate of wind power and other renewable energy projects in 2013 and potentially 2014 from a high of 13,124 MW installed in 2012, according to AWEA. The EIA expects an additional 37 GW of wind power generating capacity to be installed in the United States and Canada between 2008 and 2020, resulting in approximately 64 GW in 2020. According to Wood Mackenzie, 8% of the U.S. and Canadian power supply is estimated to come from wind by 2020. This rapid growth 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 past 20 years, according to AWEA.

Wind power projects have a longstanding history of being able to secure long-term PPAs with creditworthy counterparties. Counterparties to PPAs, which are typically electric utilities, enter into these agreements to satisfy their requirements for electricity generating capacity, interest in diversifying their power sources, interests of their customers, or governmental mandates requiring a portion of their electricity supply to come from renewable energy sources. By entering into long-term, fixed-price PPAs, utilities are able to insulate themselves from the volatility in wholesale electricity prices that are typically passed on to ratepayers in their jurisdictions. Wind power generating capacity is typically sourced through a RFP, which is a solicitation by electric utilities for bids to provide a fixed generation amount, or a FIT program, which offers project operators fixed prices under long-term contracts for electricity typically generated from renewable energy sources. However, there are numerous cases of PPAs being negotiated on a bilateral basis with utilities and IPPs, such as PEG LP.

The United States is the second largest market for wind power in the world by electricity generating capacity. According to the 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 is evidenced by approximately $120 billion in investments to date, according to the AWEA. According to AWEA, 13,124 MW of new wind power generating capacity was installed across 32 U.S. states in 2012, a 93% increase from new installations in 2011. In 2012, wind power generating capacity grew 28% from 2011 to a total of 60 GW, equivalent to powering over 14.7 million homes. As of the end of 2012, 39 of the 50 U.S. states and Puerto Rico had utility-scale wind projects, and 15 states had more than 1,000

MW of wind power generating capacity. Texas and California, two of our markets, represent the first- and second-ranked states in terms of wind power generating capacity, as of the end of 2012. Despite this growth, wind power represented only 2.9% of electricity generating capacity in the United States as of the end of 2011. Based on the percentage of electricity generated by wind power in other developed countries, we believe that, despite a reduction in the build rate of wind power and other renewable energy projects in 2013 and potentially 2014, as a result of the uncertainty related to the demand for new power projects in general and the potential expiration of U.S. federal incentives on December 31, 2012, substantial growth potential remains in the U.S. market over the long-term.

Source: American Wind Energy Association, U.S. Wind Industry Fourth Quarter 2012 Market Report

As of December 31, 2012, California ranked second nationally in terms of overall wind installations, after Texas, with 5,549 MW of wind power generating capacity. In 2011, 4.1% of electricity in the state was generated from wind power, equivalent to powering approximately 1.2 million homes. The wind power installed in California avoids over 8.5 million metric tons of carbon dioxide annually. According to the National Renewable Energy Laboratory, or “NREL,” the California wind resource could meet 39.4% of the state’s current electricity needs.

As of December 31, 2012, Texas ranked first nationally in terms of overall wind installations with 12,212 MW of wind power generating capacity and was the first state to reach 10 GW of wind power generating capacity. It is home to seven of the nation’s largest ten wind power projects, including four of the top five. In 2011, 6.9% of electricity generated in the state was generated by wind power, and, as of the third quarter of 2012, the state generated electricity from wind power in an amount equivalent to powering over 2.7 million homes. The wind power installed in Texas avoids over 19 million metric tons of carbon dioxide annually. According to NREL, the Texas wind resource could meet 19 times the state’s current electricity needs. AWEA ranks the state’s wind resource as the first in the United States.

Our Spring Valley project was the first commercial-scale wind power project commissioned in Nevada, and the output from Spring Valley is currently being sold to NV Energy under a long-term PPA. According to NREL, the Nevada wind resource could meet nearly 60% of the state’s current electricity needs.

Our Santa Isabel project was the first commercial-scale wind power project to achieve commercial operations in Puerto Rico.

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. In 2012, new wind power projects were built in Ontario, Manitoba, British Columbia, Alberta, the Northwest Territories, Quebec and Nova Scotia, resulting in wind power generating capacity in Canada reaching approximately 6,500 MW as of January 2013. According to CanWEA, new installed wind power generating capactity 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 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.

Ontario is the current provincial leader, with approximately 2,043 MW of wind power generating capacity. We expect our South Kent project, representing 135 MW of owned capacity, to achieve commercial operation in the second quarter of 2014.

Manitoba has 259 MW of wind power generating capacity, including our St. Joseph project, which commenced commercial operations in 2011 and represents 138 MW of electricity generating capacity.

Chile has an abundant wind resource, which GWEC estimates could provide the potential for more than 40 GW of electricity generating capacity, including within the south-central zone where approximately 80% of Chile’s population resides. As of the end of 2011, Chile had approximately 200 MW of wind power generating capacity, representing approximately 1% of total electricity generating capacity. According to GWEC, as of the end of 2011, approximately 200 MW of wind power projects were under construction in Chile and an additional 2,700 MW were under development.

Wind power harnesses the kinetic energy of moving air. Electricity is generated from the energy of wind flows exerted on the blades of a wind turbine, which activates an electric generator. Wind turbines are equipped with a control system that optimizes electricity generation output. In addition, wind power projects can be monitored and operated remotely to respond to changing weather conditions, including shutting down during heavy lightning storms and rotating to adjust to shifts in wind direction.

The amount of energy that the wind transfers to the turbine depends on the blades’ surface area and the wind speed. The amount of energy captured by a wind turbine increases as a square-function of an increase in blade size. For example, doubling the surface area of the blades quadruples the wind energy captured. The speed of the wind has an even greater effect. As wind speed doubles, the available energy increases by a factor of eight. Stronger winds are also able to drive larger turbine blades. In order to maximize the efficiency of the transfer of energy from wind to electricity, blade size must be chosen to capture the most wind energy the highest proportion of the time.

As a result of these factors, manufacturers have developed wind turbines to increase blade size in order to increase the swept area of a turbine, thereby increasing the electricity generation of the turbine and simultaneously decreasing the cost of electricity generated. In addition, manufacturers have successfully increased the height of towers in order to benefit from greater wind speeds at higher elevations (e.g., shear) in many wind regions. According to AWEA, a typical wind turbine today generates approximately 15 times more electricity than a typical turbine in 1990 and can generate electricity equivalent to powering approximately 500 homes.

Not only has technological evolution increased a wind turbine’s ability to generate electricity, it has also increased the accuracy with which wind is forecast. New meteorological technology dispatched to a potential project site can measure wind at a higher hub height and rotor swept area with greater accuracy than previously possible. Additionally, improvements and new analytical methods have been incorporated into the prediction models. This improvement in forecasting has increased the predictability of the electricity generation of wind power projects, which, in turn, has increased their ability to attract long-term debt financing.

Wind is a source of energy that is naturally variable; wind generally does not blow at a constant speed throughout a given day nor month-to-month. As a result, the amount of electricity generated on a daily or monthly basis is also variable or intermittent. However, long-term historical site-specific measurements for wind power allow for an annual average or “mean” wind speed, enabling the use of statistical analyses to estimate electricity generation.

There are a number of factors that preclude a wind turbine from operating at its maximum theoretical electricity generation, but the primary factor is wind speed. As a result of the variance in wind speed at any given project, a turbine will be operating for significant periods of time at levels less than its maximum electricity generating capacity. Other factors also affect the capacity factor but are generally much less significant, including scheduled annual maintenance of electricity-generating equipment and unscheduled non-operation resulting from equipment failure. In general, wind power projects have capacity factors, defined as the percentage of electricity that an electricity-generating source is expected to generate relative to the maximum theoretical electricity generation in a given period of time, ranging from 20% to 60%, depending on various site and equipment-specific factors.

Wind power projects do not have any fuel costs and typically use remote monitoring systems, which enable off-site operation and supervision. In addition, improvements in wind turbine technology have increased the efficiency and reliability of wind power projects. As a result, operating expenses for wind power projects are generally lower than those of comparably-sized fossil fuel-fired power projects such as natural gas or coal.

Wind power projects are relatively simple to construct relative to conventional power projects. We believe that 50 MW and 200 MW wind power projects can be constructed within approximately six and 12 months, respectively, while constructing large-scale hydro power, natural gas, nuclear power or coal projects typically requires a longer timeframe. As a result, wind power projects are susceptible to far fewer risks associated with construction delays and cost over-runs.

Wind power projects do not emit any greenhouse gases or contribute to acid rain, both of which have significant negative impacts on the environment. Electricity generation from wind power does not result in thermal, chemical, radioactive, water or air pollution that is typically associated with fossil fuel-fired and nuclear power projects. According to GWEC, collectively, U.S. wind power projects avoid the emission of approximately 75 million tons of carbon dioxide annually, equivalent to removing 13 million cars from the road, and conserve an estimated 27 billion gallons of water annually, which would otherwise be used for steam or cooling by conventional power projects. Wind power projects can have an adverse impact on birds and bats, as well as plants and animals. However, a well-designed and operated wind power project can minimize these impacts and have a significantly lower environmental impact relative to most environmentally-responsible conventional power projects.

Technological improvements resulting in greater power efficiency are decreasing the cost of electricity generated from wind toward parity with the cost of other energy sources, such as natural gas. The diagram below exemplifies how, at specified wind speeds, new turbine technology that we believe can be deployed in 2014 is able to produce 50% to 100% more power for most North American wind locations than the technology that was available in 2009.

Wind power projects require only a small percentage of the land they occupy for road access and foundations for wind turbines. The remainder of a wind power project site is available for other uses such as agriculture, industry and recreation. We believe a typical wind power project uses only 1% to 5% of the land area leased to or owned by the project.

We believe the following factors have driven, and will continue to drive, the growth of wind power in North America:

As stated above, from 2008 to 2020, the EIA expects global net electricity generation to grow at a CAGR of 2.4% from 2008 to 2020; however, OECD countries are expected to grow at a CAGR of 1.1% over the same period. In the United States and Canada, in addition to the new electricity generating capacity associated with this growth, further capacity additions will be required to replace aging fossil fuel-fired and nuclear power projects. With the current low natural gas price environment and increased sensitivity regarding environmental concerns, it is expected that natural gas and renewable energy, including wind power, will be the future choice for new electricity generating capacity.

Increasing concerns regarding manufacturing jobs, security of energy supply and consequences of greenhouse gas emissions as well as the outlook for fossil-fuel prices have resulted in support for governmental policies at the federal and state or provincial level that support electricity generation from wind power and other renewable energy sources. The state and provincial RPS as well as FIT programs have been and will continue to be the most important governmental policies supporting wind power. In order to promote employment in the manufacturing sector, jurisdictions are implementing domestic content requirements for renewable energy projects. For example, the FIT program in Ontario requires wind power projects greater than 10 KW and all solar projects to include a minimum amount of Ontario-based content. Minimum domestic content of 50% is required for projects that achieve commercial operations in Ontario after January 1, 2012.

Wind turbine technology has evolved significantly over the last 20 years and technological advances are expected to continue in the future. The cost of electricity generation from wind projects has dropped over 80% over the last 20 years, we believe, as a result of technological advances, which have included:

The growing concern over the environmental consequences of greenhouse gas emissions has contributed to the growth of wind power generation. According to the World Meteorological Organization, 2011 ranks as the tenth warmest year on record, and the thirteen warmest years have all occurred in the fifteen years between 1997 and 2011. As one of the largest emitters of greenhouse gases in the world, the United States has experienced growing awareness of climate change and other effects of greenhouse gas emissions, which has resulted in increased demand for emissions-free electricity generation. As an emissions-free electricity source, wind power is an attractive alternative that is capable of addressing these growing environmental concerns.

We expect that increased demand for electricity coupled with a finite supply of fossil fuels, and capacity and distribution constraints, including volatility in fossil-fuel prices, will result in continued increases and volatility in electricity prices. Current natural gas prices are low; however, they are expected to increase in coming years. Additionally, electricity generation from natural gas is either exposed to volatility in natural gas prices or is priced at a premium for medium-term, fixed-price gas supply contracts. Wind power projects, in contrast, typically contract for long periods (e.g., 20 years) at fixed prices. As a result and given the lack of fuel costs associated with wind power projects, we believe that wind power has become cost competitive with conventional power projects and that this cost competitiveness will contribute to further growth in wind power.

Growing environmental concerns have made it increasingly difficult to construct new or expand existing fossil fuel-fired electricity generation projects. For example, according to industry sources, only 41 of the approximately 150 coal plants proposed in the United States between 2000 and 2006 were built or were under construction by the end of 2011. Nuclear power projects have also faced significantly increasing capital costs and steep environmental hurdles associated with, among other things, complications relating to the disposal of spent nuclear fuel and concerns over operational safety. Wind power, in contrast, does not create solid waste by-products, emit greenhouse gases or deplete non-renewable resources, and, as a result, is an attractive alternative to fossil fuel-fired power projects.

According to the EIA, the net import share of total U.S. energy consumption was 19% in 2011. In addition, many of the regions rich in energy supply are politically unstable, raising public concerns regarding the dependence of the United States on foreign energy imports and related threats to U.S. national security. The potential for future growth in U.S. wind power generating capacity is supported by the large amount of land available for turbine installations and the availability of significant wind resources. According to the DoE, wind power industry experts estimate that the United States has more than 10,500 GW of available land-based wind resources that can be captured economically, assuming 80 meter turbine heights and a capacity factor of at least 30%. Increased public awareness of the dependence of the United States on foreign energy sources has generated momentum to diversify the energy supply within the United States. We believe that wind power, which supplied only 1.3% of the total net electricity generation in the United States in 2008, according to the EIA, is a viable domestic alternative to decrease the dependence of the United States on foreign energy sources and satisfy a portion of the expected increased demand for electricity in the United States.

Generally, there has been broad support from governments to facilitate growth in electricity generation from renewable energy through the development of mechanisms that encourage the adoption of renewable energy, including wind power.

Presently under U.S. law, the PTC provides a tax credit of 2.3 cents/kWh for the production of electricity for utility-scale wind power projects. In order to efficiently realize the value of the PTC, a project owner must either be a U.S. taxpayer or have a co-investment with an investor with U.S. taxable income that can be offset by the PTC. This incentive is scheduled to expire on December 31, 2013, and only projects that have begun construction on or before that date will be eligible to claim the incentive. As an alternative to the PTC, for projects placed into service on or before December 31, 2012, for which construction began on or after January 1, 2009 and before the end of 2011, project owners may elect to receive an ITC cash grant equivalent to 30% of the capital cost of qualified equipment. On March 4, 2013, the U.S. Treasury announced that the automatic federal spending reductions occurring across most U.S. government programs, known as sequestration, will apply to ITC cash grants. Awards made through the remainder of the government’s current fiscal year (September 30, 2013) will be reduced by 8.7%, at which time the sequestration rate is subject to change. Alternatively, project owners may elect to claim an ITC equal to 30% of the capital cost of qualified equipment for wind projects placed in service on or after January 1, 2009 for which construction begins before January 1, 2014. Given that many of the factors that gave rise to the initial establishment of the U.S. federal incentives remain, including strong public support for the continued expansion of renewable energy, we believe new U.S. federal incentives may be enacted, although the form and timing of any potential future incentives remain uncertain.

U.S. state RPS and targets have been a key driver of the expansion of wind power and will continue to drive wind power installations in many areas of the United States. As of March 2013, 29 states and the District of Columbia have RPS in place, and eight other states have non-binding goals supporting renewable energy. California, one of our markets, has been a leader in RPS with one of the highest state targets. In 2011, the governor of California signed into law legislation that increased the state’s RPS from 20% to 33% by 2020. Texas, another of our markets, has surpassed its mandated RPS of 5,880 MW by 2015 as well as its target of 10,000 MW by 2025, but is completing a large expansion of the electricity grid in Texas principally to facilitate the development of additional wind power generating capacity.

Source: Database of State Incentives for Renewables & Efficiency, U.S. Department of Energy

California. California has one of the most aggressive RPS in the United States with a target of 33% of electricity to be generated from renewable energy sources by 2020. Load-serving entities in California satisfy their RPS requirements, in part, by issuing requests for proposals for new renewable energy PPAs. The success of bringing currently contracted projects into operation will impact future demand for renewable energy in California.

Texas. While the Texas RPS requires 5,880 MW of renewable energy generating capacity by 2015 and Texas has a target of 10,000 MW by 2025, both of these levels have already been met.

Nevada. Under Nevada’s RPS, NV Energy is required to utilize renewable energy sources to supply a minimum percentage of the electricity it sells in the state, which was set at 6% in 2005, increasing by 3% every two years to 20% by 2015 and to 25% by 2025. Both of NV Energy’s operating subsidiaries, Nevada Power Company and Sierra Pacific Power Company, surpassed the minimum requirement of 15% in 2011, delivering 16.7% and 24.9%, respectively. NV Energy satisfies its RPS requirements, in part, by issuing requests for proposals for new renewable energy PPAs.

Puerto Rico. Under Puerto Rico’s RPS, PREPA is required to meet targets for electricity generation from renewable energy sources as a percentage of electricity sales as follows: 12% by 2015; 15% by 2020; and 20% by

2035. In the 12-month period ended June 30, 2011, less than 1% of electricity generation in Puerto Rico was generated from renewable energy sources. PREPA primarily satisfies its RPS requirements by entering into power sale agreements for new electricity generation from renewable energy. As of June 30, 2011, PREPA had signed a total of 37 power sale agreements representing 982 MW of renewable energy projects. Should these projects achieve commercial operation, PREPA expects that, collectively, they will generate approximately 3%, 8% and 10% of electricity generation in 2013, 2015 and 2016, respectively, in all years below the relevant RPS targets.

While provincial governments have jurisdiction over their respective intra-provincial electricity markets, from 2007 to 2011, the Canadian federal government supported the development of renewable energy through its ecoENERGY for Renewable Power program, or “ecoEnergy federal incentive,” which resulted in a total of 104 projects qualifying for funds, including our St. Joseph project, and will represent cash incentives of approximately C$1.4 billion over 14 years and encouraged an aggregate of approximately 4,500 MW of new renewable energy generating capacity. The program is now fully subscribed, and the Canadian federal government has not signaled an intention to renew it.

Provincial governments have been active in promoting renewable energy in general and wind power in particular through RPS as well as through RFPs and FIT programs for renewable energy. Several provinces are currently preparing new RFPs for renewable energy. Current provincial targets for renewable energy in those provinces with stated targets are outlined below.

Ontario. In 2009, the Green Energy and Green Economy Act, 2009 was passed into law and the OPA launched its FIT program, which offers stable prices under long-term contracts for electricity generation from renewable energy, including biomass, wind, solar photovoltaic and hydro power. In November 2010, the Ministry of Energy, or “MoE,” released the draft Supply Mix Directive and Long Term Energy Plan, or “LTEP.” Ontario, one of our markets, has been a leader in supporting the development of renewable energy through the LTEP, which calls for 10,700 MW of renewable energy generating capacity (excluding small-scale hydro power) by 2018. In addition, Ontario was the first jurisdiction in North America to introduce a FIT program, which has resulted in contracts being executed for approximately 4,546 MW of electricity generating capacity as of January 31, 2013. These new contract awards under the FIT program along with previously-awarded PPAs suggests Ontario is close to meeting its current RPS by 2015, provided that all of the currently-contracted projects are successfully developed, financed and constructed.

In April and July of 2012, the MoE implemented version 2.0 of the FIT program, which, among other things, reduced contract prices for new wind power and solar power projects, limited the acceptance of applications to specific application windows, and prioritized projects based upon project type (community participation, Aboriginal participation, public infrastructure participation), municipal and Aboriginal support, project readiness and electricity system benefit. The revisions to the FIT program do not affect FIT contracts issued prior to October 31, 2011, including our South Kent project and the Grand, K2 and Armow projects. Prices under the FIT program will be reviewed annually, with prices established in November that will take effect January 1^st of the following year. Such price changes do not affect previously issued FIT contracts but, rather, only FIT contracts to be entered into subsequent to the price change. The revisions may, however, make project economics less attractive (because of the PPA price reduction) and by granting priority points or status to certain types of projects, may make it more difficult to obtain PPAs in the future.

Manitoba. The Manitoba government and Manitoba Hydro independently undertook studies to determine the potential of wind power generation in the province of Manitoba. As a result of such studies, in November 2005, the Manitoba government announced that it was targeting plans to add approximately 1,000 MW of new

wind power generating capacity by 2016, a portion of which is expected to be procured from IPPs. To date, it has awarded three PPAs for electricity generating capacity in excess of 250 MW, including our St. Joseph project.

Other Provinces. Provincial support for renewable energy in other provinces includes the following objectives:

In 2008, the Chilean government enacted the Renewable and Non-Conventional Energy Law (law 20.257), which required power generation companies who sell directly to end-use customers, to source 5% of their electricity from renewable energy sources by 2010, which such percentage gradually increasing each year until it reaches 10% in 2024. Currently proposed amendments to the Renewable and Non-Conventional Energy Law are expected to increase the percentage of renewable energy to 20% by 2025 and introduce a tendering system. As of the end of 2011, renewable energy accounted for approximately 3% of total electricity generation in Chile.

We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued growth of our business. We own interests in eight 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 1,041 MW, consisting of six operating projects and two projects under construction. We expect that our two construction projects will commence commercial operations prior to the end of the second 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-five 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 19 years. Our business is fundamentally simple and our cash flows are largely derived from a few key components: forecasted wind, equipment availability, price of power and controlled costs.

We intend to use a 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 will initially be set at $ per Class A share, or $ per Class A share on an annualized basis. We have established our initial quarterly dividend level 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 consideration given to retaining a portion of the cash available for distribution to grow our business. 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. See “Cash Dividend Policy.”

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 PEG LP, a leading developer of renewable energy and transmission projects, will be an important source of growth for our business.

Our financial objectives, which we believe will maximize long-term value for our shareholders, are to:

Upon completion of this offering, we will own interests in eight wind power projects, consisting of six operating projects and two 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. The following table provides an overview of our projects:

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

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

We intend to efficiently operate our projects to meet or exceed our 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 and by investing in our key personnel. 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 contracting with third parties when they can provide better services at lower cost than we are able to provide in-house.

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 “—Organization of Our Business.”

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. Our construction projects consist of interests in two projects that we expect will contribute an additional owned capacity of 171 MW in 2014, for an aggregate of 1,041 MW together with our operating projects.

We utilize experienced, creditworthy contractors and proven technology to build high-quality power projects. In addition, over the past 10 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.

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. The average maturity of our project-level debt is approximately 14 years. 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.

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.

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 PEG LP 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.

Our strategy for growth is focused on the acquisition of operational and construction-ready power projects from PEG LP 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 PEG LP, which provides us with the opportunity to acquire projects that it successfully develops and efficiently completing construction and achieving commercial operations at these projects. The Initial ROFO Projects represent a total PEG LP-owned capacity of 746 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 PEG LP intends to sell.

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

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 PEG LP will become our employees. For the purposes of determining the 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 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 PEG LP 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 PEG LP 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 employee reintegration, we expect that our principal focus will continue to be owning operational and under-construction power projects. However, 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 services to PEG LP to the extent required by PEG LP’s remaining development activities, and PEG LP will continue to pay us for those services primarily on a cost reimbursement basis. Because the terms of the employee reintegration will be set forth in the Management Services Agreement that will be entered into concurrently with the completion of this offering, the employee reintegration will have been approved by our Board of Directors and, as a result, no further approvals, including in respect of the Conflicts Committee, will be required to effectuate the employee reintegration.

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 eight distinct creditworthy counterparties will deliver stable long-term revenues. Our power sale agreements cover 95% of the electricity to be generated across our projects with a weighted average remaining contract life of approximately 19 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 favourable 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 provided by leading manufacturers. 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 years.

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.

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 awards for its outstanding environmental analysis and documentation from both the National Association of Environmental Professionals and the California Association of Environmental Professionals.

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 and favourable and dependable winds. We believe the members of our management team are recognized by their industry peers as experts in identifying, analysing 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, we believe that our team sponsored more than 50% of the assets built during the last expiry of the PTC. In addition, 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 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. 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 continuing relationship with PEG LP provides us with access to a pipeline of acquisition opportunities. We believe PEG LP’s ownership position in our company following the completion of this offering will incentivize PEG LP to support the successful execution of our objectives and business strategy, including through the preparation of projects to the stage where they are construction-ready. PEG LP has a dedicated development team of 32 professionals with significant experience across the spectrum of power project development:

PEG LP also has teams devoted to engineering, legal and project financing that enable it to develop and construct projects through to commercial operations. We believe PEG LP’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.

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 PEG LP’s management teams include professionals that 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 PEG LP 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 CAGR of 32% from 2003 to 2014, measured by cumulative wind MW installed), several independent transmission projects and other conventional power assets. Before forming PEG LP in 2009, our and PEG LP’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 PEG LP in 2009, the PEG LP management team has acquired and developed the operational and in-construction wind power projects that will comprise our owned capacity of 1,041 MW upon completion of the Contribution Transactions, representing a CAGR of 42%, and more than a 3,000 MW portfolio of development assets, which we will have preferential rights to acquire as described further in “—Our Relationship with PEG LP.” Additionally, our and PEG LP’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 PEG LP’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.

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 PEG LP and other third parties. In addition to our executive officers, we employ 32 full-time staff in two key functional stages associated with operations and maintenance and commercial management. We rely on some services to be performed by third parties, including PEG LP, but have all the core functions required for overseeing construction, operating and managing our projects.

Our operations team’s objective is to maximize revenues from each of our projects rather than solely focus 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;

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.

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, including at PEG LP, 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 ten 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.

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 investment advisory, principal investment and

finance. While working together at PEG LP 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, (iii) which meet our core values, including our commitments to environmental stewardship and being a good neighbour 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 will require that all of our executive officers maintain a material, 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, including acquisitions from PEG LP 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.

Upon completion of this offering, we will own interests in eight wind power projects, consisting of six operating projects and two 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.

The electricity generated by our projects for the six months ended June 30, 2013 and the years ended December 31, 2012, 2011 and 2010 is summarized in the following table:

For a description of our project-level financing arrangements, see “Description of Certain Financing Arrangements.”

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. PEG LP acquired

this operational project in March 2010. Gulf Wind is held by a tax equity partnership owned by MetLife Capital, Limited Partnership, or “MetLife,” and PEG LP, with each owning equity stakes of approximately 33% and 67%, respectively. Upon the completion of this offering, we, PEG LP and MetLife will own approximately 40%, 27% and 33% of Gulf Wind, respectively. For more information about our tax equity partnership, see “Description of Certain Financing Arrangements—Gulf Wind Tax Equity Partnership Transaction.”

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 our operating project subsidiary 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 favour of Credit Suisse Energy LLC in excess of the first and second lien caps. See also “Description of Certain Financing Arrangements—Gulf Wind Senior Secured Credit Agreement.”

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 The John G. and Marie Stella Kenedy Memorial Foundation 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 a daily wind production profile that generally follows the electricity demand load, which is heaviest during the daytime.

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 Pacific Gas and Electric Company, or “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. See also “Description of Certain Financing Arrangements—Hatchet Ridge Wind Lease Financing.” The PPA also contains customary termination and event of default provisions. Subject to the terms of the PPA, Hatchet Ridge is required to pay liquidated damages for failure to produce a certain amount of energy in one 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 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. Subject to the terms of the PPA, St. Joseph is required to post performance security in the amount of C$4.5 million to secure damages. See also “Description of Certain Financing Arrangements—St. Joseph Amended Credit and Security Agreement.” 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. Manitoba Hydro’s right of first offer is not triggered by the Contribution Transactions or this offering.

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 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.

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. Subject to the terms of the PPA, 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. See also “Description of Certain Financing Arrangements—Spring Valley Credit Facilities.” 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 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. Subject to the terms of the PPA, Santa Isabel is required to post operating security in the amount of $3.0 million for the performance of its obligations under the PPA. See also “Description of Certain Financing Arrangements—Santa Isabel Senior Financing Agreement.” 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 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 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 also entered into an affected system study agreement with the Imperial Irrigation District.

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. See also “Description of Certain Financing Arrangements—Ocotillo Senior Financing Agreement.” The PPA also contains customary termination and event of default provisions. Subject to the terms of the PPA, Ocotillo is required to pay liquidated damages for failure to produce a certain amount of energy in the two previous years.

Project construction is being performed by Blattner Energy, Inc., or “Blattner,” a leading wind power construction provider with whom we have worked in the past. As of June 2013, construction efforts remain on schedule and within budget. However, 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. For information regarding the consequences of the blade separation event, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Electricity Sales and Energy Derivative Settlements of Our Operating Projects.”

Ocotillo is the subject of four active lawsuits brought by a variety of project opponents. See “—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.

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 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. See also “Description of Certain Financing Arrangements—South Kent Senior Financing Agreement.”

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 favour 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.

The project’s generation tie to the HONI transmission system will be 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 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 June 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 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.

We compete with other wind power 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.

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 demand for turbines is relatively low. Our turbine supply strategy is largely based on establishing framework agreements and developing strong relationships with leading turbine suppliers to secure our supply needs.

To date, our projects have purchased or agreed to purchase 500 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-93 turbine technology has a significant and well established track record. First installed in February 2005, Siemens has installed 5,855 SWT-2.3MW turbines worldwide, with 3,387 in the United States, as of December 2012. 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. For information regarding the consequences of the blade separation event, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Electricity Sales and Energy Derivative Settlements of Our Operating Projects.”

Other important suppliers include the engineering and construction companies, such as Mastec Construction, Inc., M. A. Mortenson Company, RES-Americas and Blattner, 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.

We sell our electricity and environmental attributes, including RECs, primarily to local utilities under long-term, fixed-price PPAs or, in limited instances, local liquid ISO markets. For the year ended December 31, 2012, Manitoba Hydro, PG&E and ERCOT accounted for 32%, 23% and 18%, respectively, of our total revenue.

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 shape that matches the forecasted production profile of the asset. 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.

Following the completion of this offering, we intend 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure about Market Risk.”

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. 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; in addition, the court has subsequently dismissed each of the three lawsuits, one in September 2012, and two in February 2013. In April 2013, two of the dismissals were appealed to the U.S. Court of Appeals for the Ninth Circuit. The state lawsuit was remanded to state court following a motion by the plaintiff. The remaining two lawsuits have been brought by a single group of plaintiffs. Briefing on the merits is underway in both cases, which we expect will be decided by the end of 2013. The claims in one of the cases substantially overlap those resolved by the court in its earlier rulings.

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 appeals described above, the actively adjudicated lawsuits have all been dismissed. We have completed and placed into service in 2012 approximately 223 MW of the project’s 265 MW of planned capacity and anticipate being able to complete the remaining planned capacity prior to the completion of this offering. We believe, but can give no assurance, that the remaining litigation will ultimately be resolved favorably to the project.

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.

Following the completion of this offering, we will have approximately 41 full-time employees of which seven are based in our corporate headquarters, 15 are based in our various project offices and 19 are based in our other offices, including our OCC, in Houston, Texas. None of our employees is represented by a labour union or is covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

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 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 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.

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.

We are required to obtain from 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.

Frequently, our 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.

As some of our U.S. projects are located on lands administered by the Bureau of Land Management, we are required to obtain rights-of-way from the Bureau of Land Management. The Bureau of Land Management encourages the development of wind power within acceptable areas, consistent with EPACT 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.

Our 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 we would agree to provide some form of mitigation to offset impacts before a denial is issued.

Federal agencies granting permits for our 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.

In addition to federal requirements, our projects, and any future 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.

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.

We are required to obtain from federal, provincial 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, including, but not limited to, environmental non-governmental organizations, neighborhood groups, municipalities and First Nations when the permits were initially applied for or when there is an appeal proceeding after permits are issued. The delay or denial of a permit or the imposition of conditions that are costly or difficult to comply with can impair or even prevent the development of a project or can increase the cost so substantially that the project is no longer attractive to us.

Our projects in Ontario are subject to Ontario’s Environmental Protection Act, which requires proponents of significant wind projects to obtain an 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 an 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 tribunal hearings.

The Manitoba Environment Act requires proponents of significant projects to submit a proposal with the Manitoba Conservation Environmental Assessment & Licensing Branch, and to comply with Manitoba’s

environmental assessment process under the Environment Act. This process will consider a similar range of impacts on the environment, the heritage and scenic values of an area and on people, communities and wildlife as the Ontario process, and brings with it similar risks.

Our projects may be subject to endangered species legislation, either federally or provincially, which prohibits and imposes stringent penalties for harming endangered or threatened species and their habitats. Our projects may also be subject to the Migratory Birds Convention Act, which protects the habitat of migratory species, and which may also trigger federal “Species at Risk” requirements. Because the operation of wind turbines may result in injury or fatalities to birds and bats, avian and bat risk assessments are generally required both prior to permits being issued for projects and after commercial operations. In Ontario, if any of the affected species are listed as endangered or threatened, permits under the Endangered Species Act may also be required.

Our 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’s Green Energy and Green Economy Act, 2009, as well as requirements for building permits and other municipal approvals that can be difficult or costly to comply with and impair or prevent the development of a project.

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.

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.

We retained the engineering and consulting services of Garrad Hassan America, Inc., or “GL GH,” to conduct an independent technical due diligence review, or the “Portfolio Review,” of the following seven of our eight projects: Gulf Wind, Hatchet Ridge, St. Joseph, Spring Valley, Santa Isabel, Ocotillo and South Kent, which we refer to collectively as the “Reviewed Projects.” In connection with the Portfolio Review, we also retained GL GH to prepare an independent engineer’s report in respect of the Reviewed Projects dated August 8, 2013, or the “Independent Engineer’s Report,” a copy of which has been filed as an exhibit to the Registration Statement of which this prospectus is a part and is publicly available on our SEDAR profile at www.sedar.com. Our El Arrayán project, of which we own a 31.5% minority interest and which represents only 3% of our aggregate owned capacity, was not included in the Portfolio Review.

At the time of the Portfolio Review, certain of our projects, including Gulf Wind, Hatchet Ridge, St. Joseph, Spring Valley, Santa Isabel and Ocotillo had commenced commercial operations, while South Kent was under construction.

GL GH is a dedicated renewable energy consultancy, offering independent technical and engineering services to the wind energy sector. GL GH’s experience spans almost three decades, working with a wide variety of technologies, manufacturers, projects and markets. Its clients include developers, owners, operators of and lenders and investors in renewable energy projects. We retained GL GH as an independent engineer based upon its solid reputation in its field. GL GH has no affiliation with us, our subsidiaries, our affiliates or PEG LP.

The scope of work for the Portfolio Review included the following: (a) for the Reviewed Projects, (i) a general project review, which included, among other things, an assessment of the suitability of the equipment, engineering and design, (ii) a review of certain material contracts, such as PPAs, turbine supply, interconnection and operations and maintenance agreements and (iii) a review of the operating plans which included, among other things, the operating expenses assumed over each Reviewed Project’s 20-year design life; (b) for our operating projects, a review of the overall availability and operations, which included, among other things, a review of historical availability and any maintenance issues; (c) for South Kent, a review of the construction budget and schedule; and (d) an overall evaluation of our operational team that provides operations and maintenance services to the Reviewed Projects.

The following statements are qualified in their entirety by the Independent Engineer’s Report itself, which should be read before making an investment in our Class A shares. Subject to the information and qualifications contained and assumptions made in the Independent Engineer’s Report and as of the date of the Independent Engineer’s Report, we summarize the conclusions to be:

Set forth below is information concerning our directors and executive officers upon completion of this offering. Our board of directors will consist of seven members. Each director will be elected annually by the vote of the holders of a majority of our shares to serve until his or her successor is duly elected or appointed and qualified or until his or her earlier death, retirement, disqualification, resignation or removal. All of our officers serve at the discretion of our board of directors. The ages of our directors and executive officers set forth below are as of December 31, 2012.

Mr. Garland will serve as our President and Chief Executive Officer upon the completion of this offering. Prior to joining our company, Mr. Garland served as Chief Executive Officer of PEG LP since June 2009. Prior to joining PEG LP, Mr. Garland was a partner of Babcock & Brown from 1986 to 2009, where he initiated and managed project finance activities, energy development and energy investment, and led Babcock & Brown’s North American Infrastructure Group. Prior to that, Mr. Garland worked for the State of California as Chief of Energy Assessments from 1975 to 1986. We believe Mr. Garland’s extensive leadership experience enables him to play a key role in all matters involving our board of directors and contribute an additional perspective from the energy industry.

Mr. Armistead will serve as our Executive Vice President, Business Development upon the completion of this offering. Prior to joining our company, Mr. Armistead served as Executive Director of PEG LP since June

2009. Prior to joining PEG LP, from 2000 to 2009, Mr. Armistead managed Babcock & Brown’s renewable energy group in North America, focusing on the origination, strategic evaluation and consummation of opportunities in the renewable energy sector. Prior to that, Mr. Armistead served as Director, Americas Finance at Edison Mission Energy, as senior power developer at ConocoPhillips and as industrial controls manager at Honeywell International Inc.

Mr. Elkort will serve as our Executive Vice President and General Counsel upon the completion of this offering. Prior to joining our company, Mr. Elkort served as Director of Legal Services and Co-Head of Finance of PEG LP since June 2009. Prior to joining PEG LP, from 1996 to 2009, Mr. Elkort was responsible for managing the various project financings of Babcock & Brown’s North American renewable energy projects and served as the senior legal officer in Babcock & Brown’s North American Infrastructure Group. Before joining Babcock & Brown, from 1985 to 1996, Mr. Elkort was employed by the San Francisco based law firm of Jackson, Tufts, Cole & Black, where he was made a partner in 1991.

Mr. Lyon will serve as our Chief Financial Officer upon the completion of this offering. Prior to joining our company, Mr. Lyon served as Head of Structured Finance of PEG LP since May 2010. Prior to joining PEG LP, Mr. Lyon independently managed a portfolio of investment assets from 2003 to 2010. He was a principal of Babcock & Brown from 1989 to 2003, where he advised clients on, and structured and placed debt and equity in, the independent power industry. Prior to that, Mr. Lyon worked for Geothermal Resources International, Inc. in a variety of roles, including as assistant vice president, from 1983 to 1988. He also worked for Main Hurdman, a predecessor to KPMG LLP, from 1980 to 1983 and is a former Certified Public Accountant.

Mr. Pedersen will serve as our Chief Investment Officer upon the completion of this offering. Prior to joining our company, Mr. Pedersen served as Co-Head of Finance of PEG LP since June 2009. Prior to joining PEG LP, Mr. Pedersen was employed by Babcock & Brown from 2007 to 2009, where he focused on the origination and execution of investments in the energy sector. Prior to that, Mr. Pedersen worked at Enron and AEI as Manager and Senior Director, respectively, from 1999 to 2006, where he served in numerous corporate development and origination roles in the United States and abroad. He is a Chartered Financial Analyst.

Mr. Lillybeck will serve as our Senior Vice President, Fiscal and Administrative Services upon the completion of this offering. Prior to joining our company, Mr. Lillybeck served as Director of Fiscal and Administrative Services of PEG LP since June 2009. Prior to joining PEG LP, Mr. Lillybeck was employed by Babcock & Brown from 2002 to 2009, where he led accounting and financial reporting for Babcock & Brown’s North American Infrastructure Group. Prior to that, Mr. Lillybeck served as Chief Financial Officer of several start-up companies and, while at Northwest Airlines, was Director of Business Planning and Development in its Asia-Pacific region and served on the board of three international joint ventures.

Mr. Russell will serve as our Senior Vice President, Engineering and Construction upon the completion of this offering. Prior to joining our company, Mr. Russell served as Director of Engineering and Construction of PEG LP since June 2009. Prior to joining PEG LP, Mr. Russell was employed by Babcock & Brown from 2002 to 2009, where he was responsible for managing the design and construction of Babcock & Brown’s North American wind power projects. Mr. Russell was a Director at Enron Corporation from 1998 to 2002, where he

was responsible for managing design and construction contract negotiations for combined cycle combustion turbine power generating projects. Prior to that he was the Vice President of Project Operations for Riley Energy Systems from 1987 to 1990, where he managed the design, construction and operation of waste-to-energy facilities. He also worked as a private consultant in the energy industry from 1991 to 1998.

Mr. Shugart will serve as our Senior Vice President, Operations upon the completion of this offering. Prior to joining our company, Mr. Shugart was employed by PEG LP beginning in 2009 where he was Director of Asset Operations and Maintenance. Prior to joining PEG LP, Mr. Shugart was employed by Babcock & Brown from 2006 to 2009, where he focused on the development and management of transmission, wind and natural gas-fired power facilities. Prior to that, Mr. Shugart worked for Calpine Corporation as Engineer and Developer from 1998 to 2006.

Ms. Blaine will serve as our Vice President and Secretary upon the completion of this offering. Prior to joining our company Ms. Blaine served as Corporate Counsel for PEG LP beginning in 2009. Prior to joining PEG LP, Ms. Blaine was employed at Babcock & Brown from 1994 to 2009, where she served most recently as Assistant General Counsel, and prior to that, as Director of Tax.

Mr. Batkin will serve as a member and chair of our board of directors. Mr. Batkin serves on the boards of Hasbro, Inc., Cantel Medical Corp. and Omnicom Group, Inc. He served on the board of Diamond Offshore Drilling, Inc. from 1999 to 2008. He was Vice Chairman of Eton Park Capital Management, L.P., from 2007 to 2012. Prior thereto, he was the Vice Chairman of Kissinger Associates, Inc. from 1990 until 2006. He is an overseer or board member for a number of non-profit organizations, including, among others, the International Rescue Committee, the Brookings Institution, and the New York City Police Foundation. We believe Mr. Batkin’s extensive public company, energy industry and leadership experience will enable him to provide essential guidance to our board of directors and our management team.

Michael B. Hoffman will serve as a member of our board of directors. Mr. Hoffman is a partner of Riverstone, where he is principally responsible for investments in power and renewable energy for Riverstone’s funds and is based in New York. Mr. Hoffman is co-head of Riverstone’s Renewable Energy Funds I and II. Before joining Riverstone in 2003, Mr. Hoffman was senior managing director and head of the mergers and acquisitions advisory business of The Blackstone Group for 15 years, where he also served on the firm’s principal group investment committee as well as its executive committee. Prior to joining Blackstone, Mr. Hoffman was managing director and co-head of the mergers and acquisitions department of Smith Barney, Harris Upham & Co. Mr. Hoffman is chairman of the board of directors of Onconova Therapeutics Inc. His non-profit board affiliations include those of North Shore-Long Island Jewish Health System and the Municipal Arts Society. We believe Mr. Hoffman’s extensive leadership and financial expertise will enable him to contribute significant managerial, strategic and financial oversight skills to our board of directors.

The Lord Browne of Madingley will serve as a member of our board of directors. Lord Browne is a partner and managing director of Riverstone and is co-head of Riverstone’s Renewable Energy Fund II. Prior to joining Riverstone in 2007, Lord Browne spent 41 years at British Petroleum, holding various senior management positions during that time. In 1991, he joined the board of The British Petroleum Company plc and was appointed group chief executive in 1995 and remained in this position until May 2007. Lord Browne was chairman of the advisory board of Apax Partners LLC from 2006 to 2007, a non-executive director of Goldman

Sachs from 1999 to 2007, a non-executive director of Intel Corporation from 1997 to 2006, a trustee of The British Museum from 1995 to 2005, a member of the supervisory board of DaimlerChrysler AG from 1998 to 2001 and a non-executive director of SmithKline Beecham from 1996 to 1999.

Lord Browne was the president of the Royal Academy of Engineering from 2006 to 2011, a fellow of the Royal Society and a foreign member of the U.S. Academy of Arts and Sciences. He was appointed a trustee of the Tate Gallery in August 2007 and chairman of the trustees in January 2009. He was the chairman of the Independent Review of Higher Education Funding and Student Finance, which published its report in October 2010. He was appointed the UK Government’s lead non-executive board member in June 2010. He was knighted in 1998 and made a life peer in 2001. We believe Lord Brown’s extensive leadership and financial and energy industry expertise will enable him to contribute significant managerial, strategic and financial oversight skills to our board of directors.

Douglas G. Hall will serve as a member of our board of directors. Mr. Hall serves on the board of NexC Partners Corp. He was a Managing Director at RBC Capital Markets covering public and private capital raising, mergers and acquisitions support and strategic advisory assignments for diversified industry groups from 1979 until his retirement in 2005. Mr. Hall is currently Vice Chair of the Atlantic Institute of Market Studies, a director of Millar Western Forest Products Ltd., a privately-held lumber and pulp company based in Alberta and a Member of the Advisory Board for Southwest Properties Ltd., a privately held real estate company based in Nova Scotia. Until 2010, he was chair of Nova Scotia Business Inc., a company formed by the Province of Nova Scotia to manage the economic development function with a private sector board of directors. We believe Mr. Hall’s experience in investment banking as well as his experience and understanding of financial and disclosure matters will enable him to provide essential guidance to our board of directors and our management team.

Patricia M. Newson will serve as a member of our board of directors. Ms. Newson currently serves on the boards of Brookfield Residential Properties Inc. and Long Run Exploration Inc. which are publicly traded companies, and is also a director of the Alberta Electric System Operator, Heritage Gas Limited and Quality Urban Energy Systems of Tomorrow (QUEST). Ms. Newson retired in 2011 from AltaGas Ltd. as President of the Utility Division and was previously President and chief executive officer of AltaGas Utility Group Inc. from 2005 to 2009, and Senior Vice President Finance and chief financial officer of AltaGas Income Trust from 1996 to 2006. Her previous board experience includes Brookfield Asset Management Inc., AltaGas Utility Group Inc., Guide Exploration Inc., Inuvik Gas Ltd., and the Canadian Gas Association. Ms. Newson is a Chartered Accountant. We believe Ms. Newson’s public company and energy industry experience as well as her experience and understanding of financial accounting, finance and disclosure matters will enable her to provide essential guidance to our board of directors and our management team.

No director or executive officer of our company is, or within the 10 years prior to the date hereof has been, a director, chief executive officer or chief financial officer of any company that (i) was subject to a cease trade order or similar order or an order that denied the company access to any exemption under securities legislation, in each case in effect for a period of more than 30 consecutive days, that was issued while that person was acting in the capacity of a director, chief executive officer or chief financial officer of that company, or (ii) was subject to such an order that was issued after that person ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while the person was acting in that capacity.

Except as disclosed below, no director or executive officer of our company or shareholder holding sufficient securities of our company to affect materially the control of our company is, or within the 10 years prior to the date hereof has been, a director or executive officer of any company that, while that person was acting in that capacity or within a year of ceasing to act in that capacity, became bankrupt, made a proposal under any

legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets. In addition, no director or executive officer of the company or shareholder holding sufficient securities of the company to affect materially the control of the company has, within the 10 years prior to the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or become subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of the director or executive officer.

Until December 31, 2011, Mr. Hoffman served as an executive officer of Amaizeingly Green Products GP Ltd., which filed an application for a receivership order in Canada with the Ontario Superior Court of Justice under section 243(1) of the Bankruptcy and Insolvency Act on December 3, 2012. In addition, Mr. Batkin served as a director of Overseas Shipholding Group, Inc., which filed for Chapter 11 protection under the U.S. Bankruptcy Code in November 2012.

No director or executive officer of our company or shareholder holding sufficient securities of our company to affect materially the control of our company has:

None of our directors or officers or any other member of management, nor any associate of such director, officer or member of management, were indebted to us as at the date of this prospectus.

We expect that our amended and restated certificate of incorporation and amended and restated bylaws will contain provisions indemnifying our directors and officers to the fullest extent permitted by law. Prior to the completion of this offering, we intend to enter into indemnification agreements with each of our directors that may, in some cases, be broader than the specific indemnification provisions contained under Delaware law.

In addition, as permitted by Delaware law, we expect that our amended and restated certificate of incorporation will provide that no director will be liable to us or our shareholders for monetary damages for breach of fiduciary duty as a director. The effect of this provision is to restrict our rights and the rights of our shareholders in derivative suits to recover monetary damages against a director for breach of fiduciary duty as a director, except that a director will be personally liable for:

This provision does not affect a director’s liability under applicable securities laws.

To the extent that our directors, officers and controlling persons are indemnified under the provisions contained in our amended and restated certificate of incorporation, Delaware law or contractual arrangements against liabilities arising under the U.S. Securities Act, we have been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the U.S. Securities Act and is therefore unenforceable.

Following the completion of this offering, PEG LP will hold a majority of our outstanding shares. As a result, and also in certain circumstances if PEG LP were to hold less than 50% of our outstanding shares, we will

be an SEC foreign issuer under Canadian securities laws and will be exempt from, among other things, requirements under those laws to (i) have an audit committee of at least three people consisting solely of independent directors, and (ii) disclose annually the extent to which we comply with certain recommendations of the Canadian Securities Administrators regarding, among other corporate governance matters, the composition of our board of directors and of committees of our board of directors. We initially intend to substantially comply with the recommendations of the Canadian Securities Administrators, but, in the future, provided we remain an SEC foreign issuer we may decide not to follow such requirements. In addition, we intend to comply at all times with the requirements of the Sarbanes-Oxley Act, which requires, among other things, that our audit committee consist solely of independent directors.

of our directors are considered “independent,” as defined under the rules and requirements of the stock exchanges upon which we intend to list our Class A shares and for purposes of Canadian securities laws. Our independent directors are , , and . is the chairman of our board of directors. For purposes of the rules of , an independent director means . A director is considered to be independent for the purposes of Canadian securities laws if the director has no direct or indirect material relationship to the company. A “material relationship” is a relationship that could, in the view of the board, be reasonably expected to interfere with the exercise of a director’s independent judgment. Certain individuals, such as employees and executive officers of the company, are deemed by Canadian securities laws to have material relationships with the company.

Our non-independent directors are Messrs. Garland and Hoffman and The Lord Browne. Mr. Garland is deemed to be non-independent because he is our Chief Executive Officer. Mr. Hoffman and The Lord Browne are also deemed non-independent because they are partners of Riverstone.

There are no family relationships among any of our directors or executive officers.

The following table shows the public companies for which our directors or director nominees also serve as directors:

The mandate of our board of directors will be to oversee corporate performance and to provide quality, depth and continuity of management so that we can meet our strategic objectives. Following the completion of this offering, we will adopt a board mandate, which will, among other things, govern the roles, responsibilities and requirements for our board of directors.

The board of directors expects to develop and implement a written position description for each of the chairman and the chief executive officer. Committees of the board of directors will have a committee charter that will set out the mandate of the committee, which includes the responsibilities of the chair of each committee.

Director orientation and continuing education will be conducted by the nominating, governance and compensation committee of the board of directors. All newly elected directors will be provided with a comprehensive orientation on our business and operations. This will include familiarization with our reporting structure, strategic plans, significant financial, accounting and risk issues, compliance programs, policies and management and the external auditor. We plan to periodically update existing directors in respect of these matters.

For the purposes of orientation, new directors will be given the opportunity to meet with members of the executive management team to discuss our business and activities. The orientation program is designed to assist the directors in fully understanding the nature and operation of our business, the role of the board of directors and its committees, and the contributions that individual directors are expected to make.

Prior to the completion of this offering, our board of directors will adopt a code of ethics and conduct establishing the standards of ethical conduct applicable to all directors, officers and employees, as applicable, of our company, members of our management team and other employees and any other person who is performing services for us or on our behalf.

We will disclose promptly any waivers of the code of ethics and conduct by our nominating, governance and compensation committee with respect to our directors and executive officers. A copy of the code of ethics and conduct will be posted on our website at www. .com.

Our board of directors plans to have an audit committee, a nominating, governance and compensation committee, and a conflicts committee upon completion of this offering. Our board of directors may establish other committees from time to time in accordance with our bylaws. See “Description of Our Capital Stock.” The members of each committee will be appointed by our board of directors in accordance with our bylaws and serve one-year terms.

Upon the completion of this offering, our audit committee will consist of , and .

Our audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee will have sole authority to (i) retain and terminate our independent registered public accounting firm, (ii) approve all auditing services performed by our independent registered public accounting firm and related fees and terms, (iii) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm and (iv) confirm the independence and objectivity of our independent registered public accounting firm.

Our audit committee will have access to all books, records, facilities and personnel and may request any information about our company as it may deem appropriate. It will also have the authority to retain and compensate special legal, accounting, financial and other consultants or advisors to advise the committee.

Following the completion of this offering, from time to time, management will recommend to and request approval from the audit committee for audit and non-audit services to be provided by our auditors. The audit

committee will consider such requests and, if acceptable, pre-approve such audit and non-audit services. During such deliberations, the audit committee will assess, among other factors, whether the services requested would be considered “prohibited services” as contemplated by the SEC, and whether the services requested and the fees related to such services could impair the independence of the auditors.

The following table presents, by category, the fees accrued by Ernst & Young LLP as external auditor of, and for other services provided to, us in connection with our formation and organization, for the period indicated.

Following the completion of this offering, our nominating, governance and compensation committee will consist of and . The nominating, governance and compensation committee will assist our board of directors in identifying and recommending candidates for nomination to the board of directors, recommending committee assignments for directors to the board of directors, overseeing the board of directors’ annual evaluation of its performance, its committees and individual directors, developing and recommending to the board of directors appropriate corporate governance policies, practices and procedures for our company, reviewing and evaluating the performance of our Chief Executive Officer, administering and making recommendations to the board of directors with respect to our incentive-compensation plans, and reviewing compensation received by directors for service on the board of directors and its committees.

None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving as a member of our board of directors or compensation committee.

Following the completion of this offering, our conflicts committee will consist of , and . The conflicts committee will review specific matters that the board of directors believes may involve conflicts of interest, including transactions with PEG LP or its affiliates, and certain matters the board determines to submit to the conflicts committee for review. We are required to seek approval of the conflicts committee for any transaction involving the sale of a project from PEG LP to us or for any amendments to the Management Services Agreement. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. See “Certain Relationships and Related Party Transactions” and “Risk Factors.” The nominating, governance and compensation committee must unanimously

determine that nominees for this committee meet the applicable independence requirements. In addition, the board of directors must affirm the nominating, governance and compensation committee’s independence determinations before it places nominees on the committee. The members of the conflicts committee may not be officers or employees of PEG LP or its affiliates, including Riverstone.

Upon the completion of this offering, the board of directors, each of its standing committees and our individual directors will be assessed on an annual basis. Each assessment will be conducted with reference to the board mandate and committee charters, position descriptions, and policies and guidelines established by our company to provide its directors, officers and employees with guidance.

Prior to this offering, we have not paid any compensation to any of our directors in their capacity as members of our board of directors. Only our independent directors will receive fees for serving as directors. They will receive an annual retainer equal to the sum of (i) $ , (ii) $ for each meeting attended and (iii) $ for each committee chair held. In addition, we expect that our board members will participate in our Incentive Stock Plan and receive equity-based awards thereunder at times and in amounts that have not yet been determined.

We have elected to comply with the scaled executive compensation disclosure rules applicable to “smaller reporting companies,” as that term is defined in SEC rules. These rules require disclosure of compensation paid or accrued in 2012 to our principal executive officer and the two most highly compensated executive officers other than our principal executive officer. We refer to this group collectively in this section of the prospectus as our named executive officers, or “NEOs.” Our NEOs for 2012 are:

We are also providing certain compensation information for our next two most highly paid executive officers. We refer to these two individuals in this section of the prospectus as our “senior managers.” Our senior managers for 2012 are:

Prior to the completion of this offering, all of our NEOs and senior managers will be employed by PEG LP. PEG LP has been responsible for the payment of compensation to our NEOs and senior managers for all prior periods. Upon or prior to the completion of this offering, our NEOs and senior managers will become employees of our company on terms substantially similar, except as described herein, to those under which they were employed by PEG LP, but these individuals will continue to devote a portion of their business time to the provision of services to PEG LP in accordance with the terms of the Management Services Agreement. We will be responsible for all of the compensation payable to our NEOs and senior managers for all future periods, subject to reimbursement from PEG LP for a portion of their compensation pursuant to the Management Services Agreement. For additional information relating to the Management Services Agreement, see “Certain Relationships and Related Party Transactions—Management Services Agreement.”

The following table sets forth certain information with respect to the compensation paid to our NEOs for the year ended December 31, 2012.

The primary elements of compensation for the NEOs in 2012 were base salary and discretionary cash bonuses. The NEOs also received certain retirement, health, welfare and additional benefits as described below.

Base Salary. Base salaries for our NEOs have generally been set at levels deemed necessary to attract and retain individuals with superior talent. Effective January 1, 2013, our NEOs and senior managers received base salary increases to reflect both “cost of living” increases as well as market-based increases made in anticipation of our becoming a public company, which increases are intended to bring our NEOs’ overall compensation more in line with similarly situated executives at comparable public companies. The following table sets forth the current annual base salaries for our NEOs and senior managers:

Annual Cash Bonuses. Our NEOs participate in an annual cash incentive bonus program. Target awards for our NEOs under the incentive bonus program were established at the time the NEO commenced employment with PEG LP. The target incentive bonus program award amounts for our NEOs and other senior managers in effect for 2012 were:

Following the completion of this offering, we expect that our NEOs will continue to participate in an annual cash incentive bonus program, with target award levels that are consistent with the amounts shown in the table above, with such changes as the nominating, governance and compensation committee may determine from time to time. We also expect that Mr. Lyon and Mr. Pedersen will be eligible to participate in our annual cash incentive bonus program, with target annual bonus levels that have not yet been determined. Following the completion of this offering, we anticipate that annual cash incentive bonuses will be provided under the Incentive Plan, which is described in greater detail below.

Award payouts under the annual incentive bonus program have historically been and for 2012 were determined in the discretion of the board of directors of Pattern Energy Group Holdings LP, which we sometimes refer to in this prospectus as “PEG Holdings,” in its capacity as the sole managing member of the general partner of PEG LP, based upon PEG LP’s overall financial performance as compared to expectations established in the PEG LP annual budget. For 2012, the board of directors of PEG Holdings determined to pay bonuses to our NEOs in amounts set forth under the heading “Bonus” in the Summary Compensation Table for 2012 above. In addition, the board of directors of PEG Holdings determined to award an additional amount of $250,000 to Mr. Garland and $75,000 to Mr. Armistead for their performance in 2012. However, such amounts will be considered earned and will be paid only upon the successful consummation of a subsequent equity raise or restructuring transaction, which would include the consummation of this offering.

Retirement, Health and Welfare and Additional Benefits. Our NEOs and senior managers are eligible to participate in employee benefit plans and programs, including PEG LP’s tax-qualified 401(k) defined contribution plan, to the same extent as all salaried employees generally, subject to the terms and eligibility requirements of those plans. Elective employee contributions to PEG LP’s 401(k) plan are immediately vested and non-forfeitable. PEG LP also provides company-paid contributions to the 401(k) plan in an amount equal to five percent of each eligible employee’s base salary, up to the IRS annual contribution limit. Neither PEG LP nor any of its affiliates that currently employ our NEOs and senior managers have maintained, or currently maintain, a defined benefit pension plan or nonqualified deferred compensation plan, and we do not intend to adopt any such arrangements. Our NEOs did not receive any perquisites or personal benefits in 2012 in excess of those provided to all salaried full time employees of PEG LP generally, and no NEO received perquisites or personal benefits in 2012 that exceeded $10,000 in the aggregate.

Our NEOs previously entered into employment agreements with PEG LP that had initial two-year terms, which have expired, but which automatically renew for successive 12-month periods on the anniversary of the agreement’s effective date, unless written notice of non-renewal is delivered not less than 60 days prior to the next renewal date. In connection with the completion of this offering, we are entering into new employment agreements with each of our NEOs and senior managers. The agreements will provide for an initial term of employment of one year following the date of this offering and will automatically renew for successive one-year periods unless either

party provides a notice of non-renewal not less than 60 days prior to the next renewal date. The employment agreements will also provide for a cash severance payment upon a termination by us without cause, by the NEO for good reason or due to a non-extension of the agreement at our election.

Each NEO’s employment agreement, other than the CEO’s, provides that, in the event of a qualifying termination by us without cause or by the NEO for good reason, severance will be paid in a lump-sum equal to the sum of (i) 1.0 times the executive’s annual base salary and (ii) 1.8 times the executive’s average bonus amount, defined as the average of the two most recent annual bonus amounts paid to the executive. The CEO’s employment agreement provides that in the event of a qualifying termination by us without cause or by the CEO for good reason, his severance will be paid in a lump-sum equal to the sum of (i) 2.8 times his annual base salary and (ii) 2.8 times his average bonus amount, defined the same as in the other NEOs’ employment agreements. In addition, in the event of a termination other than for cause or due to death, each executive may be reimbursed for up to 12 months of premiums incurred to receive continued benefit coverage under the Consolidated Omnibus Budget Reconciliation Act, or “COBRA.” Severance payable under the agreements is subject to the execution and non-revocation of a general release of claims and is also conditioned on the executive’s compliance for a period of 24 months with an agreement to refrain from soliciting employees to leave their employment relationship with us. If an NEO’s employment is terminated due to non-extension of the executive’s employment term at our election, the executive will be entitled to receive 50% of the foregoing severance benefits.

Assuming the new employment agreements for our NEOs were in place as of December 31, 2012 and a termination of employment effective as of December 31, 2012 (i) by us without cause, (ii) due to non-extension of the executive’s employment term at our election or (iii) due to the executive’s resignation for good reason, each of our NEOs would have received the following severance payments and benefits:

As a newly formed company, we have not previously granted any equity compensation to our NEOs and senior managers. Our NEOs hold, and on completion of this offering will continue to hold, direct and indirect limited partner interests in PEG Holdings, including certain “B interests” that effectively entitle holders thereof to, in the aggregate, up to 15% of the cumulative profits of PEG LP. Please see “Conflicts of Interest and Fiduciary Duties.”

In connection with the consummation of this offering, we expect to grant options to purchase shares of our Class A common stock and restricted stock awards to certain employees under our 2013 Equity Incentive Award Plan, which is described below. The number of options and restricted stock awards that will be granted to each recipient will be determined based on a targeted value for the award and the initial public offering price per Class A share in this offering. The table below sets forth additional details regarding these awards. The options and restricted stock awards will be granted effective upon the consummation of this offering. The per Class A share option exercise price will be equal to the initial public offering price per Class A share of this offering. The options and restricted stock awards will vest monthly on a pro rata basis during the three-year period following the consummation of this offering.

We expect the nominating, governance and compensation committee of our board of directors will administer the compensation programs for our NEOs and senior managers following the completion of this offering. We anticipate that the nominating, governance and compensation committee will seek to use compensation as a tool to enable us to attract, retain and reward key individuals who contribute to our long-term success and that our executive compensation program will continue to consist of base salaries, annual cash incentive bonuses (which, following the completion of this offering, will be provided under the terms of our Incentive Plan as described in more detail below) and retirement and health and welfare benefits. In addition, we anticipate that we will grant equity and equity-based awards to our NEOs and senior managers on a periodic basis to align compensation with our performance. These awards will be granted under a 2013 Equity Incentive Award Plan that we intend to adopt prior to the completion of this offering. The 2013 Equity Incentive Award Plan, which we sometimes refer to as the “Equity Plan,” is described in more detail below. In addition, we anticipate our nominating, governance and compensation committee will maintain flexibility to adjust our executive compensation program from time to time as market and business conditions affecting our management and operations evolve.

We intend to adopt the Equity Plan prior to the completion of this offering. The Equity Plan will be effective no later than the day prior to the completion of this offering. The principal purpose of the Equity Plan will be to attract, retain and engage selected employees, consultants and directors through the granting of stock-based compensation awards. The material terms of the Equity Plan are summarized below.

Eligibility and Administration. Our and our subsidiaries’ employees, consultants and directors, including our NEOs and senior managers, will be eligible to receive awards under the Equity Plan. The nominating, governance and compensation committee will administer the Equity Plan unless our board of directors assumes authority for administration. The nominating, governance and compensation committee will be authorized to delegate its duties and responsibilities as plan administrator to subcommittees comprised of our directors and/or officers, subject to certain limitations. Our board of directors will administer the Equity Plan with respect to awards to non-employee directors.

Subject to the express terms and conditions of the Equity Plan, the plan administrator will have the authority to make all determinations and interpretations under the plan, prescribe all forms for use with the plan and adopt, amend and/or rescind rules for the administration of the plan. The plan administrator will also set the terms and conditions of all awards under the plan, including any vesting and vesting acceleration conditions.

Limitation on Awards and Shares Available. Initially, the aggregate number of our Class A shares available for issuance pursuant to awards granted under the Equity Plan will be (which represents approximately % of our total shares outstanding as of immediately following the completion of this offering), subject to adjustment as described below. See “—Certain Transactions.” This number will also be adjusted due to the following Class A shares becoming eligible to be used again for grants under the Equity Plan:

However, Class A shares which are tendered by the recipient or withheld by us in payment of an exercise price or to satisfy any tax withholding obligation shall not be added to the shares authorized for grants and will not be available for future grants of awards under the Equity Plan. Class A shares granted under the Equity Plan may be treasury shares, authorized but unissued shares, or shares purchased in the open market. The payment of dividend equivalents in cash in conjunction with any outstanding awards will not be counted against the Class A shares available for issuance under the Equity Plan. In addition, if we, or one of our subsidiaries, acquires or combines with another company that has shares available for grant pursuant to a qualifying equity plan, we may use those shares (until such date as they could not have been used under such company’s plan) to grant awards pursuant to the Equity Plan to individuals who were not providing services to us immediately prior to the acquisition or combination.

The Equity Plan will not provide for individual limits on awards that may be granted to any individual participant under the Equity Plan. In addition, the Equity Plan will not provide for a limit on awards that may be granted to insiders of our company (as such term is defined under Canadian securities laws) under the Equity Plan. Rather, the amount of awards to be granted to individual participants will be determined by our board of directors or the nominating, governance and compensation committee from time to time, as part of their compensation decision-making processes, provided, however, that the Equity Plan will not permit awards to be granted to our independent directors in any fiscal year having a fair value as of the date of grant (as determined in accordance with FASB ASC Topic 718, or any successor standard) in excess of $500,000.

Awards. The Equity Plan provides for the grant of stock options (including non-qualified stock options, or “NQSOs,” and incentive stock options, or “ISOs”), restricted stock, dividend equivalents, stock payments, restricted stock units, or “RSUs,” performance awards, stock appreciation rights, or SARs, and other equity-based and cash-based awards, or any combination thereof. Awards under the Equity Plan will generally be set forth in award agreements, which will detail the terms and conditions of the awards, including any applicable

vesting and payment terms and post-termination exercise limitations as well as any other consequences with respect to the awards upon a termination of the applicable eligible individual’s service. Equity-based awards will generally be settled in our Class A shares, but the plan administrator may provide for cash settlement of any award. A brief description of each award type follows.

Certain Transactions. The plan administrator will have broad discretion to equitably adjust the provisions of the Equity Plan and the terms and conditions of existing and future awards, including with respect to aggregate number and type of shares subject to the Equity Plan and awards granted pursuant to the Equity Plan, to prevent the dilution or enlargement of intended benefits and/or facilitate necessary or desirable changes in the event of certain transactions and events affecting our Class A shares, such as stock dividends, stock splits, mergers, acquisitions, consolidations and other corporate transactions. In the case of certain events or changes in capitalization that constitute “equity restructurings,” equitable adjustments will be non-discretionary. In the event of a change in control where the acquirer does not assume or replace awards granted under the Equity Plan, such awards will be subject to accelerated vesting so that 100% of such awards will become vested and exercisable or payable, as applicable, prior to the consummation of the change in control transaction and, if not exercised or paid, will terminate upon consummation of the transaction. The plan administrator may also provide for the acceleration, cash-out, termination, assumption, substitution or conversion of awards in the event of a change in control or certain other unusual or nonrecurring events or transactions. A “change in control” is defined in the Equity Plan to mean (i) the acquisition by a person or group of more than 50% of the total combined voting power of our outstanding securities, (ii) during any consecutive two-year period, the replacement of a majority of our incumbent directors with directors whose election was not supported by at least two-thirds of our incumbent directors, (iii) a merger, consolidation, reorganization or business combination or the sale of substantially all of our assets, in each case, other than a transaction which results in our voting securities before such transaction continuing to represent or being converted into a majority of the voting securities of the surviving entity and after which no person or group owns a majority of the combined voting power of the surviving entity or (iv) where our shareholders approve a liquidation or dissolution of the company.

Transferability, Repricing and Participant Payments. With limited exceptions for estate planning, domestic relations orders, certain beneficiary designations and the laws of descent and distribution, awards under the Equity Plan are generally non-transferable and are exercisable only by the participant. The price per share of a stock option or SAR may not be decreased and an underwater stock option or SAR may not be replaced or cashed out without shareholder approval. With regard to tax withholding, exercise price and purchase price obligations arising in connection with awards under the Equity Plan, the plan administrator may, in its discretion, accept cash or check, our Class A shares that meet specified conditions, a “market sell order” (or other cashless broker-assisted transaction) or such other consideration as it deems suitable.

Amendment and Termination. Our board of directors may terminate, amend or modify the Equity Plan at any time and from time to time. However, we must generally obtain shareholder approval to increase the number of Class A shares available under the Equity Plan (other than in connection with certain corporate events, as described above), extend the term of a stock option held by an insider (as such term is defined under Canadian securities laws), an amendment to the amendment provision, or to the extent required by applicable law, rule or regulation (including any applicable stock exchange rule). As our Equity Plan does not limit the participation of insiders (as defined under Canadian securities laws), the rules of certain stock exchanges provide that the votes attached to securities held by insiders eligible to participate in our Equity Plan must be excluded from voting on certain matters relating to our Equity Plan which require shareholder approval, including specific amendments thereto.

Termination of Employment. The consequences of the termination of a participant’s employment, membership on our board of directors or other service arrangement will generally be determined by the plan administrator in the terms of the relevant award agreement.

Expiration Date. The Equity Plan will expire on, and no option or other award may be granted pursuant to the Equity Plan after, the tenth anniversary of the date the Equity Plan was adopted by our board of directors in 2013. Any award that is outstanding on the expiration date of the Equity Plan will remain in force according to the terms of the Equity Plan and the applicable award agreement.

Our board of directors also intends to adopt an incentive plan, which we refer to as the “Incentive Plan,” under which we will provide incentives to our NEOs and other key employees following the completion of this offering. The purpose of the Incentive Plan is to enable the company and its subsidiaries to attract, retain, motivate and reward the best qualified executive officers and key employees by providing them with the opportunity to earn competitive compensation directly linked to our performance. The material terms of the Incentive Plan are summarized below.

Administration. The Incentive Plan is administered by our nominating, governance and compensation committee, which may delegate its authority under the Incentive Plan to any of its duly constituted subcommittees.

Performance Criteria. The nominating, governance and compensation committee will be authorized to establish the performance objective or objectives that must be satisfied in order for a participant to receive an award under the Incentive Plan or to make discretionary payments from the plan. Performance objectives under the Incentive Plan will be based upon the relative or comparative achievement of performance criteria, whether in absolute terms or relative to the performance of one or more similarly situated companies or a published index covering the performance of a number of companies, as determined by the nominating, governance and compensation committee for the applicable performance period, which performance criteria may include, but will not be limited to, the following: earnings before interest, taxes, depreciation and accretion; operating earnings; net earnings; income; earnings before interest and taxes; total shareholder return; return on assets; increase in the company’s earnings or earnings per share; revenue; revenue growth; share price performance; return on invested capital; operating income; pre- or post-tax income; net income; economic value added; profit margins; cash flow; improvement in or attainment of expense or capital expenditure levels; improvement in or attainment of working capital levels; return on equity; debt reduction; gross profit; market share; cost reductions; workforce satisfaction and diversity goals; workplace health and safety goals; product quality goals; employee retention; customer satisfaction; customer retention; completion of key projects, including, but not limited to, asset acquisitions and dispositions and financial transactions; strategic plan development and/or implementation; and job profit or performance against a multiplier. Performance objectives may be established on a company-wide basis or with respect to one or more business units, divisions, subsidiaries or products, or with respect to an individual. The nominating, governance and compensation committee will be authorized to exclude any or all extraordinary, unusual or non-recurring items and the cumulative effects of accounting changes from performance objectives for a performance period and also to adjust performance objectives in its discretion.

Payment. Payment of awards will be made as soon as practicable after the nominating, governance and compensation committee determines that one or more of the applicable performance criteria have been attained or determines the payable amount of an award. The nominating, governance and compensation committee will determine whether an award will be paid in cash, stock (including restricted stock or RSUs) or other awards under the Equity Plan, or in a combination of cash, stock and other awards, and will be authorized to impose whatever additional conditions on such shares or other awards as it deems appropriate, including conditioning the vesting of such shares or other awards on the performance of additional service.

Maximum Award; Discretion. The maximum award amount payable to a participant in cash per fiscal year under the Incentive Plan will be established by our nominating, governance and compensation committee. The nominating, governance and compensation committee will be authorized, in its discretion, to increase, reduce or eliminate awards otherwise payable under the Incentive Plan for any reason.

Termination of Employment. Unless otherwise determined by the nominating, governance and compensation committee in its discretion, any participant whose employment terminates will forfeit all rights to any and all unpaid awards under the Incentive Plan.

We were incorporated in October 2012 by PEG LP, a leading developer of renewable energy and transmission projects, to own and operate certain of its power assets with stable long-term cash generation profiles. At the completion of this offering, PEG LP will own a majority of our outstanding shares. We expect to establish a mutually beneficial working relationship with PEG LP. We will own, acquire and operate projects for which the development risks have been substantially reduced in order to generate stable long-term returns, and we expect that PEG LP will invest in and deploy its staff to engage in higher-risk project development activities. We will enter into the Management Services Agreement with PEG LP that will provide for each of us to share with the other on a primarily cost-reimbursement basis our management, other personnel and administrative functions.

At the completion of this offering, PEG LP will hold interests in development projects with an expected total rated capacity of more than 3,000 MW, including the Initial ROFO Projects as well as certain transmission development projects.

To promote our growth strategy, upon the completion of this offering we will enter into a purchase rights agreement with PEG LP and its equity owners that will provide us three distinct avenues to grow our business through acquisition opportunities from PEG LP:

We refer to this collection of rights as “our Purchase Rights.” Our Gulf Wind Call Right will terminate on the second anniversary of the completion of this offering. Our Project Purchase Right and PEG LP Purchase Right will terminate together upon the fifth anniversary of the completion of this offering, but are subject to automatic five-year renewals unless either party dissents at the time of renewal. In addition, our Project Purchase Right and PEG LP Purchase Right terminate together upon the third occasion (within any five-year initial or renewal term) on which we have elected not to exercise our Project Purchase Right with respect to an operational or construction-ready project and following which PEG LP has sold the project to an unrelated third party.

Any purchase of assets from PEG LP, or of PEG LP itself, pursuant to our Project Rights will be subject to customary conditions precedent as well as the approval of the conflicts committee of our Board of Directors. See “Management—Committees of our Board of Directors—Conflicts Committee.”

At the completion of this offering, PEG LP will hold the PEG LP retained Gulf Wind interest, representing an approximate 76 MW interest in our Gulf Wind operating project. Pursuant to our Gulf Wind Call Right, we will have the right to acquire the PEG LP retained Gulf Wind interest from PEG LP at any time between the first and second anniversary of the completion of this offering at its then current fair market value. Following the first anniversary of this offering, and during the term of our Gulf Wind Call Right, we may provide notice to PEG LP of our election to exercise our Gulf Wind Call Right and, following such election, we will have an additional 120

days to consummate the acquisition. The terms of our Gulf Wind Call Right will allow us to mutually agree with PEG LP as to, or otherwise obtain an appraisal of, the then current fair market value of the PEG LP retained Gulf Wind interest.

Following completion of this offering, PEG LP will continue development of its development projects. Pursuant to, and during the term of, our Project Purchase Right, PEG LP has agreed to offer us a right of first offer with respect to any power project that it decides to sell. Given that PEG LP is primarily in the business of power project development, we anticipate that PEG LP will generally seek a purchaser of its development projects upon construction-readiness. However, PEG LP may choose to seek a purchaser of a project earlier in the project’s development stage or following commencement of its construction, in either case, depending upon the facts and circumstances applicable to such project’s anticipated timeframe for commercial operations. Our Project Purchase Right extends to the sale of all of PEG LP’s projects, including development projects. However, PEG LP will have the right to terminate our Project Purchase Right (within any five-year initial or renewal term) upon PEG LP’s third sale of an operational or construction-ready project to persons other than affiliates of PEG LP or us following our third election not to exercise our Project Purchase Right. Operational or construction-ready projects that PEG LP chooses to sell will generally include projects that have secured a power sale agreement, real estate rights, required permits, interconnection rights and equipment supply and construction agreements. Under the terms of our Project Purchase Right, once we are notified by PEG LP that it is seeking a purchaser for one of its projects, we shall either (a) deliver a written offer, or the “First Rights Project Offer,” to PEG LP to purchase its entire interest in the project setting forth our offer price, or our “Project Offer Price” and other material terms and conditions on which we propose to purchase such project, or the “Project Sale Terms,” or (b) deliver a written notice to PEG LP that we will not make an offer to purchase PEG LP’s entire interest in the project. If PEG LP elects not to accept our First Rights Project Offer, it may sell the project to a third party, provided that it sells the project within nine months of such rejection at a price not less than 105% of our Project Offer Price set forth in the First Rights Project Offer and on terms not materially less favourable than the Project Sale Terms.

The following table provides an overview of the six Initial ROFO Projects with a total PEG LP-owned capacity of 746 MW, which are predominantly operational or construction ready. All of these projects have power sale agreements and real estate and interconnection rights appropriate for each project’s stage of development. Except for the Meikle project, they all have, or are expected to have by the closing of this offering, their material permits. Excluding Gulf Wind, which is already operational, PEG LP expects to begin construction on the Initial ROFO Projects in 2013 and 2014, except for the Meikle project for which it expects to initiate construction in 2015.

PEG LP is in documentation with construction lenders that would provide financing for both the Grand Renewable and Panhandle projects. As a result, we understand that PEG LP may start construction, before the completion of this offering, of both the Grand Renewable project and the first phase of the Panhandle project, with an estimated PEG LP-owned capacity of approximately 170 MW. The electricity generated from the Meikle project is committed for sale under a 25-year PPA with BC Hydro that commences from the date of commercial operations. PEG LP is developing the Grand Renewable and Armow projects with its joint venture partner, a subsidiary of Samsung, and the K2 project with its joint venture partners, subsidiaries of Samsung and Capital Power Corporation. The electricity generated from each of these projects is committed for sale under a 20-year PPA with the OPA that commences from the date of commercial operations.

With respect to our potential acquisition of an operational or construction-ready project pursuant to our Project Purchase Right, we anticipate related discussions with PEG LP will generally commence immediately prior to or following PEG LP’s procurement of project-level construction financing.

PEG LP has notified us that it intends to sell its interest in an approximately 100 MW portion of the Panhandle project provided that it is able to achieve a financial closing for that portion of the project in 2013. We have not yet determined our offer price, and our exercise of our Project Purchase Right with respect to this project will be subject to our review of the final agreed terms and conditions of the proposed transaction and the expected accretion to our shareholder returns and risk profile of the project, as well as the approval of our conflicts committee and board of directors.

We have a right of first offer with respect to PEG LP itself or substantially all of its assets, if the equity owners of PEG LP decide to sell PEG LP or substantially all of its assets.

Under the terms of our PEG LP Purchase Right, the equity owners of PEG LP will be required to notify us if they intend to sell PEG LP or substantially all of its assets, and we will be required to either (a) deliver a written offer, or the “First Rights PEG LP Offer,” to purchase PEG LP or substantially of its assets, setting forth our offer price, or our “PEG LP Offer Price,” and the other material terms and conditions upon which we propose to purchase PEG LP, or the “PEG LP Sale Terms,” or (b) deliver a written notice to the equity owners of PEG LP that we will not make an offer to purchase PEG LP or substantially all of its assets. If the equity owners of PEG LP elect not to accept our First Rights PEG LP Offer, they may sell PEG LP or substantially all of its assets to another third party, provided that the sale is consummated within nine months of the date of the First Rights PEG LP Offer, at a price not less than 105% of the PEG LP Offer Price and otherwise on terms not materially less favourable than those set forth in the First Rights PEG LP Offer.

At the completion of this offering, PEG LP will own a majority of our outstanding shares.

We will pay a portion of the net proceeds from this offering to PEG LP as part of the consideration to acquire our projects from PEG LP in the Contribution Transactions. See “Use of Proceeds.” In the Contribution

Transactions, and prior to the completion of this offering, PEG LP will contribute to us all of the assets that will be used in the operation of our business. As consideration for this contribution, we will pay $ million from the proceeds of this offering to PEG LP and issue to PEG LP of our Class A shares and of our Class B shares in the aggregate having a total value of $ million based on an initial public offering price of $ per Class A share (the midpoint of the range set forth on the cover of this prospectus). If the underwriters choose to exercise their overallotment option, they have the right to purchase up to Class A shares from the selling shareholder for resale to the public in connection with this offering. Upon completion of this offering, PEG LP will hold approximately % of our outstanding Class A shares and % of our outstanding Class B shares (or % and %, respectively, if the underwriters exercise their overallotment option in full), representing in the aggregate an approximate % voting interest in our company (or % if the underwriters exercise their overallotment option in full). The remaining % of our outstanding Class B shares will be held by members of our management. Until the Conversion Event, neither PEG LP nor the management holders of our Class B shares will be entitled to receive any dividends on their Class B shares. For a further discussion of our Class A and Class B shares, see “The Offering” and “Description of Capital Stock.” See “Principal and Selling Shareholders” and “Shares Eligible for Future Sale—Registration Rights Agreement” for more information about these registration rights.

Pursuant to the terms of the Shareholder Agreement, for so long as PEG LP beneficially owns at least 33¹/₃% of our outstanding shares, PEG LP’s consent will be necessary for us to take certain material corporate actions, including:

Pursuant to the Non-Competition Agreement, PEG LP will agree 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. In addition, PEG LP will notify us of opportunities to acquire power generation or transmission projects that it wishes to pursue, and, should we be interested in acquiring all or a portion of such projects, we will have the right to direct PEG LP to forego such opportunities and to cause employees of PEG LP to assist us in connection with pursuing such acquisition as a result of the Management Services Agreement (as discussed below). We may also elect to collaborate with PEG LP to jointly pursue acquisition opportunities from time to time. Riverstone will not be subject to the Non-Competition Agreement.

Our project operations personnel and executive officers will be solely compensated by us and their employment with PEG LP will terminate. These executives will lead our business functions and rely on support from PEG LP employees for certain professional, technical and administrative functions. PEG LP will retain only those employees whose primary responsibilities relate to project development or legal, financial or other administrative functions. The Management Services Agreement with PEG LP that will provide for us and PEG LP to benefit, primarily on a cost-reimbursement basis, from our respective management and other professional, technical and administrative personnel, all of whom will ultimately report to and be managed by our executive officers. In the event that PEG LP is, or substantially all of its assets are, acquired by an unrelated third party, we will also have the unilateral right to terminate the Management Services Agreement.

Under this arrangement, we anticipate that we will utilize employees from several of PEG LP’s departments, including accounting and tax, construction and engineering, corporate legal, corporate support, finance and analysis, human resources, information technology support and project development. We will agree to make our personnel available to PEG LP to the extent required for PEG LP’s development activities. For more information on management and management’s relationship with PEG LP, see “Conflicts of Interest and Fiduciary Duties” and “Management.”

The Management Services Agreement will entitle us to acquire from PEG LP any assets reasonably necessary for the administration of our business, such as computer hardware, software and data back-up infrastructure, and PEG LP will be required to reimburse us for an allocation of the costs paid by us for its share of costs going forward to the extent these assets are subsequently used in the administration of PEG LP’s business.

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 PEG LP will become our employees. For the purpose of determining the 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 daily volume weighted average price of our Class A shares 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 PEG LP 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. The employee reintegration will result in our complete internalization of the administrative, technical and other services that were initially provided to us by PEG LP 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.

The following discussion sets forth the agreements (in addition to the Management Services Agreement) that we intend to enter into with related parties in connection with this offering. The statements relating to each agreement set forth in this section and elsewhere in this prospectus are subject to and are qualified in their entirety by reference to the other discussions of such agreements in this prospectus and all of the provisions of such agreements, forms of which have been filed as exhibits to this registration statement of which this prospectus is a part.

The terms and conditions, including those relating to pricing, of these agreements to which we, PEG LP and certain other related parties are a party were negotiated in the overall context of this offering.

PEG LP intends to enter into the Contribution Agreement with us pursuant to which we will acquire our projects. See “Use of Proceeds.”

Our Santa Isabel project is currently in a dispute with PREPA over the appropriate rate being charged to the project for the electric services it uses. Currently, the difference between what we believe is the appropriate monthly charge and PREPA’s bill is approximately $200,000 each month. PEG LP has agreed to provide us with an indemnity to mitigate the economic impact on us of this dispute. Once the dispute is resolved, PEG LP will be released from any unused portion of the indemnity.

In connection with the issuance of Class A shares to PEG LP in connection with the Contribution Transactions, we intend to enter into a registration rights agreement with PEG LP, or the “Registration Rights Agreement,” for the registration and sale of such Class A shares under the U.S. Securities Act and/or the qualification for distribution of such Class A shares under the securities laws of the provinces and territories of Canada. See “Shares Eligible for Future Sale—Registration Rights Agreement” for more information about the Registration Rights Agreement.

While we believe our relationship with PEG LP provides us with a significant advantage, it is also a potential source of conflicts of interest. Prior to the completion of this offering, all of our executive officers were employees of PEG LP. In addition, three of our seven directors will not qualify as independent directors under the applicable Canadian securities laws and stock exchange rules due to their affiliation with PEG LP. See “Management.” While all of our executive officers will terminate their employment with PEG LP prior to the completion of this offering, pursuant to the terms of the Management Services Agreement, the shared PEG executives will also serve as executive officers of PEG LP and will continue to provide services to PEG LP and, as a result, will have fiduciary or other obligations to PEG LP and its equity owners. None of our officers will receive any compensation paid by PEG LP after the completion of this offering, but some of our executive officers will continue to have economic interests in PEG LP. Each of Mr. Garland, our Chief Executive Officer (and one of our directors), Mr. Armistead, our Executive Vice President, Business Development, Mr. Elkort, our Executive Vice President and General Counsel, Mr. Lillybeck, our Senior Vice President, Fiscal and Administrative Services, Mr. Russell, our Senior Vice President, Engineering and Construction, and Ms. Blaine, Vice President and Secretary, will continue to have economic interests in PEG LP. In addition, Messrs. Garland and Armistead will continue to serve as directors of, and will therefore have certain fiduciary duties to, PEG LP. As a result of these relationships, conflicts of interest may arise in the future between us (and our shareholders other than PEG LP) and PEG LP (and its owners and affiliates).

The officers and directors of PEG LP have a fiduciary duty to manage its business in a manner beneficial to its owners and, in connection with fulfilling this duty, PEG LP’s ownership and management may compete with us for the time and focus of the shared PEG executives or for employment of other talented individuals, or may develop PEG LP’s business plan in a manner that is incompatible with our objectives, any of which might result in our failure to realize the full benefits of the relationship that we currently contemplate and jeopardize our ability to execute our growth plan. In addition, although we believe that PEG LP will continue to focus its efforts on power project development and not on our core business function of operating and constructing commercially viable power projects, other than with respect to the terms of Non-Competition Agreement, PEG LP will not be restricted from competing with us and we cannot assure you that PEG LP’s business focus will not change over time. See “Certain Relationships and Related Party Transactions—Non-Competition Agreement.” Pursuant to the Shareholder Agreement, PEG LP’s consent will be necessary for us to take certain material corporate actions, which could adversely effect our business. See “Certain Relationships and Related Party Transactions—Shareholder Agreement.”

Given that PEG LP will beneficially own a majority of our voting securities following the completion of this offering, PEG LP will effectively control our company and will also be a related party. As a result, any material transaction between us and PEG LP will be subject to our corporate governance guidelines and the prior approval of the conflicts committee, which will be comprised solely of independent members of our board of directors. Because certain of our directors and executive officers will continue to have economic interests in PEG LP, these individuals will have an interest in any transaction between our company and PEG LP in proportion to their respective economic interests in PEG LP. As a result, these individuals may be conflicted when advising the conflicts committee or otherwise participating in the negotiation or approval of such transactions on our behalf. The conflicts committee will have the ability to consult with those of our executive officers and operating personnel who do not have economic interests in PEG LP, including Mr. Lyon, our Chief Financial Officer, and Mr. Pedersen, our Chief Investment Officer, as well as other external advisors that the conflicts committee deems appropriate, in connection with reviewing a transaction with PEG LP, in connection with reviewing a transaction with PEG LP. In addition, in some cases, transactions between our company and PEG LP will be related party transactions for the purposes of MI 61-101. MI 61-101 provides, among other things, that in certain circumstances a transaction between an issuer and a related party of the issuer is subject to formal valuation and minority shareholder approval requirements. The occurrence of the employee reintegration will neither alter our Purchase Rights nor the terms of the Management Services Agreement. Following the employee reintegration, we will continue to provide services to PEG LP to the extent required by PEG LP’s development activities and

the consideration for such services would continue to be paid primarily on a cost reimbursement basis pursuant to the terms of the Management Services Agreement. Upon employee reintegration, we expect that our principal focus will continue to be owning operational and under construction power projects. However, reintegration is expected to enhance our long-term ability to independently develop projects and grow our business without reliance on PEG LP. For more information about the reintegration, see “Business—Our Strategy—Reintegration of PEG LP Employees.”

Following the completion of this offering, Mr. Garland, our Chief Executive Officer (and one of our directors), Mr. Armistead, our Executive Vice President, Business Development, Mr. Elkort, our Executive Vice President and General Counsel, Mr. Lillybeck, our Senior Vice President, Fiscal and Administrative Services, Mr. Russell, our Senior Vice President, Engineering and Construction, and Ms. Blaine, Vice President and Secretary, will continue to hold direct and indirect limited partnership interests in PEG Holdings. Messrs. Garland, Armistead, Elkort, Lillybeck, Russell’s and Ms. Blaine’s continuing interests in PEG Holdings will entitle them to indirectly receive a proportionate share of the distributable profits of PEG LP, which would include a proportionate share of profits from the sale of a project to our company, or the sale of our shares, by PEG LP. PEG Holdings has both A interests and B interests. The A interests and B interests effectively entitle holders thereof, in aggregate, to at least 85% and up to 15% of the cumulative profits of PEG LP, respectively. The table below sets forth the number and percentage of A interests and B interests held by each of Messrs. Garland, Armistead, Elkort, Lillybeck, Russell and Ms. Blaine.

On or immediately prior to the completion of this offering, pursuant to the terms of the Contribution Agreement, we will enter into the Contribution Transactions. In connection with the Contribution Transactions, PEG LP will contribute to us all of our projects, including the related properties and other assets that will be used in our business, together with liabilities and obligations to which such projects are subject. PEG LP currently holds its interests in these projects through one or more holding companies, the sole purposes of which are to hold such interests or to obtain related financing. We will also assume responsibility for approximately $ million of accrued employee bonuses and other costs, which we refer to as the “employee accruals.”

As consideration for the assets contributed to us by PEG LP in the Contribution Transactions, net of employee accruals we will pay $ million from the proceeds of this offering to PEG LP and issue to PEG LP of our Class A shares and of our Class B shares. Upon completion of this offering, PEG LP will hold approximately % of our outstanding Class A shares and % of our outstanding Class B shares (or % and %, respectively, if the underwriters exercise their overallotment option in full), representing in the aggregate an approximate % voting interest in our company (or % if the underwriters exercise their overallotment option in full). The remaining % of our outstanding Class B shares will be held by members of our management. Until the Conversion Event, neither PEG LP nor the management holders of our Class B shares will be entitled to receive any dividends on their Class B shares. For a further discussion of our Class A and Class B shares, see “The Offering” and “Description of Capital Stock.” In connection with the Contribution Transactions, PEG LP also will receive customary resale registration rights with respect to our shares. See “Shares Eligible for Future Sale—Registration Rights Agreement.”

The following diagram summarizes our ownership structure upon completion of this offering and the completion of the Contribution Transactions. Except as specified below, each of our subsidiaries is wholly owned.

The following subsidiaries represent our subsidiaries with total assets exceeding 10% of our consolidated assets or with revenue exceeding 10% of our consolidated revenue as of June 30, 2013.

The following table sets forth information with respect to the beneficial ownership of, and the combined voting power with respect to, our Class A shares and Class B shares immediately following the completion of this offering and the Contribution Transactions by:

and, with respect to each of the foregoing, excluding and including, the impact of the exercise of the underwriters’ overallotment option to purchase an up to an additional of our Class A shares from the selling shareholder within 30 days from the closing date of this offering.

The amounts and percentages of shares beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under SEC rules, a person is deemed to be a “beneficial” owner of a security if that person has or shares voting power or investment power, which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Securities that can be so acquired are not deemed to be outstanding for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed to be a beneficial owner of securities as to which such person has no economic interest.

Except as otherwise indicated in these footnotes, each of the beneficial owners listed will have, to our knowledge, sole voting and investment power with respect to the shares of capital stock and the business address of each such beneficial owner is c/o Pattern Energy Group Inc., Pier 1, Bay 3, San Francisco, California 94111.

The following is a description of the material terms of our outstanding indebtedness on completion of this offering.

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 will have an “accordion feature” under which we will 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 June 30, 2013, letters of credit of $39.1 million have been issued and we have drawn $56.0 million under the revolving credit facility.

The loans under our revolving credit facility will either be 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 will accrue interest at a rate per annum equal to LIBOR, as published by Reuters plus 3.50%.

Certain of our project subsidiaries will be subject to usual and customary affirmative and negative covenants under our revolving credit facility. Specifically, such project subsidiaries will be 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.

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

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 June 30, 2013 approximately $168.9 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. Other than Pattern Renewables LP’s portion of the reactive power upgrade loans, the financing is non-recourse to us.

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%.

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.

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.

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 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 favour 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.

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

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 (iv) is continuing and the rent service coverage ratio is equal to or greater than 1.20:1.00.

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.

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 June 30, 2013, C$232.9 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.

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.

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.

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.

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 June 30, 2013, approximately $176.1 million of indebtedness was outstanding under the Spring Valley Financing Agreement, all of which was outstanding under the term loan. PEG LP has agreed to indemnify Spring Valley LLC in the event of disallowance of the ITC cash grant and we will assume these obligations in connection with the Contribution Transactions. Other than the indemnification, the financing is non-recourse to us.

The grant bridge loan and reserve loans are either base rate loans or LIBOR loans. Grant bridge loans and reserve loans that are LIBOR loans accrue interest at LIBOR plus 2.00% per annum and grant bridge loans 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 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 construction loan commitment, the grant bridge loan commitment, 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.

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.

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.

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 are 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 June 30, 2013, approximately $117.8 million of indebtedness was outstanding under the Santa Isabel Financing Agreement. PEG LP has agreed to indemnify Santa Isabel LLC in the event of disallowance of the ITC cash grant, and we will assume this obligation in connection with the Contribution Transactions. See “Business—Legal Proceedings.” Other than the indemnifications, the financing is non-recourse to us.

The cash grant bridge loan, operations and maintenance reserve loans, debt service reserve loans and PPA collateral loans are either base rate loans or LIBOR loans. Cash grant bridge loans that are LIBOR loans accrue interest at LIBOR plus 2.00% per annum, and cash grant bridge loans that are base rate loans accrue interest at the greater of (i) the prime rate and (ii) the federal funds rate plus 0.50%, plus 1.00% per annum. 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 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 construction loan commitment, the cash grant bridge loan commitment, the operations and maintenance reserve loan commitment the debt service reserve loan commitment, the PPA collateral commitment and PPA collateral advance fees.

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.

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 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 will be used to finance the construction of the Ocotillo wind project and will be 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 is to be repaid from reimbursements by the interconnecting utility of reimbursable network upgrade costs following completion of the project. The construction loans convert into term loans upon completion of construction of the Ocotillo wind project and certain other specified conditions.

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. PEG LP has 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, and we will assume these obligations in connection with the Contribution Transactions. See “Business—Legal Proceedings.” Other than these indemnifications, the financing is non-recourse to us.

The network upgrade bridge loan, 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 rate plus 1.00%. The applicable margin for network upgrade bridge loans and for

commercial bank tranche construction loans is 3.00%, and the applicable margin for network upgrade bridge loans after conversion is 2.75%. 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 4.4%. 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 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 4.8%. 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 June 30, 2013, approximately $387.4 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, the network upgrade bridge loan commitment, and each of the LC commitments.

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.

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.

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 June 30, 2013, approximately $121.8 million of indebtedness was outstanding under the El Arrayán Credit Agreement. The financing is non-recourse to us.

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.

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.

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.

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 June 30, 2013, the outstanding balance under the value added tax facility was zero.

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 $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 $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 June 30, 2013, the outstanding balance of the loan was approximately $175.5 million.

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

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.

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.

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 LLC is owned 100% by Pattern Gulf Wind Holdings LLC, or “Pattern Gulf Holdings.” On August 25, 2010, a subsidiary of PEG LP 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. In connection with the Contribution Transactions, we will acquire 60% of the existing Class B member interests in Pattern Gulf Holdings and one of our subsidiaries will assume responsibility as the managing member of Pattern Gulf Holdings. Throughout the remainder of this description, we and PEG LP (as a result of its ownership of the PEG LP retained Gulf Wind interest) together are collectively referred to as the “Class B Members.”

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 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.

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.

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.

Pattern Gulf Holdings and the Project are managed by the existing Class B Member, as the managing member, which role will be assumed by one of our subsidiaries following the execution of the Contribution Transactions. 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.

The following is a description of our capital stock and the material provisions of our amended and restated certificate of incorporation and amended and restated bylaws, as each will be in effect upon the closing of this offering and following the Contribution Transactions. The following is only a summary and is qualified in its entirety to the provisions of our amended and restated certificate of incorporation and amended and restated bylaws, copies of which are available as set forth under the caption entitled “Where You Can Find More Information.”

Prior to the effectiveness of our amended and restated certificate of incorporation, our authorized capital stock consists of shares of 1,000 common stock, par value $0.01 per share. Upon effectiveness of our amended and restated certificate of incorporation, our authorized capital stock will consist of Class A shares, par value $0.01 per share, Class B shares, par value $0.01 per share and shares of preferred stock, par value $0.01 per share. Following the completion of this offering, and shares of Class A common stock and Class B common stock, respectively, will be issued and outstanding. The underwriters have been granted an option to purchase up to of our Class A shares from PEG LP within 30 days from the closing date of this offering at the initial public offering price per Class A share less underwriters’ commissions. However, because the Class A shares subject to the underwriters’ overallotment option will be issued to PEG LP in connection with the Contribution Transactions, any exercise by the underwriters of their overallotment option will not increase our issued and outstanding Class A shares. The rights and privileges of holders of our Class A shares and Class B shares are subject to any series of preferred stock that we may issue in the future.

Holders of Class A shares will be entitled to one vote for each share held of record on all matters submitted to a vote of the shareholders, including the election of directors. There will be no cumulative voting in the election of directors, which means that holders of a majority of the outstanding Class A and Class B shares will be able to elect all of the directors, and holders of less than a majority of such shares will be unable to elect any director. Under our amended and restated certificate of incorporation, subject to preferences that may be applicable to any outstanding shares of preferred stock, holders of Class A shares are entitled to receive ratably such dividends, if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. Our revolving credit facility imposes restrictions on certain of our project subsidiaries’ ability to distribute funds to us. See “Description of Certain Financing Arrangements—Revolving Credit Facility.” The holders of Class A shares will have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to the Class A shares. In the event of any liquidation, dissolution or winding-up of our affairs, holders of Class A shares will be entitled to share ratably, together with holders of Class B shares, in our assets that are remaining after payment or provision for payment of all of our debts and obligations and after liquidation payments to holders of outstanding shares of preferred stock, if any.

The rights of the holders of our Class A and Class B shares will be identical other than in respect of dividends and the conversion rights of the Class B shares. While each Class A and Class B share will have one vote on all matters submitted to a vote of our shareholders, our Class B shares will have no rights to dividends or distributions (other than upon liquidation). Upon the Conversion Event, all of our outstanding Class B shares will automatically convert, on a one-for-one basis, into Class A shares. Upon the later of December 31, 2014 and the date on which our South Kent project has achieved commercial operations, all of our outstanding Class B shares will automatically convert, on a one-for-one basis, into Class A shares.

Upon the completion of this offering, our amended and restated certificate of incorporation will authorize the issuance of blank check preferred stock, which, if issued, would have priority over the shares of common

stock with respect to dividends and other distributions, including the distribution of our assets upon liquidation. Unless required by law or by applicable stock exchanges, our board of directors will have the authority without further shareholder authorization to issue from time to time shares of preferred stock in one or more series and to fix the terms, limitations, relative rights and preferences and variations of each series. Although we have no present plans to issue any shares of preferred stock, the issuance of shares of preferred stock, or the issuance of rights to purchase such shares, could decrease the amount of earnings and assets available for distribution to the holders of shares of common stock, could adversely affect the rights and powers, including voting rights, of the shares of our common stock, and could have the effect of delaying, deterring or preventing a change in control of us or an unsolicited acquisition proposal.

Our amended and restated certificate of incorporation and amended and restated bylaws will contain provisions indemnifying our directors and officers to the fullest extent permitted by law. Prior to the completion of this offering, we intend to enter into indemnification agreements with each of our directors and executive officers that may, in some cases, be broader than the specific indemnification provisions contained under Delaware law.

This provision does not affect a director’s liability under the federal securities laws.

Provisions of Our Certificate of Incorporation and Delaware Law that May Have an Anti-Takeover Effect

Upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will contain certain provisions that could discourage, delay or prevent a change in control of our company or changes in our management that the shareholders of our company may deem advantageous. Among other things, these provisions could include those that would:

The foregoing provisions of our amended and restated certificate of incorporation and bylaws could discourage potential acquisition proposals and could delay or prevent a change in control. These provisions are intended to enhance the likelihood of continuity and stability in the composition of the board of directors and in the policies formulated by the board of directors and to discourage certain types of transactions that may involve an actual or threatened change of control. These provisions are designed to reduce our vulnerability to an unsolicited acquisition proposal. The provisions also are intended to discourage certain tactics that may be used in proxy fights. However, such provisions could have the effect of discouraging others from making tender offers for our shares and, as a consequence, they also may inhibit fluctuations in the market price of our shares of common stock that could result from actual or rumoured takeover attempts. Such provisions also may have the effect of preventing changes in our management.

Subject to certain exceptions, Section 203 of the Delaware General Corporation Law, or “DGCL,” prohibits a Delaware corporation from engaging in any “business combination” (as defined below) with any “interested shareholder” (as defined below) for a period of three years following the date that such shareholder became an interested shareholder, unless: (1) prior to such date, the board of directors of the corporation approved either the business combination or the transaction that resulted in the shareholder becoming an interested shareholder; (2) on consummation of the transaction that resulted in the shareholder becoming an interested shareholder, the interested shareholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of determining the number of shares outstanding those shares owned (x) by persons who are directors and also officers and (y) by employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or (3) on or subsequent to such date, the business combination is approved by the board of directors and authorized at an annual or special meeting of shareholders, and not by written consent, by the affirmative vote of at least 66 2/3% of the outstanding voting stock that is not owned by the interested shareholder.

In our amended and restated certificate of incorporation, we will elect not to be governed by Section 203 of the DGCL, as permitted under and pursuant to subsection (b)(3) of Section 203. Section 203 of the DGCL defines “business combination” to include: (1) any merger or consolidation involving the corporation and the interested shareholder; (2) any sale, transfer, pledge or other disposition of 10% or more of the assets of the corporation involving the interested shareholder; (3) subject to certain exceptions, any transaction that results in the issuance or transfer by the corporation of any stock of the corporation to the interested shareholder; (4) any transaction involving the corporation that has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested shareholder; or (5) the receipt by the interested shareholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the corporation. In general, Section 203 defines an “interested shareholder” as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by such entity or person.

Subject to the terms of the Non-Competition Agreement with and our Purchase Rights granted to us by PEG LP (see “Certain Relationships and Related Party Transactions”), 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 their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries 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 controlling shareholder 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, any such business opportunity is expressly offered to such director in writing solely in his or her capacity as our director.

We have appointed Computershare Trust Company, N.A. (including its affiliates in Canada) as the transfer agent and registrar for our shares of common stock.

Upon the completion of this offering, we will have outstanding Class A shares and Class B shares. Of these shares, Class A shares and Class B shares, respectively, will be freely transferable without restriction or further registration under the U.S. Securities Act by persons other than “affiliates,” as that term is defined in Rule 144 under the U.S. Securities Act, or “control persons” within the meaning of Canadian securities laws. Generally, the balance of our outstanding shares are “restricted securities” within the meaning of Rule 144 under the U.S. Securities Act, subject to the limitations and restrictions that are described below. Shares purchased by our affiliates, such as PEG LP, will be “restricted securities” under Rule 144. Restricted securities may be sold in the public market only if registered or if they qualify for an exemption from registration under Rules 144 or 701 promulgated under the U.S. Securities Act.

In connection with this offering, we, our executive officers and directors and PEG LP have agreed, subject to certain exceptions, not to sell or transfer any shares or securities convertible into, exchangeable for, exercisable for, or repayable with shares, for 180 days after the date of the closing of this offering without first obtaining the written consent of the representatives of the underwriters. See “Underwriting.”

In general, under Rule 144 as in effect on the date of this prospectus, beginning 90 days after the completion of this offering, a person (or persons whose shares are required to be aggregated) who is an affiliate and who has beneficially owned our shares for at least six months is entitled to sell in any three-month period a number of shares that does not exceed the greater of:

Sales by our affiliates under Rule 144 are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us. An “affiliate” is a person that directly, or indirectly through one or more intermediaries, controls or is controlled by, or is under common control with an issuer.

Under Rule 144, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least six months (including the holding period of any prior owner other than an affiliate), would be entitled to sell those shares subject only to availability of current public information about us, and after beneficially owning such shares for at least 12 months (including the holding period of any prior owner other than an affiliate), would be entitled to sell an unlimited number of shares without restriction. To the extent that our affiliates sell their shares, other than pursuant to Rule 144 or a registration statement, the purchaser’s holding period for the purpose of effecting a sale under Rule 144 commences on the date of transfer from the affiliate.

In general, under Rule 701 as in effect on the date of this prospectus, any of our employees, directors, officers, consultants or advisors who purchased shares from us in reliance on Rule 701 in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering, or who purchased shares from us after that date upon the exercise of options granted before that date, are eligible to resell such shares 90 days after the effective date of this offering in reliance upon Rule 144. If such person is not

an affiliate, such sale may be made subject only to the manner of sale provisions of Rule 144. If such a person is an affiliate, such sale may be made under Rule 144 without compliance with the holding period requirement, but subject to the other Rule 144 restrictions described above.

In conjunction with this offering, we expect to file a registration statement on Form S-8 under the U.S. Securities Act, which will register up to Class A shares in the form of underlying stock options or restricted stock awards or reserved for issuance under our equity incentive plans. That registration statement will become effective upon filing, and Class A shares covered by such registration statement are eligible for sale in the public market immediately after the effective date of such registration statement, subject to Rule 144 volume limitations applicable to affiliates, vesting restrictions with us and the lock-up agreements described above.

In connection with the completion of this offering, we will grant PEG LP, who will receive our shares in the Contribution Transactions, certain registration rights with respect to the resale of such shares. All of the Class A shares issued to PEG LP in the Contribution Transactions will be subject to the Registration Rights Agreement, as well as Class A shares held by PEG LP upon the conversion of the Class B shares. Beginning as early as six months following completion of this offering, the holders of such Class A shares will be entitled to require us to seek to register all such Class A shares for public sale under the U.S. Securities Act, and/or qualify such Class A shares for distribution under Canadian securities laws, subject to certain exceptions, limitations and conditions precedent.

The sale of any of our shares in the public market in Canada by a control person will be subject to restrictions under applicable Canadian securities laws in addition to those restrictions noted above, unless the sale is qualified under a prospectus filed with Canadian securities regulatory authorities or if the following conditions are fulfilled:

Sales under the procedure noted above are also subject to other requirements and restrictions regarding the manner of sale, payment of commissions, reporting and availability of current public information about us and compliance with applicable Canadian securities laws.

The following discussion is a summary of the material U.S. federal income tax consequences relevant to the purchase, ownership and disposition of our Class A common shares issued pursuant to this offering, but does not purport to be a complete analysis of all potential tax effects related thereto. The effects of other U.S. federal tax laws, such as estate and gift tax laws, and any applicable state, local or foreign tax laws are not discussed. This discussion is based on the Code, Treasury Regulations promulgated thereunder, judicial decisions and published rulings and administrative pronouncements of the U.S. Internal Revenue Service, or “IRS,” in effect as of the date of this offering. These authorities may change or be subject to differing interpretations. Any such change may be applied retroactively in a manner that could adversely affect a holder of our Class A common shares. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance the IRS or a court will not take a contrary position regarding the tax consequences of the purchase, ownership and disposition of our Class A common shares.

This discussion is limited to persons that hold our Class A common shares as a “capital asset” within the meaning of Section 1221 of the Code (generally property held for investment). This discussion does not address all U.S. federal income tax consequences relevant to a holder’s particular circumstances or to a holder subject to particular rules, including, without limitation:

If an entity taxed as a partnership for U.S. federal income tax purposes holds our Class A common shares, the tax treatment of a partner in the partnership will depend on the status of the partner, the activities of the partnership and certain determinations made at the partner level. Accordingly, partnerships holding our Class A common shares and the partners in such partnerships should consult their tax advisors regarding the specific U.S. federal income tax consequences to them.

THIS DISCUSSION IS FOR INFORMATIONAL PURPOSES ONLY AND IS NOT INTENDED AS TAX ADVICE. YOU SHOULD CONSULT YOUR TAX ADVISOR WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO YOUR PARTICULAR SITUATION AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON STOCK ARISING UNDER OTHER FEDERAL TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, FOREIGN OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

The following is a summary of the material U.S. federal income tax consequences relevant to U.S. Holders. For purposes of this discussion, a “U.S. Holder” is a beneficial owner of our Class A common shares that is any of the following:

We expect to distribute cash in excess of our earnings and profits computed under U.S. federal income tax principles due to a variety of factors, including significant non-cash deductions, such as depreciation and amortization. If our distributions to holders of our Class A common shares exceed our current and accumulated earnings and profits for a taxable year, the excess distributions will not be taxable as dividends but rather will be treated as a return of capital for U.S. federal income tax purposes, causing a reduction in the adjusted tax basis of the Class A common shares to the extent thereof, and any balance in excess of adjusted tax basis will be treated as gain from the sale or exchange of such Class A common shares. As a result, U.S. Holders should expect to receive distributions that may represent a non-taxable return of capital to the extent thereof (and gain thereafter), although no assurance can be given in this regard. The amount of any distribution of property other than cash will be the fair market value of such property on the date of the distribution.

Upon a sale, taxable exchange or other taxable disposition of our Class A common shares, a U.S. Holder generally will recognize capital gain or loss equal to the difference between (i) the amount realized (that is, the

amount of cash and the fair market value of any property received) upon such taxable disposition and (ii) the U.S. Holder’s adjusted tax basis in such Class A common shares. A U.S. Holder’s adjusted tax basis in our Class A common shares will generally equal its cost for such shares, decreased by the amount of any distributions treated as a nontaxable return of capital. Such capital gain or loss will generally be long-term capital gain or loss if the U.S. Holder’s holding period in the Class A common shares is more than one year at the time of the taxable disposition. In the case of certain non-corporate U.S. Holders (including individuals), long-term capital gain generally will be subject to tax at a reduced rate. The deductibility of capital losses is subject to limitations.

When required, we or our paying agent will report to U.S. Holders and to the IRS amounts paid on or with respect to our Class A common shares and the amount of tax, if any, withheld from such payments. A U.S. Holder will generally be subject to backup withholding on any distributions paid on our Class A common shares and proceeds from a disposition of our Class A common shares at the applicable rate if the U.S. Holder fails to provide us or our paying agent with a correct taxpayer identification number, has been notified by the IRS that it is subject to backup withholding as a result of the failure to properly report payments of interest or dividends or, in certain circumstances, has failed to certify under penalty of perjury that it is not subject to backup withholding. U.S. Holders may be eligible for an exemption from backup withholding by providing a properly completed IRS Form W-9 (or suitable substitute successor form) to us or our paying agent.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a U.S. Holder’s U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

The following is a summary of the material U.S. federal income tax consequences relevant to Non-U.S. Holders. For purposes of this discussion, a “Non-U.S. Holder” is a beneficial owner of our Class A common shares that is not a U.S. Holder.

Distributions we make on our Class A common shares will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Subject to the discussions below relating to backup withholding and foreign accounts, dividends paid to a Non-U.S. Holder that are not effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States will generally be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividends. However, Non-U.S. Holders may be entitled to a reduction in or an exemption from withholding on dividends either (i) as provided in an applicable income tax treaty or (ii) in the event such dividends are effectively connected with the conduct by the Non-U.S. Holder of a trade or business within the United States. For example, Non-U.S. Holders that are Canadian residents qualifying for the benefits of the income tax treaty between the United States and Canada will generally be entitled to claim a reduced 15% rate with respect to such withholding tax on dividends. To claim any such reduction or exemption from withholding, the Non-U.S. Holder must provide us, our paying agent or other relevant withholding agent with a properly executed (a) IRS Form W-8BEN claiming an exemption from or reduction of the withholding tax under the benefit of an income tax treaty between the United States and the Non-U.S. Holder’s country of residence or (b) IRS Form W-8ECI stating that the dividends are not subject to withholding tax because they are effectively connected with the conduct by the Non-U.S. Holder of a trade or business within the United States, as may be applicable. These certifications must be provided to us, our paying agent or other relevant withholding agent prior to the payment of dividends and must be updated in accordance with applicable rules. Non-U.S. Holders should consult their tax advisors regarding their entitlement to benefits under any applicable income tax treaty.

If dividends paid to a Non-U.S. Holder are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such dividends are attributable), then, although exempt from U.S. federal withholding tax (provided the Non-U.S. Holder provides appropriate certification, as described above), the Non-U.S. Holder will be subject to U.S. federal income tax on such dividends on a net income basis at regular graduated U.S. federal income tax rates. In addition, if the Non-U.S. Holder is a corporation, a branch profits tax equal to 30% (or such lower rate specified by an applicable income tax treaty) of its effectively connected earnings and profits for the taxable year, as adjusted for certain items.

As discussed above under “Consequences to U.S. Holders—Distributions,” we expect to distribute cash in excess of our earnings and profits computed under U.S. federal income tax principles. Such excess distributions will not be taxable as dividends but rather will be treated as a return of capital for U.S. federal income tax purposes, causing a reduction in the adjusted tax basis of the Class A common shares to the extent thereof, and any balance in excess of adjusted tax basis will be treated as gain from the sale or exchange of such Class A common shares. To the extent such distributions are treated as a return of capital or gain with respect to our Class A common shares for U.S. federal income tax purposes, subject to the discussions below on backup withholding and foreign accounts, a Non-U.S. Holder should not be subject to any U.S. federal withholding tax, so long as we are not, and have not been during the applicable holding period, a USRPHC (as discussed below). It is possible that a distribution made to Non-U.S. Holders may be subject to over-withholding because, for example, at the time of the distribution we or the relevant withholding agent may not be able to determine how much of the distribution constitutes dividends or the proper documentation establishing the benefits of any applicable treaty has not been supplied. If there is any over-withholding on distributions made to a Non-U.S. Holder, such Non-U.S. Holder should be able to obtain a refund of the over-withheld amount from the IRS (or a credit in lieu of a refund) by complying with certain applicable procedures. Non-U.S. Holders should consult their tax advisors regarding the applicable withholding tax rules and the possibility of obtaining a refund of any over-withheld amounts.

Subject to the discussions below on backup withholding and foreign accounts, a Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our Class A common shares unless:

Gain described in the first bullet point above will generally be subject to U.S. federal income tax on a net income basis at regular graduated U.S. federal income tax rates. A Non-U.S. Holder that is a foreign corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) of a portion of its effectively connected earnings and profits for the taxable year, as adjusted for certain items.

A Non-U.S. Holder described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on any gain derived from the sale or other disposition, which may be offset by certain U.S. source capital losses of the Non-U.S. Holder, subject to certain limitations.

With respect to the third bullet point above, we believe we are not currently, and do not anticipate becoming in the foreseeable future, a USRPHC. However, the determination of whether we are a USRPHC depends on the fair market value of our USRPIs relative to the fair market value of our other business assets and our non-U.S. real property interests, and it is not always clear whether an asset is a USRPI. In addition, whether we become a USRPHC in future years will depend on our actual operations and assets at such time. As a result, there is no assurance that we are not a USRPHC or will not become one in the future, and the foregoing sentences do not constitute a representation regarding the likelihood that we are not, or will not become, a USRPHC. Non-U.S. Holders should consult their tax advisors regarding the possibility and consequences of our being or becoming a USRPHC. Notwithstanding the foregoing, even if we are or were to become a USRPHC, gain arising from the sale or other taxable disposition by a Non-U.S. Holder of our Class A common shares will not be subject to U.S. federal income tax if our Class A common shares are “regularly traded,” as defined by applicable Treasury Regulations, on an established securities market, and such Non-U.S. Holder owned, actually or constructively, 5% or less of our Class A common shares throughout the shorter of the five-year period ending on the date of the sale or other disposition or the Non-U.S. Holder’s holding period for such Class A common shares.

Non-U.S. Holders should consult their tax advisors regarding applicable income tax treaties that may provide for different rules.

Subject to the discussion below of foreign accounts, a Non-U.S. Holder generally will not be subject to backup withholding with respect to payments of dividends, provided we (or other applicable withholding agents) do not have actual knowledge or reason to know such holder is a “United States person” within the meaning of the Code and the holder certifies its non-U.S. status, such as by providing a valid IRS Form W-8BEN or W-8ECI, or other applicable certification. However, we generally must report annually to the IRS and to each Non-U.S. Holder the amount of dividends paid to such holder, the name and address of the recipient and the amount of any tax withheld with respect to those dividends. Copies of these information returns may also be made available under the provisions of a specific treaty or agreement to the tax authorities of the country in which the Non-U.S. Holder resides or is established.

Information reporting and backup withholding may apply to the proceeds of a sale of our Class A common shares within the United States, and information reporting may (although backup withholding generally will not) apply to the proceeds of a sale of our Class A common shares outside the United States conducted through certain U.S.-related financial intermediaries, in each case, unless the beneficial owner certifies under penalty of perjury that it is a Non-U.S. Holder on IRS Form W-8BEN or other applicable form (and the payor does not have actual knowledge or reason to know that the beneficial owner is a United States person) or such owner otherwise establishes an exemption.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a Non-U.S. Holder’s U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Legislation incorporating provisions referred to as the Foreign Account Tax Compliance Act, or “FATCA,” was enacted March 18, 2010. Withholding taxes may be imposed under FATCA on certain types of payments made to “foreign financial institutions” (as defined in the Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on any payments made on our Class A common shares to a “foreign financial institution” (as defined in the Code) or to a “non-financial foreign entity” (as defined in the Code), unless (1) the foreign financial institution undertakes certain diligence and reporting obligations, (2) the non-financial foreign entity either certifies it does not have any “substantial United States owners” (as defined in the Code) or furnishes identifying information regarding each substantial United States owner or (3) the foreign

financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities (as defined in applicable Treasury Regulations), annually report certain information about such accounts and withhold 30% on payments to non-compliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

Although the Code provides that the withholding rules described above apply to relevant payments made after December 31, 2012, Treasury Regulations defer the effective date and provide that such rules will apply to payments of dividends on our Class A common shares made on or after July 1, 2014 and to payments of gross proceeds from the sale or other disposition of such Class A common shares on or after January 1, 2017. Prospective investors should consult their tax advisors regarding these withholding provisions.

MATERIAL CANADIAN FEDERAL INCOME TAX CONSIDERATIONS FOR HOLDERS OF OUR CLASS A COMMON SHARES

The following is a summary of the material Canadian federal income tax considerations under the Income Tax Act (Canada), or the “Tax Act,” generally applicable to a holder who acquires our Class A shares pursuant to this offering, and who, for the purposes of the Tax Act and at all relevant times, holds such Class A shares as capital property and deals at arm’s length with, and is not affiliated with, us, which we refer to as a “Holder.” The Class A shares will generally be considered to be capital property to a Holder unless the Holder holds such Class A shares in the course of carrying on a business of buying and selling securities or has acquired them in one or more transactions considered to be an adventure or concern in the nature of trade.

This summary is not applicable to a holder: (i) with respect to whom our company is or will be a “foreign affiliate” within the meaning of the Tax Act, (ii) that is a “financial institution” for the purposes of the mark-to-market rules under the Tax Act, (iii) an interest in which is a “tax shelter” or a “tax shelter investment” as defined in the Tax Act, (iv) that is a “specified financial institution” as defined in the Tax Act, or (v) who has made a “functional currency” reporting election under section 261 of the Tax Act to report the holder’s “Canadian tax results” (as defined in the Tax Act) in a currency other than the Canadian currency. Any such holder should consult its own tax advisor with respect to the income tax considerations applicable to it in respect of acquiring, holding and disposing of the Class A shares.

This summary is based on the current provisions of the Tax Act and the regulations thereunder and an understanding of the current published administrative policies and assessing practices of the Canada Revenue Agency, or the “CRA,” made public prior to the date hereof. This summary takes into account all proposed amendments to the Tax Act and the regulations that have been publicly announced by or on behalf of the Minister of Finance (Canada), or “Finance,” prior to the date hereof, which we refer to as the “Proposed Amendments,” and assumes that such Proposed Amendments will be enacted in the form proposed, although no assurance can be given that the Proposed Amendments will be enacted in their current form or at all. Except for the Proposed Amendments, this summary does not take into account or anticipate any other changes in law or any changes in the CRA’s administrative policies and assessing practices, whether by judicial, governmental or legislative action or decision, nor does it take into account other federal or any provincial, territorial or foreign tax legislation or considerations, which may differ from the Canadian federal income tax considerations described herein. The provisions of provincial income tax legislation vary from province to province in Canada and in some cases differ from the Tax Act.

For purposes of the Tax Act, all amounts relating to the acquisition, holding or disposition of securities (including dividends, adjusted cost base and proceeds of disposition) must generally be expressed in Canadian dollars. Amounts denominated in any other currency must be converted into Canadian dollars generally based on the exchange rate quoted by the Bank of Canada for noon on the date such amounts arise or such other rate of exchange as is acceptable to the Minister of National Revenue (Canada).

This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal or tax advice to any particular Holder, and no representations with respect to the income tax considerations applicable to any particular Holder are made. This summary is not exhaustive of all Canadian federal income tax considerations. The relevant tax considerations applicable to the acquiring, holding and disposing of Class A shares may vary according to the status of the purchaser, the jurisdiction in which the purchaser resides or carries on business and the purchaser’s own particular circumstances. Accordingly, prospective Holders are urged to consult their own tax advisors about the specific tax consequences to them of acquiring, holding and disposing of Class A shares.

The following discussion applies to a Holder who, for the purposes of the Tax Act and any applicable income tax treaty or convention, and at all relevant times, is resident in Canada, which we refer to as a “Resident Holder.”

A Resident Holder will be required to include in computing such Holder’s income for a taxation year the amount of any dividends including amounts deducted for U.S. withholding tax, if any, received on our Class A shares. Dividends received on our Class A shares by a Resident Holder who is an individual will not be subject to the gross-up and dividend tax credit rules in the Tax Act normally applicable to taxable dividends received from taxable Canadian corporations. A Resident Holder that is a corporation will be required to include dividends received on our Class A shares in computing its income and will not be entitled to deduct the amount of such dividends in computing its taxable income.

To the extent that U.S. withholding tax is payable by a Resident Holder in respect of any dividends received on our Class A shares, the Resident Holder may be eligible for a foreign tax credit or deduction under the Tax Act to the extent and under the circumstances described in the Tax Act. Generally, a Resident Holder will be eligible to claim a foreign tax credit or deduction in respect of U.S. withholding tax payable by the Resident Holder only to the extent the Resident Holder has U.S. source income. Dividends paid on our Class A shares to a Resident Holder will generally be regarded as U.S. source income if the company is a resident of the United States for Canadian federal income tax purposes. Resident Holders should consult their own tax advisors regarding the availability of a foreign tax credit or deduction in their particular circumstances.

A disposition or deemed disposition of our Class A shares by a Resident Holder (including on a purchase of a Class A share for cancellation by the company) will generally result in a capital gain (or capital loss) to the extent that the proceeds of disposition, net of any reasonable costs of the disposition, exceed (or are less than) the adjusted cost base to the Resident Holder of our Class A shares immediately before the disposition. See “—Taxation of Capital Gains and Capital Losses.”

Generally, one-half of any capital gain, or a “taxable capital gain,” realized by a Resident Holder will be included in the Resident Holder’s income for the year of disposition. One-half of any capital loss, or an “allowable capital loss,” realized by a Resident Holder in a taxation year generally must be deducted by the Holder against taxable capital gains in that year (subject to, and in accordance with, the provisions of the Tax Act). Any excess of allowable capital losses over taxable capital gains of a Resident Holder realized in the year of disposition may be carried back up to three taxation years or forward indefinitely and deducted against net taxable capital gains realized in such years, to the extent and under the circumstances described in the Tax Act.

Capital gains realized by a Resident Holder that is an individual or trust, other than certain specified trusts, may give rise to a liability for alternative minimum tax under the Tax Act.

U.S. tax, if any, levied on any gain realized on a disposition of our Class A shares may be eligible for a foreign tax credit under the Tax Act to the extent and under the circumstances described in the Tax Act. Resident Holders should consult their own tax advisors with respect to the availability of a foreign tax credit, having regard to their own particular circumstances.

The Tax Act contains provisions, or the “OIF Rules,” which, in certain circumstances, may require a Resident Holder to include an amount in income in each taxation year in respect of the acquisition and holding of our Class A shares if (1) the value of such Class A shares may reasonably be considered to be derived, directly or indirectly, primarily from portfolio investments in: (i) shares of the capital stock of one or more corporations, (ii) indebtedness or annuities, (iii) interests in one or more corporations, trusts, partnerships, organizations, funds

or entities, (iv) commodities, (v) real estate, (vi) Canadian or foreign resource properties, (vii) currency of a country other than Canada, (viii) rights or options to acquire or dispose of any of the foregoing, or (ix) any combination of the foregoing, which we collectively refer to as “Investment Assets;” and (2) it may reasonably be concluded that one of the main reasons for the Resident Holder acquiring, holding or having our Class A shares was to derive a benefit from portfolio investments in Investment Assets in such a manner that the taxes, if any, on the income, profits and gains from such Investment Assets for any particular year are significantly less than the tax that would have been applicable under Part I of the Tax Act if the income, profits and gains had been earned directly by the Resident Holder.

In making this determination, the OIF Rules provide that regard must be had to all of the circumstances, including (i) the nature, organization and operation of any non-resident entity, including our company, and the form of, and the terms and conditions governing, the Resident Holder’s interest in, or connection with, any such non-resident entity, (ii) the extent to which any income, profit and gains that may reasonably be considered to be earned or accrued, whether directly or indirectly, for the benefit of any such non-resident entity, including our company, are subject to an income or profits tax that is significantly less than the income tax that would be applicable to such income, profits and gains if they were earned directly by the Resident Holder, and (iii) the extent to which any income, profits and gains of any such non-resident entity, including our company, for any fiscal period are distributed in that or the immediately following fiscal period.

If applicable, the OIF Rules can result in a Resident Holder being required to include in its income for each taxation year in which such Resident Holder owns our Class A shares the amount, if any, by which (i) the total of all amounts each of which is the product obtained when the Resident Holder’s “designated cost” (as defined in the Tax Act) of our Class A shares at the end of a month in the year is multiplied by 1/12 of the aggregate of the prescribed rate of interest for the period including that month plus two percentage points exceeds (ii) any dividends or other amounts included in computing such Resident Holder’s income for the year (other than a capital gain) in respect of our Class A shares determined without reference to the OIF Rules. Any amount required to be included in computing a Resident Holder’s income under these provisions will be added to the adjusted cost base of our Class A shares to the Resident Holder.

The CRA has taken the position that the term “portfolio investment” should be given a broad interpretation. While the value of our Class A shares should not be regarded as being derived primarily from portfolio investments in Investment Assets, there is a possibility that the CRA may take a different view. However, as noted above, even if this is the case, the OIF Rules will apply only if it is reasonable to conclude that one of the main reasons for a Resident Holder acquiring, holding or having our Class A shares was to derive, either directly or indirectly, a benefit from Investment Assets in such a manner that the taxes, if any, on the income, profits and gains from such Investment Assets for any particular year are significantly less than the tax that would have been applicable under Part I of the Tax Act if the income, profits and gains had been earned directly by the Resident Holder.

The OIF Rules are complex and their application will potentially depend, in part, on the reasons for a Resident Holder acquiring, holding or having our Class A shares. Resident Holders are urged to consult their own tax advisors regarding the application and consequences of the OIF Rules in their own particular circumstances.

A Resident Holder that is, throughout the relevant taxation year, a “Canadian-controlled private corporation” (as defined in the Tax Act) may be subject to pay a refundable tax on its “aggregate investment income” (as defined in the Tax Act), including taxable capital gains and certain dividends.

In general, a Resident Holder that is a “specified Canadian entity” (as defined in the Tax Act) for a taxation year or a fiscal period and whose total cost amount of “specified foreign property” (as defined in the Tax Act), including our Class A shares, at any time in the year or fiscal period exceeds C$100,000 will be required to file an information return with the CRA for the taxation year or fiscal period disclosing certain prescribed information in respect of such property. Subject to certain exceptions, a taxpayer resident in Canada, other than a corporation or trust exempt from tax under Part I of the Tax Act, will be a “specified Canadian entity,” as will certain partnerships. Our Class A shares will be “specified foreign property” to a Resident Holder. Substantial penalties may apply where a Resident Holder fails to file the required information return in respect of such Resident Holder’s “specified foreign property” (as defined in the Tax Act) on a timely basis in accordance with the Tax Act. The reporting requirements with respect to “specified foreign property” were recently expanded so that more detailed information is required to be provided to the CRA.

The reporting rules in the Tax Act are complex and this summary does not purport to address all circumstances in which reporting may be required by a Holder. Holders should consult their own tax advisors regarding the reporting rules contained in the Tax Act.

The Class A shares offered hereby will, on the date of this offering, provided that the Class A shares are on that date listed on a designated stock exchange, as defined in the Tax Act (which currently includes the Toronto Stock Exchange, or “TSX” and the New York Stock Exchange, or “NYSE,” and the NASDAQ Stock Market, or “NASDAQ”), be qualified investments under the Tax Act and the regulations thereunder for trusts governed by a registered retirements savings plan, or “RRSP,” registered retirement income fund, or “RRIF,” registered disability savings plan, deferred profit sharing plan, tax-free savings account, or ‘‘TFSA,” or registered education savings plan, all within the meaning of the Tax Act.

Notwithstanding, that the Class A shares may be qualified investments for a trust governed by a TFSA, RRSP or RRIF, the holder of the TFSA or the annuitant under a RRSP or RRIF, as the case may be, will be subject to tax in respect of the Class A shares if such Class A shares are “prohibited investments” for either TFSA, RRSP or RRIF, as the case may be. The Class A shares will generally not be a “prohibited investment” provided the holder of the TFSA or the annuitant under the RRSP or RRIF, as the case may be, deals at arm’s length with our company for purposes of the Tax Act and does not have a “significant interest” in our company for purposes of the prohibited investment rules in the Tax Act. Holders of a TFSA and annuitants under a RRSP or RRIF should consult their own tax advisors as to whether the Class A shares will be a “prohibited investment” in their particular circumstances.

The following portion of this summary is applicable to a Holder who: (i) has not been, is not, and will not be resident or deemed to be resident in Canada for purposes of the Tax Act or any applicable tax treaty; and (ii) does not and will not use or hold, and is not and will not be deemed to use or hold, our Class A shares in connection with, or in the course of, carrying on a business in Canada, or a “Non-Resident Holder.” Special rules, which are not discussed in this summary, may apply to a Non-Resident Holder that is an insurer carrying on business in Canada and elsewhere. Such Non-Resident Holders should consult their own tax advisors.

Dividends paid in respect of our Class A shares to a Non-Resident Holder will not be subject to Canadian withholding tax or other income tax under the Tax Act.

A Non-Resident Holder who disposes or is deemed to dispose of our Class A shares that were acquired under the offering will not be subject to Canadian income tax in respect of any capital gain realized on the disposition unless such Class A shares constitute “taxable Canadian property” of the Non-Resident Holder for the purposes of the Tax Act and no exemption is available under an applicable income tax convention between Canada and the jurisdiction in which the Non-Resident Holder is resident.

Generally, our Class A shares will not be taxable Canadian property at a particular time of a Non-Resident Holder provided that our Class A shares are listed on a designated stock exchange (which currently includes the TSX, the NYSE and NASDAQ) at that time, unless, at any time during the sixty-month period that ends at that time when (a)(i) the Non-Resident Holder, (ii) persons not dealing at arm’s length with such Non-Resident Holder, (iii) partnerships in which the Non-Resident Holder or a person mentioned in (a)(ii) holds a membership interest directly or indirectly through one or more partnerships or (iv) any combination of (a)(i) to (iii), owned 25% or more of the issued shares of any class of the capital stock of our company and (b) at that time more than 50% of the value of such Class A shares was derived directly or indirectly from one or any combination of (i) real or immoveable property situated in Canada; (ii) “Canadian resource properties” as defined in the Tax Act; (iii) “timber resource properties” as defined in the Tax Act; and (iv) options in respect of, interests in or rights in any property listed in (i)-(iii). Notwithstanding the foregoing, in certain circumstances set out in the Tax Act, our Class A shares may be deemed to be taxable Canadian property to a Non-Resident Holder. Non-Resident Holders whose Class A shares are taxable Canadian property should consult their own tax advisors for advice having regard to their particular circumstances.

BMO Nesbitt Burns Inc., RBC Dominion Securities Inc., Morgan Stanley & Co. LLC, and are acting as the underwriters of this offering. BMO Nesbitt Burns Inc., RBC Dominion Securities Inc., Morgan Stanley & Co. LLC are acting as the joint book-running managers of this offering. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, or the “Underwriting Agreement,” each underwriter named below has severally agreed to purchase from us, and we have agreed to sell to such underwriter, the respective number of our Class A shares shown opposite its name below at a price of $ per Class A share by , payable in cash against delivery.

This offering is being made concurrently in the United States and in each of the provinces and territories of Canada. Our Class A shares will be offered in the United States through those underwriters or their U.S. affiliates who are registered to offer the Class A shares for sale in the United States, and in Canada through those underwriters or their Canadian affiliates who are registered to offer our Class A shares for sale in applicable Canadian provinces or territories, and such other registered dealers as may be designated by the underwriters. Subject to applicable law, the underwriters may offer our Class A shares outside of the United States and Canada.

The obligations of the underwriters under the Underwriting Agreement may be terminated at their discretion based on their assessment of the state of the financial markets and may also be terminated upon the occurrence of certain stated events. The underwriters are, however, obligated to take up and pay for all of the offered Class A shares if any of the Class A shares are purchased under the Underwriting Agreement. The Underwriting Agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may also be increased or the offering may be terminated.

The underwriters propose to offer our Class A shares directly to the public at the initial public offering price set forth on the cover page of this prospectus and to certain dealers at that price less a concession not in excess of $ per Class A share. After the initial public offering of the Class A shares, the offering price and other selling terms may be changed by the underwriters.

The underwriters have an option to buy up to additional Class A shares from the selling shareholder at a price of $ per Class A share to cover sales of Class A shares by the underwriters which exceed the number of Class A shares specified in the table above. The underwriters have 30 days from the closing date of this offering to exercise this overallotment option. If any Class A shares are purchased with this overallotment option, the underwriters will purchase Class A shares in approximately the same proportion as shown in the table above. If any additional Class A shares are purchased, the underwriters will offer the additional Class A shares on the same terms as those on which the Class A shares are being offered. We will not receive any proceeds from the exercise of the underwriters’ overallotment option.

A purchaser who acquires Class A shares forming part of the underwriters’ over-allocation position acquires such shares under this prospectus, regardless of whether the over-allocation position is ultimately filled through the sales of our Class A shares by the selling shareholder upon exercise of the overallotment option or secondary market purchases.

The following table shows the per Class A share and total underwriters’ commission to be paid to the underwriters, assuming both no exercise and full exercise of the underwriters’ option to purchase additional Class A shares.

The public offering price for our Class A shares, wherever offered, is payable in U.S. dollars, except as may otherwise be agreed by the underwriters.

In addition to the underwriters’ commissions, we and PEG LP are jointly and severally responsible for reimbursing all of the expenses of the underwriters incurred in relation to this offering, including legal expenses and expenses related to road show and marketing activities. We estimate that the total amount of such reimbursable expenses will be approximately $ . At the closing of this offering or the closing of the sale of additional Class A shares upon the exercise of the overallotment option, we or the selling shareholder, as applicable, may also elect at our sole discretion to pay up to an additional 0.25% of the gross proceeds of this offering or in respect of the exercise of the overallotment option, as the case may be, to BMO Nesbitt Burns Inc. and RBC Dominion Securities Inc., to be divided equally between them.

We estimate that the total expenses of this offering to us, including registration, filing and listing fees, printing fees, and legal and accounting expenses, but excluding the underwriters’ commission, will be approximately $ .

A prospectus in electronic format may be made available on the websites maintained by one or more underwriters, or selling group members, if any, participating in the offering. The underwriters may agree to allocate a number of Class A shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated to underwriters and selling group members that may make Internet distributions on the same basis as other allocations.

Each of PEG LP, us and our directors and executive officers have entered into lock-up agreements with the underwriters pursuant to which each of these persons or entities, with limited exceptions, for a period of 180 days after the date of the closing of this offering, may not, without the prior written consent of BMO Nesbitt Burns Inc., (1) offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right, or warrant to purchase, or otherwise transfer or dispose of, directly or indirectly, any of our shares or any securities convertible into or exercisable or exchangeable for our shares (including, without limitation, our shares or such other securities which may be deemed to be beneficially owned by such persons in accordance with the rules and regulations of the SEC and securities which may be issued upon exercise of a stock option or warrant), (2) enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of our shares or such other securities, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of our shares or such other securities, in cash, or otherwise, or (3) make any demand for or exercise any right with respect to the registration of any of our shares or any security convertible into or exercisable or exchangeable for our shares. In addition, the lock-up agreements will not restrict the transfer of our shares as bona fide gifts, transfer by will or the laws of intestacy, transfers to family members (including to vehicles of which they are beneficial owners), transfers pursuant to domestic relations or court orders, or (in the case of corporations or other entities) transfers to affiliates, in each case so long as the transferee agrees to be bound by the restrictions in the lock-up agreements.

We and PEG LP have agreed to indemnify the underwriters against certain liabilities, including liabilities under the U.S. Securities Act and applicable Canadian securities laws.

Pursuant to Canadian securities laws and the Universal Market Integrity Rules for Canadian Marketplaces, the underwriters may not, throughout the period of distribution, bid for, or purchase our shares, except in accordance with certain permitted transactions, including market stabilization and passive market making activities.

In connection with this offering, the underwriters may engage in stabilizing transactions, which involves making bids for, purchasing, and selling our Class A shares in the open market for the purpose of preventing or retarding a decline in the market price of our Class A shares while this offering is in progress. These stabilizing transactions may include making short sales of our Class A shares, which involves the sale by the underwriters of a greater number of our Class A shares than they are required to purchase in this offering, and purchasing our Class A shares on the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ overallotment option referred to above, or may be “naked” shorts, which are short positions in excess of that amount. The underwriters may close out any covered short position either by exercising their overallotment option, in whole or in part, or by purchasing Class A shares in the open market. In making this determination, the underwriters will consider, among other things, the price of Class A shares available for purchase in the open market compared to the price at which the underwriters may purchase Class A shares through the overallotment option. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our Class A shares in the open market that could adversely affect investors who purchase in this offering. To the extent that the underwriters create a naked short position, they will purchase Class A shares in the open market to cover the position.

The underwriters have advised us that, pursuant to Regulation M of the U.S. Securities Act and applicable Canadian securities laws, they may also engage in other activities that stabilize, maintain, or otherwise affect the price of our shares, including the imposition of penalty bids. This means that if the underwriters purchase our Class A shares in the open market in stabilizing transactions or to cover short sales, the joint book-running managers can require the underwriters that sold those Class A shares as part of this offering to repay the underwriters’ commission received by them.

These activities may have the effect of raising or maintaining the market price of our Class A shares or preventing or retarding a decline in the market price of our Class A shares, and, as a result, the price of our Class A shares may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them at any time. The underwriters may carry out these transactions on applicable stock exchanges, in the over-the-counter market, or otherwise.

Prior to this offering, there has been no public market for our Class A shares. The initial public offering price will be determined by negotiations between us and the underwriters. In determining the initial public offering price, we and the underwriters expect to consider a number of factors including:

Neither we nor the underwriters can assure investors that an active trading market will develop for our Class A shares, or that the Class A shares will trade in the public market at or above the initial public offering price.

Other than in the United States and in each of the Canadian provinces and territories, no action has been taken by us or the underwriters that would permit a public offering of the securities offered by this prospectus in any jurisdiction where action for that purpose is required. The securities offered by this prospectus may not be offered or sold, directly or indirectly, nor may this prospectus or any other offering material or advertisements in connection with the offer and sale of any such securities be distributed or published in any jurisdiction, except under circumstances that will result in compliance with the applicable rules and regulations of that jurisdiction. Persons into whose possession this prospectus comes are advised to inform themselves about and to observe any restrictions relating to the offering and the distribution of this prospectus. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any securities offered by this prospectus in any jurisdiction in which such an offer or a solicitation is unlawful.

This document is only being distributed to and is only directed at (1) persons who are outside the United Kingdom, (2) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, which we refer to as the Order, or (3) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order, all such persons together we refer to as relevant persons. The securities are only available to, and any invitation, offer, or agreement to subscribe, purchase, or otherwise acquire such securities will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a “Relevant Member State”), with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), an offer of securities described in this prospectus may not be made to the public in that Relevant Member State other than:

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in the Relevant Member State, and includes any relevant implementing measure in each Relevant Member State. The expression 2010 PD Amending Directive means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Certain of the underwriters and their affiliates have provided in the past to us and our affiliates and may provide from time to time in the future certain commercial banking, financial advisory, investment banking, and

other services for us and such affiliates in the ordinary course of their business, for which they have received and may continue to receive customary fees and commissions. In addition, from time to time, certain of the underwriters and their affiliates may effect transactions for their own account or the account of customers, and hold, on behalf of themselves or their customers, long or short positions in our equity or debt securities or loans, and may do so in the future. In addition, certain affiliates of the Canadian underwriters act as agents and/or are lenders, as applicable, under our revolving credit facility. Accordingly, we may be considered a “connected issuer” (as defined in National Instrument 33-105—Underwriting Conflicts of the Canadian Securities Administrators) of BMO Nesbitt Burns Inc., RBC Dominion Securities Inc. and Morgan Stanley Canada Limited for the purposes of applicable Canadian securities laws. The decision to offer our Class A shares was made solely by us and PEG LP, and the terms upon which the Class A shares are being offered were determined by negotiation between us, PEG LP, and the underwriters. Our subsidiaries which are party to the revolving credit facility are currently in compliance with the facility, and no breach thereof has been waived since the execution of our revolving credit facility. Other than as disclosed in this prospectus, our financial position has not changed since the execution of our revolving credit facility. See “Description of Certain Financing Arrangements—Revolving Credit Facility”. As a result of this offering, each of such underwriters (or their respective U.S. underwriter affiliate) will receive their share of the underwriting fee payable to the underwriters.

Our offered Class A shares (other than any Class A shares issuable or to be sold on exercise of the overallotment option) are to be taken up by the underwriters, if at all, on or before a date not later than 42 days after the date of the receipt for the final Canadian prospectus.

The validity of the Class A shares being sold in this offering will be passed upon for us by Latham & Watkins LLP, New York, New York. Certain Canadian legal matters relating to this offering are being passed on for us by Blake, Cassels & Graydon LLP. Certain U.S. legal matters relating to this offering will be passed upon for the underwriters by Vinson & Elkins L.L.P., New York, New York. Certain Canadian legal matters relating to this offering will be passed upon for the underwriters by Torys LLP. The partners and associates of Blake, Cassels & Graydon LLP, collectively, beneficially own, directly or indirectly, less than 1% of our shares. The partners and associates of Torys LLP, collectively, beneficially own, directly or indirectly, less than 1% of our shares.

The combined financial statements of our predecessor, Pattern Energy Predecessor at December 31, 2011 and 2012 and for each of the three years in the period ended December 31, 2010, 2011 and 2012, and the financial statements of Pattern Energy Group Inc. as of October 17, 2012 (initial capitalization), and December 31, 2012 and for the period from October 17, 2012 (initial capitalization) to December 31, 2012 appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such reports, given on the authority of such firm as experts in auditing and accounting.

The information included in this prospectus set forth under the heading “Independent Engineer Report” has been derived from the Independent Engineer’s Report of Garrad Hassan America, Inc., a dedicated renewable energy consultant offering independent technical and engineering services. Garrad Hassan America, Inc.’s Independent Engineer’s Report has been filed as Exhibit 99.1 to the Registration Statement (of which this prospectus forms a part) based on, and the information derived therefrom included in this prospectus has been so included upon, the authority of said firm as an expert with respect to the matters covered by its report. The Independent Engineer’s Report is also publicly available on our SEDAR profile at www.sedar.com.

Garrad Hassan America, Inc. and its “designated professionals” (as defined under Canadian securities laws.) collectively beneficially own, directly or indirectly, 0% of our shares.

We have filed with the SEC a registration statement on Form S-1 pursuant to the U.S. Securities Act covering our shares being offered hereby. This prospectus, which constitutes part of this registration statement, does not contain all the information set forth in this registration statement. For further information about us and our shares, we refer you to this registration statement and the exhibits and schedules filed as a part of this registration statement. Statements contained in this prospectus as to the contents of any contract or other document filed as an exhibit to this registration statement are not necessarily complete. If a contract or document has been filed as an exhibit to this registration statement, we refer you to the copy of the contract or document that has been filed.

You may inspect a copy of this registration statement and the exhibits and schedules to this registration statement without charge at the Public Reference Room of the SEC at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You can receive copies of these documents upon payment of a duplicating fee by writing to the SEC. The SEC maintains a web site at www.sec.gov that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. You can also inspect our registration statement on this web site. In addition, the Canadian Securities Administrators maintains the System for

Electronic Document Analysis and Retrieval, or “SEDAR,” web site at www.sedar.com that contains reports, proxy and information statements and other information regarding reporting issuers under their relevant SEDAR profile. You can inspect the Canadian prospectus on this website.

Upon completion of this offering, we will become subject to the information and reporting requirements of the Exchange Act pursuant to Section 13 thereof and applicable Canadian securities rules. Our filings with the SEC (other than those exhibits specifically incorporated by reference into this registration statement of which this prospectus forms a part) and the Canadian Securities Administrators are not incorporated by reference into this prospectus.

We, PEG LP, our promoter, Garrad Hassan America, Inc., independent engineer, and Ernst & Young LLP, our external auditor, are incorporated or otherwise organized under the laws of a foreign jurisdiction. In addition, Michael M. Garland and Michael B. Hoffman, the current directors of Pattern, reside outside of Canada.

We, PEG LP, Michael M. Garland and Michael B. Hoffman have appointed the following [respective] agent[s] for service of process:

Purchasers are advised that it may not be possible for investors to enforce judgments obtained in Canada against any person or company that is incorporated, continued or otherwise organized under the laws of a foreign jurisdiction or resides outside of Canada, even if the party has appointed an agent for service of process.

We prepare our financial statements in accordance with U.S. GAAP. The historical financial statements of our predecessor have been prepared in accordance with U.S. GAAP, which differ in certain material respects from IFRS. As we will become an SEC foreign issuer (as such term is defined in National Instrument 52-107—Acceptable Accounting Principles and Auditing Standards of the Canadian Securities Administrators), we are not required to provide, and have not provided, a reconciliation of our financial statements to IFRS.

Upon the filing of the final prospectus with the securities regulatory authorities in each of the provinces and territories of Canada, we will become a reporting issuer under the securities laws of such jurisdictions. Pursuant to the rules of the securities regulatory authorities of such jurisdictions, we (or, in the case of insider reporting, our insiders) will generally be exempt from the requirements of the laws of such jurisdictions relating to continuous disclosure, proxy solicitation and insider reporting. These rules generally permit us to comply with certain informational requirements applicable in the United States instead of the continuous disclosure requirements normally applicable in such Canadian jurisdictions, provided that the relevant documents are filed with the securities regulatory authorities in the relevant Canadian jurisdictions and are provided to security holders in Canada to the extent and in the manner and within the time required by applicable U.S. requirements.

PEG LP may be considered to be the promoter of our company in that it directly took the initiative in substantially reorganizing our company and its affiliates in connection with the Contribution Transactions. Upon completion of this offering, PEG LP will hold approximately % of our outstanding Class A shares and % of our outstanding Class B shares (or % and %, respectively, if the underwriters exercise their overallotment option in full), representing in the aggregate an approximate % voting interest in our company (or % if the underwriters exercise their overallotment option in full).

In connection with the Contribution Transactions, on or immediately prior to the completion of the offering, PEG LP will contribute their ownership interests in all of the projects that will make up our business. In exchange for this contribution, we will pay PEG LP $ million from the proceeds of this offering and issue to PEG LP of our Class A shares and of our Class B shares in the aggregate having a total value of $ million based on an initial public offering price of $ per Class A share (the midpoint of the range set forth on the cover of this prospectus). See “Business—Our Projects” for more information about each of the power projects we will acquire. The consideration paid to PEG LP in connection with the Contribution Transactions was negotiated between us and PEG LP when setting the terms of the Contribution Agreement. See “Certain Relationships and Related Party Transactions—Other Contractual Arrangements with Related Persons—Contribution Agreement” and “Structure and Formation of Our Company.”

In connection with the Contribution Transactions and this offering, we will enter into a number of other arrangements with PEG LP, including a Management Services Agreement, the Non-Competition Agreement, the Purchase Rights Agreement, the Shareholder Agreement and the Registration Rights Agreement. See “Certain Relationships and Related Party Transactions” for more information about these contractual arrangements.

PEG LP has not, within the 10 years before the date of this prospectus, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of PEG LP.

PEG LP has not been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or nor has it entered into a settlement agreement with a securities regulatory authority; or been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor making an investment decision.

Except the 100 shares issued to Pattern Renewables LP, a subsidiary of PEG LP, at a total issue price of US$1,000 in connection with our initial capitalization, no other shares, or securities convertible into shares, have been issued by us during the 12-month period prior to the date of this prospectus. See “Structure and Formation of Our Company.”

In the opinion of Blake, Cassels & Graydon LLP, Canadian counsel to our company, and Torys LLP, Canadian counsel to the underwriters, the Class A shares offered hereby will, on the date of this offering, provided that the Class A shares are on that date listed on a designated stock exchange, as defined in the Income Tax Act, or the “Tax Act,” (which currently includes the TSX, the NYSE and NASDAQ), be qualified investments under the Tax Act and the regulations thereunder for trusts governed by a registered retirement savings plan, or “RRSP,” registered retirement income fund, or “RRIF,” registered disability savings plan, deferred profit sharing plan, tax-free savings account, or “TFSA,” or registered education savings plan, all within the meaning of the Tax Act.

Notwithstanding that the Class A shares may be qualified investments for a trust governed by a TFSA, RRSP or RRIF, the holder of the TFSA or the annuitant under a RRSP or RRIF, as the case may be, will be subject to tax in respect of the Class A shares if such Class A shares are “prohibited investments” for the TFSA,

RRSP or RRIF, as the case may be. The Class A shares will generally not be a “prohibited investment” provided the holder of the TFSA or the annuitant under the RRSP or RRIF, as the case may be, deals at arm’s length with our company for purposes of the Tax Act and does not have a “significant interest” in our company for purposes of the prohibited investment rules in the Tax Act. Holders of a TFSA and annuitants under a RRSP or RRIF should consult their own tax advisors as to whether the Class A shares will be a “prohibited investment” in their particular circumstances.

The following are the only material contracts, other than those contracts entered into in the ordinary course of business, which we have entered into during the most recently completed financial year or before the most recently completed financial year that are still in effect or to which we are or will become a party on or prior to the closing date of this offering.

Copies of the above material agreements, once executed, may be inspected during ordinary office business hours at our principal executive offices located at Pier 1, Bay 3, San Francisco, California 94111 during the period of distribution of our Class A shares or may be viewed at the website maintained by the SEC at http://www.sec.gov or the SEDAR website maintained by the Canadian Securities Administrators at www.sedar.com.

Our auditors are Ernst & Young LLP, 560 Mission Street, Suite 1600, San Francisco, California, USA 94105-2907.

Ernst & Young LLP have advised us that they have complied with the SEC’s rules on auditor independence.

Securities legislation in certain of the provinces and territories of Canada provides purchasers with the right to withdraw from an agreement to purchase securities. This right may be exercised within two business days after receipt or deemed receipt of a prospectus and any amendment. In several of the provinces and territories, the securities legislation further provides a purchaser with remedies for rescission or, in some jurisdictions, revisions of the price or damages if the prospectus and any amendment contains a misrepresentation or is not delivered to the purchaser, provided that the remedies for rescission, revisions of the price or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory for the particulars of these rights or consult with a legal adviser.

We have audited the accompanying balance sheets of Pattern Energy Group Inc., or the “Company,” as of December 31, 2012 and October 17, 2012 (initial capitalization), and the related statements of operations, shareholder’s (deficit) equity and cash flows for the period from October 17, 2012 (initial capitalization) to December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Pattern Energy Group Inc. as of December 31, 2012 and October 17, 2012 (initial capitalization), and the results of operations and cash flows for the period from October 17, 2012 (initial capitalization) to December 31, 2012 in conformity with U.S. generally accepted accounting principles.

Pattern Energy Group Inc., or the “Company,” was organized in the state of Delaware on October 2, 2012. Under the Company’s charter, the Company is authorized to issue up to 1,000 shares of common stock. The Company issued 100 shares on October 17, 2012, to Pattern Renewables LP.

The Company plans to operate as an independent power company, focused on owning and operating power projects.

The Company has not commenced operations, nor has the Company entered into any contracts. The Company intends to file a Registration Statement on Form S-1 with the Securities and Exchange Commission and a prospectus with Canadian securities regulators with respect to an initial public offering of common stock (the “IPO”). Proceeds from the IPO will be used (i) to provide the consideration to be paid to Pattern Energy Group LP (PEG LP) in connection with the contribution of assets to the Company and (ii) for working capital and general corporate purposes. The Company’s fiscal year end is December 31.

The accompanying financial statements have been prepared in accordance with U.S. generally accepted accounting principles.

The accompanying balance sheet as of June 30, 2013, and statements of operations for the three and six months ended June 30, 2013, and changes in shareholder’s (deficit) equity and cash flows for the six months ended June 30, 2013 are unaudited. The unaudited interim financial statements have been prepared on a basis consistent with the annual combined financial statements and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to present fairly the Company’s financial position and results of operations and cash flows for the three and six months ended June 30, 2013. The results of the three and six months ended June 30, 2013 are not necessarily indicative of the results to be expected for the calendar year ending December 31, 2013, or for other interim periods or future years.

The preparation of the financial statements in conformity with accounting principles generally accepted in the U.S. 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 these estimates, and such differences may be material to the financial statements.

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 exceed amounts covered by federal deposit insurance. The Company believes that its credit risk is not significant.

Offering costs incurred by PEG LP, the Company’s parent, have been deferred and recorded by PEG LP as prepaid expense as incurred. Upon the successful completion of the Company’s offering these costs will be reimbursed by the Company and recorded by the Company as a reduction to shareholder’s equity.

The Company accounts for income taxes under an asset and liability approach. Deferred income taxes reflect the impact of temporary differences between assets and liabilities recognized for financial reporting purposes and the amounts recognized for income tax reporting purposes, net operating loss carryforwards, and other tax credits measured by applying currently enacted tax laws. A valuation allowance is provided when necessary to reduce deferred tax assets to an amount that is more likely than not to be realized.

The Company has negotiated, but not signed, a contribution agreement with PEG LP that will become effective concurrent with the completion of the IPO. Immediately prior to the completion of the IPO, pursuant to the terms of the contribution agreement, the Company will enter into a series of transactions with PEG LP to create a new organizational structure, which the Company collectively refers to as the “Contribution Transactions”. In connection with these transactions, PEG LP will contribute to the Company certain projects and related entities, currently consisting of interests in eight wind power projects located in the United States, Canada and Chile. PEG LP currently holds its interests in these projects through one or more holding companies, the sole purposes of which are to hold such interests or to obtain related financing.

In connection with the Contribution Transactions, the Company will also assume the liabilities associated with the contributed assets, including project-level or holding company indebtedness, ordinary-course operational liabilities, and indemnities that PEG LP granted for the benefit of certain lenders. These indemnity obligations indemnify the lenders for the amount of any anticipated project-level investment tax credit cash grants, or “ITC cash grants,” not received by a project from the U.S. Treasury or, following receipt of an ITC cash grant, any amount of the grant recaptured by the U.S. Treasury. The Company will also assume indemnities that were granted by PEG LP to certain lenders in connection with certain legal costs, as well as to certain owner lessors of a project in connection with certain potential tax losses.

We have audited the accompanying combined balance sheets of Pattern Energy Predecessor (Predecessor) as of December 31, 2012 and 2011, and the related combined statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Predecessor’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of Predecessor as of December 31, 2012 and 2011, and the combined results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles

Pattern Energy Predecessor or the Company is an independent energy generation company focused on constructing, owning and operating energy projects with long-term energy sales contracts in certain markets, currently including the United States, Canada and Chile. The Company consists of the combined operations of certain entities and assets currently owned by Pattern Energy Group LP (PEG LP), as discussed in the basis of presentation below. The principal business objective of the Company is to produce stable and sustainable cash flows through the generation and sale of energy.

The Company is not an existing legal entity. Rather, it is a combination of entities and assets currently owned by Pattern Energy Group LP. 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) and AEI- Pattern Holdings Limitada (El Arrayán). The Company combines Gulf Wind and the wholly-owned investments as consolidating investments, and uses the equity method to combine its noncontrolling investments. As of June 30, 2013, the Company’s project portfolio consists of interests in eight wind power projects, including six projects in operation (Gulf Wind, Hatchet Ridge, St. Joseph, Spring Valley, Santa Isabel and Ocotillo, which commenced operations on 223 MW (unaudited) of initial electricity generating capacity and on an additional 42 MW (unaudited) in July 2013 and expects to commence operations on two projects under construction (El Arrayán and South Kent).

The Company receives certain project, administrative and overhead services from PEG LP which are recorded as expenses in the combined statements of operations or are capitalized as deferred development costs in the balance sheets, and as increased capital contributions. See Note 15 Related Party Transactions. The accompanying historical financial statements include the combined results of operations of the Company as if it had operated as a single company during the periods presented.

The accompanying combined balance sheet as of June 30, 2013, and the combined statements of operations and comprehensive income (loss) for the three and six months ended June 30, 2013 and 2012 and the combined statements of changes in equity and cash flows for the six months ended June 30, 2013 are unaudited. The unaudited interim financial statements have been prepared on a basis consistent with the annual combined financial statements and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to present fairly the Company’s financial position and results of operations for the three and six months ended June 30, 2013 and 2012, and cash flows for the six months ended June 30, 2013 and 2012. The results of the three and six months ended June 30, 2013 are not necessarily indicative of the results to be expected for the calendar year ending December 31, 2013, or for other interim periods or future years.

The accompanying combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States (US 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.

Certain prior period balances have been reclassified to conform to the current period presentation in the Company’s combined financial statements and the accompanying notes. Such reclassifications had no effect on previously reported balance sheet subtotals, results of operations or retained earnings.

In order to present the tax effect of the Contribution Transactions, the Company has presented a 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.

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 combined balance sheets.

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. The Company has determined that the operating partnership agreement for Gulf Wind does not allocate economic benefits pro rata to its two 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.

Under the HLBV method, the amounts reported as noncontrolling interest in the combined balance sheets and combined 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 US 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 combined 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 combined balance sheets.

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 combined financial statements.

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 as other comprehensive income (loss) in the accompanying combined statements of changes in 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 (expense) in the accompanying combined 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 (expense) in the accompanying combined statements of operations.

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

For the three months ended June 30, 2013 and 2012, Customer A accounted for 16.0% (unaudited) and 36.2% (unaudited) of total revenue, respectively, Customer B accounted for 13.4% (unaudited) and 28.5% (unaudited) of total revenue, respectively, and Customer C accounted for 14.7% (unaudited) and 22.9% (unaudited) of total revenue, respectively. For the six months ended June 30, 2013 and 2012, Customer A accounted for 18.4% (unaudited) and 31.5% (unaudited) of total revenue, respectively, Customer B accounted for 14.3% (unaudited) and 24.8% (unaudited) of total revenue, respectively, and Customer C accounted for 14.0% (unaudited) and 17.1% (unaudited), of total revenue, respectively. For the years ended December 31, 2012, 2011 and 2010, Customer A accounted for 32.1%, 20.9% and zero % of total revenue, respectively, Customer B accounted for 23.1%, 20.7% and 1.7% of total revenue, respectively, and Customer C accounted for 18.3%, 35.2%, and 46.8% of total revenue, respectively.

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 utility companies. The Company has determined that the credit rating of Credit Suisse and the large utility companies are of a high quality as of June 30, 2013 (unaudited) and December 31, 2012, 2011 and 2010.

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. 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 11 Fair Value Measurements.

The Company is eligible for 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 matches proportionally 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 Property, Plant and Equipment.

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 not significant.

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

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 June 30, 2013 and December 31, 2012 and 2011.

During 2012 and the six months ended June 30, 2013, the Company paid to construct interconnect network upgrades for one of its utility customers. The utility owns the interconnect upgrades and is required to reimburse the Company with interest when the project reaches commercial operation, which is expected to be in the third quarter of 2013.

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

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.

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 June 30, 2013, no impairment charges have been recorded.

The Company recognizes its derivative instruments as assets or liabilities at fair value in the combined 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 (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 on the combined statement of operations.

For undesignated derivative instruments their change in fair value is reported as a component of net income on the combined 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, interest rate swaptions, interest rate caps and an electricity price derivative.

Interest rate swaps are instruments used to fix the interest rate on variable interest rate debt. The Company entered into interest rate swaps in 2012, 2011 and 2010.

Interest rate swaptions are instruments used to fix the terms of prospective interest rate derivatives that may be required when the related debt is refinanced. The Company entered into interest rate swaptions in 2009. The swaptions were terminated in 2010.

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 June 30, 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.

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 combined statements of operations following commencement of commercial operation.

Income taxes have not been provided for as the Company is treated as a pass-through entity for U.S. federal and state income tax purposes, except for certain of the Company’s Canadian entities which are subject to Canadian income taxes and a U.S. entity which became subject to U.S. income taxes in 2012. Federal and state income taxes are assessed at the owner level and each owner is liable for its own tax payments. Certain combined entities are corporations or have elected to be taxed as corporations. In these circumstances, income tax is accounted for under the asset and liability method.

The Company’s contingent liabilities represent deferred and contingent purchase price obligations related to projects acquired by Predecessor. Because the transaction through which Predecessor acquired contingent liabilities was accounted as a business combination, the Company’s contingent liabilities are recorded at fair value at each reporting date.

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 of approximately 6%.

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 840 Leases and ASC 815 Derivatives and Hedging, respectively. As of June 30, 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 under the terms of the Gulf Acquisition, which fixes approximately

58% of the Company’s expected electricity generation at Gulf Wind 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 combined 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 combined statements of operations.

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.

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

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.

In May 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-04, Fair Value Measurement (Topic 820), Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU 2011-04). The ASU amends the fair value measurement and disclosure guidance in ASC 820, Fair Value Measurement, to converge US GAAP and IFRS requirements for measuring amounts at fair value as well as disclosures about these measurements. ASU 2011-04 is effective for annual periods beginning after December 15, 2011. The Company adopted this ASU on January 1, 2012. The adoption of this standard did not have a significant impact on the Company’s combined financial statements.

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220), Presentation of Comprehensive Income (ASU 2011-05), requiring companies to present items of net income, items of other comprehensive income and total comprehensive income in one continuous statement or two consecutive statements. ASU 2011-05 is effective for fiscal years and interim periods within those years, beginning after December 15, 2011. In December 2011, the FASB released an update that deferred a portion of the new accounting requirements for comprehensive income. The Company adopted this ASU on January 1, 2012. The adoption of this standard did not have a significant impact on the Company’s combined financial statements.

On March 16, 2010, the Company acquired a 283.2 megawatt (MW) capacity (unaudited) wind power project (the Gulf Acquisition) under the terms of an Asset Purchase Agreement (the APA). The Gulf Acquisition included substantially all of the assets and operating contracts for Gulf Wind and the purchase price totaled approximately $341.8 million, including assumed liabilities. The identifiable assets acquired and liabilities assumed were recorded at their fair values which resulted in a gain on acquisition as measured by the excess net asset value over the purchase price. The amount of the gain recorded by the Company at March 16, 2010, was $22.9 million, which is reflected in gain on transactions in the combined statements of operations. The Gulf Wind assets and liabilities were acquired from a “distressed” seller that was liquidating or seeking to liquidate all of its assets and that had filed for bankruptcy. The identifiable assets and liabilities acquired as a part of this acquisition are as follows (in thousands):

Cash, accounts receivable, other current assets, other long-term receivables, current liabilities and long-term debt were recorded at fair value. The debt was repaid immediately after the closing of the Gulf Acquisition.

Property, plant and equipment and the asset retirement obligation were recorded at fair value using a combination of market data, operational data and discounted cash flows and were adjusted by a discount rate factor reflecting then current market conditions.

The energy derivative instrument is recorded at a fair value which is based on discounted projected net cash flows over the remaining life of the derivative instrument using forward energy curves, adjusted by a nonperformance credit adjusted risk factor.

The unaudited pro forma statement of operations data below gives effect to the Gulf Acquisition as if it had occurred on January 1, 2010. The unaudited pro forma data is presented for illustrative purposes only and is not intended to be indicative of actual results that would have been achieved had the Gulf Acquisition been consummated as of January 1, 2010. The unaudited pro forma data should not be considered representative of the Company’s future financial condition or results of operations.

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

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

The Company recorded depreciation expense related to property, plant and equipment of $17.7 million (unaudited) and $10.7 million (unaudited) for the three months ended June 30, 2013 and 2012, respectively, $40.0 million (unaudited ) and $21.4 million (unaudited) for the six months ended June 30, 2013 and 2012, respectively, and $48.3 million, $38.9 million and $12.7 million for the years ended December 31, 2012, 2011 and 2010, respectively.

In December 2012, the Company received $79.9 million under a cash grant in lieu of investment tax credit (Cash Grant) from the U.S. Department of Treasury. The Company recorded the cash proceeds as a deduction from the carrying amount of the related wind farm asset which resulted in the asset being recorded at a lower amount and a reduction of depreciation expense of approximately $4.0 million per year over the life of the asset.

In June 2013, the Company received $115.9 million and $57.6 million for Ocotillo and Santa Isabel, respectively, under cash grants from the U.S. Department of 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 a lower amount and a reduction of depreciation expense per year of approximately $5.8 million (unaudited), and $2.9 million (unaudited ), for Ocotillo and Santa Isabel, respectively.

For the three and six months ended June 30, 2013 and the year ended December 31, 2012, the Cash Grants reduced depreciation expense recorded in the combined statement of operations by approximately $5.6 million (unaudited), $6.6 million (unaudited) and $1.5 million, respectively.

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

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 and commenced construction in March 2013.

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.

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

The Company’s long term debt as of June 30, 2013 and December 31, 2012 and 2011 is presented below (in thousands):

The following are amounts due for long-term debt as of December 31, 2012 (in thousands):

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

In October 2009, Hatchet Ridge entered into a $203.5 million construction and term loan facility. In connection with the loan facility, Hatchet Ridge entered into interest rate swaps and swaption agreements to hedge its exposure to variable interest rates over the terms of the loan facility and its exposure to re-financing rate risk.

In December 2010, Hatchet Ridge re-financed the facility through a sale-leaseback transaction. All outstanding amounts due under the facility were repaid and the interest rate swaps and swaption agreements were terminated. The Company recorded a loss on the early extinguishment of debt of $5.8 million and realized a loss on the termination of the interest rate swaps and swaptions of $6.6 million. 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.

The Company acquired Gulf Wind in March 2010. Concurrent with its acquisition, Gulf Wind entered into a $195.4 million credit facility which, along with equity provided by the Company, was used to repay the acquired debt. 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.

In March 2010, St. Joseph entered into a $259.5 million construction and term loan facility. It was converted to a term loan in May 2011 with a term of 20 years.

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 standard 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.

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 COD 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.

In October 2011, Santa Isabel entered into a $119.0 million construction loan facility and a $57.4 million cash grant bridge loan facility. On December 5, 2012, Santa Isabel achieved commercial operation 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.

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 construction loan facilities consist of a development bank tranche of $110.0 million and a commercial bank tranche of $241.5 million and mature 20 years and 7 years after the occurrence of term loan conversion, respectively. The construction loans convert into term loans when Ocotillo achieves COD and certain other specified conditions. The network upgrade bridge loan is to be repaid from reimbursements by

the interconnecting utility of reimbursable network upgrade costs following completion of the project. In connection with the financing agreement, the Company entered into interest rate swaps on 90% of the loan commitment.

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.

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 June 30, 2013 and December 31, 2012, letters of credit of $43.1 million (unaudited) and $39.1 million, respectively, have been issued and loans of $56 million (unaudited) and zero, respectively, have been drawn against 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 1.00%. The Eurodollar rate loans will accrue interest at a rate per annum equal to LIBOR, as published by Reuters plus 3.50%. 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. As of June 30, 2013, the Eurodollar interest rate on the $56 million loan was 3.70%.

The Company’s asset retirement obligations represent the estimated cost, at all of its projects, of decommissioning the turbines, removing above-ground installations and restoring the sites at a date that is 19.3 to 20 years from the commencement of commercial operations.

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligations as of June 30, 2013 and December 31, 2012 and 2011 (in thousands):

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 combined balance sheets as of June 30, 2013 and December 31, 2012, and 2011 and combined statements of operations for the three and six months ended June 30, 2013 and 2012, and the years ended December 31, 2012, 2011 and 2010 (in thousands):

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 three and six months ended June 30, 2013 and 2012, and the years ended December 31, 2012 and 2011, and 6.4% for the year ended December 31, 2010. 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 three and six months ended June 30, 2013 and 2012, and the years ended December 31, 2012, 2011 and 2010. The Company expects to reclassify $5.6 million into earnings from accumulated other comprehensive losses during 2013 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 that declines in value beginning in March 2020 to $2.3 million at September 30, 2024. The cap is a derivative but does not qualify for hedge accounting and has not been designated. Changes in its fair value are recorded to other income, net in the combined statements of operations. The derivative instrument’s asset value as of June 30, 2013 and December 31, 2012 and 2011, was approximately $0.5 million (unaudited), $0.4 million and $0.5 million, respectively. The Company recognized expense to other income, net in the combined statements of operations of ($37,000) (unaudited) and $0.1 million (unaudited) for the three months ended June 30, 2013 and 2012, respectively, ($0.1) million (unaudited) and $0.1 million (unaudited) for the six months ended June 30, 2013 and 2012, respectively, and $44,000, $0.3 million and $0.3 million of for the years ended December 31, 2012, 2011 and 2010, 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 June 30, 2013 and December 31, 2012 and 2011 was $67.7 million (unaudited), $79.6 million and $86.6 million, respectively. Gulf Wind recognized revenue in the combined statements of operations of ($5.1) million (unaudited) and ($4.0) million (unaudited) for the three months ended June 30, 2013 and 2012, respectively, ($11.9) million (unaudited) and $1.7 million (unaudited) for the six months ended June 30, 2013 and 2012, respectively, and ($7.0) million, $17.6 million, and $14.0 million for the years ended December 31, 2012, 2011 and 2010, respectively.

In 2009, Hatchet Ridge entered into interest rate swaps with its construction lenders to manage exposure to interest rate risk on its construction debt. In December 2010, commensurate with the repayment of its construction loan, Hatchet Ridge terminated its interest rate swaps. The interest rate swaps qualified for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the year ended December 31, 2010. A termination payment of approximately $6.4 million was recorded in realized derivative loss on the combined statement of operations for the year ended December 31, 2010.

In 2009, the Hatchet Ridge also entered into interest rate swaptions to manage exposure to future interest rates when its long-term debt was expected to be refinanced at the end of its seven-year term. The swaptions were derivatives but did not qualify for hedge accounting. Changes in fair value were recorded to other income, net in the combined statements of operations. The swaptions were terminated on December 14, 2010 and the Company recorded a $0.2 million realized derivative loss in the combined statement of operations for the year ended December 31, 2010.

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. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded as of June 30, 2013, December 31,

2012 and December 31, 2011. The Company expects to reclassify $5.0 million of accumulated other comprehensive losses into earnings during 2013 as quarterly swap settlement payments occur.

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 2.45% and 2.17% 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 as of June 30, 2013 and December 31, 2012. The Company expects to reclassify $1.1 million into earnings from accumulated other comprehensive income during 2013 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.

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 combined 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, restricted cash, 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.

Long term debt is presented on the combined 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, interest rate cap and swaptions 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). An unobservable discount rate of 7% was used to determine the present value of the contractual liabilities and an unobservable probability factor of 75% was assigned to the contingent event prior to realization after considering contract terms, land rights, interconnect network, and environmental permits. The significant primary unobservable input used for contingent liabilities is the probability factor. Significant increases or decreases in this unobservable input would result in a significantly lower or higher fair value measurement.

The fair value of the energy derivative instrument was based on discounting the projected net cash flows over the remaining life of the derivative using unobservable discount factors of 86% to 99% and unobservable forward electricity prices ranging from $20 MWh to $97 MWh which are derived from observable historical heat rates and observable forward natural gas prices (Level 3). The significant primary unobservable input used for the energy derivative is forward electricity prices. Significant increases or decreases in this unobservable input would result in a significantly lower or higher fair value measurement.

Assets measured and recorded at fair value on a non-recurring basis consist primarily of property, plant and equipment from acquisitions made in 2010. No impairment charge has been recognized since the assets were acquired. They are categorized as Level 3 in the fair value hierarchy as the Company used unobservable inputs to the valuation methodologies and the valuations required management judgment due to the absence of quoted market prices. The valuation methodologies include the market approach and the income approach. The market approach includes the use of financial metrics and ratios of comparable public companies. The income approach includes the use of a discounted cash flow model, which requires estimates of revenue, costs, and discount rates based on the risk profile of comparable companies.

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

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

The change in fair value for the six months ended June 30, 2013 and the years ended December 31, 2012, 2011 and 2010 related to assets and liabilities still held at the end of the respective period.

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

The Company is treated as a pass-through entity for U.S. federal and state income tax purposes, except for certain of the Company’s Canadian and Chilean entities which are subject to Canadian and Chilean income taxes, a U.S. entity which is subject to Puerto Rico income taxes, and a U.S. entity which became subject to federal and state income taxes in 2012 after changing its tax status by electing to be treated as a Subchapter C corporation for federal income tax purposes, which required the inclusion of deferred tax assets related to book tax basis difference. The Company has recorded tax provisions or benefits for the Canadian and Chilean entities and U.S. entity. Deferred income taxes have been provided for net operating losses and temporary differences between book and tax basis. These differences create taxable or tax deductible amounts for future periods.

The table below presents the principal components of the Company’s net deferred tax assets and liabilities (in thousands):

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, 2012, 2011 and 2010 (in thousands):

The Company recorded income tax (benefit) provision of ($7.7) million (unaudited) and $0.2 million (unaudited) for the three months ended June 30, 2013 and 2012, respectively, ($7.4) million (unaudited) and $1.0 million (unaudited) for the six months ended June 30, 2013 and 2012, respectively, ($3.6) million, $0.7 million and ($0.7) million and for the years ended December 31, 2012, 2011 and 2010, respectively. The tax benefit and tax provision were comprised of estimated federal and provincial income taxes or benefits for the Company’s Canadian corporations and estimated federal and state income tax benefit for the U.S. corporation.

The deferred tax assets and deferred tax liabilities resulted primarily from temporary differences between book and tax bases 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 likely, additional valuation allowance would be established which would increase the Company’s tax provision in the period of such determination.

The threshold for recognizing the effects of tax return positions in the financial statements is more-likely-than-not that the position would be sustained by the taxing authority. The Company is required to measure a tax position meeting the more-likely-than-not criterion, based on the largest effect that is more than 50% likely to be realized. Management has analyzed the Company’s inventory of tax positions taken with respect to all applicable income tax issues for all open tax years (in each respective jurisdiction) and has concluded that no uncertain tax positions are required to be recognized in the Company’s combined financial statements. The Company is subject to examination by federal and state or provincial taxing authorities in Canada and the U.S. for the years 2009 through 2012.

The table below provides information, by country, about the Company’s combined 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):

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.

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 June 30, 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.

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. The Company issued irrevocable letters of credit totaling $57.6 million, of which $43.1 million was from the Company’s revolving credit facility, to ensure performance under these various project finance agreements.

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

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 base fees are approximately $18.8 million per year adjusted for inflation.

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 (unaudited), $8.0 million and $6.0 million as of June 30, 2013 and December 31, 2012 and 2011, 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 zero (unaudited) $2.8 million and $4.8 million as of June 30, 2013 and December 31, 2012 and 2011, respectively.

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 were $1.3 million (unaudited), $5.1 million and $6.4 million as of June 30, 2013 and December 31, 2012 and 2011, respectively.

The Company has open commitments for turbines of $4.6 million (unaudited), $1.7 million and $136.0 million, as of June 30, 2013 and December 31, 2012 and 2011, respectively, and for construction of $11.2 million (unaudited), $22.3 million and $118.2 million as of June 30, 2013 and December 31, 2012 and 2011, respectively.

The Company has entered into various long-term land leases. Rent expense recorded to the combined statements of operations was $1.7 million (unaudited) and $1.1 million (unaudited) for the three months ending June 30, 2013 and 2012, respectively, $3.3 million (unaudited) and $2.3 million (unaudited) for the six months ending June 30, 2013 and 2012, respectively, $4.2 million, $4.6 million and $1.8 million for the years ended December 31, 2012, 2011 and 2010, respectively.

The future minimum payments related to these leases as of December 31, 2012, are as follows (in thousands):

The Company 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.

In March 2013, the Company became aware that an upstream owner of the Company inadvertently failed upon its formation and thereafter to file an election to not be treated as a tax-exempt entity under the Internal Revenue Code. As a result of the discovery of this inadvertent failure, the upstream owner filed such an election in April 2013, which is effective as of January 1, 2012, and requested from the IRS a further retroactive application of the election beginning upon the formation of the upstream owner, the outcome of which will not be known until later in 2013.

Unless the IRS grants the upstream owner’s request for retroactive application of the election, the Company is technically in breach of certain affirmative representations made to certain financing counterparties and may be subject to indemnity and damage claims with respect to a resulting deferral of tax benefits. The Company believes it is likely that relief will be granted to the upstream owner, and that no indemnity or damages will be payable to affected counterparties, and accordingly has made no accrual related to this issue.

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.

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 liquidating damages a fee for each percent that the turbine operates below the minimum availability threshold. In addition, also pursuant to 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, 2011 and 2010, no liquidating damages or bonus were recorded by the Company.

In May 2013, a blade separated from the turbine hub on one of the wind turbines at the Ocotillo project following which the Company shut down all of the SWT-2.3-108 turbines at the Ocotillo and Santa Isabel projects, pending determination of the cause. The turbine manufacturer has completed, and the Company has 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. The Company’s warranties require the manufacturer to complete the remediation plan at its cost and pay liquidated damages to the projects in the event that turbine availability falls below specified thresholds.

In June 2013, the Company entered into warranty settlements with the blade manufacturer. The warranty settlements provide for total liquidated damage payments of approximately $13.9 million and $3.4 million for Ocotillo and Santa Isabel, respectively, for the three months ended June 30, 2013 and allows for a partial credit against future availability liquidated damages owed by the blade manufacturer. The Company estimates the maximum future refund of the liquidated damage payment to be $4.0 million and $1.9 million for Ocotillo and Santa Isabel, respectively, and has recorded a long term liability for these amounts. The warranty settlements, net of the maximum estimated future refund to the blade manufacturer, have been recorded as other revenue in the combined statements of operations.

The Company’s project management and administrative activities are provided by PEG LP. Costs associated with these activities are allocated to the Company and recorded in its combined 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 PEG LP. The Company believes the allocated costs presented in its combined 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. The tables below present allocated costs included in the combined statement of operations (in thousands):

PEG LP provides letters-of-credit that secure the Company’s obligations under PPAs and interconnection agreements. Letters-of-credit totaling zero (unaudited), zero and approximately $16.2 million, were outstanding as of June 30, 2013 and December 31, 2012 and 2011, respectively.

PEG LP agreed to indemnify lenders that provided a bridge loan to Spring Valley and Santa Isabel against the cash grants being disallowed or recaptured for certain eligibility-related reasons. The total amount of bridge loans drawn down was approximately $38.3 million and $85.7 million as of December 31, 2012 and 2011, respectively. Both loans were fully repaid as of June 30, 2013.

PEG LP 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, as required by Ocotillo’s lender.

PEG LP 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.

The Company entered into three turbine supply arrangements with PEG LP through which it acquired turbines for its wind power projects. The Company paid turbine access fees to PEG LP related to the turbine purchases of zero (unaudited) for the three and six months ended June 30, 2013 and 2012, and $55.0 million and $72.0 million for the years ended December 31, 2012 and 2011, respectively. The turbine access fees are included in construction in progress or property, plant and equipment in the Company’s combined balance sheets.

The Company has purchase arrangements with PEG LP under which the latter purchases various services and supplies on behalf of the Company and receives reimbursement for these purchases. As of June 30, 2013 and December 31, 2012 and 2011, the net amounts payable to PEG LP for these purchases were $0.1 million (unaudited), $0.2 million and $0.1 million, respectively.

The Company provides management services and receives a fee for such services under an agreement with South Kent, its joint venture investee. Management fees of $0.3 million (unaudited) were recorded as related party revenue in the combined statement of operations for the three and six months ended June 30, 2013, and related party receivable of $0.1 million (unaudited) was recorded in the combined balance sheet as of June 30, 2013. The Company eliminates the intercompany profit from management fees related to its ownership interest in South Kent.

On July 16, 2013, the Company received payments of $3.4 million and $13.9 million for Santa Isabel and Ocotillo, respectively, in connection with warranty settlements with the Company’s blade manufacturer.

On July 24, 2013, a letter of credit for $1.2 million was issued against the revolving credit facility.

In July 2013, Ocotillo commenced commercial operations on the remaining 42 MW of its electricity generating capacity.

This prospectus, together with the documents and information incorporated by reference, will, as of the date of the supplemented prospectus providing the information permitted to be omitted from this prospectus, constitute full, true and plain disclosure of all material facts relating to the securities offered by this prospectus as required under the securities legislation of the provinces and territories of Canada.

To the best of our knowledge, information and belief, this prospectus, together with the documents and information incorporated by reference, will, as of the date of the supplemented prospectus providing the information permitted to be omitted from this prospectus, constitute full, true and plain disclosure of all material facts relating to the securities offered by this prospectus as required under the securities legislation of the provinces and territories of Canada.

The actual and estimated expenses in connection with this offering, all of which will be borne by us, are as follows:

Reference is made to Section 102(b)(7) of the DGCL, which enables a corporation in its original certificate of incorporation or an amendment thereto to eliminate or limit the personal liability of a director for violations of the director’s fiduciary duty, except (1) for any breach of the director’s duty of loyalty to the corporation or its stockholders, (2) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (3) pursuant to Section 174 of the DGCL, which provides for liability of directors for unlawful payments of dividends of unlawful stock purchase or redemptions or (4) for any transaction from which a director derived an improper personal benefit.

Reference is also made to Section 145 of the DGCL, which provides that a corporation may indemnify any person, including an officer or director, who is, or is threatened to be made, party to any threatened, pending or completed legal action, suit or proceeding, whether civil, criminal, administrative or investigative, other than an action by or in the right of such corporation, by reason of the fact that such person was an officer, director, employee or agent of such corporation or is or was serving at the request of such corporation as a director, officer, employee or agent of another corporation or enterprise. The indemnity may include expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding, provided such officer, director, employee or agent acted in good faith and in a manner he reasonably believed to be in, or not opposed to, the Company’s best interest and, for criminal proceedings, had no reasonable cause to believe that his conduct was unlawful. A Delaware corporation may indemnify any officer or director in an action by or in the right of the corporation under the same conditions, except that no indemnification is permitted without judicial approval if the officer or director is adjudged to be liable to the corporation. Where an officer or director is successful on the merits or otherwise in the defense of any action referred to above, the corporation must indemnify him against the expenses that such officer or director actually and reasonably incurred.

Our amended and restated certificate of incorporation filed as Exhibit 3.1 to this registration statement provides that our directors will not be personally liable to the Company or its stockholders for monetary damages resulting from breach of their fiduciary duties. However, nothing contained in such provision will eliminate or limit the liability of directors (1) for any breach of the director’s duty of loyalty to us or our stockholders, (2) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of the law, (3) under Section 174 of the DGCL or (4) for any transaction from which the director derived an improper personal benefit.

Our amended and restated bylaws provide for indemnification of the officers and directors to the full extent permitted by applicable law.

In addition, we entered into agreements to indemnify our directors and executive officers containing provisions which are in some respects broader than the specific indemnification provisions contained in the DGCL. The indemnification agreements may require us, among other things, to indemnify our directors against certain liabilities that may arise by reason of their status or service as directors and to advance their expenses incurred as a result of any proceeding against them as to which they could be indemnified. The proposed form of such indemnification agreement is filed as Exhibit 10.4 to this registration statement.

The proposed form of Underwriting Agreement filed as Exhibit 1.1 to this registration statement provides for indemnification by the underwriters of the registrant and its officers and directors for certain liabilities arising under the U.S. Securities Act, or otherwise.

On October 17, 2012, in connection with our formation, Pattern Renewables LP, a subsidiary of Pattern Energy Group LP, was issued 100 shares of our common stock for total consideration of $1,000 in cash in order to provide our initial capitalization.

Certain information required in Schedule II, Valuation and Qualifying Accounts, has been omitted because equivalent information has been included in the financial statements included in this registration statement.

Other financial statement schedules have been omitted because they either are not required, are immaterial or are not applicable.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the U.S. Securities Act may be permitted to our directors, officers, and controlling persons pursuant to the foregoing provisions, or otherwise, we have been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the U.S. Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by us of expenses incurred or paid by a director, officer, or controlling person of us in the successful defense of any action, suit, or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, we will, unless in the opinion of counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by us is against public policy as expressed in the U.S. Securities Act and will be governed by the final adjudication of such issue.

Pursuant to the requirements of the Securities Act of 1933 as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of San Francisco, state of California, on August 9, 2013.

Each person whose signature appears below constitutes and appoints Michael M. Garland and Michael J. Lyon, and each of them singly, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and any and all additional registration statements pursuant to Rule 462(b) of the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agents full power and authority to do and perform each and every act in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or either 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 Act of 1933 as amended, this registration statement has been signed by the following persons in the capacities indicated on August 9, 2013.


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



Title of Securities to be Registered	Proposed maximum aggregate offering price(a)(b)	Amount of registration fee
Class A common stock, $0.01 par value per share	$345,000,000	$47,058


	Per Class A Share	Total
Public offering price	$	$

Underwriters’ commissions⁽¹⁾	$	$

Net proceeds to us, before expenses	$	$


	Page

BUSINESS SUMMARY		1

THE OFFERING		16

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA		20

RISK FACTORS		25

FORWARD-LOOKING STATEMENTS		51

USE OF PROCEEDS		53

CAPITALIZATION		54

DILUTION		55

CASH DIVIDEND POLICY		56

SELECTED HISTORICAL FINANCIAL DATA		70

UNAUDITED PRO FORMA FINANCIAL DATA		73

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		80

INDUSTRY		102

BUSINESS		118

INDEPENDENT ENGINEER REPORT		141

MANAGEMENT		143

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		161

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		167

STRUCTURE AND FORMATION OF OUR COMPANY		169

PRINCIPAL AND SELLING SHAREHOLDERS		172

DESCRIPTION OF CERTAIN FINANCING ARRANGEMENTS		174

DESCRIPTION OF CAPITAL STOCK		184

SHARES ELIGIBLE FOR FUTURE SALE		188

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR HOLDERS OF OUR CLASS A COMMON SHARES		190

MATERIAL CANADIAN FEDERAL INCOME TAX CONSIDERATIONS FOR HOLDERS OF OUR CLASS A COMMON SHARES		196

UNDERWRITING		201

LEGAL MATTERS		206

EXPERTS		206

WHERE YOU CAN FIND MORE INFORMATION		206

INDEX TO COMBINED FINANCIAL STATEMENTS		F-1


	Page
BUSINESS SUMMARY		1
THE OFFERING		16
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA		20
RISK FACTORS		25
FORWARD-LOOKING STATEMENTS		51
USE OF PROCEEDS		53
CAPITALIZATION		54
DILUTION		55
CASH DIVIDEND POLICY		56
SELECTED HISTORICAL FINANCIAL DATA		70
UNAUDITED PRO FORMA FINANCIAL DATA		73
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		80
INDUSTRY		102
BUSINESS		118
INDEPENDENT ENGINEER REPORT		141
MANAGEMENT		143
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		161
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		167
STRUCTURE AND FORMATION OF OUR COMPANY		169
PRINCIPAL AND SELLING SHAREHOLDERS		172
DESCRIPTION OF CERTAIN FINANCING ARRANGEMENTS		174
DESCRIPTION OF CAPITAL STOCK		184
SHARES ELIGIBLE FOR FUTURE SALE		188
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR HOLDERS OF OUR CLASS A COMMON SHARES		190
MATERIAL CANADIAN FEDERAL INCOME TAX CONSIDERATIONS FOR HOLDERS OF OUR CLASS A COMMON SHARES		196
UNDERWRITING		201
LEGAL MATTERS		206
EXPERTS		206
WHERE YOU CAN FIND MORE INFORMATION		206
ENFORCEMENT OF LEGAL RIGHTS		208
NOTICE TO INVESTORS REGARDING U.S. GAAP		208
CONTINUOUS DISCLOSURE		208
PROMOTER		208
PRIOR SALES OF SHARES		209
ELIGIBILITY FOR INVESTMENT		209
MATERIAL CONTRACTS		210
AUDITORS		210
PURCHASER’S STATUTORY RIGHTS OF WITHDRAWAL AND RECISSION		165
INDEX TO COMBINED FINANCIAL STATEMENTS		F-1
CERTIFICATE OF THE COMPANY AND THE PROMOTER		C-1
CERTIFICATE OF THE CANADIAN UNDERWRITERS		C-2


BMO Capital Markets		RBC Capital Markets			Morgan Stanley


	Canadian dollars per US$ 1.00
	High		Low		Period Average⁽¹⁾		Period End
Year
2010	C$	1.0776	C$	0.9960	C$	1.0298	C$	1.0009
2011		1.0605		0.9448		0.9887		1.0168
2012		1.0417		0.9710		0.9995		0.9958
Month
January 2013		1.0078		0.9839		0.9921		0.9992
February 2013		1.0286		0.9987		1.0098		1.0286
March 2013		1.0314		1.0155		1.0244		1.0174
April 2013		1.0270		1.0072		1.0187		1.0072
May 2013		1.0371		1.0023		1.0196		1.0337
June 2013		1.0532		1.0170		1.0314		1.0513
July 2013		1.0578		1.0259		1.0402		1.0287


	As of June 30, 2013
	Historical Predecessor			Pro forma Pattern			Pro Forma, As Adjusted Pattern
	(U.S. dollars in thousands, except share data)
Cash and cash equivalents	$	41,774		$	41,775

Long-term debt	$	1,210,564		$	1,210,564
Current portion of long term debt		105,246			105,246
Revolving credit facility		56,000			56,000
Total stockholders’ equity:
Class A common stock, $0.01 par value per share: no shares authorized or issued and outstanding, pro forma; shares authorized and shares issued and outstanding, pro forma, as adjusted⁽¹⁾		—			—
Class B common stock, $0.01 par value per share: no shares authorized or issued and outstanding, pro forma; shares authorized and shares issued and outstanding, pro forma, as adjusted⁽²⁾		—			—
Preferred stock, $0.01 par value per share: no shares authorized or issued and outstanding, pro forma; shares authorized and no shares issued and outstanding, pro forma, as adjusted		—			—
Additional paid-in capital		—			—
Capital		477,028			478,007
Accumulated income (deficit)		32,054			(12,184	)
Accumulated other comprehensive loss		(17,979	)		(15,053	)
Noncontrolling interest		73,771			101,923

Total equity		564,874			552,693

Total capitalization	$	1,936,684		$	1,924,503


(U.S. dollars)
Assumed initial public offering price per Class A share		$
Net tangible book value per share of our predecessor as of June 30, 2013, assuming the issuance of our shares to PEG LP in the Contribution Transactions, but before the issuance and sale of shares in connection with this offering and the use of proceeds therefrom⁽¹⁾	$
Increase in net tangible book value per share attributable to purchasers in this offering

Pro forma net tangible book value per share after the Contribution Transactions, issuance and sale of shares in connection with this offering and the use of proceeds therefrom⁽²⁾

Immediate dilution in net tangible book value per share to new investors⁽³⁾		$


	Forecast Year Ending December 31,
	2013			2014
	(U.S. dollars in thousands, except $/MWh, share data, and as otherwise noted) (unaudited)
Operating Data:
MWh sold		2,422,600			2,810,412
Average realized electricity price ($/MWh)	$	86		$	90
Revenue:
Electricity sales and energy derivative settlements	$	208,560		$	251,928
Unrealized loss on energy derivative		(18,334	)		(14,350	)
Other revenue		20,027			2,142

Total revenue		210,253			239,720

Cost of revenue:
Project expense		60,210			69,244
Depreciation and accretion		83,216			84,644

Total cost of revenue		143,426			153,888

Gross profit		66,827			85,832
Total operating expenses		14,201			14,917

Operating income		52,626			70,915
Other income (expense):
Interest expense		(67,851	)		(65,978	)
Unrealized gain on interest rate derivative		12,105			3,501
Realized loss on interest rate derivative		(2,071	)		(3,584	)
Equity in earnings in unconsolidated investments		3,218			16,816
Other income, net		8,880			673

Total other income (expense)		(45,719	)		(48,572	)

Net income (loss) before income tax		6,907			22,343
Tax provision (benefit)		804			1,728

Net income (loss)		6,103			20,615
Net loss attributable to noncontrolling interest		(10,644	)		(5,439	)

Net income attributable to controlling interest	$	16,747		$	26,054

Adjusted EBITDA⁽¹⁾	$	153,009		$	217,656

Adjustments to reconcile net income to net cash provided by operating activities:
Net income	$	6,103		$	20,615
Deferred taxes		774			1,698
Unrealized gain on energy derivative		18,334			14,350
Unrealized gain on interest rate derivative		(12,105	)		(3,501	)
Changes in operating assets and liabilities		(13,647	)		(498	)
Depreciation, amortization and accretion		89,508			89,609
Deferred compensation expense		610			1,220
Distributions from unconsolidated investments		—			6,877
Equity in losses (earnings) in unconsolidated investments		(3,218	)		(16,816	)

Net cash provided by operating activities	$	86,359		$	113,554

Adjustments to reconcile net cash provided by Operating Activities to Cash Available for Distribution:
Net cash provided by operating activities	$	86,359		$	113,554
Network upgrade reimbursements		2,447			2,507
Changes in operating assets and liabilities		13,647			498
Non-expansionary capital expenditures		(500	)		(500	)
Sale of investment tax credits		(7,200	)		—
Distributions to noncontrolling partners		(5,772	)		(6,596	)

Cash available for distribution before principal payments		88,981			109,463
Principal payments paid from operating cash flows		(44,519	)		(54,025	)

Cash available for distribution⁽¹⁾	$	44,462		$	55,438

Aggregate annual dividend	$			$
Shares of common stock, basic and diluted
Annual dividend per share of common stock	$			$


	Forecast Year Ending December 31,
	2013			2014
	(U.S. dollars in thousands) (unaudited)
Net income (loss)	$	6,103		$	20,615
Plus:
Interest expense, net of interest income		66,170			65,305
Tax provision		804			1,728
Depreciation and accretion		83,216			84,644

EBITDA	$	156,293		$	172,292

Unrealized loss on energy derivative		18,334			14,350
Unrealized gain on interest rate derivative		(12,105	)		(3,501	)
Realized loss on interest rate derivative		2,071			3,584
Sales of investment tax credits		(7,200	)		—
Plus, our proportionate share in the following from our equity accounted investments:
Interest expense, net of interest income		(111	)		14,048
Tax provision (benefit)		(61	)		285
Depreciation and accretion		3			16,408
Unrealized loss (gain) on interest rate derivatives		(3,954	)		(3,634	)
Realized loss (gain) on derivatives		(261	)		3,824

Adjusted EBITDA	$	153,009		$	217,656


	Capacity (MW)
Project	Rated⁽¹⁾		Owned⁽²⁾		Projected MWh Generation⁽³⁾
Consolidated Investments
Gulf Wind		283		113		869,593
Hatchet Ridge		101		101		290,400
St. Joseph		138		138		490,420
Spring Valley		152		152		347,478
Santa Isabel		101		101		171,061
Ocotillo⁽⁴⁾		265		265		641,460

Total for consolidated investments		1,040		870		2,810,412

Unconsolidated Investments
South Kent⁽⁵⁾		270		135		456,445
El Arrayán⁽⁵⁾		115		36		116,980

Total for unconsolidated investments		385		171		573,425

		1,425		1,041		3,383,837


	Forecast Year Ending December 31,
Project	2013		2014		Thereafter
	(U.S. dollars in thousands)
Consolidated Investments
Gulf Wind	$	9,361	$	10,275	$	155,333
Hatchet Ridge		11,254		11,577		228,288
St. Joseph		8,196		8,690		221,851
Spring Valley		5,790		5,849		167,261
Santa Isabel		3,315		3,112		112,608
Ocotillo		7,293		15,640		331,166
ITC and network upgrade bridge loans		114,056		—		—
Unconsolidated Investments⁽¹⁾
El Arrayán		2,483		3,659		65,928
South Kent		—		957		340,951
Other

Total	$	161,748	$	59,759	$	1,623,386


	Forecast Year ending December 31, 2013			Forecast Year ending December 31, 2014
	(U.S. dollars in thousands, except $/MWh)
MWh sold		—			397,250
Average realized electricity price ($/MWh)	$	—		$	142
Electricity sales and energy derivative settlements	$	—		$	56,287
Project expense		(1,197	)		(8,540	)
Depreciation and accretion		(3	)		(16,408	)
Interest expense		111			(14,048	)
Unrealized (gain) loss on interest rate derivatives		3,954			3,634
Realized gain (loss) on interest rate derivatives		261			(3,824	)
Foreign currency gain		31			—
Deferred Taxes		61			(285	)

Equity in earnings in unconsolidated investments	$	3,218		$	16,816


	Forecast Year Ending December 31, 2014			Timing Adjustment			Illustrative Forecast
	(U.S. dollars in thousands, except MWh sold and $/MWh)
MWh sold		397,250			176,175			573,425
Average realized electricity price ($/MWh)	$	142		$	141		$	142
Proportional interest in components of equity in earnings in unconsolidated investments:
Electricity sales and energy derivative settlements	$	56,287		$	24,873		$	81,160
Project expense		(8,540	)		(4,309	)		(12,849	)
Depreciation and accretion		(16,408	)		(6,925	)		(23,333	)
Interest expense		(14,048	)		(8,432	)		(22,480	)
Unrealized loss on interest rate derivatives		3,634			—			3,634
Realized loss on interest rate derivatives		(3,824	)		—			(3,824	)
Deferred Taxes		(285	)		26			(259	)

Equity in earnings in unconsolidated investments	$	16,816		$	5,233		$	22,049


Prospectus		Subject to Completion, dated August 9, 2013


	Forecast Year Ending December 31, 2014		Timing Adjustment		Illustrative Forecast
	(U.S. dollars in thousands)
Net Income	$	20,615	$	5,233	$	25,848
Adjusted EBITDA⁽²⁾⁽³⁾	$	217,656	$	20,564	$	238,220
Cash available for distribution before principal payments⁽²⁾⁽⁴⁾	$	109,463	$	24,790	$	134,253
Cash Available for Distribution⁽²⁾⁽⁴⁾	$	55,438	$	24,790	$	80,228


	Three months ended June 30,						Six months ended June 30,						Year ended December 31,
	2013			2012			2013			2012			2012			2011			2010
	(U.S. dollars in thousands)
Statement of Operations Data:
Revenue:
Electricity sales	$	47,351		$	23,015		$	92,583		$	49,874		$	101,835		$	108,770		$	24,669
Energy derivative settlements		4,809			5,918			10,217			11,659			19,644			9,512			10,905
Unrealized (loss) gain on energy derivative		(5,078	)		(3,995	)		(11,881	)		1,746			(6,951	)		17,577			14,000
Related party revenue		263			—			263			—			—			—			—
Other revenue		11,367			—			11,367			—			—			—			—

Total revenue		58,712			24,938			102,549			63,279			114,528			135,859			49,574
Cost of revenue:
Project expenses		14,492			7,910			27,469			15,758			34,843			31,343			18,530
Depreciation and accretion		17,998			10,853			40,564			21,736			49,027			39,424			12,951

Total cost of revenue		32,490			18,763			68,033			37,494			83,870			70,767			31,481

Gross profit		26,222			6,175			34,516			25,785			30,658			65,092			18,093
Operating expenses:
Development expenses		7			(8	)		8			—			174			704			3,065
General and administrative		198			276			341			513			851			866			356
Related party general and administrative		2,699			2,593			5,361			4,751			10,604			8,098			6,734

Total operating expenses		2,904			2,861			5,710			5,264			11,629			9,668			10,155

Operating income		23,318			3,314			28,806			20,521			19,029			55,424			7,938
Other income (expense):
Interest expense		(16,832	)		(8,051	)		(33,474	)		(16,182	)		(36,502	)		(29,404	)		(11,361	)
Equity in earnings in unconsolidated investments		13,368			(82	)		3,343			(104	)		(40	)		(205	)		(1	)
Unrealized loss on derivatives		8,202			(115	)		10,133			(95	)		(4,953	)		(345	)		(289	)
Realized loss on derivatives		—			—			—			—			—			—			(6,596	)
Early extinguishment of debt		—			—			—			—			—			—			(5,837	)
Net gain on transactions		7,200			4,173			7,200			4,173			4,173			—			22,009
Other income, net		1,044			410			1,802			684			1,320			1,125			503

Total other income (expense)		12,982			(3,665	)		(10,996	)		(11,524	)		(36,002	)		(28,829	)		(1,572	)
Net income (loss) before income tax		36,300			(351	)		17,810			8,997			(16,973	)		26,595			6,366

Tax (benefit) provision		(7,688	)		224			(7,396	)		1,004			(3,604	)		689			(672	)

Net income (loss)		43,988			(575	)		25,206			7,993			(13,369	)		25,906			7,038
Net (loss) income attributable to noncontrolling interest		(359	)		(2,928	)		(3,938	)		1,552			(7,089	)		16,981			2,474

Net income (loss) attributable to controlling interest	$	44,347		$	2,353		$	29,144		$	6,441		$	(6,280	)	$	8,925		$	4,564

Unaudited pro forma net income (loss) after tax:
Net income (loss) before income tax							$	17,810					$	(16,973	)
Pro forma tax provision								674						818

Pro forma net income (loss)							$	17,136					$	(17,791	)

Other Data:
Net cash provided by (used in):
Operating activities	$	33,268		$	11,506		$	41,659		$	24,808		$	35,050		$	46,930		$	(3,011	)
Investing activities	$	124,130		$	(183,743	)	$	63,414		$	(241,439	)	$	(638,953	)	$	(340,977	)	$	(460,207	)
Financing activities	$	(144,111	)	$	124,217		$	(79,772	)	$	217,694		$	573,167		$	331,336		$	472,321


	As of June 30,		As of December 31,
	2013		2012		2011		2010
	(U.S. dollars in thousands)
Balance Sheet Data:
Cash	$	41,774	$	17,573	$	47,672	$	8,928
Construction in progress	$	69,769	$	6,081	$	201,245	$	291,089
Property, plant and equipment, net	$	1,441,319	$	1,668,302	$	784,859	$	500,403
Total assets	$	2,010,053	$	2,035,729	$	1,390,426	$	1,058,493
Long-term debt	$	1,315,810	$	1,290,570	$	867,548	$	637,964
Total liabilities	$	1,445,179	$	1,446,311	$	943,728	$	722,549
Total equity before noncontrolling interest	$	491,103	$	514,117	$	362,226	$	255,160
Noncontrolling interest	$	73,771	$	75,301	$	84,472	$	80,784
Total equity	$	564,874	$	589,418	$	446,698	$	335,944


	Six months ended June 30, 2013
	Pattern			Predecessor			Pro Forma Adjustments⁽¹⁾			Pro Forma Adjustments⁽²⁾			Pro Forma Pattern Combined
	(U.S. dollars in thousands, except MWh sold and $/MWh)
Statement of Operations Data:
Revenue:
Electricity sales	$	—		$	92,583		$	—		$	—		$	92,583
Energy derivative settlements		—			10,217			—			—			10,217
Unrealized loss on energy derivative		—			(11,881	)		—			—			(11,881	)
Related party revenue		—			263			—			—			263
Other revenue		—			11,367			—			—			11,367

Total revenue		—			102,549			—			—			102,549
Cost of revenue:
Project expenses		—			27,469			—			—			27,469
Depreciation and accretion		—			40,564			—			—			40,564

Total cost of revenue		—			68,033			—			—			68,033

Gross profit		—			34,516			—			—			34,516
Operating expenses:
Development expenses		—			8			—			—			8
General and administrative		—			341			—			—			341
Related party general and administrative		—			5,361			—			—			5,361

Total operating expenses		—			5,710			—			—			5,710

Operating income		—			28,806			—			—			28,806
Other income (expense):
Interest expense		—			(33,474	)		—			—			(33,474	)
Equity in earnings in unconsolidated investments		—			3,343			—			—			3,343
Unrealized gain on derivatives		—			10,133			—			—			10,133
Net gain on transactions		—			7,200			—			—			7,200
Other income, net		—			1,802			—			—			1,802

Total other income (expense)		—			(10,996	)		—			—			(10,996	)
Net income before income tax		—			17,810			—			—			17,810
Tax expense (benefit)		2			(7,396	)		—			8,070			676

Net (loss) income		(2	)		25,206			—			(8,070	)		17,134
Net loss attributable to noncontrolling interest		—			(3,938	)		(1,500	)		—			(5,438	)

Net (loss) income attributable to controlling interest	$	(2	)	$	29,144		$	1,500		$	(8,070	)	$	22,572

Other Data:
Net cash provided by (used in):
Operating activities	$	(2	)	$	41,659		$	—		$	—		$	41,657
Investing activities	$	—		$	63,414		$	—		$	—		$	63,414
Financing activities	$	2		$	(79,772	)	$	—		$	—		$	(79,770	)
Operating Data:
MWh Sold⁽³⁾		—			1,261,876			—			—			1,261,876
Average realized electricity price ($/MWh)⁽⁴⁾	$	—		$	81		$	—		$	—		$	81


	Year ended December 31, 2012
	Pattern			Predecessor			Pro Forma Adjustments⁽¹⁾			Pro Forma Adjustments⁽²⁾			Pro Forma Pattern Combined
	(U.S. dollars in thousands, except MWh sold and $/MWh)
Statement of Operations Data:
Revenue:
Electricity sales	$	—		$	101,835		$	—		$	—		$	101,835
Energy derivative settlements		—			19,644			—			—			19,644
Unrealized loss on energy derivative		—			(6,951	)		—			—			(6,951	)

Total revenue		—			114,528			—			—			114,528
Cost of revenue:
Project expenses		—			34,843			—			—			34,843
Depreciation and accretion		—			49,027			—			—			49,027

Total cost of revenue		—			83,870			—			—			83,870

Gross profit		—			30,658			—			—			30,658
Operating expenses:
Development expenses		—			174			—			—			174
General and administrative		—			851			—			—			851
Related party general and administrative		7			10,604			—			—			10,611

Total operating expenses		7			11,629			—			—			11,636
Operating income		(7	)		19,029			—			—			19,022
Other income (expense):
Interest expense		—			(36,502	)		—			—			(36,502	)
Equity in earnings in unconsolidated investments		—			(40	)		—			—			(40	)
Unrealized loss on derivatives		—			(4,953	)		—			—			(4,953	)
Net gain on transactions		—			4,173			—			—			4,173
Other income, net		—			1,320			—			—			1,320

Total other income (expense)		—			(36,002	)		—			—			(36,002	)
Net loss before income tax		(7	)		(16,973	)		—			—			(16,980	)
Tax (benefit) provision		—			(3,604	)		—			4,422			818

Net loss		(7	)		(13,369	)		—			(4,422	)		(17,798	)
Net loss attributable to noncontrolling interest		—			(7,089	)		(1,155	)		—			(8,244	)

Net loss attributable to controlling interest	$	(7	)	$	(6,280	)	$	1,155		$	(4,422	)	$	(9,554	)

Other Data:
Net cash provided by (used in):
Operating activities				$	35,050		$	—		$	—		$	35,050
Investing activities				$	(638,953	)	$	—		$	—		$	(638,953	)
Financing activities				$	573,167		$	—		$	—		$	573,167
Operating Data:
MWh Sold⁽³⁾					1,673,413			—			—			1,673,413
Average realized electricity price ($/MWh)⁽⁴⁾				$	73		$	—		$	—		$	73


	Payments due by period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Contractual Obligations
Long-term debt principal payments⁽¹⁾	$	1,290,570	$	137,258	$	103,189	$	111,754	$	938,369
Long-term debt interest payments		600,113		54,019		114,432		104,013		327,649
Purchase commitments		29,141		29,141		—		—		—
Land leases		167,607		9,514		9,763		10,117		138,213
Turbine operations and maintenance⁽²⁾		41,339		17,563		18,979		4,153		644
Asset retirement liabilities⁽³⁾		19,056		—		—		—		19,056
Contingent liabilities⁽⁴⁾		8,001		—		8,001		—		—

Total	$	2,155,827	$	247,495	$	254,364	$	230,037	$	1,423,931


	Six Months Ended June 30, 2013		Year Ended December 31, 2012		Year Ended December 31, 2011		Year Ended December 31, 2010
*MWh sold*
Gulf Wind		494,156		827,310		927,720		635,095
Hatchet Ridge		149,248		256,302		277,089		8,383
St Joseph		247,401		471,766		363,214		N/A
Spring Valley		132,299		109,296		N/A		N/A
Santa Isabel		60,694		6,780		N/A		N/A
Ocotillo		178,078		1,959		N/A		N/A

		1,261,876		1,673,413		1,568,023		643,478


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


Name	Age		Position(s) Held	Residence (State/Province & Country)
Michael M. Garland		62	Director, President and Chief Executive Officer	California, USA
Hunter H. Armistead		44	Executive Vice President, Business Development	California, USA
Daniel M. Elkort		55	Executive Vice President and General Counsel	California, USA
Michael J. Lyon		54	Chief Financial Officer	Washington, USA
Esben W. Pedersen		40	Chief Investment Officer	California, USA
Eric S. Lillybeck		59	Senior Vice President, Fiscal and Administrative Services	California, USA
Dean S. Russell		62	Senior Vice President, Engineering and Construction	California, USA
Christopher M. Shugart		41	Senior Vice President, Operations	Texas, USA
Dyann S. Blaine		49	Vice President and Secretary	California, USA
Michael B. Hoffman		63	Director	New York, USA
Alan R. Batkin		66	Director Nominee ⁽¹⁾⁽²⁾	Connecticut, USA
The Lord Browne of Madingley		65	Director Nominee⁽¹⁾⁽²⁾	London, England, UK
Douglas G. Hall		63	Director Nominee⁽¹⁾⁽²⁾	Nova Scotia, Canada
Patricia M. Newson		55	Director Nominee⁽¹⁾⁽²⁾	Alberta, Canada
			Director Nominee⁽¹⁾⁽²⁾


Name:		Public Company
Alan R. Batkin		Cantel Medical Corp. Hasbro, Inc. Omnicom Group, Inc.
Douglas G. Hall		NexC Partners Corp.
Michael B. Hoffman		Onconova Therapeutics Inc.
Patricia M. Newson		Brookfield Residential Properties Inc. Long Run Exploration Inc.


	Year ended December 31, 2012
Category of Fees	(dollars in thousands)
Audit fees⁽¹⁾	$	2,865
Audit-related fees		0
Tax fees		0
All other fees		0

Total	$	2,865


Name and Principal Position	Year		Salary		Bonus⁽¹⁾		All Other Compensation⁽²⁾	Total Compensation


Michael M. Garland,		2012	$	302,500	$	650,000	$12,500	$	965,000
President and Chief Executive Officer

Hunter H. Armistead,		2012	$	281,500	$	650,000	$12,500	$	944,000
Executive Vice President, Business Development

Daniel M. Elkort,		2012	$	281,500	$	650,000	$12,500	$	944,000
Executive Vice President and General Counsel


Name		Current Annual Base Salary
		(U.S. dollars)
Michael M. Garland		$400,000
Hunter H. Armistead		$325,000
Daniel M. Elkort		$290,000
Michael J. Lyon		$230,625
Esben W. Pedersen		$231,275


Name		Target Annual Bonus (% of base salary)
Michael M. Garland		150%
Hunter H. Armistead		150%
Daniel M. Elkort		125%
Michael J. Lyon		Not eligible
Esben W. Pedersen		Not eligible


Name and Principal Position⁽¹⁾	Cash Severence⁽²⁾		COBRA Benefit Continuation		Total
Michael M. Garland, President and Chief Executive Officer		2,870,000		19,095		2,889,095

Hunter H. Armistead, Executive Vice President, Business Development		1,414,000		27,832		1,441,832

Daniel M. Elkort, Executive Vice President and General Counsel		1,316,000		27,832		1,343,832


	Restricted Stock Awards			Stock Options
	Targeted Value ($000’s)		Number of shares⁽¹⁾	Targeted Value ($000’s)		Number of options⁽¹⁾
Michael M. Garland	$	720		$	720
Hunter H. Armistead		250			250
Daniel M. Elkort		200			200
Michael J. Lyon		150			150
Esben W. Pedersen		150			150
All others		360			360
Total	$	1,830		$	1,830


	A Interests					Direct and Indirect B Interests⁽¹⁾
Name and Title	Number Held		Percentage of Total			Number Held		Percentage of Total
Michael M. Garland President and Chief Executive Officer		2,278,268		0.31	%		255,639		26.18	%
Hunter H. Armistead Executive Vice President, Business Development		1,605,972		0.22	%		220,957		22.62	%
Daniel M. Elkort Executive Vice President and General Counsel		180,684		0.02	%		89,900		9.15	%
Eric S. Lillybeck, Senior Vice President, Fiscal and Administrative Services		90,352		0.01	%		35,346		3.62	%
Dean S. Russell, Senior Vice President, Engineering and Construction		90,328		0.01	%		14,111		1.44	%
Dyann S. Blaine Vice President and Secretary		177,344		0.02	%		2,966		0.03	%

Total		4,422,948		0.59	%		618,419		63.32	%


Subsidiary	Jurisdiction of Incorporation/Governing Jurisdiction	% of Voting or Interests Held (directly or indirectly)
Ocotillo Wind Holdings LLC	Delaware		100	%
Ocotillo Express LLC	Delaware		100	%
Pattern US Finance Company LLC	Delaware		100	%
Pattern Gulf Wind Equity LLC	Delaware		100	%
Pattern Gulf Wind Holdings LLC	Delaware		60	%⁽¹⁾
Pattern Gulf Wind LLC	Delaware		100	%
Hatchet Ridge Holdings LLC	Delaware		100	%
Hatchet Ridge Wind, LLC	Delaware		100	%
Nevada Wind Holdings LLC	Delaware		100	%
Spring Valley Wind LLC	Nevada		100	%
Santa Isabel Holdings LLC	Delaware		100	%
Pattern Santa Isabel LLC	Delaware		100	%
Pattern Canada Finance Company ULC	Nova Scotia		100	%
Pattern St. Joseph Holdings Inc.	Canada		100	%
St. Joseph Windfarm Inc.	Canada		100	%


Underwriter		Number of Class A Shares
BMO Nesbitt Burns Inc.
RBC Dominion Securities Inc.
Morgan Stanley & Co. LLC

Total


Name of Person or Company		Name and Address of Agent
Pattern Energy Group Inc.		—
Pattern Energy Group LP		—
Michael M. Garland		—
Michael B. Hoffman		—