Pattern Energy Group Inc.
Pattern Energy Group Inc. (Form: 10-K, Received: 02/29/2016 17:11:10)

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549  
 
 
 
FORM 10-K
 
 
 
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2015.
-OR-
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-36087
 
 
 
PATTERN ENERGY GROUP INC.
(Exact name of Registrant as specified in its charter)
 
 
 
Delaware
 
90-0893251
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
Pier 1, Bay 3, San Francisco, CA 94111
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (415) 283-4000
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Class A Common Stock, par value $0.01 per share
 
NASDAQ Global Select Market
Toronto Stock Exchange
Securities registered pursuant to Section 12 (g) of the Act: None
 
 
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes   ý     No   ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes   ¨     No   ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   ý     No   ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   ý     No   ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
x
 
Accelerated filer
¨
Non-accelerated filer
¨
 
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.)    Yes   ¨     No   ý
The aggregate market value of the voting stock and non-voting stock held by non-affiliates of the registrant based upon the last trading price of the registrant’s Class A common stock as reported on the NASDAQ Global Market on June 30, 2015 was approximately $ 1,462,489,654 . This excludes 17,705,514 shares of Class A common stock held by directors, officers and Pattern Renewables LP and certain of its affiliates. Exclusion of shares does not reflect a determination that persons are affiliates for any other purpose.
The registrant’s Class A common stock began trading on the NASDAQ Global Market under the symbol "PEGI" and on the Toronto Stock Exchange under the symbol "PEG" on October 2, 2013.
On February 24, 2016 , the registrant had 74,643,763 shares of Class A common stock, $0.01 par value per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement relating to its 2016 annual meeting of stockholders (the "2016 Proxy Statement") are incorporated by reference into Part III of this Form 10-K where indicated. The 2016 Proxy Statement will be filed with the U.S. Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates.
 





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


2




CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K ("Form 10-K") contains statements that may constitute forward-looking statements. You can identify these statements by forward-looking words such as "anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan," "potential," "should," "will," "would," or similar words. You should read statements that contain these words carefully because they discuss our current plans, strategies, prospects, and expectations concerning our business, operating results, financial condition, and other similar matters. While we believe that these forward-looking statements are reasonable as and when made, there may be events in the future that we are not able to predict accurately or control, and there can be no assurance that future developments affecting our business will be those that we anticipate. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause our actual results to differ from those in the forward-looking statements, include but are not limited to, those summarized below and further described in Part I, Item 1A "Risk Factors:"
our ability to complete acquisitions of power projects;
our ability to complete construction of construction projects and transition them into financially successful operating projects;
fluctuations in supply, demand, prices and other conditions for electricity, other commodities and renewable energy credits ("RECs");
our electricity generation, our projections thereof and factors affecting production, including wind and other conditions, other weather conditions, availability and curtailment;
changes in law, including applicable tax laws;
public response to and changes in the local, state, provincial and federal regulatory framework affecting renewable energy projects, including the U.S. federal production tax credit ("PTC"), investment tax credit ("ITC") and potential reductions in Renewable Portfolio Standards ("RPS") requirements;
the ability of our counterparties to satisfy their financial commitments or business obligations;
the availability of financing, including tax equity financing, for our power projects;
an increase in interest rates;
our substantial short-term and long-term indebtedness, including additional debt in the future;
competition from other power project developers;
development constraints, including the availability of interconnection and transmission;
potential environmental liabilities and the cost and conditions of compliance with applicable environmental laws and regulations;
our ability to operate our business efficiently, manage capital expenditures and costs effectively and generate cash flow;
our ability to retain and attract executive officers and key employees;
our ability to keep pace with and take advantage of new technologies;
the effects of litigation, including administrative and other proceedings or investigations, relating to our wind power projects under construction and those in operation;
conditions in energy markets as well as financial markets generally, which will be affected by interest rates, foreign currency exchange rate fluctuations and general economic conditions;
the effectiveness of our currency risk management program;
the effective life and cost of maintenance of our wind turbines and other equipment;
the increased costs of, and tariffs on, spare parts;
scarcity of necessary equipment;
negative public or community response to wind power projects;
the value of collateral in the event of liquidation; and
other factors discussed under "Risk Factors."

3




Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
MEANING OF CERTAIN REFERENCES
Unless the context provides otherwise, references herein to "we," "our," "us," "our company" and "Pattern" refer to Pattern Energy Group Inc., a Delaware corporation, together with its consolidated subsidiaries. In addition, unless the context requires otherwise, any reference in this Form 10-K to:
 
"Conversion Event" refers to the event pursuant to which all of our Class B shares automatically converted into Class A shares on a one-for-one basis on December 31, 2014;
"employee transfer" refers to the event contemplated by the Management Services Agreement pursuant to which we have the option, exercisable by delivery of written notice of exercise to Pattern Development at any time during a period of eighteen (18) months commencing July 1, 2015, to require Pattern Development to cause the employees of Pattern Development and its subsidiaries to become employees of us and our subsidiaries. From and after the occurrence of the employee transfer event, we and Pattern Development will cooperate to cause such employee transfer to occur by the six month anniversary of the employee transfer event or as soon as reasonably practical thereafter;
"FERC" refers to the U.S. Federal Energy Regulatory Commission;
"FIT" refers to feed-in-tariff regime;
"FPA" refers to the Federal Power Act;
"Identified ROFO Projects" refers to thirteen projects that we identified as development projects, each owned by Pattern Development and subject to our Project Purchase Right, consisting of Armow, Meikle, Conejo Solar, Belle River, Henvey Inlet, Mont Sainte-Marguerite, North Kent, Broadview projects, Grady, Tsugaru, Ohorayama, Kanagi Solar and Futtsu Solar projects. The Tsugaru, Ohorayama, Kanagi Solar and Futtsu Solar projects are held through Pattern Development’s majority stake investment in Green Power Investment Corporation ("GPI") based in Tokyo, Japan;
"IPPs" refers to independent power producers;
"ISOs" refers to independent system organizations, which are organizations that administer wholesale electricity markets;
"ITCs" refers to investment tax credits;
"Management Services Agreement" refers to the bilateral services agreement between us and Pattern Development, as amended;
"MW" refers to megawatts;
"MWh" refers to megawatt hours;
"Non-Competition Agreement" refers to a non-competition agreement between us and Pattern Development pursuant to which Pattern Development agrees that, for so long as any of our Purchase Rights are exercisable, it will not compete with us for acquisitions of power generation or transmission projects from third parties;
"OCC" refers to our operations control center;
"Pattern Development" refers to Pattern Energy Group LP and its subsidiaries (other than us and our subsidiaries);
"Pattern Development Purchase Rights" refer to the right to acquire Pattern Development itself or substantially all of its assets, as contemplated by the Purchase Rights Agreement between us and Pattern Development;
"power sale agreements" refer to PPAs and/or hedging arrangements, as applicable;
"PPAs" refer to power purchase agreements;

4




"Project Purchase Right" refers to a right of first offer with respect to any power project that Pattern Development decides to sell, including the Identified ROFO Projects;
"Purchase Rights" refer to the Project Purchase Right and the Pattern Development Purchase Rights, as contemplated by the Purchase Rights Agreement between us and Pattern Development;
"RECs" refers to renewable energy credits;
"Riverstone" refers to Riverstone Holdings LLC;
"ROFO" refers to right of first offer;
"RPS" refers to Renewable Portfolio Standards;
"Sarbanes-Oxley Act" refers to the Sarbanes-Oxley Act of 2002;
"Samsung" means Samsung C&T Corporation; and
"U.S. Treasury" refers to the U.S. Department of the Treasury.

5




CURRENCY AND EXCHANGE RATE INFORMATION
In this Form 10-K, 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 historical consolidated financial statements are presented in U.S. dollars. The following chart sets forth for each of 2015 , 2014 and 2013 , the high, low, period average and period end noon buying rates of Canadian dollars expressed as Canadian dollars per US$1.00.
 
 
Canadian Dollars per US$1.00
 
High
 
Low
 
Period Average (1)
 
Period End
Year
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015
C$
 
1.3987

 
C$
 
1.1601

 
C$
 
1.2788

 
C$
 
1.3835

2014
 
 
1.1643

 
 
 
1.0614

 
 
 
1.1045

 
 
 
1.1501

2013
 
 
1.0697

 
 
 
0.9839

 
 
 
1.0300

 
 
 
1.0637


(1)
The average of the noon buying rates on the last business day of each month during the relevant one-year period and, in respect of monthly or interim period information, the average of the noon buying rates on each business day for the relevant period.
The noon buying rate in Canadian dollars on February 24, 2016 was US$1.00 = C$ 1.3707 .
The above rates differ from the actual rates used in our consolidated historical financial statements and the calculation of cash available for distribution and dividends we declared and paid described elsewhere in this Form 10-K. 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 Item 1A " Risk Factors —Risks Related to Our Projects—Currency exchange rate fluctuations may have an impact on our financial results and condition" and Item 7A " Quantitative and Qualitative Disclosure About Market Risk —Foreign Currency Exchange Rate Risk."


6




PART I
Item 1.
Business.
Overview
We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued growth of our business. We hold interests in 16 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 2,282 MW. 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. Eighty-nine percent of the electricity to be generated by our projects will be sold under our power sale agreements which have a weighted average remaining contract life of approximately 14 years.
Our growth strategy is focused on the acquisition of operational and construction-ready power projects from Pattern Development and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per Class A share over time. Pattern Development is a leading developer of renewable energy and transmission projects. We believe Pattern Development’s ownership position in our company incentivizes Pattern Development to support the successful execution of our objectives and business strategy, including through the development of projects to the stage where they are at least construction-ready. Currently, Pattern Development has a 5,900 MW pipeline of development projects, all of which are subject to our right of first offer. We target achieving a total owned capacity of 5,000 MW by year end 2019 through a combination of acquisitions from Pattern Development and other third parties capitalizing on the large and fragmented global renewable energy market. In addition, we expect opportunities in Japan and Mexico will form part of our growth strategy.
Our Core Values and Financial Objectives
We intend to maximize long-term value for our stockholders in an environmentally responsible manner and with respect for the communities in which we operate. Our business is built around three core values of creative energy and spirit, pride of ownership and follow-through, and a team first attitude, which guide us in:  
creating a safe and high-integrity work environment for our employees;
applying rigorous analysis to all aspects of our business in a timely, disciplined and functionally integrated manner to understand patterns in wind regimes, technology developments, market trends and regulatory, financial and legal constraints; and
working proactively with our stakeholders to address environmental and community concerns, which we believe is a socially responsible approach that also benefits our business by reducing operating risks at our projects.
Our financial objectives, which we believe will maximize long-term value for our stockholders, are to:  
produce stable and sustainable cash available for distribution;
selectively grow our project portfolio and our dividend per Class A share; and
maintain a strong balance sheet and flexible capital structure.

7




Our Projects
The following table provides an overview of our wind projects:
 
Location and Start-up
 
Capacity (MW)
 
Power Sale Agreements
Projects
Location
 
Construction
Start
(1)
 
Commercial
Operations
(2)
 
Rated (3)
 
Owned (4)
 
Type
 
Contracted
Volume
(5)
 
Counterparty
 
Counterparty
Credit Rating
(6)
 
Expiration
Operating Projects
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf Wind
Texas
 
Q1 2008
 
Q3 2009
 
283

 
283

 
Hedge
(7)  
~58 %
 
Morgan Stanley
 
BBB+/A3

2019
Hatchet Ridge
California
 
Q4 2009
 
Q4 2010
 
101

 
101

 
PPA

100%
 
Pacific Gas & Electric
 
BBB/A3

2025
St. Joseph
Manitoba
 
Q1 2010
 
Q2 2011
 
138

 
138

 
PPA

100%
 
Manitoba Hydro
 
AA/Aa2
(8)  
2039
Spring Valley
Nevada
 
Q3 2011
 
Q3 2012
 
152

 
152

 
PPA

100%
 
NV Energy
 
BBB+/Baa2

2032
Santa Isabel
Puerto Rico
 
Q4 2011
 
Q4 2012
 
101

 
101

 
PPA

100%
 
Puerto Rico Electric Power Authority
 
CC/Caa3

2037
Ocotillo
Californ ia
 
Q3 2012
 
Q4 2012
 
223

 
223

 
PPA

100%
 
San Diego Gas & Electric
 
A/A1

2033
Ocotillo
California
 

 
Q2 2013
 
42

 
42

 
PPA

100%
 
San Diego Gas & Electric
 
A/A1

2033
South Kent
Ontario
 
Q1 2013
 
Q2 2014
 
270

 
135

 
PPA

100%
 
Independent Electricity System Operator
 
Aa2
(9)  
2034
El Arrayán
Chile
 
Q3 2012
 
Q2 2014
 
115

 
81

 
Hedge
(10)  
~74%
 
Minera Los Pelambres
 
NA

2034
Panhandle 1
Texas
 
Q3 2013
 
Q2 2014
 
218

 
172

 
Hedge
(11)  
~80%
 
Citigroup Energy Inc.
 
BBB+/Baa1

2027
Panhandle 2
Texas
 
Q4 2013
 
Q4 2014
 
182

 
147

 
Hedge
(11)  
~80%
 
Morgan Stanley
 
BBB+/A3

2027
Grand
Ontar io
 
Q3 2013
 
Q4 2014
 
149

 
67

 
PPA

100%
 
Independent Electricity System Operator
 
Aa2
(9)  
2034
Post Rock
Kansas
 
Q4 2011
 
Q4 2012
 
201

 
120

 
PPA

100%
 
Westar Energy, Inc.
 
BBB+/Baa1

2032
Lost Creek
Missouri
 
Q2 2009
 
Q2 2010
 
150

 
150

 
PPA

100%
 
Associated Electric Cooperative, Inc.
 
AA/A2

2030
K2
On tario
 
Q1 2014
 
Q2 2015
 
270

 
90

 
PPA

100%
 
Independent Electricity System Operator
 
Aa2
(9)  
2035
Logan's Gap
Texas
 
Q4 2014
 
Q3 2015
 
200

 
164

 
PPA

~58%
 
Wal-Mart Stores, Inc.
 
AA/Aa2

2025
 
 
 
 
 
 
 
 
 
 
 
Hedge
(12)  
~17%
 
Merrill Lynch Commodities, Inc.
 
BBB+/Baa1

2028
Amazon Wind Farm Fowler Ridge
Indiana
 
Q2 2015
 
Q4 2015
 
150

 
116

 
PPA

100%
(13)  
Amazon.com, Inc.
 
AA-/Baa1
(14)  
2028
 
 
 
 
 
 
 
2,945

 
2,282

 
 
 
 
 
 
 
 
 
 
 
(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 may be less than its rated capacity.

8




(4)
Owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW multiplied by our percentage ownership interest in the distributable cash flow of the project.
(5)
Represents the percentage of a project’s total estimated average annual MWh of electricity generation contracted under power sale agreements or hedge arrangements.
(6)
Reflects the counterparty’s or counterparty guarantor's corporate credit ratings issued by either S&P or Moody’s, or both S&P and Moody's, as of December 31, 2015 .
(7)
Represents a 10-year fixed-for-floating power price swap. See Item 2 "Properties—Operating Projects—Gulf Wind."
(8)
Reflects the corporate credit ratings of the Province of Manitoba, which owns 100% of Manitoba Hydro-Electric.
(9)
Reflects the corporate credit ratings of the Province of Ontario, which owns 100% of the Independent Electricity System Operator ("IESO"), formerly the Ontario Power Authority.
(10)
Represents a 20-year fixed-for-floating swap. See Item 2 "Properties—Operating Projects—El Arrayán."
(11)
Represents a fixed-for-floating swap of more than ten years duration. See Item 2 "Properties—Operating Projects—Panhandle 1 and Panhandle 2."
(12)
Represents a 13-year fixed-for-floating swap. See Item 2 "Properties—Operating Projects—Logan’s Gap."
(13)
Contracted volume begins at 50% and increases pro rata to 100% over a period of 18 months, beginning January 2016.
(14)
Contractual counterparty is a wholly-owned subsidiary of Amazon Web Services and obligations are guaranteed by Amazon.com, Inc.

Each of our projects has gone through a rigorous vetting process in order to meet our investment and our lenders’ financing criteria. As a result, our projects generally have the following characteristics:  
multi-year on-site wind data analysis tied to one or more long-term wind energy reference sources. Pattern Development employs a full-time meteorological team that manages and verifies third party wind analysis. This wind analysis is carefully vetted through detailed studies by internal and independent experts in meteorology and statistics to derive an expected production profile based on daily and seasonal wind patterns, structural interference, topography and atmospheric conditions. Our average on-site wind data collection is over four years (or approximately seven years including post-construction data collection);
long-term power sale agreements designed to ensure a predictable revenue stream. As is typical in our industry, we sell our electricity at a fixed price on a contingent, as-produced basis such that only the electricity that we generate is sold to and must be purchased by the counterparty at the agreed price. Our power sale agreements have a weighted average remaining contract life of approximately 14 years;
contractually secured real estate property and easement rights for a period well in excess of the project’s expected useful life and contractual obligations. Each of our projects has land rights for 25 years or more;
a firm right to interconnect to the electricity grid through interconnection agreements, which define the cost allocation and schedule for interconnection, as well as any upgrades required to connect the project to the transmission system. Our interconnection agreements allow our projects to connect to the electricity transmission system. Market rules and protocols generally govern dispatch of our electricity generation and allow it to flow freely into the grid as it is produced, except in very limited circumstances where our projects can be curtailed, for example during system emergencies;
long-term, limited-recourse, amortizing project financing designed to match the long-lived nature of our power projects and the related power sales agreements. The interest rates on our long-term loans are fixed for the tenor of the loans or are subject to fixed-for-floating swaps that match the amortization schedules of the debt;
all necessary construction and operating permits and other requisite federal, state or provincial and local permits, and regulatory approvals secured , which critical permits typically include federal aviation, state or provincial environmental approvals and local zoning and land-use permits and are designed to protect the community, cultural resources, plants, animal and other affected resources at or near the facility;
fixed-price turbine supply and construction contracts with guaranteed completion dates to ensure that our projects are completed on time and within the estimated budget. The construction period for our projects has typically been less than one year, although in certain instances circumstances warrant a longer construction period;
an operations and maintenance service program based on our own on-site personnel and central operations management as well as equipment warranties and service arrangements with qualified contractors experienced in wind project maintenance . We have existing turbine equipment warranties for approximately 75% of our operating turbine units; and
safety, environmental and community programs to support our existing projects and relationships in the communities in which we operate.

9




For additional information regarding each of our projects, see Item 2 "Properties." Our ability to transition each of our construction projects to commercial operations and achieve anticipated power output at all of our operating projects is subject to numerous risks and uncertainties as described under Item 1A "Risk Factors."
Our Business Strategy
We intend to make profitable investments in environmentally responsible power projects, while embracing a long-term commitment to the communities in which we operate. To achieve our financial objectives while adhering to our core values, we intend to execute the following business strategies:
Maintaining and Increasing the Value of Our Projects
We intend to efficiently operate our projects to meet projected revenue and cash available for distribution. We expect to maximize the long-term value of our projects by focusing on value-oriented project availability (by ensuring our projects are operational when the wind is strong and PPA prices are at their highest) and by regularly scheduled and preventative maintenance. We believe that good operating performance begins with a long-term maintenance program for our equipment. We also seek to improve performance or lower operating costs by working closely with our equipment vendors and considering contracting with third parties, when appropriate.
We believe it is important to employ our own personnel in aspects of our business that we deem critical to the value of our projects 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 employ on-site personnel, maintain a 24/7 operations control center to monitor our projects and control all critical aspects of commercial asset management.
Selectively Growing Our Business
Our strategy for growth is focused on the acquisition of operational and construction-ready power projects from Pattern Development and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per Class A share over time. We expect that projects we may acquire in the future will represent a logical extension of our existing business and be consistent with our risk profile, and that any incremental assumption of risk will require commensurate expectations of higher returns. As a result, our near-term growth strategy will remain focused on largely contracted cash flows with creditworthy counterparties and operating or in-construction projects.
We expect that new opportunities will arise from our relationship with Pattern Development, which provides us with the opportunity to acquire projects that it successfully develops and efficiently completing construction and achieving commercial operations at these projects.

10




Below is a summary of the Identified ROFO Projects that we expect to acquire from Pattern Development in connection with our Project Purchase Right.  
 
 
 
 
 
 
 
 
 
 
 
Capacity (MW)
Identified
ROFO Projects
Status
 
Location
 
Construction
Start
(1)
 
Commercial
Operations
(2)
 
Contract
Type
 
Rated (3)
 
Pattern
Development-
Owned
(4)
Armow
Operational
 
Ontario
 
2014
 
2015
 
PPA
 
180

 
90

Meikle
In construction
 
British Columbia
 
2015
 
2016
 
PPA
 
180

 
180

Conejo Solar
In construction
 
Chile
 
2015
 
2016
 
PPA
 
104

 
84

Belle River
Securing final permits
 
Ontario
 
2016
 
2017
 
PPA
 
100

 
50

Henvey Inlet
Late stage development
 
Ontario
 
2016
 
2017
 
PPA
 
300

 
150

Mont Sainte-Marguerite
Late stage development
 
Québec
 
2016
 
2017
 
PPA
 
147

 
147

North Kent
Late stage development
 
Ontario
 
2016
 
2017
 
PPA
 
100

 
43

Broadview projects
Late stage development
 
New Mexico
 
2016
 
2017
 
PPA
 
324

 
259

Grady
Late stage development
 
New Mexico
 
2016
 
2017
 
PPA
 
220

 
176

Tsugaru
Late stage development
 
Japan
 
2015
 
2018
 
PPA
 
126

 
63

Ohorayama
Late stage development
 
Japan
 
2015
 
2017
 
PPA
 
33

 
31

Kanagi Solar
In construction
 
Japan
 
2014
 
2016
 
PPA
 
14

 
6

Futtsu Solar
Operational
 
Japan
 
2014
 
2016
 
PPA
 
42

 
19

 
 
 
 
 
 
 
 
 
 
 
1,870

 
1,298

(1)
Represents date of actual or anticipated commencement of construction.
(2)
Represents date of actual or anticipated commencement of commercial operations.
(3)
Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of wind and other conditions, a project or a turbine will not operate at its rated capacity at all times and the amount of electricity generated may be less than its rated capacity.
(4)
Pattern Development-owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW, multiplied by Pattern Development’s percentage ownership interest in the distributable cash flow of the project.
Our management team will rigorously review and analyze new market opportunities and selectively consider opportunities offered by Pattern Development as well as those offered by other third parties, either independently or jointly with Pattern Development. From time to time, we may submit bids in connection with third party acquisition opportunities, including opportunities to purchase the interests of projects held by our joint venture partners. These bids can be binding bids or non-binding bids, can be for single assets or a group of assets, and (if accepted) can be material acquisitions for us. There can be no assurance any such bids will be accepted.
Completing Our Construction Projects on Schedule and Within Budget
We promote 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. We utilize experienced, creditworthy contractors and proven technology to build high-quality power projects. In 2015, we completed construction at two construction projects which increased our owned capacity by 280 MW, for an aggregate of 2,282 MW together with our other operating projects.
Maintaining a Prudent Capital Structure and Financial Flexibility
We intend to maintain a conservative approach to our capital structure to protect our ability to pay regular dividends and fund investments to provide for future growth. Power projects by their nature require significant upfront capital investment and as a result we believe it prudent to match these long-lived assets with long-term debt and/or equity. The average maturity of our project-level term debt is approximately 12 years, although our scheduled loan amortization is typically 18 years or more, and we have an expected average annual debt service coverage ratio over the remaining scheduled loan amortization periods of more than 1.7 to 1.0. This prudent capital structure coupled with our predictable price for our electricity and our standard operations and maintenance programs help to achieve a stable cash flow profile.
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

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consideration of project-level financial restructuring and recapitalization opportunities, will contribute to our ability to maintain and, over time, increase our cash available for distribution.
Working Closely With Our Stakeholders
We believe that close working relationships with our various stakeholders, including suppliers, power sales agreement counterparties, regulators, the local communities where we are located and environmental organizations and with Pattern Development and other developers enable us to best support our existing projects and will help us access attractive, construction-ready projects.
Employee Transfer of Pattern Development Employees
In 2015, we amended our Management Services Agreement with Pattern Development to change the terms upon which the employees of Pattern Development will become our employees. We refer to this event as the employee transfer. The employee transfer is no longer conditioned upon our achievement of $2.5 billion in market capitalization. Instead, we have the option, exercisable at any time until January 1, 2017, to require the employee transfer to occur. We will not be required to make any payments to Pattern Development upon the occurrence of the employee transfer, other than the payment of any statutory severance payments that may as a result be due and payable to employees in certain jurisdictions outside the United States. The employee transfer will result in our complete internalization of the administrative, technical and other services that were initially provided to us by Pattern Development under the Management Services Agreement. The occurrence of the employee transfer will neither alter our Purchase Rights nor the terms of the Management Services Agreement.
Upon the employee transfer, we expect that our principal focus will continue to be owning operational and under-construction power projects. However, the employee transfer is expected to enhance our long-term ability to independently develop projects and grow our business. Following the employee transfer, we will continue to provide management and other services to Pattern Development (including services from the reintegrated departments of Pattern Development) to the extent required by Pattern Development’s remaining development activities, and Pattern Development will continue to pay us for those services primarily on a cost reimbursement basis.
Competitive Strengths
We believe our key competitive strengths include:
Our High-Quality Projects
We believe our high-quality projects are better positioned to generate stable long-term cash flows compared to typical projects in the industry and will generate available cash in excess of our initial dividend level, providing us the financial resources for investing in new opportunities. Having high-quality projects also provides us access to low-cost project-level debt and strong stakeholder relationships. The key attributes and strengths of our projects are:
Long-Term, Fixed-Price Power Sale Agreements . We believe our long-term, fixed-price power sale agreements with 14 distinct creditworthy counterparties will deliver stable long-term revenues, although we note that the credit rating of the Puerto Rico Electric Power Authority, or "PREPA," counterparty to our Santa Isabel project’s PPA, was downgraded a number of times in each of 2014 and 2015. Our power sale agreements cover 89% of the electricity to be generated across our projects with a weighted average remaining contract life of approximately 14 years.
Geographically Diverse Markets and Wind Regimes . Our geographically diverse projects are located across regions generally characterized by high demand for renewable energy, documented reliable wind resources, deregulated energy markets and favorable renewable energy policies. The geographic diversity of our projects—from California to Puerto Rico, and Manitoba to Chile—helps insulate us against regional wind fluctuations as well as the possibility of adverse regulatory conditions in any one jurisdiction.
State-of-the-Art Wind Turbine Technologies. Our projects utilize state-of-the-art, proven, reliable wind turbine technologies. Our projects utilize Siemens 2.3 MW, Mitsubishi MWT95/2.4, General Electric 1.5-82.5 and 1.85-87 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 age of approximately three years.

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Our Strong Reputation in the Industry
We believe the success of our team has created a highly respected organization which attracts talented people and new opportunities. Our integrity, expertise, and solutions-oriented approach is attractive to stakeholders and parties providing services to our existing projects as well as those who are looking for buyers of their assets.
In 2015, the Conejo Solar project, which is on our list of identified ROFO projects, won the Chilean International Renewable Energy Congress's ("CIREC") "Latin American Renewables Deal of the Year". In 2013, our Ocotillo project received an award for its outstanding environmental analysis and documentation from the California Association of Environmental Professionals and also received the Renewable Project Finance Deal of the Year award from Power Finance & Risk published by Power Intelligence. 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 CIREC's 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).
Our Approach to Project Selection
Our approach to project selection aims to deliver superior financial results and minimize long-term operating risks by focusing on the acquisition of projects that are operational or construction-ready and have long-term power sales agreements with creditworthy counterparties. Once we identify an attractive opportunity, we apply rigorous analysis in a timely, disciplined and functionally integrated manner to evaluate the wind regime, technology options, site design improvement, regional market trends and regulatory, financial and legal constraints. The most attractive projects offer the proper combination of land accessibility, power transmission capacity, attractive power sales markets and favorable and dependable winds. We believe the members of our management team are recognized by their industry peers as skilled in identifying, analyzing and executing successful power project acquisitions.
Our approach to project selection has also enabled us to successfully execute new projects in a complex renewable energy market characterized by economic, political and regulatory changes that affect energy investment opportunities. Examples include the cyclical nature of U.S. federal incentives and the challenge of realizing the full value of these incentives, volatility in the equity markets, increasing environmental and permitting concerns, reduced PPA opportunities that are influenced by changing power markets, a cyclical wind turbine supply environment that alternates between tight and loose supply constraints, changes in wind turbine technology, changes in availability of debt markets, and changes in electricity market structure. Our management team has had success in identifying and executing attractive acquisitions through all of these changing circumstances. For example, through our innovative approach to our business, we developed a financial structure to realize value for PTCs, implemented ground-breaking radar technology to protect bird and bat populations, became one of the first IPPs to capture value from a number of newly deregulated markets and found long-term debt solutions even when the debt markets were highly constrained.
As a fundamental principle, we seek to acquire projects that will contribute measurable improvements in our adjusted EBITDA and our cash available for distribution and that will have a risk profile consistent with our current business objectives. In addition, we view projects as long-term partnerships with all stakeholders, and the benefits that we pledge to the community are fundamental to creating a positive environment for a project’s long-term success.
Our Relationship with Pattern Development
Our continuing relationship with Pattern Development, for which Pattern Energy's ownership interest is 23%, provides us with access to a pipeline of acquisition opportunities. We believe Pattern Development’s ownership position in our company incentivizes Pattern Development to support the successful execution of our objectives and business strategy, including through the preparation of projects to the stage where they are at least construction-ready. We believe Pattern Development’s focus on project development combined with our Project Purchase Right will complement our acquisition strategy, which focuses on the identification and acquisition of operational and construction-ready power projects.
Organization of Our Business
Our business is organized around our current projects. In the future, we expect that our business will include additional operating and construction-ready projects acquired from Pattern Development and other third parties. In addition to our executive officers, we employ 116 full-time staff in key functional areas associated with construction and engineering, operations and maintenance, and commercial management. We rely on some services to be performed by third parties, including Pattern Development, but have all the core functions required for the overseeing of constructing, operating and managing our projects.

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Operations and Maintenance
Our operations team’s objective is to maximize revenues from each of our projects. In order for us to maximize our revenues, we seek to operate and maintain our equipment so that we can ensure our equipment is productive during times of optimal wind resources and power prices. Our approach to achieving efficient operations involves the following key strategic objectives:  
Safety . We believe that the safety of our workers, our contractors, our visitors and the community is paramount and takes precedence over all other aspects of operations. We demonstrate this through promoting a strong safety culture, implementing a formal safety management program, employing a full time in-house safety organization and conducting annual site safety audits.
Equipment reliability and fleet management . We have selected high-quality equipment with a goal of having a concentration of equipment from top manufacturers. We employ the Siemens 2.3 MW turbine at 12 of our 16 project sites, the Mitsubishi MWT95/2.4 at one site, the General Electric 1.5-82.5 at two sites and the General Electric 1.85-87 at the remaining site. With a combination of high-quality equipment and scale, we have structured our fleet such that we may:
expect high availability and long-term production from the equipment;
continue developing operating expertise and experience, which can be shared among our operators;
obtain a high level of attention and focus from the manufacturer; and
maintain a shared spare parts inventory and common operating practices.
Long-term service and maintenance . Good operating performance begins with a long-term maintenance approach to the equipment. While approximately 75% of our operating turbine units remain under original or extended warranty, on-going maintenance and replacement of parts is essential to equipment longevity. All of our wind turbines are managed either under service or warranty agreements that ensure regular repair and replacement of parts.
Inspection . As our warranty contracts and service arrangements expire, we conduct extensive third-party end of warranty inspections to identify any potential equipment or service issues which can be remedied by the manufacturer pursuant to their contractual obligations under the warranty and ensure the projects start their post-warranty periods with reliably functioning equipment.
Staff training . We employ highly experienced personnel from a variety of power generation sectors. In addition, we bring into the organization a broad base of best industry practices. After hiring, we provide our operators with on-going training, in-house and from manufacturers and from third parties, to keep them current on latest industry practices and experiences.
Focus on our value-added capabilities . In order to maximize efficiencies, we concentrate our resources on our core operating areas. In particular, we believe it is critical to have on-site management personnel that are our employees and provide oversight of all site activities to ensure our safety and financial objectives have priority. We contract with third parties, often the turbine manufacturer, for on-going major maintenance of the turbines and similar specialized services such as repairs on our substations or transmission lines.
Maximize structural efficiencies . Our operating resources are allocated across three key areas, site operations, our 24/7 OCC and other central support services.
Site-operators . All of our projects have our employees as on-site operators, which allows for direct management of the projects and all contractors working on site. In addition, these individuals also strive for a high level of involvement in the communities we serve, including with respect to our power purchasers, the regulatory agencies and local communities. Each of our projects has the latest, state-of-the-art supervisory control and data acquisition systems that help us efficiently assess operating faults and plan preventative maintenance.
24/7 Operations Control Center. Our OCC, located in Houston, Texas, focuses on monitoring and controlling each of our wind turbines to prevent downtime, monitoring regional and local climate, tracking real time market prices and, for some of our projects, monitoring certain environmental activities. In addition, the OCC supports various other central activities such as safety, power marketing, and regulatory compliance, and it maintains constant communications with each of our site operators, which frees our site operators to concentrate on day-to-day equipment and safety activities.
Central Support Services. In addition to our OCC, our Houston office also hosts the balance of our operations organization which provides critical support to the operating projects. This team includes our operations

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management team and specialists in safety, environmental management, regulatory compliance, contract management, turbine specialists and asset administration.
Equipment improvements . We believe that our foundation of reliable and proven equipment allows us to make further operating improvements over time. For example, in 2015, we implemented certain control upgrades and blade modifications at our Post Rock and Lost Creek sites. We are also in continuing discussions with the turbine manufacturers and other innovative suppliers regarding new technologies to identify additional promising solutions which will improve our projects’ performance and increase our electricity generation.
Commercial Management
Our commercial management group is tasked with protecting the long-term value of our projects’ commercial arrangements. We have adopted a commercial strategy of managing our projects and other assets with an in-house commercial management group acting as "owners’ representatives." The role of the commercial management group is to oversee contract management, environmental management, community relations, power marketing and finance and to closely monitor the performance of each project from an owner’s point of view in order to maximize financial performance and minimize risk. Although the commercial management group manages the day-to-day aspects of commercial management, functional and managerial expertise is often brought in to support key areas such as legal, finance and power marketing.  
Contract Management . With a group of seasoned managers, our commercial management group optimizes the commercial performance of our assets, services the project debt, manages project agreements and compliance with relevant laws, regulations and rules and has ultimate responsibility for the financial performance of each project. The team also manages our real estate obligations as well as our corporate insurance program, local government obligations, home office, remote facilities and mobile assets. Our commercial management group also facilitates a seamless transfer of responsibilities from the development team through construction to commercial operations in order to ensure all contractual and regulatory obligations are clearly captured and tracked in a formal compliance program.
Environmental Management and Community Relations. Adaptive environmental management is increasingly the standard by which power projects are managed. Our company has been a leader in adopting strategies to minimize environmental impacts, such as bird and bat fatalities. Each project has different circumstances so our environmental and community programs range from hiring of local personnel and historical preservation to use of advanced radar systems to monitor birds and bats and presence of on-site biologists to assist in species recognition and mitigation management. By proactively addressing the concerns of the regions, our environmental management and community relations programs seek to minimize additional costs and burdens from a potential increase in regulations or law suits.
Power Marketing. A crucial element of a successful project is assuring revenue from the sale of power and other environmental attributes. We manage the risk associated with fluctuations in electricity prices across our business by seeking to commit the electricity we generate under long-term, fixed-price power sale agreements. Our uncontracted power and renewable attributes are sold in the spot-market or under shorter term contracts to optimize revenue realization. We believe this management philosophy will result in a steady, predictable source of revenue for each of our projects.
Finance. Our projects are typically funded with construction financing during the construction phase which converts to long-term financing when the project commences commercial operations. Debt at each individual project is project financed, which means that, with very limited exceptions, the lenders have no or only limited recourse to other assets of the company other than the assets that are being financed. Debt for our projects is typically provided by commercial banks and institutional lenders that have the expertise to evaluate the risks associated with the construction and operation of a wind power project, including evaluation of the equipment technology, construction, operations and wind resources. These lenders provide construction financing for many sizable industrial and infrastructure projects. Since debt comprises a significant portion of total project capitalization, achievement of construction financing is a general indication that lenders and their independent consultants have carefully evaluated the project and find it viable for long-term financing. Given the complexity involved in financing large infrastructure assets, projects are often completed with a syndicate of lenders, and the credibility we have established among the financial community allows lenders to have confidence in the quality of our projects and enables us to secure competitive financing terms and other financing efficiencies for our projects. Over the years, our team has developed close relationships with many of the active renewable energy lenders.
Engineering and Construction
The key leadership in our engineering and construction group resides within our company, which provides us with the in-house capabilities required to evaluate and manage a project’s design and construction processes. We will rely as necessary upon

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additional personnel from third-party sources and Pattern Development with respect to the construction of our projects. We also typically enter into fixed-price construction contracts for our projects’ 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. Pattern Development 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 on budget completion of construction of 35 wind power projects over the last 13 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.
Investing
We are organized in a manner that will allow us to independently and comprehensively evaluate investments in new projects. Key members of our management team, including Messrs. Garland, Armistead, Elkort, Lyon, and Pedersen, have spent extensive periods of their careers in the investment advisory, principal investment and finance fields.
As a major part of our growth strategy, we intend to seek to acquire projects that would contribute measurable amounts to our cash available for distribution and adjusted EBITDA. Our approach to project selection is focused on projects (i) with strong economics that will support our long-term financial goals, as determined by intensive analysis and in-depth due diligence, (ii) in which we can add value and which have characteristics that are strategically compatible with our other projects and overall business, and (iii) which meet our core values, including our commitments to environmental stewardship and being a good neighbor in the communities in which our projects are located. To achieve proper investment management, we have implemented processes to ensure rigorous analysis and proper internal approval controls, including preparing formal investment approval documentation, maintaining strict limits on delegation of authority for making capital commitments, and vetting our assumptions with independent technical experts and advisors.
Competition
We compete with other wind power, infrastructure funds and renewable energy companies, as well as conventional power companies, to acquire profitable construction-ready and operating projects. In addition, competitive conditions may be substantially affected by various forms of energy legislation and regulation considered from time to time by federal, state, provincial and local legislatures and administrative agencies.

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Suppliers
There are a limited number of turbine suppliers and, although demand for turbines in the past has generally been high relative to manufacturing capacity, we believe that current turbine manufacturing capacity is adequate. Our turbine supply strategy is largely based on maintaining strong relationships with leading turbine suppliers to secure our supply needs.
Project
Supplier
 
Number of
Turbines
 
Turbine Type
Operating Projects

 

 

Gulf Wind
Mitsubishi
 
118
 
MWT 95/2.4
Hatchet Ridge
Siemens
 
44
 
SWT-2.3-93
St. Joseph
Siemens
 
60
 
SWT-2.3-101
Spring Valley
Siemens
 
66
 
SWT-2.3-101
Santa Isabel
Siemens
 
44
 
SWT-2.3-108
Ocotillo
Siemens
 
112
 
SWT-2.3-108
South Kent
Siemens
 
124
 
SWT-2.3-101
El Arrayán
Siemens
 
50
 
SWT-2.3-101
Panhandle 1
General Electric
 
118
 
1.85 - 87
Panhandle 2
Siemens
 
79
 
SWT-2.3-108
Grand
Siemens
 
67
 
SWT-2.3-101
Post Rock
General Electric
 
134
 
1.5-82.5
Lost Creek
General Electric
 
100
 
1.5-82.5
K2
Siemens
 
140
 
SWT-2.3-101
Logan’s Gap
Siemens
 
87
 
SWT-2.3-108
Amazon Wind Farm Fowler Ridge
Siemens
 
65
 
SWT-2.3-108
To date, our projects listed above have purchased 938 turbines from Siemens. Siemens data indicates that worldwide fleet availability for the 2.3MW turbine class exceeds 97%, and our Siemens fleet availability also exceeded 97% in 2015. Apart from Siemens we have relationships with other reputable turbine manufacturers such as General Electric and Mitsubishi. Some of our future projects may utilize turbines from these and other manufacturers.
Our Ocotillo and Santa Isabel (Siemens) and Gulf Wind (MHI) projects have experienced certain blade failures in the last three years. We believe the Siemens blade failures have been fully addressed through the completion of an agreed inspection and repair program. With respect to MHI, we worked with MHI to complete a root cause analysis, testing of the blades at the Gulf Wind facility, and development of a protocol for determining whether a blade might pose a threat to long-term reliable operation. We reached in November 2015 a long term arrangement with MHI to address potential deficiencies and, if applicable, mitigation for lost revenue resulting from blade downtime at the facility. We believe that this agreement and mitigation strategy provide adequate technical and commercial protections to the project to mitigate the impacts of this issue, but can give no assurance that additional issues will not arise for which these measures prove inadequate.
Other important suppliers include engineering and construction companies, such as M. A. Mortenson Company, RES-Americas and Blattner Energy, Inc., with whom we contract to perform civil engineering, electrical work and other infrastructure construction for our projects.
We currently depend on service providers to provide maintenance services to our project equipment. These services are currently provided by the turbine manufacturers, such as Siemens or General Electric, at most of our project sites. We believe there are currently adequate independent service provider alternatives to the turbine manufacturers to meet our needs, and in some cases we do utilize such alternative providers.
Customers
We sell our electricity and RECs, primarily to local utilities under long-term, fixed-price PPAs or, in limited instances, local liquid ISO markets. For the year ended December 31, 2015 , the significant customer representing greater than 10% of total revenue was San Diego Gas & Electric ("SDG&E"), which accounted for 17% of our total revenue.
Hedging Activity

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From time to time, we enter into hedges to manage our business exposure to commodity, foreign exchange rate and interest rate risks. In doing so, our hedging strategy is generally focused on reducing potential changes to key business drivers such as power prices, interest rates and changes in income from overseas investments.
Most of our revenue is subject to long-term PPAs. To the extent that PPAs are not available in a given market, but market prices allow for acceptable project economics, we will enter into hedging agreements to obtain a fixed price for the energy output of our projects, typically by hedging volumes that are expected to be exceeded 99.0% of the time. Those hedging agreements are executed for a monthly or hourly production profile that matches the forecasted production profile of the project. On an overnight basis, we will also consider hedging agreements beyond the initial volume up to an amount that is expected to be exceeded over half the time.
Most of our interest rate exposure is hedged either through fixed-rate debt arrangements or hedging of floating rate loans. We enter into interest rate hedging agreements to convert floating-rate debt to fixed-rate debt for some of our projects, usually at the time we close construction or term financing of a project. We also monitor our corporate-level interest rate exposure and may, from time to time, enter into interest rate hedges in order to mitigate our exposure.
In 2015, we initiated 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, see Item 7A "Quantitative and Qualitative Disclosure about Market Risk."

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Structure of Our Company
(1)
These funds and these employees hold indirect interests in Pattern Development.
(2)
Subsequent to our issuance of shares and the sale of certain of our shares held by Pattern Development during 2015, Pattern Development’s ownership interest in us was reduced to approximately 23%, while public and management ownership increased to approximately 77%.

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Employees
As of December 31, 2015 , we had 116 full-time employees of whom 32 are based in our corporate headquarters, 46 are based at our project sites and 38 are based at our other offices, including our OCC, in Houston, Texas. None of our employees are represented by a labor union or covered by any collective bargaining agreement.
Insurance
We maintain insurance on terms generally carried by companies engaged in similar business and owning similar properties in the United States, Canada and Chile and whose projects are financed in a manner similar to 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 war risk 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; workers’ compensation and employer’s liability insurance; and (except in Chile) title insurance. The "all risk" property insurance coverage is currently maintained in amounts based on the full replacement value of our projects (subject to certain sub-limits for windstorm, flood, and earthquake risks) and the business interruption insurance generally provides 15 months of coverage in amounts that vary from project to project based on the revenue generation potential of each project. All types of coverage are subject to applicable deductibles. We generally do not maintain insurance for certain environmental risks, such as environmental contamination.
Industry
Wind power has been one of the fastest growing sources of electricity generation in North America and globally over the past decade. According to the Global Wind Energy Council, or "GWEC," from 2001 through 2013, total net electricity generation from wind power in the United States and Canada grew at a combined annual growth rate 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 energy security and environmental concerns. 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 largest producer of wind power in the world. According to AWEA, wind power was the largest source of new electricity generating capacity in the U.S. in 2015, accounting for more than 35% of new generation. Wind power was the first or second largest source of new generating capacity in the United States for seven of the eight years between 2005 and 2012, according to the U.S Department of Energy and AWEA. According to AWEA, wind power became the leading source of new electricity generating capacity in the United States for the first time in 2012. The American wind energy industry installed 8,598 MW in 2015 and 4,854 MW in 2014 and the U.S. now has an installed wind capacity of 74,472 MW with over 9,400 MW of wind currently under construction across 22 states. The success of wind power in the United States is evidenced by over $120.0 billion in investments to date, according to AWEA.
Renewable energy sources in the United States have benefited from various federal and state governmental incentives, such as production tax credits and investment tax credits. Production tax credits and investment tax credits for wind energy on the federal level were extended in December of 2015, under the Consolidated Appropriations Act. The Act extended the expiration date for tax credits for wind facilities commencing construction, with a five year phase-down beginning for wind projects commencing construction after December 31, 2016. The Act also applies retroactively to January 1, 2015. In addition to an extension of the production tax credits, in August 2015, President Obama and the Environmental Protection Agency announced the Clean Power Plan, or "CPP," a key step in reducing carbon pollution from power plants which is designed to strengthen the fast-growing trend toward cleaner and lower-emitting power plants. The CPP is expected to reduce carbon dioxide emissions from power plants to 32% below 2005 levels by 2030. For each state, the CPP rules will establish a target emissions rate, or the amount of carbon dioxide that could be emitted per megawatt-hour of power produced and states are expected to start working toward interim emissions goals beginning in 2022. Depending on how the rule is implemented, it could drive demand for up to 100 GW of new wind energy by 2030 according to AWEA. However, in February 2016, the U.S. Supreme Court issued a stay prohibiting the implementation of the CPP pending a challenge to the CPP before a U.S. Court of Appeals.
The Canadian wind power industry has also experienced dramatic growth in recent years. Canada gained 1,505 MW in 2015, and 1,416 MW in 2014 of new installed wind power generating capacity. This investment resulted in wind power generating capacity in Canada reaching approximately 11,205 MW as of December 2015. According to the Canadian Wind Energy Association, or

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"CanWEA," new installed wind power generating capacity is expected to average 1,500 MW annually over the next three years. Ontario, one of our markets, is the national leader in installed capacity, with approximately 4.4 GW of wind power generating capacity at the close of 2015, although recent changes to the Ontario government feed-in tariff, or "FIT," regime may make future projects less attractive and power purchase agreements more difficult to obtain. CanWEA forecasts total wind power generating capacity in Canada to exceed 12 GW at the end of 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. 2014 was a strong year for Chilean wind development, with the country’s new installed capacity reaching 506 MW, which is nearly four times the previous record of 130 MW set in 2013, according to the state-run Renewable Energy Centre. That brought the country’s total wind power capacity to 836 MW. Wind now supplies approximately 2% of the country’s electricity demand.
In June 2015, we added three Japanese wind projects and two Japanese solar projects to our list of Identified ROFO Projects. Following the nuclear meltdown at the Fukushima Daiichi plant in 2011, the Japanese government has placed a greater emphasis on the development of renewable resources in order to reduce its reliance on nuclear power, having released its Innovative Strategy for Energy and the Environment in September 2012. By 2030, the plan calls for renewable power generation to triple compared to 2010, reaching about 30% of total generation. In 2012, Japan also introduced a FIT program that offers fixed-term, fixed-price contracts (up to 20 years) to renewable power projects. The tariff will be re-assessed every year based on the latest market experience in Japan. At the end of 2014, 2,789 MW of wind capacity was operating in Japan. This accounted for approximately 1% of the total power supply in 2014.
Although the Company does not yet have assets or Identified ROFO Projects in Mexico, it is a key potential market for us as Pattern Development is actively working in the country and we expect to add Mexican projects to the Identified ROFO Projects list in the future. Mexico’s Congress has enacted sweeping reforms to its electric generation industry in recent years, opening new opportunities for private investment in generation and creating a mandate to obtain at least 35% of its generation from clean sources by 2024. High prices and strong load growth were key factors in encouraging the reforms, and Mexico’s SENER (Secretaria de Energia) has published rules for interconnection and a new market-oriented regime. Mexico has substantial wind and solar resources, and thus far has only developed less than two thousand megawatts of wind generation under the pre-reform system. It is anticipated by the Mexican Wind Energy Association (Asociación Mexicana de Energía Eólica) that several thousand megawatts of wind generation will be developed over the next few years. During 2014, Mexico added 634 MW of new wind power to the country’s electricity grid bringing the total capacity to 2,551 MW.
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 Pattern Development and other third parties.
While we currently operate primarily in wind power markets, we expect to continue to evaluate other types of independent power projects for possible acquisition, including renewable energy projects other than wind power projects and non-renewable energy projects. In September 2014, we announced the addition of our first solar project, the 104 MW Conejo Solar photovoltaic power project in Chile, to our list of Identified ROFO, and in June 2015, we added two Japanese solar projects to that list.
Regulatory Matters
Environmental Regulation
We are subject to various environmental, health and safety laws and regulations in each of the jurisdictions in which we operate. These laws and regulations require us to obtain and maintain permits and approvals, undergo environmental review processes and implement environmental, health and safety programs and procedures to monitor and control risks associated with the siting, construction, operation and decommissioning of wind power projects, all of which involve a significant investment of time and can be expensive.
We incur costs in the ordinary course of business to comply with these laws, regulations and permit requirements. We do not anticipate material unplanned 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

21




issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property or for injunctive relief have been brought and may in the future result from environmental and other impacts of our activities.
Environmental Permitting—United States
We are required to obtain from U.S. federal, state and local governmental authorities a range of environmental permits and other approvals to build and operate our projects, including, but not limited to, those described below. In addition to being subject to these regulatory requirements, we could experience and have experienced significant opposition from third parties when we initially apply for permits or when there is an appeal proceeding after permits are issued. The delay or denial of a permit or the imposition of conditions that are costly or difficult to comply with can impair or even prevent the development of a project or can increase the cost so substantially that the project is no longer attractive to us.
Federal Clean Water Act
Frequently, our U.S. projects are located near wetlands, and we are required to obtain permits under the U.S. Clean Water Act from the U.S. Army Corps of Engineers, or the "Army Corps," for the discharge of dredged or fill material into waters of the United States, including wetlands and streams. The Army Corps may also require us to mitigate any loss of wetland functions and values that accompanies our activities. In addition, we are required to obtain permits under the Clean Water Act for water discharges, such as storm water runoff associated with construction activities, and to follow a variety of best management practices to ensure that water quality is protected and impacts are minimized. Certain activities, such as installing a power line across a navigable river, may also require permits under the Rivers and Harbors Appropriation Act of 1899.
Federal Bureau of Land Management Permits
As some of our U.S. projects are located on lands administered by the Bureau of Land Management, we are required to obtain rights-of-way from the Bureau of Land Management. The Bureau of Land Management encourages the development of wind power within acceptable areas, consistent with Environmental Policy Act of 2005 and the Bureau of Land Management’s energy and mineral policy. Obtaining a grant requires that the proposed project prepare a plan of development and demonstrate that it will adhere to the Bureau of Land Management’s best management practices for wind power development, including meeting criteria for protecting biological, archaeological and cultural resources.
National Environmental Policy Act and Endangered Species Requirements
Our U.S. projects may also be subject to environmental review under the U.S. National Environmental Policy Act, or "NEPA," which requires federal agencies to evaluate the environmental impact of all "major federal actions" significantly affecting the quality of the human environment. The granting of a land lease, a federal permit or similar authorization for a major development project, or the interconnection of a significant private project into a federal project generally is considered a "major federal action" that requires review under NEPA. As part of the NEPA review, the federal agency considers a broad array of environmental impacts, including impacts on air quality, water quality, wildlife, historical and archaeological resources, geology, socioeconomics and aesthetics and alternatives to the project. The NEPA review process, especially if it involves preparing a full Environmental Impact Statement, can be time-consuming and expensive. A federal agency may decide to deny a permit based on its environmental review under NEPA, though in most cases a project would be redesigned to reduce impacts or agree to provide some form of mitigation to offset impacts before a denial is issued.
Federal agencies granting permits for our U.S. projects also consider the impact on endangered and threatened species and their habitat under the U.S. Endangered Species Act, which prohibits and imposes stringent penalties for harming endangered or threatened species and their habitats. Our projects also need to consider the Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act, which protect migratory birds and bald and golden eagles and are administered by the U.S. Fish and Wildlife Service. Most states also have similar laws. Because the operation of wind turbines may result in injury or fatalities to birds and bats, federal and state agencies often recommend or require that we conduct avian and bat risk assessments prior to issuing permits for our projects. They may also require ongoing monitoring or mitigation activities as a condition to approving a project. In addition, U.S. federal agencies consider a project’s impact on historical or archeological resources under the U.S. National Historic Preservation Act and may require us to conduct archeological surveys or take other measures to protect these resources. Among other things, the National Historic Preservation Act requires federal agencies to evaluate the impact of all federally funded or permitted projects on historic properties (buildings, archaeological sites, etc.) through a process known as " Section 106 Review."

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Other State and Local Programs
In addition to federal requirements, our U.S. projects, and any future U.S. projects we may acquire, are subject to a variety of state environmental review and permitting requirements. Many states where our projects are located, or may in the future be located, have laws that require state agencies to evaluate a broad array of environmental impacts before granting state permits. The state environmental review process often resembles the federal NEPA process and may be more stringent than the federal review. Our projects also often require state law based permits in addition to federal permits. State agencies evaluate similar issues as federal agencies, including the project’s impact on wildlife, historic sites, aesthetics, wetlands and water resources, agricultural operations and scenic areas. States may impose different or additional monitoring or mitigation requirements than federal agencies. Additional approvals may be required for specific aspects of a project, such as stream or wetland crossings, impacts to designated significant wildlife habitats, storm water management and highway department authorizations for oversize loads and state road closings during construction. Permitting requirements related to transmission lines may be required in certain cases.
Our projects also are subject to local environmental and regulatory requirements, including county and municipal land use, zoning, building and transportation requirements. Permitting at the local municipal or county level often consists of obtaining a special use or conditional use permit under a land use ordinance or code, or, in some cases, rezoning in connection with the project. Obtaining a permit usually depends on our demonstrating that the project will conform to development standards specified under the ordinance so that the project is compatible with existing land uses and protects natural and human environments. Local or state regulatory agencies may require modeling and measurement of permissible sound levels in connection with the permitting and approval of our projects. Local or state agencies also may require us to develop decommissioning plans for dismantling the project at the end of its functional life and establish financial assurances for carrying out the decommissioning plan.
Environmental Permitting—Canada
We are required to obtain from Canadian federal, provincial and local governmental authorities a range of environmental permits and other approvals to build and operate our Canadian projects, including, but not limited to, those described below. In addition to being subject to these regulatory requirements, we could experience and have experienced significant opposition from third parties, including, but not limited to, environmental non-governmental organizations, neighborhood groups, municipalities and First Nations when the permits were initially applied for or when there is an appeal proceeding after permits are issued. The delay or denial of a permit or the imposition of conditions that are costly or difficult to comply with can impair or even prevent the development of a project or can increase the cost so substantially that the project is no longer attractive to us.
Ontario Renewable Energy Approvals
Our projects in Ontario are subject to Ontario’s Environmental Protection Act , which requires proponents of significant renewable energy projects to obtain a Renewable Energy Approval, or "REA." The REA application requires a variety of studies on environmental, archeological and heritage issues. Significant public consultation, as well as consultation with indigenous communities, is also required. Before issuing a REA, the Ontario Ministry of the Environment evaluates a broad range of potential impacts, including on wildlife, wetlands and water resources, communities, scenic areas, species and heritage resources, as well as impacts on people. This review can be time consuming and expensive, and an approval can be rejected or approved with conditions that are costly or difficult to comply with. REAs are also subject to appeal by third parties and can result and have resulted in lengthy appeal tribunal hearings.
The Henvey Inlet Wind Identified ROFO Project is located within Henvey Inlet Reserve No. 2, a reserve held by Her Majesty the Queen in right of Canada for the benefit of Henvey Inlet First Nation, and since the REA process is not directly applicable to Reserve lands, the project will be subject to an environmental assessment and protection regime adopted and enforced by the Henvey Inlet First Nation, acting through its elected Band Council. The Band Council has legal authority to enact and enforce land laws, including this regime, pursuant to relevant codes, acts, agreements and legislation. The foregoing legal regime provides Henvey Inlet First Nation with control and management of the Reserve for the purposes of the enactment of the applicable environmental regime, and the granting of a lease of portions of the Reserve for the purposes of the project. The risks and obligations of the foregoing permitting and enforcement regime are similar in substance to those which exist under the REA process.
Quebec Environmental Impact Assessment
Our Identified ROFO Project in Quebec (Mont Sainte-Marguerite) is subject to Quebec`s Environmental Impact Assessment, or "EIA," which is a required permit for wind energy projects with a nameplate capacity above 10 MW. The EIA requires a variety of studies related to environmental, archeological and heritage issues. Significant public consultation, as well as consultation with indigenous communities, is also required. The culmination of this permitting process is the issuing of a project specific decree by

23




the provincial council of ministers. Before issuing the decree, the Quebec Ministry of Environment evaluates a broad range of potential impacts, including on wildlife, wetlands and water resources, communities, scenic areas, species and heritage resources, as well as impacts on people. Within the EIA process, there is the possibility that a formal public hearing takes place. This public hearing is conducted by an independent commission called the BAPE (Public Audience Bureau on the Environment). This hearing can be triggered by private citizens, public interest groups, or any other interested parties. The BAPE hearing will add four additional months to the permitting schedule. For large industrial projects, the calling of this hearing is the norm.
Quebec Commission for the Protection of Agricultural Land
In addition to the EIA process, the other major permit in Quebec is granted by the Quebec Commission for the Protection of Agricultural Land, or "CPTAQ." This permit is only required on land that is zoned agricultural. This encompasses traditional grain farming land, as well as commercial forestry land. This permitting body will push proponents to minimize footprints during both the construction phase and the operations phase. The CPTAQ is an independent commission from the agricultural ministry.
Manitoba Environment Act
The Manitoba Environment Act requires proponents of significant projects to submit a proposal with the Manitoba Conservation Environmental Assessment & Licensing Branch, and to comply with Manitoba’s environmental assessment process under the Environment Act . This process will consider a similar range of impacts on the environment, the heritage and scenic values of an area and on people, communities and wildlife as the Ontario process, and brings with it similar risks.
Endangered Species Legislation
Our Canadian renewable energy projects may be subject to endangered species legislation, either federally or provincially, which prohibits and imposes stringent penalties for harming endangered or threatened species and their habitats. Our projects may also be subject to the Migratory Birds Convention Act , which protects the habitat of migratory species, and which may also trigger federal "Species at Risk" requirements. Because the operation of wind turbines may result in injury or fatalities to birds and bats, avian and bat risk assessments are generally required both prior to permits being issued for projects and after commercial operations. In Ontario, if any of the affected species are listed as endangered or threatened, permits under the Endangered Species Act may also be required.
Other Approvals
Our Canadian projects, and any future projects we may acquire, are subject to a variety of other federal, provincial and municipal permitting and zoning requirements. Most provinces where our projects are located or may be located have laws that require provincial agencies to evaluate a broad array of environmental impacts before granting permits and approvals. These agencies evaluate similar issues as the permitting regimes above, including impact on wildlife, historic sites, 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.
Environmental Permitting – Chile
Ministry of Environment, Environmental Assessment Service and Superintendency of Environment
The Ministry of the Environment, the Environmental Assessment Service and the Superintendency of Environment are primarily responsible for environmental issues in Chile, including those affecting the wind industry. The Ministry of the Environment is responsible for the formulation and implementation of environmental policies, plans and programs, as well as for the formulation of environmental quality and emission standards, the protection and conservation of biological diversity, renewable natural resources and water resources, and for promoting sustainable development and the integrity of environmental policy and regulations. The Environmental Assessment Service is responsible for assessing whether projects that might have an adverse effect on the environment, including wind projects, comply with Chilean environmental laws and regulations. The Environmental Assessment Service coordinates the environmental impact assessment process, whose final qualifications are granted by the competent regional Environmental Assessment Commission. The Superintendency of the Environment’s primary responsibilities are monitoring compliance with the terms of the corresponding environmental licenses, as well as monitoring compliance with

24




government plans to prevent environmental damage or to clean or restore contaminated geographical areas. The Superintendency of the Environment has the power to suspend activities that it deems to have an adverse environmental impact, even if such activities comply with a previously approved environmental impact assessment. In case of noncompliance with environmental regulations, it is enabled to apply fines, revoke the environmental license of a project or determine its closure.
The Environmental Courts, and Health and Safety
The Environmental Courts are principally responsible for hearing appeals of determinations made by the Superintendency of the Environment and for adjudicating claims for environmental damage.
Companies in the wind energy sector, like all companies, must comply with the general principles concerning employee health and safety contained in the Chilean Sanitary Code, Labor Code and other labor and health regulations. The Chilean Health Ministry and the Department of Labor are responsible for the enforcement of those standards, with the authority to impose fines among other sanctions. In addition, the Superintendence of Electricity and Fuels has the responsibility to monitor compliance and also the authority to impose fines and stop operations of violators.
Management, Disposal and Remediation of Hazardous Substances
We own and lease real property and may be subject to requirements regarding the storage, use and disposal of petroleum products and hazardous substances, including spill prevention, control and counter-measure requirements. If our owned or leased properties are contaminated, whether during or prior to our ownership or operation, we could be responsible for the costs of investigation and cleanup and for any related liabilities, including claims for damage to property, persons or natural resources. That responsibility may arise even if we were not at fault and did not cause or were not aware of the contamination. In addition, waste we generate is at times sent to third-party disposal facilities. If those facilities become contaminated, we and any other persons who arranged for the disposal or treatment of hazardous substances at those sites may be jointly and severally responsible for the costs of investigation and remediation, as well as for any claims for damage to third parties, their property or natural resources.
Intellectual Property
In September 2014, we exercised our right to acquire the name "Pattern" and the Pattern logo from Pattern Development, and granted to Pattern Development a license to use the name "Pattern" and the Pattern logo. We have registrations and pending applications for registration of marks in the United States, Canada and Chile. We do not own any intellectual property material to the conduct of our business. We also own various information that includes, without limitation, financial, business, scientific, technical, economic, engineering information, formulas, designs, methods, techniques, processes, and procedures, all of which is protected confidential and proprietary information.
Geographic information
The table below provides information about our consolidated operations by country. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located (in thousands):
 
 
Revenue
 
Property, Plant and Equipment, net
(including Construction in Progress)
 
 
Year ended December 31,
 
December 31,
 
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
United States
 
$
258,542

 
$
201,408

 
$
161,505

 
$
2,791,259

 
$
1,810,414

 
$
1,210,319

Canada
 
39,178

 
46,593

 
40,068

 
184,115

 
233,690

 
265,823

Chile
 
32,111

 
17,492

 

 
319,246

 
332,947

 

Total
 
$
329,831

 
$
265,493

 
$
201,573

 
$
3,294,620

 
$
2,377,051

 
$
1,476,142

Available Information
Periodic reports for the Company on Form 10-K and Form 10-Q and current reports on Form 8-K are made available to the public, free of charge, on the Company's website (www.patternenergy.com) through links on this website to the SEC’s website at www.sec.gov, as soon as reasonably practicable after they have been filed with the SEC. The contents of the above referenced website address are not part of this Form 10-K. The public may also read any copy of materials filed with the SEC by the Company at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the

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Public Reference Room may be obtained by calling the SEC at 1-(800) SEC-0030. Reports, proxy and information statements, and other information regarding the Company may also be obtained directly from the SEC’s website, www.sec.gov. Printed copies of these documents may be obtained free of charge by writing to the Company's Corporate Secretary at Pattern Energy Group Inc., Pier 1, Bay 3, San Francisco, CA 94111.

Item 1A.
Risk Factors.
RISK FACTORS
You should carefully consider the following risks, together with other information provided to you in this Form 10-K. If any of the following risks were to occur, our business, financial condition, results of operations and liquidity could be materially adversely affected. In that case, we might have to decrease, or may not be able to pay, dividends on our Class A shares, the trading price of our Class A shares could decline and you could lose all or part of your investment. The risks described below are not the only risks facing our company. Risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and results of operations and liquidity.
Risks Related to Our Projects
Electricity generated from wind energy depends heavily on suitable wind conditions and wind turbines being available for operation. If wind conditions are unfavorable or below our expectations, or our wind turbines are not available for operation, our projects’ electricity generation and the revenue generated from our projects may be substantially below our expectations.
The revenue generated by our projects is principally dependent on the number of MWh generated in a given time period. The quantity of electricity generation from a wind power project depends heavily on wind conditions, which are variable. Variability in wind conditions can cause our project revenues to vary significantly from period to period. We base our decisions about which projects to acquire as well as our electricity generation estimates, in part, on the findings of long-term wind and other meteorological studies conducted on the project site and its region, which measure the wind’s speed, prevailing direction and seasonal variations. Projections of wind resources also rely upon assumptions about turbine placement, wind turbine power curves, interference between turbines and the effects of vegetation, land use and terrain, which involve uncertainty and require us to exercise considerable judgment. We may make incorrect assumptions in conducting these wind and other meteorological studies. Any of these factors could cause our projects to generate less electricity than we expect and reduce our revenue from electricity sales, which could have a material adverse effect on our business, 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. For example, according to Vaisala, a globally-recognized environmental measurement company with meteorological expertise, average wind conditions across the western United States and Texas were 20% or more below normal for the first quarter of 2015. The low production was primarily the result of unusual weather conditions brought on by particular features of an El Niño weather pattern over the Pacific Ocean. Vaisala stated at the time that the observed weather pattern was nothing unusual or outside of the range of the expected after their review of long term global datasets. The El Niño weather pattern strengthened through 2015, became one of the strongest observed, and had varying effects on our fleet level production during the year based on season. No assurances can be given that there will not continue to be material deviations from average wind resources. A diversified portfolio of projects located in different geographical areas tends to reduce the magnitude of the deviation, but material deviations may still occur. Our cash available for distribution is most directly affected by the volume of electricity generated and sold by our projects. However, for a static portfolio of projects, our consolidated expenses, including operating expenses and interest payments on indebtedness, have less variability than the volume of electricity generated and sold. Accordingly, decreases in the volume of electricity generated and sold by our projects typically result in a proportionately greater decrease in our cash available for distribution. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operation-Factors that Significantly Affect our Business-Factors Affecting our Operational Results-Electricity Sales and Energy Derivative Settlements of Our Operating Project.”
A reduction in electricity generation and sales, whether due to the inaccuracy of wind energy assessments or otherwise, could lead to a number of material adverse consequences for our business, including:
our projects’ failure to produce sufficient electricity to meet our commitments under our PPAs, hedge arrangements or contracts for sale of RECs, which could result in our having to purchase electricity or RECs on the open market to cover our obligations or result in the payment of damages or the termination of a PPA;

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our projects not generating sufficient cash flow to make payments of principal and interest as they become due on project-related debt, or distributing sufficient cash flow to pay dividends to holders of our Class A shares. See “-Risks Related to Ownership of our Class A Shares - Our cash available for distribution to holders of our Class A shares may be reduced as a result of restrictions on our subsidiaries’ cash distributions to us under the terms of their indebtedness;” and
our projects’ hedging arrangements being ineffective or more costly.
Our projects rely on a limited number of key power purchasers. The power purchaser for our Santa Isabel project has been downgraded.
There are a limited number of possible power purchasers for electricity and RECs produced in a given geographic location. Because our projects depend on sales of electricity and RECs to certain key power purchasers, our projects are highly dependent upon these power purchasers fulfilling their contractual obligations under their respective PPAs. Our projects’ power purchasers may not comply with their contractual payment obligations or may become subject to insolvency or liquidation proceedings during the term of the relevant contracts and, in such event, we may not be able to find another purchaser on similar or favorable terms or at all. In addition, we are exposed to the creditworthiness of our power purchasers and there is no guarantee that any power purchaser will maintain its credit rating, if any. 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.
For example, our 101 MW Santa Isabel project located on the south coast of Puerto Rico sells 100% of its electricity generation including environmental attributes to PREPA under a 20-year PPA. PREPA’s credit rating was downgraded multiple times in each of 2014 and 2015. As of February 24, 2016, the credit rating of PREPA was Caa3, CC, and CC by each of Moody’s, Standard & Poor’s, and Fitch, respectively, which ratings are all below investment grade. In addition, in June 2014, Puerto Rico enacted legislation to establish a bankruptcy-like regime for public corporations in Puerto Rico, like PREPA, which were ineligible for relief under U.S. federal bankruptcy laws, to restructure their debt and other obligations. The validity of such legislation was challenged in U.S. federal court, and in 2015 the court declared such legislation unconstitutional, which decision was later confirmed by an appeals court. The Commonwealth of Puerto Rico sought review before the U.S. Supreme Court which agreed to hear the case, and oral argument is expected to take place around March 2016. PREPA has hired a chief restructuring officer to produce a restructuring plan, and entered into a forbearance agreement and multiple extensions with certain of its creditors. PREPA has entered into a restructuring support agreement with certain lenders, bondholders and other parties which would implement a plan that would reduce PREPA’s principal debt burden and provide debt service relief for five years. Legislation called for under the agreement and essential to the successful execution of the plan was approved by the Puerto Rico legislature and enacted into law on February 16, 2016. The final version of the statute approved by the legislature is currently under review by PREPA's creditors. While as of February 29, 2016, PREPA is current with respect to payments due under the PPA, a failure by PREPA to perform its payment obligations under the PPA, a restructuring of its obligations under judicially determined valid legislation, or a failure to consummate the restructuring support agreement may affect its obligations under the PPA which could have a material adverse effect on our business, financial condition and results of operations.
A prolonged environment of low prices for natural gas, other conventional fuel sources, or competing renewable resources could have a material adverse effect on our long-term business prospects, financial condition and results of operations.
Historically low prices for traditional fossil fuels, particularly natural gas, could cause demand for wind power and solar power to decrease and adversely affect 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 11% 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 or competing renewable resources could also have a negative impact on the power prices we are able to negotiate upon the expiration of our current power sale agreements or upon entering into a power sale agreement for a subsequently acquired power project. As a result, the price of our electricity or RECs subject to the open market could be materially and adversely affected, which could, in turn, have a material adverse effect on our results of operations and cash available for distribution. 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.
Operational problems and natural events may cause our electricity generation to fall below our expectations.
Our electricity generation levels depend upon our ability to maintain the working order of our wind turbines and balance of the plant. A natural disaster, severe weather, accident, failure of major equipment, shortage of or inability to acquire critical replacement or spare parts, failure in the operation of any future transmission facilities that we may acquire, including the failure of interconnection to

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available electricity transmission or distribution networks, could damage or require us to shut down our turbines or related equipment and facilities, impeding our ability to maintain and operate our facilities and decreasing electricity generation levels and our revenues. For example, our Ocotillo and Santa Isabel (Siemens) and Gulf Wind (MHI) projects had experienced certain blade failures in 2013 and 2014. We believe the Siemens blade failures have been fully addressed through the completion of an agreed inspection and repair program. With respect to MHI, we worked with MHI to complete a root cause analysis, testing of the blades at the Gulf Wind facility, and development of a protocol for determining whether a blade might pose a threat to long-term reliable operation. While we reached in November 2015 a long term arrangement with MHI to address potential deficiencies and, if applicable, mitigation for lost revenue resulting from blade downtime at the facility, no assurances can be given that potential deficiencies will not in fact continue to occur and result in blade failures, or that any such effects will not have a material adverse effect on our business, financial condition and results of operation.
In addition, replacement and spare parts for wind turbines and key pieces of electrical equipment may be difficult or costly to acquire or may be unavailable. Sources for some significant spare parts and other equipment are often located outside of the jurisdictions in which our power projects operate. Additionally, our operating projects generally do not hold spare substation main transformers. These transformers are designed specifically for each wind power project, and order lead times can be lengthy. If one of our projects had to replace any of its substation main transformers, it would be unable to sell all of its power until a replacement is installed. To the extent we experience a prolonged interruption at one of our operating projects due to natural events or operational problems and such events are not fully covered by insurance, our electricity generation levels and revenues could materially decrease, which could have a material adverse effect on our business, financial condition and results of operation.
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 typically enter into warranty agreements with the turbine manufacturer for two- to ten-year terms, such agreements are typically subject to an aggregate maximum cap and there can be no assurance that the supplier will be able to fulfill its contractual obligations.
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. Stockholders should consider our prospects in light of the risks and uncertainties growing companies encounter in rapidly evolving industries such as ours. Also, our anticipated near-term growth could make it difficult for us to manage our project expansion efficiently due to an inability to employ a sufficient number of skilled personnel or otherwise to effectively manage our capital expenditures and control our costs, including the requisite general and administrative costs necessary to achieve our anticipated growth. These challenges could adversely affect our ability to manage our current or future operating projects in an efficient manner and complete construction of our construction projects in a timely manner, either of which could have a material adverse effect on our business, financial condition and results of operation.
Our operations are subject to numerous environmental, health and safety laws and regulations.
Our projects are subject to numerous environmental, health and safety laws and regulations in each of the jurisdictions in which our projects operate or will operate. These laws and regulations require our projects to obtain and maintain permits and approvals, undergo environmental impact assessments and review processes and implement environmental, health and safety programs and procedures to control risks associated with the siting, construction, operation and decommissioning of power projects. For example, to obtain permits some projects are, in certain cases, required to undertake programs to protect and maintain local endangered or threatened species. If such programs are not successful, our projects could be subject to increased levels of mitigation, penalties or revocation of our permits.
Violations of environmental and other laws, regulations and permit requirements, including certain violations of laws protecting wetlands, migratory birds, bald and golden eagles and threatened or endangered species, may also result in criminal sanctions or injunctions. In addition, if our projects do not comply with applicable laws, regulations or permit requirements, or if there are endangered or threatened species fatalities at our projects, we may be required to pay penalties or fines or curtail or cease operations of the affected projects. For example, in connection with a permit we obtained at our Spring Valley wind facility, we had to adopt a mitigation plan with respect to injuries and fatalities to golden eagles, and were required to establish a process in the event of incidents, including reporting to the U.S. Fish and Wildlife Service. We have followed such required processes in connection with three golden eagle incidents since January 1, 2013, and, in addition, we have filed an application for an eagle take permit which is under consideration by the U.S. Fish and Wildlife Service. While we have recently entered into an agreement with U.S. Fish and Wildlife to fund additional research into mitigation measures and incurred nominal fines with respect to the prior eagle incidents, no assurances can be given that we will not be required to implement further increased levels of mitigation, or face additional penalties,

28




fines, or other measures as a result of golden eagle incidents at our Spring Valley facility or any of our other wind facilities.  In addition, no assurances can be given that our eagle take permit will be approved.
No assurances can be given that our application for an eagle take permit will be approved, or that we will not be required to implement increased levels of mitigation, or face penalties, fines, or other measures as a result of prior or future golden eagle incidents at our Spring Valley facility or any of our other wind facilities.
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 and become more stringent. Any such changes could require our projects to incur additional material costs or cause our projects to suffer adverse consequences. For example, the Ministry of Environment in Ontario has established regulatory requirements governing noise restrictions for wind farms which are an integral part of the permitting framework for our projects in that jurisdiction. In the event of changes in either the regulatory requirements or permitting framework, there is risk that our projects that were designed for compliance within the existing framework and requirements for noise could still be evaluated by regulators as noncompliant. These risks are enhanced because testing for compliance with noise requirements is technically complex, carries some degree of uncertainty, and does not have significant precedent in that market. In the event of a determination of noncompliance, there is risk that the necessary mitigation, which would likely need to occur during periods of higher wind speeds, could require curtailment of energy production at the facility, with a resulting reduction in revenues.
Our projects’ costs of complying with current and future environmental, health and safety laws, regulations and permit requirements (including any change in noise regulations), and any liabilities, fines or other sanctions resulting from violations of them, could have a material adverse effect on our business, financial condition and results of operations.
We may be unable to complete any future construction projects on time, and our construction costs could increase to levels that make a project too expensive to complete or make the return on our investment in that project less than expected.
While we currently do not have projects in construction, there may be delays or unexpected developments in completing any future construction projects, which could cause the construction costs of these projects to exceed our expectations. Our construction projects are typically constructed under fixed-price and fixed-schedule contracts with construction and equipment suppliers. However, these contracts typically 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. No assurances can be given that disputes with our project construction providers will not arise in the future, and if they do, we can reach a settlement, such settlement amount would be covered by the remaining budgeted project contingencies or otherwise be favorable, arbitration or legal action would not be commenced, or we would not have to bear increased costs associated with any such disputes which could make the return on our investment in the project less than expected.
Additionally, various other factors could contribute to construction-cost overruns and construction delays, including:
inclement weather conditions;
failure to receive turbines or other critical components and equipment necessary to maintain the operating capacity of our projects, in a timely manner or at all;
failure to complete interconnection to transmission networks, which relies on several third parties, including interconnection facilities provided by local utilities;
failure to maintain all necessary rights to land access and use;
failure to receive quality and timely performance of third-party services;
failure to maintain environmental and other permits or approvals;
failure to meet domestic content requirements;

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appeals of environmental and other permits or approvals that we hold;
lawful or unlawful protests by or work stoppages resulting from local community objections to a project;
shortage of skilled labor on the part of our contractors;
adverse environmental and geological conditions; and
force majeure or other events out of our control.
Any of these factors could give rise to construction delays and construction costs in excess of our expectations. These circumstances could prevent our construction projects from commencing operations or from meeting our original expectations about how much electricity they will generate or the returns they will achieve. In addition, substantial delays could cause defaults under our financing agreements or under PPAs that require completion of project construction by a certain date at specified performance levels or could result in the loss or reduction of expected tax benefits. Our inability to transition our construction projects into financially successful operating projects would have a material adverse effect on our business, financial condition and results of operations and our ability to pay dividends.
Our projects rely on 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 any construction projects or reduce the return to us on those investments.
Our projects depend upon interconnection to electric transmission lines owned and operated by regulated utilities to deliver the electricity we generate. A failure or delay in the operation or development of these interconnection or transmission facilities could result in our losing revenues because such a failure or delay could limit the amount of power our operating projects deliver or delay the completion of any construction projects. In addition, in those countries in which we have operating projects, 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, in many of the markets in which we operate or are looking to expand, should there be any excess capacity available in those generator lead facilities, and should a third party request access to such capacity, the relevant regulatory authority in such jurisdiction, such as FERC in the United States, or other authorities might, require our projects to provide service over such facilities for that excess capacity to the requesting third party at regulated rates. Should this occur in markets with such regulations, the projects could be subject to additional regulatory risks and costly compliance burdens associated with being considered the owner and operator of a transmission facility.
The loss of one or more of our executive officers or key employees may adversely affect our ability to effectively manage our operating projects and complete any construction projects on schedule.
We depend on our experienced management team and the loss of one or more key executives could have a negative impact on our business. We also depend on our ability to retain and motivate key employees and attract qualified new employees. Because the wind power industry is relatively new, there is a scarcity of experienced employees in the wind power industry. We may not be able to replace departing members of our management team or key employees. Integrating new executives into our management team and training new employees with no prior experience in the power industry could prove disruptive to our projects, require a disproportionate amount of resources and management attention and ultimately prove unsuccessful. An inability to attract and retain sufficient technical and managerial personnel could limit our ability to effectively manage our operating projects and complete any construction projects on schedule and within budget, which could have a material adverse effect on our business, financial condition and results of operations.
The employee transfer may adversely affect our costs.
In July 2015, we amended the agreement relating to the employee transfer event to provide that the employee transfer event is no longer conditioned upon our achievement of $2.5 billion in market capitalization. Instead, we have the option, exercisable at any time until January 1, 2017 to require the employee transfer event to occur. Following the occurrence of the employee transfer event, we will

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be faced with increased costs associated with employing a larger number of employees. If Pattern Development reduces the scope of its development activities and is therefore not paying us for the services of the transferred 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 efforts may, however, be inadequate to protect our operating projects against all risk of loss of our rights to use the land on which our projects are located, which could have a material adverse effect on our business, 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 and other obligations, such as the amount of required reclamation security, to market terms. Any such loss or curtailment of our rights to use the land on which our projects are located, any increase in rent due, or any increase in other obligations with respect to such lands could have a material adverse effect on our business, financial condition and results of operations.
Our operating projects are, and other future projects may be, subject to various governmental regulations, approvals, and compliance requirements that regulate the sale of electricity, which could have a material adverse effect on our business, 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, Panhandle 1, Panhandle 2, and Logan’s Gap, our operating projects in the United States are, however, public utilities under the Federal Power Act subject to rate regulation by FERC. Our future projects in the United States will also likely be subject to such rate regulation once they are placed into service. Our projects in the United States that are subject to FERC rate regulation are required to obtain acceptance of their rate schedules for wholesale sales of energy ( i.e. , not retail sales to consumers), capacity and ancillary services, including their ability to charge “market-based rates.” FERC may revoke or revise an entity’s authorization to make wholesale sales at market-based rates if FERC subsequently determines that such entity and its affiliates can exercise horizontal or vertical market power, create barriers to entry or engage in abusive affiliate transactions or market manipulation. In addition, public utilities in the United States are subject to FERC reporting requirements that impose administrative burdens and that, if violated, can expose the company to criminal and civil penalties or other risks.
Most of our North American projects are located in regions in which the wholesale electric markets are administered by ISOs and Regional Transmission Organizations, or “RTOs.” Several of our current operating projects are subject to the California ISO, or “CAISO,” which is the ISO that prescribes rules for the terms of participation in the California energy market; ERCOT, which is the ISO that prescribes the rules for and terms of participation in the Texas energy market; and the Independent Electricity System Operator, or “IESO,” which is the ISO that administers the wholesale electricity market in Ontario. The Southwest Power Pool is the RTO and regional market administrator for our Post Rock project. Lost Creek is in the Associated Electric Cooperative, Inc. a subregion of the SERC Reliability Corporation. Many of these entities can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, ISOs and RTOs have developed bid-based locational pricing rules for the energy markets that they administer. In addition, most ISOs and RTOs have also developed bidding, scheduling and market behavior rules, both to curb the potential exercise of market power by electricity generating companies and to ensure certain market functions and system reliability. These actions could materially adversely affect our ability to sell, and the price we receive for, our energy, capacity and ancillary services.
All of our current operating projects located in North America are also subject to the reliability standards of the North American Electric Reliability Corporation, or “NERC.” If we fail to comply with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. Although our U.S. projects are not subject to state utility regulation because our projects sell power exclusively on a wholesale basis, we are subject to certain state regulations that may affect the sale of electricity from our projects, the operations of our projects, as well as the potential for state electricity taxes. All of our current operating projects in Canada are subject to exclusive provincial regulatory authority with respect to the generation and production of electricity, which

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varies across provincial jurisdictions. Changes in regulatory treatment at the state and provincial level are difficult to predict and could have a significant impact on our ability to operate and on our financial condition and results of operations.
Our industry could be subject to increased regulatory oversight.
Our industry could be subject to increased regulatory oversight. Changing regulatory policies and other actions by governments and third parties with respect to curtailment of electricity generation, electricity grid management restrictions, interconnection rules and transmission may all have the effect of limiting the revenues from, and increasing the operating costs of, our projects which could have a material adverse effect on our business, financial condition and results of operations.
Due to regulatory restructuring initiatives at the federal, provincial and state levels, the electricity industry has undergone changes over the past several years. Future government initiatives will further change the electricity industry. Some of these initiatives may delay or reverse the movement towards competitive markets. We cannot predict the future design of wholesale power markets or the ultimate effect that on-going regulatory changes will have on our business, 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 certain force majeure events or terrorism. In addition, our insurance policies for our projects may cover losses as a result of certain types of natural disasters or sabotage, among other things, but such coverage is not always available in the insurance market on commercially reasonable terms and is often capped at predetermined limits that may not be adequate. In addition, our insurance policies are subject to annual review by our insurers and may not be renewed on similar or favorable terms or at all. A serious uninsured loss or a loss significantly exceeding the limits of our insurance policies could have a material adverse effect on our business, financial condition and results of operations.
Currency exchange rate fluctuations may have an impact on our financial results and condition.
We have exposures to currency exchange rate fluctuations, primarily the Canadian dollar, related to buying, selling and financing our business in currencies other than the local currencies of the countries in which we operate. A portion of our revenue for the years ended December 31, 2015, 2014 and 2013 was denominated in currencies other than the U.S. dollar, and we expect net revenue from non-U.S. dollar markets to continue to represent a portion of our net revenue. We manage our currency exposure through a variety of methods, including efforts to match our asset and liabilities in the same currencies, mainly by raising local currency debt. In addition, we have implemented a currency hedging program to manage short and medium term fluctuations in our dividends from our wind facilities located outside the United States. However, any measures that we have implemented or may implement in the future to reduce the effect of currency exchange rate fluctuations and other risks of our global operations may not be effective or may be expensive. We cannot provide assurance that currency exchange rate fluctuations will not otherwise have a material adverse effect on our financial condition or results of operations or cause significant fluctuations in quarterly and annual results of operations.
Foreign currency translation risk arises upon the translation of statement of financial position and income statement items of our foreign subsidiaries whose functional currency is a currency other than the U.S. dollar into U.S. dollars for purposes of preparing the consolidated financial statements included elsewhere in this Form 10-K, which are presented in U.S. dollars. The assets and liabilities of our non-U.S. dollar denominated subsidiaries are translated at the closing rate at the date of reporting and income statement items are translated at the average rate for the period. All resulting exchange differences are recognized in a separate component of equity, “Foreign currency translation, net of tax,” and are recorded in “Other comprehensive income (loss), net of tax.” These currency translation differences may have significant negative or positive impacts. Upon the disposal of a non-U.S. dollar denominated subsidiary, the cumulative amount of exchange differences relating to that non-U.S. dollar denominated subsidiary are reclassified from equity to profit or loss. Our foreign currency translation risk mainly relates to our operations in Canada.
In addition, foreign currency transaction risk arises when we or our subsidiaries enter into transactions where the settlement occurs in a currency other than the functional currency of us or our subsidiary. Exchange differences (gains and losses) arising on the settlement of monetary items or on translation of monetary items at rates different from those at which they were translated on initial recognition during the period or in previous financial statements are recognized 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.

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Our cross-border operations require us to comply with anti-corruption laws and regulations of the U.S. government and various non-U.S. jurisdictions.
Doing business in multiple countries requires us and our subsidiaries to comply with the laws and regulations of the U.S. government and various non-U.S. jurisdictions. Our failure to comply with these rules and regulations may expose us to liabilities. These laws and regulations may apply to our companies, individual directors, officers, employees and agents and may restrict our operations, trade practices, investment decisions and partnering activities. In particular, our non-U.S. operations are subject to U.S. and foreign anti-corruption laws and regulations, such as the Foreign Corrupt Practices Act of 1977, or the “FCPA.” The FCPA prohibits U.S. companies and their officers, directors, employees and agents acting on their behalf from corruptly offering, promising, authorizing or providing anything of value to foreign officials for the purposes of influencing official decisions or obtaining or retaining business or otherwise obtaining favorable treatment. The FCPA also requires companies to make and keep books, records and accounts that accurately and fairly reflect transactions and dispositions of assets and to maintain a system of adequate internal accounting controls. As part of our business, we deal with state-owned business enterprises, the employees and representatives of which may be considered foreign officials for purposes of the FCPA. As a result, business dealings between our employees or our agents and any such foreign official could expose our company to the risk of violating anti-corruption laws even if such business practices may be customary or are not otherwise prohibited between our company and a private third-party. Violations of these legal requirements are punishable by criminal fines and imprisonment, civil penalties, disgorgement of profits, injunctions, debarment from government contracts as well as other remedial measures. We have established policies and procedures designed to assist us and our personnel in complying with applicable U.S. and non-U.S. laws and regulations; however, we cannot assure stockholders that these policies and procedures will completely eliminate the risk of a violation of these legal requirements, and any such violation (inadvertent or otherwise) could have a material adverse effect on our business, financial condition and results of operations.
We own, and in the future may acquire, certain projects in joint ventures, and our joint venture partners’ interests may conflict with our and our stockholders’ interests.
We own, and in the future may acquire, certain projects in joint ventures, including South Kent, Grand and K2, in each of which we have a 50%, 45% and 33% interest, respectively, and El Arrayán, in which we have a 70% interest. In the future, we may invest in other projects with a joint venture partner, including certain Pattern Development-owned 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 and internal control requirements. To the extent we do not have a controlling interest in a project, our joint venture partners could take actions that decrease the value of our investment and lower our overall return. In addition, conflicts of interest may arise in the future between our company and our stockholders, on the one hand, and our joint venture partners, on the other hand, where our joint venture partners’ business interests are inconsistent with our and our stockholders’ interests. Further, disagreements or disputes between us and our joint venture partners may arise which could result in litigation, increase our expenses and potentially limit the time and effort our officers and directors are able to devote to our business, all of which could have a material adverse effect on our business, financial condition and results of operations.
Security breaches, including cybersecurity breaches, and other disruptions could compromise our business operations and critical and proprietary information and expose us to liability, which could adversely affect our business, financial condition and reputation.
In the ordinary course of our business, we store sensitive data and proprietary information regarding our business, employees, shareholders, offtakers, service providers, business partners and other individuals in our data center and on our network. Additionally, we use and are dependent upon information technology systems that utilize sophisticated operational systems and network infrastructure to run our wind farms. Through our 24/7 operations control center, we can, among other things, monitor and control each wind turbine, monitor regional and local climate, track real time market prices and, for some of our projects, monitor certain environmental activities. The secure maintenance of information and information technology systems is critical to our operations. Despite security measures we have employed, including certain measures implemented pursuant to mandatory NERC Critical Infrastructure Protection standards, our infrastructure may be increasingly vulnerable to attacks by hackers or terrorists as a result of the rise in the sophistication and volume of cyberattacks. Also, our information and information technology systems may be breached due to viruses, human error, malfeasance or other malfunctions and disruptions. Any such attack or breach could: (i) compromise our turbines and wind farms thereby adversely affecting generation and transmission to the grid; (ii) adversely affect our operations; (iii) corrupt data; or (iv) result in unauthorized access to the information stored on our networks, including, company proprietary information and employee data causing the information to be publicly disclosed, lost or stolen or result in incidents that could result in harmful effects on the environment and human health, including loss of life. Any such attack, breach, access, disclosure or other loss of information could result in lost revenue, the inability to conduct critical business functions, legal claims or proceedings, regulatory penalties, increased regulation, increased protection costs for enhanced cyber security systems or personnel, damage to our reputation

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and/or the rendering of our disclosure controls and procedures ineffective, all of which could adversely affect our business, financial condition and reputation.
Risks Related to Future Growth and Acquisitions
The growth of our business depends on locating and acquiring interests in additional attractive independent power and transmission projects .
Our business strategy includes acquiring power projects that are either operational, construction-ready, or in limited circumstances, under development. We intend to pursue opportunities to acquire projects from third-party IPPs where we may submit bids from time to time, and from Pattern Development pursuant to our Purchase Rights. In addition, we and the equity owners of Pattern Development have begun discussions regarding a potential investment by us in a portion of the business of Pattern Development. Various factors could affect the availability of attractive projects to grow our business, including:
competing bids for a project, including a project subject to our Purchase Rights, from other IPPs, including companies that may have substantially greater capital and other resources than we do;
fewer third-party acquisition opportunities than we expect, which could result from, among other things, available projects having less desirable economic returns or higher risk profiles than we believe suitable for our business plan and investment strategy;
Pattern Development’s failure to complete the development of (i) the Identified ROFO Projects, which could result from, among other things, permitting challenges, failure to procure the requisite financing, equipment or interconnection, or an inability to satisfy the conditions to effectiveness of project agreements such as PPAs and (ii) any of the other projects in its development pipeline, in a timely manner, or at all, in either case, which could limit our acquisition opportunities under our Purchase Rights;
our failure to exercise our Purchase Rights or acquire assets from Pattern Development;
our failure to successfully develop and finance projects, to the extent that we decide to pursue development activities with respect to new power projects;
local opposition to wind turbine installations is growing in certain markets due to concerns about noise, health and other alleged impacts of wind power projects. In addition, indigenous communities in the United States and Canada, including Native Americans and First Nations, are becoming more involved in the development of wind power projects and have certain treaty rights that can negatively affect the viability of power projects. As a result, for these and other reasons, litigation and challenges to wind power projects has increased; and
limited access to capital may impair our ability to buy certain projects or buy them at the time we had expected.
Any of these factors could prevent us from executing our growth strategy or otherwise have a material adverse effect on our business, 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 stockholders will not generally have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Capital market conditions can have an effect on both our timing and ability to consummate future acquisitions.
Since we often finance acquisitions of clean energy projects partially or wholly through the issuance of additional Class A shares, we may need to be able to access the capital markets on commercially reasonable terms when acquisition opportunities arise. For example, we utilized in part proceeds from underwritten public offerings of our Class A shares in both July 2015 and February 2015 and a private placement of convertible debt securities in July 2015 for investment in acquisition opportunities and to repay other debt previously incurred to finance acquisition opportunities. Our ability to access the equity capital markets is dependent on, among other factors, the overall state of the capital markets and investor appetite for investment in clean energy projects in general and our Class A shares in particular. Volatility in the market price of our Class A shares may prevent or limit our ability to utilize our equity securities as a source of capital to help fund acquisition opportunities. During 2015, the prices for our Class A shares traded on The NASDAQ Global Select Market ranged from a high of $32.00 to a low of $16.96 . On February 24, 2016, the last reported sale price of our Class A shares on such market was $16.40. An inability to obtain equity financing on commercially reasonable terms could significantly limit our timing and

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ability to consummate future acquisitions, and to effectuate our growth strategy. In addition, the issuance of additional Class A shares in connection with acquisitions, particularly if consummated at depressed price levels, could cause significant shareholder dilution and reduce the cash distribution per share if the acquisitions are not sufficiently accretive.
In the event we determine it is not economical to utilize, or we are unable to utilize our equity securities as a source of capital to fund acquisition opportunities, we may need to consider utilizing other sources of capital, such as cash on hand, borrowings under our existing credit facilities, arranging additional credit facilities, or the issuance of debt securities, none of which may be available or may not be available at attractive terms. Our inability to effectively consummate future acquisitions could have a material adverse effect on our ability to grow our business and make cash distributions to our shareholders.
Acquisition of power projects involves numerous risks.
Our strategy includes acquiring power projects. The acquisition of power projects involves numerous risks, many of which may not be able to be discovered through our due diligence process, including exposure to previously existing liabilities and unanticipated costs associated with the pre-acquisition period; difficulty in integrating the acquired projects into our existing business; and, if the projects are in new markets, the risks of entering markets where we have limited experience. While we will perform our due diligence on prospective acquisitions, we may not be able to discover all potential operational deficiencies in such projects or problematic wind characteristics. A failure to achieve the financial returns we expect when we acquire power projects could have a material adverse effect on our ability to implement our growth strategy and, ultimately, our business, financial condition and results of operations.
Our growth strategy is dependent upon the acquisition of attractive power projects developed by third-parties, including Pattern Development, and an inability of such development companies to obtain the requisite financing to develop and construct projects could have a material adverse effect on our ability to grow our business.
Power project development is a capital intensive, high-risk business that relies heavily on and, therefore, is subject to the availability of debt and equity financing sources to fund projected construction and other projected capital expenditures. As a result, in order to successfully develop a power project, development companies, including Pattern Development, from which we may seek to acquire power projects, must obtain at-risk funds sufficient to complete the development phase of their projects. We, on the other hand, must anticipate obtaining funds from equity or debt financings, including tax equity transactions, or from government grants in order to successfully complete our acquisitions and fund any required construction and other capital costs of the acquired projects. We currently intend to acquire power projects that are at least at the stage of being construction-ready, which is generally the point in time when the project is able to procure construction financing. 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 any construction of a project we may seek to acquire. If development companies from which we seek to acquire projects are unable to raise funds when needed or if we or they are unable to secure construction financing, the ability to grow our project portfolio may be limited, which could have a material adverse effect on our ability to implement our growth strategy and, ultimately, our business, financial condition and results of operations.
Our ability to grow our cash available for distribution is substantially dependent on our ability to make acquisitions from Pattern Development or third parties on economically favorable terms.
Our goal of growing our cash available for distribution and increasing dividends to our Class A stockholders is substantially dependent on our ability to make and finance acquisitions on terms that result in an increase in cash available for distribution per Class A share. To grow our cash available for distribution per Class A share through acquisitions, we must be able to acquire new generation assets, such as the Identified ROFO Projects, on economically favorable terms. If we are unable to make accretive acquisitions from Pattern Development or third parties because we are unable to identify attractive acquisition opportunities, negotiate acceptable purchase contracts, obtain financing on economically acceptable terms (as a result of the then current market value of our Class A shares or otherwise) or are outbid by competitors, we may not be able to realize our targeted growth in cash available for distribution per Class A share.
The energy industry in the markets in which we operate, as well as the markets we are looking to expand into, benefit from governmental support that is subject to change.
The energy industry in the markets in which we operate and are looking to expand into, including both fossil fuel and renewable energy sources, in general benefits from various forms of governmental support. Renewable energy sources in Canada benefit from federal and provincial incentives, such as RPS programs, accelerated cost recovery deductions, the availability of off-take contracts through RFP and standard offer programs including the Hydro-Quebec call for tenders, the Ontario feed-in tariff and large renewable procurement programs, and other commercially oriented incentives. Renewable energy sources in the United States have benefited

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from various federal and state governmental incentives, such as PTCs, ITCs, ITC cash grants, loan guarantees, RPS programs and accelerated tax depreciation. PTCs and ITCs for wind energy on the federal level were extended in December 2015. The extension extended the expiration date for tax credits for wind facilities with a five year phase-down for wind projects commencing construction after December 31, 2014. Renewable energy sources in Chile benefit from the Renewable and Non-Conventional Energy Law, which stipulates that by 2025 a portion of the total energy withdrawn from the grid, starting with 5% in 2015 and progressively increasing up to 20% by 2025, shall be produced with renewable and non-conventional technologies. Such obligations translate into “green attributes” which can be freely traded. In 2012, Japan introduced a feed-in-tariff program that offered fixed term, fixed price contracts of up to 20 years to renewable power projects. The Mexican congress has established a mandate that at least 35% of its energy consumption be supplied by clean sources by 2024. While such developments extending various forms of governmental support provide general benefits to the wind power industry in which we operate, to the extent that these governmental incentive programs may be amended or changed in the future, particularly if amendments or changes are unexpected or unfavorable and after we have developed long-term business plans and strategies based upon them, it could adversely affect the price of electricity sold to power purchasers generated by developed or planned wind power projects, decrease demand for wind power, or reduce the number of projects available to us for acquisition, any of which could have a material adverse effect on our ability to implement our growth strategy and, ultimately, our business, financial condition and results of operations. For example, in February 2016, the U.S. Supreme Court issued a stay prohibiting the implementation of the Clean Power Plan, a regulation issued by the U.S. Environmental Protection Agency aimed at reducing use of existing coal-fired electricity generation facilities and increasing renewable generation in order to reduce greenhouse gas emissions, pending a challenge to such regulation before a U.S. Court of Appeals.
Wind power procurement in Canada is a provincial matter, with relatively irregular, infrequent and competitive procurement windows.
Each province in Canada has its own regulatory framework and renewable energy policy, with few material federal policies to drive the growth of renewable energy. Renewable energy developers must anticipate the future policy direction in each of the provinces, and secure viable projects before they can bid to procure a PPA through highly competitive PPA auctions. Most markets are relatively small. Energy policy in our key market of Ontario is subject to a political process, including with respect to its FIT program, and renewable energy procurement may change dramatically as a result of changes in the provincial government or political climate.
We face competition primarily from other renewable energy IPPs and, in particular, other wind power companies.
We believe our primary competitors are infrastructure funds and some wind power companies or IPPs focused on renewable energy generation. We compete with these companies to acquire well-developed projects with projected stable cash flows that can be built in a cost-effective manner. We also compete with other wind power developers and operators for the limited pool of personnel with requisite industry knowledge and experience. Furthermore, in recent years, there have been times of increased demand for wind turbines and their related components, causing turbine suppliers to have difficulty meeting the demand. If these conditions return in the future, turbine and other component manufacturers may give priority to other market participants, including our competitors, who may have resources greater than ours.
We compete with other renewable energy companies (and power companies in general) for the lowest cost financing, which provides the highest returns for our projects. Once we have acquired a construction project and put it into operation, we may compete on price if we sell electricity into power markets at wholesale market prices. Depending on the regulatory framework and market dynamics of a region, we may also compete with other wind power companies and other renewable energy generators, when our projects bid on or negotiate for long-term power sale agreements or sell electricity or RECs into the spot-market. Our ability to compete on price with other wind power companies and other renewable energy IPPs may be negatively impacted if the regulatory framework of a region favors other sources of renewable energy over wind power.
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

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adversely affect the demand for renewable energy. For example, low natural gas prices have led, in some instances, to increased natural gas consumption by electricity-generating utilities in lieu of other power sources. To the extent renewable energy and wind power, in particular, becomes less cost-competitive on an overall basis as a result of a lack of governmental incentives, cheaper alternatives or otherwise, demand for wind power and other forms of renewable energy could decrease. Slow growth in overall demand for electricity or a long-term reduction in the demand for renewable energy could have a material adverse effect on our plan to grow our business and could, in turn, have a material adverse effect on our business, financial condition and results of operations.
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 and provinces 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, the Canadian province of Ontario has a renewable energy target of 10.7 GW, excluding hydroelectric sources. Presently, the province anticipates meeting its target by 2018. 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 had the potential to meet a prior goal of 33% renewable power generation by 2020 with already-proposed new renewable power projects, although such target had recently been increased to 50%. As a result of achieving targets, and if such U.S. states and Canadian provinces with targets do not increase targets in the future, like California has done, demand for additional wind power generating capacity could decrease. In addition, 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, financial condition and results of operations. For example, Ohio in 2014 became the only state to freeze its RPS, effectively stopping the state’s mandates for renewable energy and efficiency until 2017. While in 2017 the standards in Ohio are expected pick up where they left off prior to the freeze, a committee is reviewing changes to the RPS which has created an atmosphere of uncertainty for renewable energy investment in the state.
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. In other cases, these permits may require compliance with terns that can change over time. We cannot predict whether all permits required for a given project will be granted or whether the conditions associated with the permits, as such conditions may change over time, will be achievable. The denial or loss of a permit essential to a project, or the imposition of impractical conditions upon renewal or over time, 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 Pattern Development experienced delays in obtaining non-appealable permits and we may experience delays in the future. For example, when we acquired our Ocotillo project, it was then the subject of four active lawsuits brought by a variety of project opponents, all of which have challenged the prior issuance of Ocotillo’s primary environmental analysis and right-of-way entitlement. We had commenced commercial operations at the Ocotillo project in anticipation of securing favorable rulings on these lawsuits. See Item 3 “Legal Proceedings.” In Ontario, anti-wind advocacy groups opposed the environmental permit granted to our South Kent and Grand projects. The permits were appealed before the Environmental Review Tribunal, which later dismissed the appeals. We are subject to the risk of being unable to complete our projects if any of the key permits are revoked. If this were to occur at any future project, we would likely lose a significant portion of our investment in the project and could incur a loss as a result, which would have a material adverse effect on our business, financial condition and results of operations.
If we are unable to make an offer, or make an attractive offer, in the event Pattern Development delivered notice that it is seeking a purchaser for the Armow wind facility, or any other project on the identified ROFO list, we may be unable to acquire such project from Pattern Development pursuant to our Project Purchase Right.
While the 180 MW Armow wind facility, an identified ROFO project, reached commercial operations in December 2015, Pattern Development has not yet delivered notice that it is seeking a purchaser for such project under our Project Purchase Right. In addition, the 42 MW Futtsu Solar facility in Japan, which is an identified ROFO project, has become operational. Although Pattern Development may choose to seek a purchaser of a project at a time of its choosing whether earlier in the project’s development stage

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or later at a time, we have generally anticipated that Pattern Development seeks a purchaser of its development projects upon construction-readiness following commencement of its construction. We do not control Pattern Development, and Pattern Development may deem it necessary or desirable to deliver such notice to us that is seeking a purchaser for its projects at any time for its own capital, liquidity, shareholder, or other requirements. While it is uncertain if or when Pattern Development may deliver a notice that it is seeking a purchaser for the Armow facility under our Project Purchase Right, in the event Pattern Development delivered such a notice, or notice for another project on the identified ROFO list, for which we are unable to, or do not, deliver a written first rights project offer or make an attractive offer to purchase its entire interest in such project, Pattern Development may reject our first rights project offer. Pattern Development may then be able to sell the project to a third party (including a competitor), provided it is at a price not less than 105% of our first rights project offer and other terms not materially less favorable. If this occurred, we would not acquire such project from Pattern Development. An inability to acquire the Armow facility, or any other project on the identified ROFO list, under our Project Purchase Right could materially adversely affect our ability to implement our growth strategy.
In spite of our Pattern Development Purchase Rights, it is possible that Pattern Development itself might be sold to third parties. In addition, both our Purchase Rights and our Pattern Development Purchase Rights may expire, and the Non-Competition Agreement with Pattern Development might terminate.
To the extent we do not exercise our Pattern Development Purchase Rights (or upon their expiration), Pattern Development itself or substantially all of its assets may be sold to third parties, including our competitors. Even if we are interested in exercising the Pattern Development Purchase Rights, Pattern Development may offer at an inopportune time for us, or we may not be able to reach an agreement on pricing or other terms. If we are unable to reach an agreement with Pattern Development or its equity owners or if we decline to make an offer, Pattern Development or its equity owners may seek alternative buyers, which could have a material adverse effect on our ability to implement our growth strategy and, ultimately, our business, financial condition and results of operations.
Additionally, our Project Purchase Right and our Pattern Development Purchase Rights terminate upon the fifth anniversary of the completion of our initial public offering, or October 2, 2018, but are subject to automatic five-year renewals unless either party dissents at the time of renewal. In addition, our Project Purchase Right and our Pattern Development Purchase Rights terminate upon the third occasion on which we decline to exercise our Project Purchase Right with respect to an operational or construction-ready project and following which Pattern Development has sold the project to an unrelated third party. Following termination of our Project Purchase Right and our Pattern Development Purchase Rights, Pattern Development will be under no obligation to offer any of its projects to us, which could have a material adverse effect on our ability to implement our growth strategy and ultimately on our business, financial condition and results of operations.
Once our Purchase Rights terminate, the Non-Competition Agreement with Pattern Development will also terminate, and at such time, Pattern Development will no longer be restricted from competing with us for acquisitions.
The loss of one or more of our Pattern Development’s executive officers or key employees may adversely affect our ability to implement our growth strategy.
In addition to relying on our management team for managing our projects, our growth strategy relies on our and Pattern Development’s executive officers and key employees for their strategic guidance and expertise in the selection of projects that we may acquire in the future. Because the wind power industry is relatively new, there is a scarcity of experienced executives and employees in the wind power industry. As a result, if one or more of our or Pattern Development’s executive officers or key employees leaves or retires, and neither we nor Patten Development are able to find a suitable replacement, our ability to implement our growth strategy may be diminished, which could have a material adverse effect on our business, financial condition and results of operations.
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. In September 2014, we announced the addition of our first solar project, Conejo Solar, a 104 MW photovoltaic solar power project being constructed in Chile, to our list of Identified ROFO Projects. In June 2015, additional solar projects were added to our list of Identified ROFO Projects which are in Japan, including the 42 MW Futtsu Solar and 14 MW Kanagi Solar projects. There can be no assurance that we will be able to identify other attractive non-wind or transmission acquisition opportunities or acquire such projects at a price and on terms that are attractive or that, once acquired, such projects will operate profitably. Additionally, these acquisitions could expose us 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

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established non-wind energy market participants. A failure to successfully integrate such acquisitions into our existing project portfolio as a result of unforeseen operational difficulties or otherwise, could have a material adverse effect on our business, financial condition and results of operations.
We are subject to risks associated with litigation or administrative proceedings that could materially impact our operations, including proceedings in the future related to power projects we subsequently acquire.
We are subject to risks and costs, including potential negative publicity, associated with lawsuits, in particular, with respect to environmental claims and lawsuits or claims contesting the construction or operation of our projects. See Item 3 "Legal Proceedings.” The result of and costs associated with defending any such lawsuit, regardless of the merits and eventual outcome, may be material and could have a material adverse effect on our operations. In the future, we may be involved in legal proceedings, disputes, administrative proceedings, claims and other litigation that arise in the ordinary course of business related to a power project that we subsequently acquire. For example, individuals and interest groups may sue to challenge the issuance of a permit for a power project or seek to enjoin construction or operation of a power project. We may also become subject to claims from individuals who live in the proximity of our power projects based on alleged negative health effects related to acoustics caused by wind turbines. In addition, we have been and may subsequently become subject to legal proceedings or claims contesting the construction or operation of our power projects. Any such legal proceedings or disputes could delay our ability to complete construction of a power project in a timely manner, or at all, or materially increase the costs associated with commencing or continuing commercial operations at a power project. Settlement of claims and unfavorable outcomes or developments relating to these proceedings or disputes, such as judgments for monetary damages, injunctions or denial or revocation of permits, could have a material adverse effect on our ability to implement our growth strategy and, ultimately, our business, financial condition and results of operations.
Risks Related to Our Financial Activities
Our substantial amount of indebtedness may adversely affect our ability to operate our business and impair our ability to pay dividends.
Our consolidated indebtedness, including the revolving credit facility and issuance in July 2015 of convertible notes, as of December 31, 2015 is approximately $ 1.77 billion , or approximately 50% of our total capitalization of $ 3.55 billion at such date. Despite our current consolidated debt levels, we or our subsidiaries may still incur substantially more debt or take other actions which would intensify the risks discussed below.
Approximately $ 208.1 million of our consolidated indebtedness as of December 31, 2015 represents project-level debt that matures prior to 2021. We do not have available cash or short-term liquid investments sufficient to repay all of this medium-term indebtedness and we have not obtained commitments for refinancing this debt. Therefore, we may not be able to extend the maturity of this indebtedness or to otherwise successfully refinance current maturities if the project finance markets deteriorate substantially or we choose not to raise corporate-level debt in place of project-level debt. Refinancing such indebtedness may force us to accept then-prevailing market terms that are less favorable than the existing indebtedness. If, for any reason, we are unable to refinance the existing indebtedness, those projects may be in default of their existing obligations, which may result in a foreclosure on the project collateral and loss of the project. Any such events could have a material adverse effect on our business, financial condition and results of operations.
Our substantial indebtedness could have important consequences, including, for example:
failure to comply with the covenants in the agreements governing these obligations could result in an event of default under those agreements, which could be difficult to cure, or result in our bankruptcy;
our debt service obligations require us to dedicate a substantial portion of our cash flow to pay principal and interest on our debt, thereby reducing the funds available to us for purposes such as capital;
in the event a project is unable to meet its debt service obligations through its own project cash flows, excess cash flow from other projects may be required to help service such obligations, thereby reducing funds available to pay dividends;
our limited financial flexibility could reduce our ability to plan for and react to unexpected opportunities; and
our substantial debt service obligations make us vulnerable to adverse changes in general economic, credit and capital markets, industry and competitive conditions and adverse changes in government regulation and place us at a disadvantage compared with competitors with less debt.

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Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. If we do not comply with our obligations under our debt instruments, we may be required to refinance all or part of our existing debt, borrow additional amounts or sell securities, which we may not be able to do on favorable terms or at all. In addition, increases in interest rates and changes in debt covenants may reduce the amounts that we can borrow, reduce our cash flows and increase the equity investment we may be required to make to complete any construction of our projects. These increases could cause some of our projects to become economically unattractive. If we are unable to raise additional capital or generate sufficient operating cash flow to repay our indebtedness, we could be in default under our lending agreements and could be required to delay construction of our 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.
We may not have the ability to raise the funds necessary to settle conversions of the notes we issued in July 2015 in cash, repay such notes at maturity or repurchase such notes upon a fundamental change, and our debt agreements may limit our ability to pay cash upon conversion or repurchase of these notes.
Holders of the notes we issued in July 2015 will have the right to require us to repurchase all or a portion of their notes upon the occurrence of a fundamental change at a repurchase price equal to 100% of the principal amount of the notes to be repurchased, plus accrued and unpaid interest, if any. In addition, upon conversion of the notes, unless we elect to deliver solely our Class A shares to settle such conversion (other than paying cash in lieu of delivering any fractional share), we will be required to make cash payments in respect of the notes being converted. However, we may not have enough available cash or be able to obtain financing at the time we are required to make repurchases of notes surrendered therefor or pay cash with respect to notes being converted or at their maturity. In addition, our ability to repurchase or to pay cash upon conversions of the notes may be limited by law, regulatory authority or agreements governing our indebtedness. Our failure to repurchase notes at a time when the repurchase is required by the indenture or to pay any cash payable on future conversions of the notes pursuant to the indenture would constitute a default under the indenture governing the issuance of the notes. A fundamental change or a default under the indenture could also lead to a default under agreements governing our or our subsidiaries’ indebtedness. If the repayment of the related indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness and repurchase the notes or make cash payments upon conversions thereof.
The conditional conversion feature of the notes we have issued, if triggered, may adversely affect our financial condition and operating results.
The notes we issued in July 2015 have a conditional conversion feature. In the event the conditional conversion feature of the notes is triggered, holders of notes will be entitled to convert the notes at any time during specified periods at their option. If one or more holders elect to convert their notes, unless we elect to satisfy our conversion obligation by delivering solely our Class A shares (other than paying cash in lieu of delivering any fractional share), we would be required to settle a portion or all of our conversion obligation through the payment of cash, which could adversely affect our liquidity. In addition, even if holders do not elect to convert their notes, we could be required under applicable accounting rules to reclassify all or a portion of the outstanding principal of the notes as a current rather than long-term liability, which would result in a material reduction of our net working capital.
The accounting method for convertible debt securities that may be settled in cash, such as the notes we issued in July 2015, could have a material effect on our reported financial results.
FASB ASC Subtopic 470-20 (“FASB ASC 470-20”), Debt with Conversion and Other Options , requires an entity to separately account for the liability and equity components of convertible debt instruments (such as the notes) that may be settled entirely or partially in cash upon conversion in a manner that reflects the issuer’s non-convertible debt interest rate. Accordingly, the equity component of the notes we issued in July 2015 was required to be included in the additional paid-in capital section of shareholders’ equity on our consolidated balance sheet at the issuance date, and the value of the equity component is treated as a discount for purposes of accounting for the debt component of the notes. As a result, we are required to recognize a greater amount of non-cash interest expense in our consolidated income statements in the current and future periods presented as a result of the amortization of the discounted carrying value of the notes to their principal amount over the term of the notes. We may report lower net income (or greater net losses) in our consolidated financial results because FASB ASC 470-20 requires interest to include both the current period’s amortization of the discount and the instrument’s cash interest coupon. This could adversely affect our reported or future consolidated financial results, the trading price of our Class A shares and the trading price of the notes.

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Provisions in the indenture for the notes we issued in July 2015 may deter or prevent a business combination that may be favorable to investors.
If a fundamental change occurs prior to the maturity date of the notes we issued in July 2015, holders of the notes will have the right, at their option, to require us to repurchase all or a portion of their notes. In addition, if a make-whole fundamental change occurs prior to the maturity date of the notes, we will in some cases be required to increase the conversion rate for a holder that elects to convert its notes in connection with such make-whole fundamental change. Furthermore, the indenture for the notes prohibits us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity assumes our obligations under the notes and the indenture. These and other provisions in the indenture for such notes could deter or prevent a third party from acquiring us even when the acquisition may be favorable to investors.
If our subsidiaries default on their obligations under their project-level debt, we may decide to make payments to lenders to prevent foreclosure on the collateral securing the project-level debt, which would, without such payments, cause us to lose certain of our wind power projects.
Our subsidiaries incur various types of debt. Non-recourse debt is repayable solely from the applicable project’s revenues and is secured by the project’s physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. Limited recourse debt is debt where we have provided a limited guarantee, and recourse debt is debt where we have provided a full guarantee, which means if our subsidiaries default on these obligations, we will be liable directly to those lenders, although in the case of limited recourse debt only to the extent of our limited recourse obligations. To satisfy these obligations, we may be required to use amounts distributed by our other subsidiaries as well as other sources of available cash, reducing our cash available to execute our business plan and pay dividends to holders of our Class A shares. In addition, if our subsidiaries default on their obligations under non-recourse financing agreements, we may decide to make payments to prevent the lenders of these subsidiaries from foreclosing on the relevant collateral. Such a foreclosure would result in our losing our ownership interest in the subsidiary or in some or all of its assets. The loss of our ownership interest in one or more of our subsidiaries or some or all of their assets could have a material adverse effect on our business, financial condition and results of operations and, in turn, on our cash available for distribution.
We are subject to indemnity obligations.
We provide a variety of indemnities in the ordinary course of business to contractual counterparties and to our lenders and other financial partners. For example, the Hatchet Ridge indemnity indemnifies MetLife Capital, Limited Partnership (“MetLife”), the owner participant, under the Hatchet Ridge Wind Lease Financing against certain tax losses. In addition, we have entered into equity partnership agreements in connection with four of our projects which also provide for specific allocations in certain circumstances.
In addition, although we primarily rely on limited recourse or non-recourse financing at our project-level entities we sometimes provide specific indemnities to support such financings. For example, some of our subsidiaries in the United States had obtained construction bridge loans to finance a portion of project construction costs, and in certain cases, such loans were secured by the ITC cash grant proceeds received from the U.S. Treasury. We have assumed certain indemnities that were originally provided by Pattern Development to certain of these bridge lenders and other on-going term lenders in the event that the ITC cash grant is recaptured by the U.S. Treasury, in whole or in part. The cash grant indemnities are in effect for five years from the date the relevant project commences commercial operations. If, for any of those subsidiaries which received the ITC cash grant, the ITC cash grant is recaptured, in whole or in part, we may be required to make payments under the indemnities to prevent the lenders of those subsidiaries from foreclosing on the relevant project collateral. Payment by us under a cash grant indemnity could have a material adverse effect on our business, financial condition and results of operations and, in turn, on our cash available for distribution.
Our failure to pay any of these indemnities would enable the applicable project lenders to foreclose on the project collateral. The payments we may be obligated to make pursuant to these indemnities could have a material adverse effect on our business, financial condition and results of operations and, in turn, on our cash available for distribution. See Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Description of Credit Agreements" and "-Tax Equity Partnership Agreements.”

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Our hedging activities may not adequately manage our exposure to commodity and financial risk, which could result in significant losses or require us to use cash collateral to meet margin requirements, each of which could have a material adverse effect on our business, financial condition, results of operations and liquidity, which could impair our ability to execute favorable financial hedges in the future.
Certain of the electricity we generate is sold on the open market at spot-market prices. In order to stabilize all or a portion of the revenue from such sales, we have entered, and may in the future enter, into financial swaps, day-ahead sales transaction or other hedging arrangements. We may acquire additional assets in the future with similar hedging agreements. In an effort to stabilize our revenue from electricity sales from these projects, we evaluate the electricity sale options for each of our projects, including the appropriateness of entering into a PPA, a physical sale, a financial swap, or combination of these arrangements. If we sell our electricity into an ISO market without a PPA, we may enter into a physical sale or financial swap to stabilize all or a portion of our estimated revenue stream. Under the term of our existing physical sales, we are obligated to physically deliver electricity to a common delivery point. Under these arrangements, we sell the electricity produced at our facility to the ISO at the project node and buy energy at the common delivery point to meet the delivery obligations under the physical sale. The delivery obligations under the physical sale are for specified volumes in each hour for an overall quantity that we estimate we are highly likely to produce. Under the terms of our existing financial swaps, we are not obligated to physically deliver or purchase electricity. Instead, we receive payments for specified quantities of electricity based on a fixed price and are obligated to pay our counterparty the real time market price for the same quantities of electricity. These financial swaps cover quantities of electricity that we estimate we are highly likely to produce. Gains or losses under the physical sales and financial swaps are designed to be offset by decreases or increases in our revenues from real time market sales of electricity in liquid ISO markets. However, the actual amount of electricity we generate from operations may be materially different from our estimates for a variety of reasons, including variable wind conditions and wind turbine availability. If a project does not generate the volume of electricity covered by the associated physical sale or financial swap contract, we could incur significant losses if electricity prices in the market rise substantially above the fixed price provided for in the physical sale or financial swap. If a project generates more electricity than is contracted in the physical sale or financial swap, the excess production will not be hedged and the related revenues will be exposed to market price fluctuations.
We would also incur financial losses as a result of adverse changes in the mark-to-market values of the financial swaps or if the counterparties to our hedging contracts fail to make payments when due. We could also experience a reduction in cash flow if we are required to post margin in the form of cash collateral to secure our delivery or payment obligations under these hedging agreements. We are not currently required to post cash collateral or issue letters of credit to backstop our obligations under our hedging arrangements after commercial operation has been achieved, but we may be required to do so in the future. However, if we were required to do so, our available cash or available borrowing capacity under the credit facilities under which these letters of credit are issued would be correspondingly reduced.
We enter into PPAs when we sell our electricity into markets other than deregulated ISO markets or where we believe it is otherwise advisable. Under a PPA, we contract to sell all or a fixed proportion of the electricity generated by one of our projects, sometimes bundled with RECs and capacity or other environmental attributes, to a power purchaser which is often a utility or large commercial entity. We do this to stabilize our revenues from that project. We are exposed to the risk that the power purchaser will fail to perform under a PPA, with the result that we will have to sell our electricity at the market price sometime in the future, which could be substantially lower than the price provided in the applicable PPA. In most instances, we also commit to sell minimum levels of generation. If the project generates less than the committed volumes, we may be required to buy the shortfall of electricity (or RECs and other environmental attributes) on the open market or make payments of liquidated damages or be in default under a PPA, which could result in its termination.
We sometimes seek to sell forward a portion of our RECs or other environmental attributes to fix the revenues from those attributes and hedge against future declines in prices of RECs or other environmental attributes. If our projects do not generate the amount of electricity required to earn the RECs or other environmental attributes sold forward or if for any reason the electricity we generate does not produce RECs or other environmental attributes for a particular state, we may be required to make up the shortfall of RECs or other environmental attributes through purchases on the open market or make payments of liquidated damages. Further, current market conditions may limit our ability to hedge sufficient volumes of our anticipated RECs or other environmental attributes, leaving us exposed to the risk of falling prices for RECs or other environmental attributes. Future prices for RECs or other environmental attributes are also subject to the risk that regulatory changes will adversely affect prices.

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Risks Related to Ownership of our Class A Shares
We are a holding company with no operations of our own, and we depend on our power projects for cash to fund all of our operations and expenses, including to make dividend payments.
Our operations are conducted almost entirely through our power projects and our ability to generate cash to meet our debt service obligations or to pay dividends is dependent on the earnings and the receipt of funds from our project subsidiaries through distributions or intercompany loans. Our power projects’ ability to generate adequate cash depends on a number of factors, including wind conditions, timely completion of any construction projects, the price of electricity, payments by key power purchasers, increased competition, foreign currency exchange rates, compliance with all applicable laws and regulations and other factors. See Item 1A "Risk Factors-Risks Related to Our Projects.” Our ability to declare and pay regular quarterly cash dividends is subject to our obtaining sufficient cash distributions from our project subsidiaries after the payment of operating costs, debt service and other expenses. See Item 5 “Market for Registrant’s Common Equity and Related Stockholder Matters-Cash Dividend Policy.” We may lack sufficient available cash to pay dividends to holders of our Class A shares due to shortfalls attributable to a number of operational, commercial or other factors, including insufficient cash flow generation by our projects, as well as unknown liabilities, the cost associated with governmental regulation, increases in our operating or general and administrative expenses, principal and interest payments on our and our subsidiaries’ outstanding debt, tax expenses, working capital requirements and anticipated cash needs.
Our cash available for distribution to holders of our Class A shares may be reduced as a result of restrictions on our subsidiaries’ cash distributions to us under the terms of their indebtedness, or in the event certain specified events occurred under our tax equity arrangements that change the percentage of cash distributions to be made to the tax equity investors.
We intend to declare and pay regular quarterly cash dividends on all of our outstanding Class A shares. However, in any period, our ability to pay dividends to holders of our Class A shares depends on the performance of our subsidiaries and their ability to distribute cash to us as well as all of the other factors discussed under Item 5 “Market for Registrant’s Common Equity and Related Stockholder Matters-Cash Dividend 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 and the provisions existing and future tax equity arrangements.
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. Low wind conditions contributed to two of our projects not satisfying financial tests required to permit distributions during certain quarters of 2015. The terms of our project indebtedness typically require commencement of commercial operations prior to our ability to receive cash distributions from a project. The terms of any such indebtedness also typically include cash management or similar provisions, pursuant to which revenues generated by projects subject to such indebtedness are immediately, or upon the occurrence of certain events, swept into an account for the benefit of the lenders under such debt agreements. As a result, project revenues typically only become available to us after the funding of reserve accounts for, among other things, operations and maintenance expenses, debt service, taxes and insurance at the project level. In some instances, projects may be required to sweep cash to reserve funds intended to mitigate the results of pending litigation or other potentially adverse events.
In addition, the terms of operating agreements for our wind facilities with tax equity investors, which include Panhandle 1, Panhandle 2, Post Rock, Logan’s Gap and Amazon Wind Farm Fowler Ridge, generally provide for specified allocations of distributions between the tax equity investors and ourselves which change at a specified point when the tax equity investor has realized a target after tax internal rate of return. In the event this change has not occurred by a targeted date, the tax equity investor begins to receive a greater allocation of distributions until the targeted rate of return has been achieved. In addition, the operating agreements also provide for earlier increases in the percentage of distributable cash to be allocated to the tax equity investors if the project fails to achieve certain defined minimum performance levels that are likely to cause the tax equity investors to not achieve the targeted after tax return by the targeted date and for increases under certain circumstances to match allocations of taxable income that are made to mitigate a negative capital account balance for such tax equity investors. As a result, in the event our share of distributable cash from these projects is changed as a result of one of these events, our distributions from such wind facilities may be less than expected that could, in turn, limit our ability to pay dividends to holders of our Class A shares.
If our projects do not generate sufficient cash available for distribution, we may be required to fund dividends from working capital, borrowings under our revolving credit facility, proceeds from future offerings, the sale of assets or by obtaining other debt or equity financing, which may not be available, any of which could have a material adverse effect on the price of our Class A shares and on our

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ability to pay dividends at anticipated levels or at all. See Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations-Description of Credit Agreements.”
Our ability to pay regular dividends on our Class A shares is subject to the discretion of our Board of Directors.
Our Class A stockholders have no contractual or other legal right to dividends. The payment of future dividends on our Class A shares will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board of Directors deems relevant. Our Board of Directors will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of or increase in those reserves could result in a reduction in cash available for distribution to pay dividends on our Class A shares at anticipated levels. Accordingly, we may not be able to make, or may have to reduce or eliminate, the payment of dividends on our Class A shares, which could adversely affect the market price of our Class A shares.
If we fail to maintain proper and effective internal controls, our ability to produce accurate and timely financial statements could be impaired and investors’ views of us could be harmed.
U.S. securities laws require, among other things, that we maintain effective internal control over financial reporting and disclosure controls and procedures. We must perform system and process evaluation and testing of our internal control over financial reporting to allow management to report on the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. If we 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. While we did not need to file with the SEC any amendments to our quarterly reports on Form 10-Q during 2015, during 2014, we filed with the SEC amendments to our quarterly reports on Form 10-Q for each of the quarters ended March 31, 2014 and June 30, 2014 to correct errors therein. Management reported material weaknesses in our system of internal control over financial reporting as of March 31, 2014, June 30, 2014 and September 30, 2014 which management believes have since been remedied. Moreover, a number of our transactions, including business combinations and other acquisitions, require complex accounting and significant accounting estimates which can result in errors in the reported amounts of acquired assets or liabilities. Accordingly, additional material weaknesses may occur in the future, and we may be unable to provide holders of our securities with the required financial information in a timely and reliable manner which could subject us to litigation and regulatory enforcement actions.
Even if we conclude, from time to time, that our internal control over financial reporting provides 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.
Risks Regarding Our Cash Dividend Policy
While we believe that we will have sufficient available cash to enable us to pay the aggregate dividend on our Class A shares for the year ending December 31, 2016, we may be unable to pay the quarterly dividend or any amount on our Class A shares during these periods or any subsequent period. Holders of our Class A shares have no contractual or other legal right to receive cash dividends from us on a quarterly or other basis and, while we currently intend to at least maintain our current dividend and to grow our business and continue to increase our dividend per Class A share over time, our cash dividend policy is subject to all the risks inherent in our business and may be changed at any time. Some of the reasons for such uncertainties in our stated cash dividend policy include the following factors:
Our revolving credit facility includes customary affirmative and negative covenants that will subject certain of our project subsidiaries to restrictions on making distributions to us. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Description of Credit Agreements-Revolving Credit Facility.” Our subsidiaries are also subject to restrictions on distributions under the agreements governing their respective project-level debt. Additionally, we may incur debt in the future to acquire new power projects, the terms of which will likely require commencement of commercial operations prior to our ability to receive cash distributions from such acquired projects. These agreements also likely will contain financial tests and covenants that our subsidiaries must satisfy prior to making distributions. The current financial tests and covenants applicable to our subsidiaries are described in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Description of Credit Agreements.” If any of our subsidiaries is unable to satisfy these restrictions or is otherwise in default under our financing agreements, it would be prohibited from making distributions to us,

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which could, in turn, limit our ability to pay dividends to holders of our Class A shares at our intended level or at all. See "-Risks Related to our Financial Activities-Our substantial amount of indebtedness may adversely affect our ability to operate our business and impair our ability to pay dividends."
Under the terms of operating agreements for our wind facilities with tax equity investors, the share of distributable cash we may receive from these projects may change under certain circumstances, and if these circumstances occurred and were adverse, our distributions from such wind facilities may be less than expected. See "-Our cash available for distribution to holders of our Class A shares may be reduced as a result of restrictions on our subsidiaries' cash distributions to us under the terms of their indebtedness, or in the event certain specified events occurred under our tax equity arrangements that change the percentage of cash distributions to be made to the tax equity investors."
Our Board of Directors will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of or increase in those reserves would reduce the cash available to pay our dividends.
We may lack sufficient cash available for distribution to pay our dividends due to operational, commercial or other factors, some of which are outside of our control, including insufficient cash flow generation by our projects, as well as unexpected operating interruptions, insufficient wind resources, legal liabilities, the cost associated with governmental regulation, changes in governmental subsidies or regulations, increases in our operating or selling, general and administrative expenses, principal and interest payments on our and our subsidiaries’ outstanding debt, tax expenses, working capital requirements and anticipated cash reserve needs.
We are an SEC foreign issuer under Canadian securities laws and, therefore, are exempt from certain requirements of Canadian securities laws applicable to other Canadian reporting issuers.
Although we are a reporting issuer in Canada, we are an SEC foreign issuer under Canadian securities laws and are exempt from certain Canadian securities laws relating to continuous disclosure obligations and proxy solicitation if we comply with certain reporting requirements applicable in the United States, provided that the relevant documents filed with the SEC are filed in Canada and sent to our Class A stockholders in Canada to the extent and in the manner and within the time required by applicable U.S. requirements. In some cases the disclosure obligations applicable in the United States are different or less onerous than the comparable disclosure requirements applicable in Canada for a Canadian reporting issuer that is not exempt from Canadian disclosure obligations. Therefore, there may be less or different publicly available information about us than would be available if we were a Canadian reporting issuer that is not exempt from such Canadian disclosure obligations.
Pattern Development’s general partner and its officers and directors have fiduciary or other obligations to act in the best interests of Pattern Development’s owners, which could result in a conflict of interest with us and our stockholders.
Pattern Development holds approximately 23% of our outstanding Class A shares, representing in the aggregate an approximate 23% voting interest in our company. Upon the occurrence of the Conversion Event on December 31, 2014, Pattern Development and the management holders who had previously held our Class B shares became entitled to receive dividends, beginning on January 1, 2015, on these shares which have been converted to Class A shares. We are party to the Management Services Agreement, pursuant to which each of our executive officers (including our Chief Executive Officer) is a shared PEG executive and devotes time to both our company and Pattern Development as needed to conduct our respective businesses. As a result, these shared PEG executives have fiduciary and other duties to Pattern Development. Conflicts of interest may arise in the future between our company (including our stockholders other than Pattern Development) and Pattern Development (and its owners and affiliates). Our directors and executive officers owe fiduciary duties to the holders of our shares. However, Pattern Development’s general partner and certain of its officers and directors also have a fiduciary duty to act in the best interest of Pattern Development’s limited partners, which interest may differ from or conflict with that of our company and our other stockholders.
Pattern Development’s share ownership may limit other stockholders ability to influence corporate matters.
Pattern Development or its affiliates hold approximately 23% of the combined voting power of our shares, and this concentration of voting power may limit other stockholders’ ability to influence corporate matters, and as a result, actions may be taken that other stockholders may not view as beneficial. As a result of its ownership in our company, Pattern Development has significant influence over all matters that require approval by our stockholders, including the election of directors, as well as 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 Pattern Development and its affiliates may differ from or conflict with the interests of our other stockholders.

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Certain of our executive officers will continue to have an economic interest in, and all of our executive officers will continue to provide services to Pattern Development, which could result in conflicts of interest.
All of our executive officers provide services to Pattern Development pursuant to the terms of the Management Services Agreement between our company and Pattern Development and, as a result, in some instances, have fiduciary or other obligations to Pattern Development. However, none of our Chief Financial Officer, Chief Investment Officer, or Senior Vice President, Operations receives compensation from, or has an economic interest in, Pattern Development. Additionally, while none of 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 receive compensation from Pattern Development, such officers have economic interests in Pattern Development and, accordingly, the benefit to Pattern Development from a transaction between Pattern Development and our company will proportionately inure to their benefit as holders of economic interests in Pattern Development. Pattern Development is a related party under the applicable securities laws governing related party transactions and, as a result, any material transaction between our company and Pattern Development is subject to our corporate governance guidelines, which require prior approval of any such transaction by the conflicts committee, which is comprised solely of independent members of our Board of Directors. Those of our executive officers who have economic interests in Pattern Development may be conflicted when advising the conflicts committee or otherwise participating in the negotiation or approval of such transactions. These executive officers have significant project- and industry-specific expertise that could prove beneficial to the conflicts committee’s decision-making process and the absence of such strategic guidance could have a material adverse effect on our company’s ability to evaluate any such transaction and, in turn, on our business, financial condition and results of operations.
Riverstone is under no obligation to offer us an opportunity to participate in any business opportunities that it may consider from time to time, including those in the energy industry, and, as a result, Riverstone’s existing and future portfolio companies may compete with us for investment or business opportunities.
Conflicts of interest could arise in the future between us, on the one hand, and Riverstone, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Riverstone is a private equity firm in the business of making investments in entities primarily in the energy industry. As a result, Riverstone’s existing and future portfolio companies (other than Pattern Development, which is subject to the Non-Competition Agreement) may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.
Subject to the terms of the Non-Competition Agreement with, and our Purchase Rights granted to us by, Pattern Development, we have expressly renounced any interest or expectancy in, or in being offered an opportunity to participate in, any business opportunity that may be from time to time presented to Riverstone or any of its officers, directors, agents, stockholders, members or partners or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of any fiduciary or other duty, as a director or officer or controlling stockholder or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of any such person who is our director or officer, any such business opportunity is expressly offered to such director or officer solely in his or her capacity as our director or officer. Riverstone has advised us that it does not have a formal policy regarding business opportunities presented to the investment funds managed or advised by it and their respective portfolio companies, but Riverstone’s practice has been that any business opportunities may be pursued by any such fund or directed to any such portfolio company except when the business opportunity has been presented to an employee of Riverstone or its affiliates solely in his or her capacity as a director of a portfolio company.
As a result, Riverstone may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which it has invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunities. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to Riverstone could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours.
Our actual or perceived failure to deal appropriately with conflicts of interest with Pattern Development could damage our reputation, increase our exposure to potential litigation and have a material adverse effect on our business, financial condition and results of operations.
Our conflicts committee is required to review, and make recommendations to the full Board of Directors regarding, any future transactions involving the acquisition of an asset or investment in an opportunity offered to us by Pattern Development to determine

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whether the offer is fair and reasonable (including any acquisitions by us of assets of Pattern Development pursuant to our Purchase Rights). However, our establishment of a conflicts committee may not prevent holders of our shares from filing derivative claims against us related to these conflicts of interest and related party transactions. Regardless of the merits of their claims, we may be required to expend significant management time and financial resources on the defense of such claims. Additionally, to the extent we fail to appropriately deal with any such conflicts, it could negatively impact our reputation and ability to raise additional funds and the willingness of counterparties to do business with us, all of which could have a material adverse effect on our business, financial condition and results of operations.
Market interest and foreign exchange rates may have an effect on the value of our Class A shares.
One of the factors that influences the price of our Class A shares will be the effective dividend yield of our Class A shares ( i.e ., the yield as a percentage of the then market price of our Class A shares) relative to market interest rates. An increase in market interest rates, which are currently at low levels relative to historical rates, may lead prospective purchasers of our Class A shares to expect a higher dividend yield and, our inability to increase our dividend as a result of an increase in borrowing costs, insufficient cash available for distribution or otherwise, could result in selling pressure on, and a decrease in the market price of, our Class A shares as investors seek alternative investments with higher yield. Additionally, we intend to pay a regular quarterly dividend in U.S. dollars and, as a result, to the extent the value of the U.S. dollar dividend decreases relative to Canadian dollars, the market price of our Class A shares in Canada could decrease.
The price of our Class A shares may fluctuate significantly, and stockholders could lose all or part of their investment.
Volatility in the market price of our shares may prevent stockholders from being able to sell their Class A shares at or above the price stockholders paid for their shares. The market price of our Class A shares could fluctuate significantly for various reasons, including: our operating and financial performance and prospects;
our quarterly or annual results of operations or those of other companies in our industry;
a change in interest rates or changes in currency exchange rates;
the public’s reaction to our press releases, our other public announcements and our filings with the Canadian securities regulators and the SEC;
changes in, or failure to meet, earnings estimates or recommendations by research analysts who track our Class A shares or the stock of other companies in our industry;
the failure of research analysts to cover our Class A shares;
strategic actions by us, our power purchasers or our competitors, such as acquisitions or restructurings;
new laws or regulations or new interpretations of existing laws or regulations applicable to our business;
changes in accounting standards, policies, guidance, interpretations or principles;
material litigation or government investigations;
changes in applicable tax laws;
changes in general conditions in the United States, Canadian and global economies or financial markets, including those resulting from war, incidents of terrorism or responses to such events;
changes in key personnel;
sales of Class A shares by us or members of our management team;
termination of lock-up agreements with our management team and principal stockholders;
the granting or exercise of employee stock options;
volume of trading in our Class A shares; and
the realization of any risks described under “Risk Factors.”

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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 and yieldcos. The changes frequently appear to occur without regard to the operating performance of the affected companies. Hence, the price of our Class A shares could fluctuate based upon factors that have little or nothing to do with our company, and these fluctuations could materially reduce the share price of our Class A shares and cause stockholders to lose all or part of their investment. Further, in the past, market fluctuations and price declines in a company’s stock have led to securities class action litigation. If such a suit were to arise, it could have a substantial cost and divert our resources regardless of the outcome.
We incur increased costs and demands upon management as a result of complying with the laws and regulations affecting public companies, which could harm our operating results.
As a public company, we incur significant legal, accounting, investor relations and other expenses that we did not incur as a private company, including costs associated with public company reporting requirements. We also have incurred and will incur costs associated with current corporate governance requirements, Section 404 and other provisions of the Sarbanes-Oxley Act and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC, the Canadian Securities Administrators and the stock exchanges on which our Class A shares are traded.
The expenses incurred by public companies for reporting and corporate governance purposes have increased dramatically over the past several years. Greater expenditures may be necessary in the future with the advent of new laws and regulations pertaining to public companies. If we are not able to comply with these requirements in a timely manner, the market price of our Class A shares could decline and we could be subject to sanctions or investigations by the SEC, the Canadian Securities Administrators, the applicable stock exchanges or other regulatory authorities, which would require additional financial and management resources.
As a result of the FPA and FERC’s regulations in respect of transfers of control, absent prior authorization by FERC, neither we nor Pattern Development can convey, nor will an investor in our company generally be permitted to obtain, a direct and/or indirect voting interest in 10% or more of our issued and outstanding voting securities, and a violation of this limitation could result in civil or criminal penalties under the FPA and possible further sanctions imposed by FERC under the FPA.
We are a holding company with U.S. operating subsidiaries that are “public utilities” (as defined in the FPA) and, therefore, subject to FERC’s jurisdiction under the FPA. As a result, the FPA requires us or Pattern Development, as the case may be, either to (i) obtain prior authorization from FERC to transfer an amount of our voting securities sufficient to convey direct or indirect control over any of our public utility subsidiaries or (ii) qualify for a blanket authorization granted under or an exemption from FERC’s regulations in respect of transfers of control. Similar restrictions apply to purchasers of our voting securities who are a “holding company” under PUHCA, in a holding company system that includes a transmitting utility or an electric utility, or an “electric holding company,” regardless of whether our voting securities were purchased in our initial public offering, subsequent offerings by us or Pattern Development, in open market transactions or otherwise. A purchaser of our voting securities would be a “holding company” under the PUHCA and an electric holding company if the purchaser acquired direct or indirect control over 10% or more of our voting securities or if FERC otherwise determined that the purchaser could directly or indirectly exercise control over our management or policies (e.g., as a result of contractual board or approval rights). Under the PUHCA, a “public-utility company” is defined to include an “electric utility company,” which is any company that owns or operates facilities used for the generation, transmission or distribution of electric energy for sale, and which includes EWGs such as our U.S. operating subsidiaries. Accordingly, absent prior authorization by FERC or an increase to the applicable percentage ownership under a blanket authorization, for the purposes of sell-side transactions by us or Pattern Development and buy-side transactions involving purchasers of our securities that are electric holding companies, no purchaser can acquire 10% or more of our issued and outstanding voting securities. A violation of these regulations by us or Pattern Development, as sellers, or an investor, as a purchaser of our securities, could subject the party in violation to civil or criminal penalties under the FPA, including civil penalties of up to $1 million per day per violation and other possible sanctions imposed by FERC under the FPA.
As a result of the FPA and FERC’s regulations in respect of transfers of control, and consistent with the requirements for blanket authorizations granted thereunder or exemptions therefrom, absent prior authorization by FERC, no purchaser of our common shares in the open market, or in subsequent offerings of our voting securities, will be permitted to purchase an amount of our securities that would cause such purchaser and its affiliate and associate companies to collectively hold 10% or more of our voting securities outstanding. Additionally, investors should manage their investment in us in a manner consistent with FERC’s regulations in respect of obtaining direct or indirect “control” of our company. Accordingly, absent prior authorization by FERC, investors in our common shares are advised not to acquire a direct and/or indirect voting interest in 10% or more of our issued and outstanding voting securities, whether in connection with an offering by us or Pattern Development or in open market purchases or otherwise.

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Provisions of our organizational documents and Delaware law might discourage, delay or prevent a change of control of our company or changes in our management and, as a result, depress the trading price of our Class A shares.
Our amended and restated certificate of incorporation and amended and restated bylaws contain provisions that could discourage, delay or prevent a change in control of our company or changes in our management that the stockholders of our company may deem advantageous. These provisions:
authorize the issuance of blank check preferred stock that our Board of Directors could issue to increase the number of outstanding shares and to discourage a takeover attempt;
prohibit our stockholders from calling a special meeting of stockholders;
prohibit stockholder action by written consent, which requires all stockholder actions to be taken at a meeting of our stockholders;
provide that the Board of Directors is expressly authorized to adopt, or to alter or repeal our bylaws; and
establish advance notice requirements for nominations for election to our Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.
These anti-takeover defenses could discourage, delay or prevent a transaction involving a change in control of our company. These provisions could also discourage proxy contests and make it more difficult for stockholders to elect directors of their choosing and cause us to take corporate actions other than those desired.
Future sales of our shares in the public market could lower our Class A share price, and any additional capital raised by us through the sale of equity or convertible debt securities may dilute stockholders’ ownership in us and may adversely affect the market price of our Class A shares.
In February 2015, we completed a follow-on offering of our Class A shares. In total 12,000,000 Class A shares were sold. Of this amount, we issued and sold 7,000,000 Class A shares and Pattern Development, a selling shareholder, sold 5,000,000 of our Class A shares. In addition, in July 2015, we completed another follow-on offering of our Class A shares in which we issued and sold 5,435,000 Class A shares. Concurrently, in July 2015, we issued $225.0 million aggregate principal amount of 4.00% Convertible Senior Notes due 2020. If we sell, or if Pattern Development sells, additional large numbers of our Class A shares, or if we issue a large number of shares of our Class A common stock in connection with future acquisitions, financings, or other circumstances, the market price of our Class A shares could decline significantly. Moreover, the perception in the public market that we or Pattern Development might sell Class A shares could depress the market price of those shares.
In addition, in May 2014, Pattern Development entered into a loan agreement pursuant to which it may pledge our Class A shares owned by it to secure a $100.0 million loan. As of December 31, 2015, substantially all of our Class A shares owned by Pattern Development, approximating 17.0 million Class A shares, have been pledged as security for such loan. If Pattern Development were to default on its obligations under the loan, the lenders would have the right to sell shares to satisfy Pattern Development’s obligation. Such an event could cause our stock price to decline. We cannot predict the size of future issuances of our Class A shares or sales of securities convertible into our Class A shares, or the effect, if any, that any such future issuances or sales will have on the market price of our shares. Sales of substantial amounts of our shares (including sales pursuant to Pattern Development’s registration rights and shares issued in connection with an acquisition) or securities convertible into our shares, or the perception that such sales could occur, may adversely affect prevailing market prices for our Class A shares.

Item 1B.
Unresolved Staff Comments .  
None
 

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Item 2.
Properties.
Leased Facilities
Our corporate headquarters and executive offices are located in San Francisco, California. Effective January 1, 2016, Pattern Development assigned to us all of Pattern Development's rights, title and interest in its existing San Francisco office lease. Concurrently with the lease assignment, we entered into an extension through 2026 of such San Francisco office lease, and agreed to a future expansion of additional office space. In addition, we conduct business activities from Pattern Development-leased office facilities in Houston, San Diego, Santiago and Toronto, as well as additional Pattern Development newly leased office facilities in San Francisco. In February 2016, we have also signed a lease for new office facilities in Houston effective July 2016, to replace the Pattern Development-leased office facilities in Houston upon the termination of such lease in June 2016. We believe that our existing office facilities are in good condition and suitable for the conduct of our business.
Our Projects
We own interests in 16 operating wind power 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. 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. We typically finance our wind projects through project entity specific debt secured by each project's assets with no recourse to us.
Operating Projects
Gulf Wind
Gulf Wind is a 283 MW project located in Kenedy County, Texas. The project consists of 118 2.4 MW Mitsubishi MWT95/2.4 turbines and commenced commercial operations in 2009. Pattern Development acquired this operational project in March 2010. On July 28, 2015, we acquired the noncontrolling interests in the Gulf Wind project, resulting in our 100% ownership of the membership interests in the Gulf Wind project. Prior to these acquisitions, Gulf Wind was held by a tax equity partnership with MetLife. We, Pattern Development, and MetLife previously owned approximately 40%, 27% and 33% of Gulf Wind, respectively.
The project is located in the South Zone of the ERCOT market and sells 100% of its power output into the ERCOT market, receiving the locational marginal price, or "LMP." Approximately 58% of the project’s expected annual electricity generation has been hedged under a 10-year fixed-for-floating swap with Morgan Stanley. This financial hedging agreement settles using the South Trading Hub hourly LMP, weighted by the settlement volume in each hour.
The project is connected to the Electric Transmission Texas 345 kV transmission system and is entirely on land owned by a single private landowner. Gulf Wind entered into an easement agreement with a single landowner on May 9, 2007 for an initial term of 30 years and with an option to extend for an additional 10 years. The land, which is primarily grassland and dunes, is part of a very large ranch. In addition to our wind operations, the ranch is also used for cattle raising, oil & gas production, and private hunting outings. Due to the afternoon sea breeze effect along the coast, Gulf Wind benefits from an average daily wind production profile that generally follows the typical electricity demand load profile, which is heaviest during the daytime.
Hatchet Ridge
Hatchet Ridge is a 101 MW project located near Burney, California. The project consists of 44 2.3 MW Siemens turbines and commenced commercial operations in December 2010. The project is connected to the PG&E transmission system.
The project sells 100% of its electricity generation, including environmental attributes, to PG&E under a 15-year PPA that expires in 2025. The price under the PPA is a stated price per MWh, adjusted by seasonal time of day multipliers, with no escalation. Hatchet Ridge is required to post performance security in the amount of $21.2 million to secure damages under the PPA. The PPA also contains customary termination and event of default provisions. Under the terms of the PPA, Hatchet Ridge is required to pay liquidated damages for failure to produce a certain amount of energy in each of two consecutive years.
The project is located in Shasta County, California and is entirely on land owned by two private landowners, subject to 30-year wind power ground lease agreements.

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St. Joseph
St. Joseph is a 138 MW project located near St. Joseph, Manitoba, just north of the U.S. border. The project consists of 60 2.3 MW Siemens turbines and commenced commercial operations in April 2011. The project is connected to the Manitoba Hydro transmission system. St. Joseph was the second commercial wind power project, and is the largest, in Manitoba.
The project sells 100% of its electricity generation, including environmental attributes, to Manitoba Hydro under a 27-year PPA that expires in 2039. The price under the PPA is a stated price per MWh at inception of the PPA, with approximately 20% of the stated price escalating annually at the consumer price index for Canada, or "Canadian CPI." The project additionally receives the ecoEnergy federal incentive of C$10/MWh for approximately ten years for up to 423,108 MWh of production per year. Under the PPA, if there is a sale of the project, Manitoba Hydro has a right of first offer to purchase the St. Joseph project for a fixed minimum purchase price on terms specified by us. In addition to customary termination and event of default provisions, the PPA will terminate upon the exercise by Manitoba Hydro of its right of first offer to purchase the St. Joseph project, and St. Joseph will trigger an event of default, if after the first three contract years, it fails to supply at least 80% of certain minimal energy obligations for two consecutive years.
The project is located on approximately 125 square kilometers of agricultural land in the Rural Municipalities of Montcalm and Rhineland, Province of Manitoba. The project is constructed on privately owned lands pursuant to right-of-way agreements with 64 private landowners, with 40-year terms and all on substantially the same form of agreement covering all of turbine sites, collection lines, roads and an operations and maintenance building for the project. In addition, the project purchased a small parcel of property for the project substation.
Spring Valley
Spring Valley is a 152 MW project located in White Pine County, Nevada. The project consists of 66 2.3 MW Siemens turbines and commenced commercial operations in August 2012. The project is connected to the NV Energy transmission system. Spring Valley was Nevada’s first commercial wind power project.
The project sells 100% of its electricity generation, including environmental attributes, to NV Energy, under a 20-year PPA that expires in 2032. The price under the PPA is a stated price per MWh escalating at 1.0% per year. Spring Valley is required to reimburse NV Energy for replacement costs for any annual energy shortfall and post operating security in the amount of $6.3 million for the performance of its obligations under the PPA. The PPA also contains customary termination and event of default provisions.
The project is located in White Pine County, Nevada on federal land administered by the Bureau of Land Management. Spring Valley was granted a right-of-way from the Bureau of Land Management with a 30-year term, which terminates on December 31, 2040.
Santa Isabel
Santa Isabel is a 101 MW project located on the south coast of Puerto Rico. The project consists of 44 2.3 MW Siemens turbines and commenced commercial operations during the fourth quarter of 2012. The project is connected to the Puerto Rico Electric Power Authority, or "PREPA," transmission system. Santa Isabel is Puerto Rico’s first commercial wind power project and is reflective of the Puerto Rican government’s efforts to diversify its energy sources away from fossil fuels by fostering local renewable energy projects.
The project sells 100% of its electricity generation including environmental attributes to PREPA under a 20-year PPA, expiring in 2030, with automatic 5-year extensions unless terminated at the end of any term or extension by us, and PREPA may terminate after year 25 if there is a liquid spot-market for electricity or the agreement has been in effect for 30 years. Under the PPA, PREPA has agreed to purchase electricity from us subject to a 75 MW per hour cap, with such cap increasing to 95 MW during certain hours of certain months. If the project is capable of generating electricity in excess of the applicable cap, PREPA has the option, but not the obligation, to purchase any such surplus electricity actually generated at the PPA price. The price for energy under the PPA and the price for RECs under a separate purchase agreement are both a stated price per MWh. Each price escalates at 1.5% per year. In the case that project electricity generation exceeds a threshold multiple of contractual electricity generation in a given year, the price for energy under the PPA reduces until output drops below contractual output for such year. Santa Isabel is required to post operating security in the amount of $3.0 million for the performance of its obligations under the PPA. In addition to customary termination and event of default provisions, the PPA may terminate if Santa Isabel fails to generate a threshold energy output during any 12 consecutive months.
The project is located on 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

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infrastructure, including all turbine sites, collection lines, roads, substation and operations and maintenance buildings for the project. The project also has entered into transmission line leases for the transmission line corridor from the project substation to the point of interconnection with PREPA with four private landowners.
Ocotillo
Ocotillo is a 265 MW project located in western Imperial County, California. The project consists of 112 2.37 MW Siemens turbines. We initially commenced commercial operations on 223 MW of Ocotillo’s electricity generating capacity during the fourth quarter of 2012 and commenced commercial operations on the remaining 42 MW of electricity generating capacity from Ocotillo’s additional 18 turbines in July 2013. The project connects to the San Diego Gas & Electric, or "SDG&E," 500 kV transmission system and has a large generator interconnection agreement with SDG&E and CAISO.
The project sells 100% of its electricity generation, including capacity and environmental attributes, to SDG&E under a 20-year PPA. The PPA has a stated price per MWh with no escalation. Ocotillo is required to post performance security in the amount of $26.7 million to secure damages. The PPA also contains customary termination and event of default provisions. Under the PPA, Ocotillo is required to pay liquidated damages for failure to produce a certain amount of energy in the two previous years.
Ocotillo is the subject of active lawsuits brought by a variety of project opponents. See Item 3 "Legal Proceedings."
The project is located on approximately 12,500 acres in Imperial County, California 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
South Kent is a 270 MW project located in the municipality of Chatham-Kent in southern Ontario and consists of 124 2.3 MW class Siemens turbines. The project connects to the Hydro One Networks, Inc., or "HONI," 230 kV transmission system at the existing Chatham switching station. The South Kent project commenced construction in the first quarter of 2013 and commenced commercial operations in March 2014.
The project sells 100% of its electricity generation, including environmental attributes, to the IESO under a 20-year PPA. The PPA has a stated price, which indexes at Canadian CPI from September 2009 until December 31 of the year prior to commencement of commercial operations which was in March 2014; 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 PPA also provides for compensation by the IESO for certain energy the project is unable to produce due to curtailments directed by the grid operator.
The project is a 50/50 joint venture between us and Samsung. Samsung has customary rights to purchase our interest in South Kent upon any subsequent sale of the project by us.
The project is located on approximately 165 distinct private land parcels and includes a conglomeration of multiple acquired wind power projects and greenfield acquired lands. The project has renegotiated and standardized each of the land agreements that were assumed along with the acquired projects. All land parcels containing project infrastructure are contracted under registered right-of-way agreements, providing for real estate interests in favor of the project in the form of easements-in-gross in respect of each land parcel, enforceable for a term of not less than 40 years.
The project’s generation tie to the HONI transmission system is located 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.
El Arrayán
El Arrayán is a 115 MW project located on the coast of Chile, near Ovalle in the Fourth Region. We owned a 31.5% indirect interest in El Arrayán prior to acquiring an additional 38.5% interest in order to obtain majority control (70%) of the project, as a part of our

52




growth strategy. The project consists of 50 2.3 MW Siemens turbines and began commercial operations in June 2014. The project is connected to the Sistema Interconectado Central’s, or "SIC," 220kV transmission system. El Arrayán is 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 sells electricity generation into the Chilean spot-market at the prevailing market price at the time of sale. Approximately 70% of the project’s expected output has been hedged under a 20-year fixed-for-floating swap with Minera Los Pelambres, or "MLP," one of the world’s largest copper mines. The hedge price escalates at 1.5% annually. 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 purely a cost pass-through arrangement intended to firm the power supplied to MLP, under which MLP will reimburse the project for amounts supplied. MLP is a subsidiary of AMSA, who owns a 30% noncontrolling interest in the project.
The project is located on 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 a 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 agreements with four private landowners 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 infrastructure including the turbines and operational facilities, the interconnecting transmission line and all main roads which are not public.
Panhandle 1
Panhandle 1 is a 218 MW project located in the Texas Panhandle, in Carson County, Texas. The project consists of 118 GE 1.85 MW turbines and commenced commercial operations in June 2014.
The project is located in the West zone of the ERCOT market and sells 100% of its power output into the ERCOT market, receiving the LMP from ERCOT for its actual generation. Approximately 80% of the project’s expected annual electricity generation has been hedged under a physical power hedge with an affiliate of Citigroup with a tenor in excess of ten years. This hedging agreement settles using the North Trading Hub hourly LMP weighted by the settlement volume in each hour. The hourly notional settlement volume varies to match the project’s expected hourly production profile. Panhandle 1’s obligations under the hedge are secured by a first priority lien on substantially all of the assets of Panhandle 1 and a first priority lien on the membership interests in the project entity.
The project is connected to the ERCOT grid via a new 345kV transmission line owned by Cross Texas Transmission, LLC, which is part of the Texas Competitive Renewable Energy Zone ("CREZ") program. The project is located on private land pursuant to 40-year easement agreements with approximately 30 private landowners, all of which agreements are in substantially the same form. The project’s operations and maintenance building is shared with the neighboring Panhandle 2 project.
Panhandle 2
Panhandle 2 is a 182 MW project located in the Texas Panhandle in Carson County, Texas. The project consists of 79 2.3 MW Siemens turbines and commenced commercial operations in November 2014.
The project is located in the West zone of the ERCOT market and sells 100% of its power output into the ERCOT market, receiving the LMP from ERCOT for its actual generation. Approximately 80% of the project’s expected annual electricity generation has been hedged under a physical power hedge with an affiliate of Morgan Stanley with a tenor in excess of ten years. This hedging agreement settles using the North Trading Hub hourly LMP weighted by the settlement volume in each hour. The hourly notional settlement volume varies to match the project’s hourly average production profile. Panhandle 2’s obligations under the hedge are secured by a first priority lien on substantially all of the assets of Panhandle 2 and a first priority lien on the membership interests in the project entity.
The project is connected to the ERCOT grid via a new 345kV transmission line owned by Cross Texas Transmission, LLC, which is part of the Texas CREZ program. The project is located on private land pursuant to 40-year easement agreements with approximately 15 private landowners, all of which agreements are in substantially the same form. The project’s operations and maintenance building is shared with the neighboring Panhandle 1 project.

53




Grand
Grand is a 149 MW project located in Haldimand County in southern Ontario, and consists of 67 2.3 MW class Siemens turbines. The project is connected to the HONI transmission system via a shared transmission line that is co-owned with an adjacent solar facility. The project has executed a co-ownership agreement with that solar facility that ensures unimpeded access across the shared transmission line to the HONI system. The Grand project commenced construction in the third quarter of 2013 and commenced commercial operations in December 2014.
The project sells 100% of its electricity generation, including environmental attributes, to the IESO under a 20-year PPA. The PPA has a stated price, which indexes at Canadian CPI from September 2009 until December 31 of the year prior to commencement of commercial operations which was in the fourth quarter of 2014; 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 PPA also provides for compensation by the IESO for certain energy the project is unable to produce due to curtailments directed by the grid operator.
The project is a 45/45/10 joint venture between us, Samsung and the Six Nations. Samsung has customary rights to purchase our interest in Grand upon any subsequent sale of the project by us.
The project occupies a combination of leased privately owned farm properties (as to 58 turbines) and leased lands owned and managed by Ontario Infrastructure and Lands Corporation ("OILC") (as to 9 turbines). All parcels containing project infrastructure are governed by the terms of standardized leases and easements with terms of a minimum of 45 years (including all renewal periods). The project’s transmission line is located primarily on a major public road allowance pursuant to a Road Use Agreement (with a registered easement).
The transmission facilities also include a collector substation located on OILC lands, underground transition stations located on two private properties and an interconnection station located on lands controlled by a local aggregate producer. Collector lines and ancillary project infrastructure are located within a public road allowance throughout Haldimand County pursuant to a Road Use Agreement with the municipality.
Logan’s Gap
Logan’s Gap is a 200 MW project in Comanche County, Texas. The project consists of 87 Siemens 2.3 MW wind turbines. Located near the Dallas-Fort Worth area, Logan’s Gap is our fourth wind project in Texas, serving three different regions throughout the state.
The project is located in the North zone of the ERCOT market and sells 100% of its power output into the ERCOT market, receiving the LMP from ERCOT for its actual generation. Approximately 58% of the expected output of the project is sold under a 10-year power purchase agreement with Wal-Mart Stores, Inc. An additional 17% of the project’s expected annual electricity generation has been hedged under a 13-year fixed-for-floating physical power hedge with an affiliate of the Bank of America Merrill Lynch. Both the power purchase agreement and the physical hedge settle using the North Trading Hub hourly LMP weighted by the settlement volume in each hour. The hourly notional settlement varies to match the project’s expected hourly production profile. Logan’s Gap’s obligations under the PPA are secured by a Letter of Credit and the obligations under the hedge are secured by a first priority lien on substantially all of the assets of Logan’s Gap and a first priority lien on the membership interests in the project entity.
The project connects to Oncor’s 138kV Comanche-Zephyr line, which crosses the project site and supplies power to the Dallas-Fort Worth area. The project is located on private land pursuant to 30-year easement agreements with approximately 15 private landowners, all of which agreements are in substantially the same form.
Amazon Wind Farm Fowler Ridge
Amazon Wind Farm Fowler Ridge is a 150 MW project located in Benton County, Indiana. The project consists of 65 2.3 MW Siemens turbines and commenced commercial operations in December 2015.
The project has a 13-year power purchase agreement with wholly-owned subsidiary of Amazon Web Services, or "Amazon", that began in January 2016. During the first month of the PPA, 50% of the production will be sold to Amazon. This amount will increase over an 18 month period until 100% of the production is being purchased by Amazon. During this period, the balance of the production will be sold in the PJM wholesale market.

54




The project is connected to the PJM grid via common transmission facilities that are shared with Fowler Ridge phases I, II and III to an existing 345kV transmission switching station at the Indiana Michigan Dequine Switching Station, where the facility will interconnect to the connecting utility’s 345 kV transmission line, and as further specified in the generator interconnection agreement between the independent system operator, the connecting utility and the seller. The common transmission facilities are owned by all four phases of the Fowler Ridge Wind Project and are operated and maintained by British Petroleum. The project is located on private land pursuant to 30-year easement agreements with approximately 69 private landowners, all of which agreements are in substantially the same form.
Post Rock
Post Rock is a 201 MW project located in Ellsworth and Lincoln Counties, Kansas. The project consists of 134 1.5 MW GE turbines and commenced commercial operations in October 2012. We acquired the project from the original developer on May 15, 2015.
The project sells 100% of its power output under a long-term power purchase agreement with Westar Energy. Westar Energy has a right to extend the agreement by five years without any change in price.
The project includes a 230 KV transmission line, which runs approximately 31 miles from the project substation to the point of interconnection at the Midwest Energy Rice County Substation. The project land is controlled by a 20-year standard lease renewal term option beyond the initial 40 years and pursuant to an easement agreement with 100 landowners for royalty payments and participation payments.
Lost Creek
Lost Creek is a 150 MW project located in King City, Missouri. The project consists of 100 1.5 MW GE turbines and commenced commercial operations in May 2010. We acquired the project from the original developer on May 15, 2015.
The project sells 100% of its power output under a long-term power purchase agreement with Associated Electric Cooperative Incorporated ("AECI"). AECI has the option to extend the term to a mutually agreeable date at a price equal to 95% of the prevailing market price, as determined by a third party consultant, or enter into exclusive negotiations to determine a new rate.
This project interconnects to a new 161 kV transmission line that is owned and operated by NW Electric Cooperative, a member of AECI. The project land is controlled by a 25-year standard lease term and pursuant to easement agreements with 59 landowners.
K2
K2 is a 270 MW project located in Goderich, Ontario. The project consists of 140 2.3 MW class Siemens turbines and commenced commercial operations in May 2015.
The project sells 100% of its power output and environment attributes under a 20-year power purchase agreement with the IESO. The PPA has a stated price, which indexes at Canadian CPI from September 2009 until December 31 of the year prior to commencement of commercial operations which was in May 2015; 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 PPA also provides for compensation by the IESO for certain energy the project is unable to produce due to curtailments directed by the grid operator.
The project is located on private land pursuant to 30-year easement agreements with approximately 82 private landowners, all of which agreements are in substantially the same form.

Item 3.
Legal Proceedings.
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, including one in state court, were filed by various local opposition groups alleging that the Approvals were not appropriately issued. In three lawsuits, the plaintiffs sought preliminary equitable relief to enjoin

55




the construction of the project while the court decided the claims, and in each instance, the court rejected such request and allowed project construction to continue. The project has since been completed and has achieved commercial operations. In addition, the courts had subsequently dismissed all of the lawsuits. The time to appeal two of the dismissed cases has lapsed. The appeal of the state lawsuit had been abandoned. Three of the dismissals were appealed to the U.S. Court of Appeals for the Ninth Circuit. Oral arguments were heard in November 2015, and the appeals court has subsequently issued a decision in one of the appeals in which it affirmed the decision of the lower court.
In addition, during the third quarter of 2015, rights to appeal prior decisions granting the Renewable Energy Approval, or "REA," under Ontario's Environmental Protection Act for our K2 facility were exhausted without further appeal. As a result, a stay of a previously filed civil suit against the K2 facility pending final determination of the REA was lifted, allowing such suit to move forward if the claimants so choose to continue such suit. Such civil suit had claimed, among other things, nuisance based on both the construction and operation of the facility.
We do not believe these proceedings will have a material adverse effect on our business, financial position or liquidity based on the information currently available to us, principally because attempts to enjoin the construction of the project have failed, and, subject to the pending appeals described above, the actively adjudicated lawsuits have all been dismissed or appeals exhausted. We believe, but can give no assurance, that the remaining litigation will ultimately be resolved favorably to the respective project.
Other Proceedings
We are also subject, from time to time, to various other routine legal proceedings and claims arising out of the normal course of business. These proceedings primarily involve claims from landowners related to calculation of land royalties and warranty claims we initiate against equipment suppliers. The outcome of these legal proceedings and claims cannot be predicted with certainty. Nevertheless, we believe the outcome of any of such currently existing proceedings, even if determined adversely, would not have a material adverse effect on our financial condition or results of operations. 
Item 4.
Mine Safety Disclosures.
Not applicable.

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PART II
 
Item 5.
Market for Registrant’s Common Equity and Related Stockholder Matters.
Our Class A common stock began trading on September 27, 2013 on the NASDAQ Global Market under the trading symbol “PEGI” and on the Toronto Stock Exchange (“TSX”) under the trading symbol “PEG.” In July 2015, our stock was moved to the NASDAQ Global Select Market. On February 24, 2016, the last reported sale price of our Class A common stock on the NASDAQ Global Select Market was $16.40 per share and on the TSX was C$22.47 per share.
The following table sets forth, for the periods indicated, the high and low sales prices for our Class A common stock on the NASDAQ Global Select Market:  
 
 
2015
 
2014
 
 
High
 
Low
 
High
 
Low
Fourth Quarter
 
$
24.09

 
$
16.96

 
$
32.03

 
$
22.68

Third Quarter
 
$
29.81

 
$
18.18

 
$
34.51

 
$
29.61

Second Quarter
 
$
32.00

 
$
27.13

 
$
34.15

 
$
24.35

First Quarter
 
$
31.20

 
$
24.13

 
$
31.79

 
$
25.82

The following table sets forth, for the periods indicated, the range of high and low sales prices for our Class A common stock on the TSX:
 
 
2015
 
2014
 
 
High
 
Low
 
High
 
Low
Fourth Quarter
 
C$
31.58

 
C$
22.79

 
C$
35.73

 
C$
26.63

Third Quarter
 
C$
38.66

 
C$
24.75

 
C$
36.70

 
C$
32.51

Second Quarter
 
C$
38.20

 
C$
32.96

 
C$
35.39

 
C$
26.82

First Quarter
 
C$
38.50

 
C$
28.81

 
C$
34.99

 
C$
26.64

On July 28, 2015, we completed an underwritten public offering of our Class A common stock. In total, 5,435,000 shares of our Class A common stock were sold. We generated net proceeds of approximately $120.8 million after deduction of underwriting discounts, commissions and transaction expenses. As a result, Pattern Development's interest in us was diluted from approximately 25% to 23%.

On February 9, 2015, we completed a follow-on offering of our Class A common stock, under which 12,000,000 shares of Class A common stock were sold. Of this, we issued and sold 7,000,000 shares of our Class A common stock, and Pattern Development sold 5,000,000 shares of its holdings in our Class A common stock. We received proceeds of approximately $196.2 million, net of underwriting discounts and commissions and offering expenses. We did not receive any proceeds from the sale of shares sold by Pattern Development. As a result of this transaction, Pattern Development’s ownership interest in us decreased to approximately 25%, following which it was no longer entitled to certain approval rights pursuant to the Shareholder Approval Rights Agreement dated October 2, 2013, and such agreement expired.
Holders of Record
Because many of our shares of Class A common stock are held by brokers and other institutions on behalf of stockholders, we are unable to estimate the total number of stockholders represented by these record holders. As of February 24, 2016, there were approximately 10 stockholders of record of our Class A common stock.

57




Stock performance chart
This performance graph shall not be deemed “soliciting material” or to be “filed” with the SEC for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the "Exchange Act," or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing of Pattern Energy under the Securities Act of 1933, as amended, or the "Securities Act."
The following graph shows a comparison from September 27, 2013 (the date our Class A common stock commenced trading on the NASDAQ Global Market) through December 31, 2015 of the cumulative total stockholder return for our Class A common stock, the NASDAQ Composite Index (“NASDAQ Composite”) and the Bloomberg Global Wind Index. The graph assumes that $100 was invested at the market close on September 27, 2013 in the Class A common stock of Pattern Energy, the NASDAQ Composite and the Bloomberg Global Wind Index and also assumes reinvestments of dividends. The stock price performance of the following graph is not necessarily indicative of future stock price performance.



58




Cash Dividend to Investors
We intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A shares. The following table sets forth the dividends declared on shares of Class A common stock for the periods indicated. On November 26, 2013, we announced the initiation of a quarterly dividend on our Class A common stock. On February 24, 2016, we increased our dividend to $ 0.3810 per Class A share, or $ 1.524 per Class A share on an annualized basis, commencing with respect to dividends paid on April 29, 2016 to holders of record on March 31, 2016 .
 
Dividends Declared
2016
 
First Quarter
$
0.3810

2015

Fourth Quarter
$
0.3720

Third Quarter
$
0.3630

Second Quarter
$
0.3520

First Quarter
$
0.3420

2014

Fourth Quarter
$
0.3350

Third Quarter
$
0.3280

Second Quarter
$
0.3220

First Quarter
$
0.3125

We have established our quarterly dividend level based on a targeted cash available for distribution payout ratio of 80% both prior to and following the Conversion Event, after considering the annual cash available for distribution that we expect our projects will be able to generate following the commencement of commercial operations at all of our construction projects and with due regard to retaining a portion of the cash available for distribution to grow our business. We intend to grow our business primarily through the acquisition of operational and construction-ready power projects, which, we believe, will facilitate the growth of our cash available for distribution and enable us to increase our dividend per Class A share over time. However, the determination of the amount of cash dividends to be paid to holders of our Class A shares will be made by our Board of Directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant. See Item 1A Risk Factors —Risks Related to Ownership of our Class A Shares—Risks Regarding our Cash Dividend Policy.”
We expect to pay a quarterly dividend on or about the 30th day following each fiscal quarter to holders of record of our Class A shares on the last day of such quarter.
Our cash available for distribution is likely to fluctuate from quarter to quarter, perhaps significantly, as a result of variability in wind conditions and other factors. Accordingly, during quarters in which we generate cash available for distribution in excess of the amount required to pay our stated quarterly dividend, we may reserve a portion of the excess to fund dividends in future quarters. In addition, we may use sources of cash not included in our calculation of cash available for distribution, such as certain net cash provided by financing and investing activities, to pay dividends to holders of our Class A 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. See Item  7 “Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Metrics—Cash Available for Distribution."

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Repurchase of Equity Securities
The table below provides information with respect to repurchases of our Class A common stock during the fourth quarter ended December 31, 2015 . All shares were tendered to us in satisfaction of employee tax withholding obligations upon the vesting of restricted stock grants under our 2013 Equity Incentive Award Plan. We currently do not have a stock repurchase plan in place.  
Period
 
Total Number of
Shares Purchased
 
Average Price
Paid Per Share
10/1/15-10/31/15
 
323

 
$
23.39

11/1/15-11/30/15
 
323

 
$
18.23

12/1/15-12/31/15
 
27,163

 
$
18.99

 
 
27,809

 
$
19.03

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

Item 6.
Selected Financial Data.
Set forth below is our summary historical consolidated financial data. The consolidated statements of operations data for the years ended December 31, 2015 , 2014 and 2013 and the consolidated balance sheet data as of December 31, 2015 and 2014 are derived from our audited consolidated financial statements included in this Form 10-K. The consolidated statements of operations data for the years ended December 31, 2012 and 2011 and the consolidated balance sheet data as of December 31, 2013, 2012 and 2011 are derived from our audited consolidated financial statements not included in this Form 10-K. This information may not be indicative of our future results of operations, financial position and cash flows and should be read in conjunction with the consolidated financial statements and notes thereto and Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations ” presented elsewhere in this Form 10-K. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable.

60




 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
 
2012
 
2011
 
 
(in thousands, except per share data)
Statement of operations data:
 
 
 
 
 
 
 
 
 
 
Total revenue
 
$
329,831

 
$
265,493

 
$
201,573

 
$
114,528

 
$
135,859

Operating income
 
34,440

 
54,981

 
47,728

 
19,022

 
55,424

Net (loss) income
 
(55,607
)
 
(39,999
)
 
10,072

 
(13,376
)
 
25,906

Net loss attributable to noncontrolling interest
 
(23,074
)
 
(8,709
)
 
(6,887
)
 
(7,089
)
 
16,981

Net (loss) income attributable to Pattern Energy
 
$
(32,533
)
 
$
(31,290
)
 
$
16,959

 
$
(6,287
)
 
$
8,925

Less: Net income attributable to Pattern Energy prior to the initial public offering on October 2, 2013
 
 
 
 
 
(30,295
)
 
 
 
 
Net loss attributable to Pattern Energy subsequent to the initial public offering
 
 
 


 
$
(13,336
)
 
 
 
 
Loss per share data:
 
 
 
 
 
 
 
 
 
 
Class A common stock: basic and diluted loss per share
 
(0.46
)
 
(0.56
)
 
(0.17
)
 
N/A

 
N/A

Class B common stock: basic and diluted loss per share
 

 
(0.49
)
 
(0.48
)
 
N/A

 
N/A

Dividends:
 
 
 
 
 
 
 
 
 
 
Dividends declared per Class A common share
 
1.43

 
1.30

 
0.31

 
N/A

 
N/A

Deemed dividends per Class B common share
 

 
1.41

 

 
N/A

 
N/A

Balance sheet data:
 
 
 
 
 
 
 
 
 
 
Total assets (1) (2)
 
3,829,592

 
2,795,287

 
1,872,233

 
1,999,347

 
1,362,272

Revolving credit facility
 
355,000

 
50,000

 

 

 

Convertible senior notes, net of financing costs
 
197,362

 

 

 

 

Long-term debt including current portion, net of financing costs (2)
 
1,218,524

 
1,413,858

 
1,217,820

 
1,254,187

 
839,394

Total liabilities
 
2,053,830

 
1,630,553

 
1,304,229

 
1,409,935

 
915,574

(1)
Total revenues and total assets increased during the years ended and as of December 31, 2015 and 2014 compared to the years ended and as of December 31, 2014 and 2013, respectively, primarily due to acquisitions and the commencement of operations at various project wind farms. For further details of acquisitions, see Note  3 , Acquisitions , in the notes to consolidated financial statements.
(2)
In 2015, we early adopted ASU 2015-03, “Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs." As a result, we reclassified deferred financing costs from other assets to long-term debt. In the table above, prior year presentation of long-term debt reflects the reclassification of deferred financing costs.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and related notes included elsewhere in this Form 10-K. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under Item 1A "Risk Factors" elsewhere in this Form 10-K. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See "Cautionary Notice Regarding Forward-Looking Statements."

Overview
We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued growth of our business. We hold interests in 16 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 2,282 MW. 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. Eighty-nine percent of the electricity to be generated by our projects will be sold under our power sale agreements which have a weighted average remaining contract life of approximately 14 years.

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We intend to maximize long-term value for our stockholders in an environmentally responsible manner and with respect for the communities in which we operate. Our business is built around three core values of creative energy and spirit, pride of ownership and follow-through, and a team first attitude, which guide us in creating a safe, high-integrity work environment, applying rigorous analysis to all aspects of our business, and proactively working with our stakeholders to address environmental and community concerns. Our financial objectives, which we believe will maximize long-term value for our stockholders, are to produce stable and sustainable cash available for distribution, selectively grow our project portfolio and our dividend per Class A share and maintain a strong balance sheet and flexible capital structure.
Our growth strategy is focused on the acquisition of operational and construction-ready power projects from Pattern Development and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per Class A share over time. Pattern Development is a leading developer of renewable energy and transmission projects. We believe Pattern Development’s ownership position in our company incentivizes Pattern Development to support the successful execution of our objectives and business strategy, including through the development of projects to the stage where they are at least construction-ready. Currently, Pattern Development has a 5,900 MW pipeline of development projects, all of which are subject to our right of first offer. We target achieving a total owned capacity of 5,000 MW by year end 2019 through a combination of acquisitions from Pattern Development and other third parties capitalizing on the large fragmented global renewable energy market. In addition, we expect opportunities in Japan and Mexico will form part of our growth strategy.
The discussion and analysis below has been organized as follows:
Factors that Significantly Affect our Business
Trends Affecting our Industry
Factors Affecting our Operational Results
Key Metrics
Results of Operations
Liquidity and Capital Resources
Sources of Liquidity
Uses of Liquidity
Description of Credit Agreements
Tax Equity Partnership Agreements
Critical Accounting Policies and Estimates

Factors that Significantly Affect our Business
Our results of operations in the near-term, as well as our ability to grow our business and revenue from electricity sales over time, could be impacted by a number of factors, including trends affecting our industry and factors affecting our operating results as discussed below:
Trends Affecting our Industry
Wind and solar power have been among the fastest growing sources of electricity generation in North America and globally over the past decade. This rapid growth is largely attributable to wind and solar power’s increasing cost competitiveness with other electricity generation sources, the advantages of wind and solar power over 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 renewable power include:
increased demand for renewable energy resulting from regulatory or policy initiatives. Notable initiatives include country, state or provincial RPS programs, and, in the U.S., the EPA’s 111d carbon regulations;
governmental incentives for renewable energy including feed-in-tariff regimes, carbon credits and the U.S. federal based production or investment tax credits, which were extended through December 2019 (wind) and December 2022 (solar), that improve the cost competitiveness of renewable energy compared to traditional sources;

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new demand created by corporate and industrial buyers directly procuring renewable electricity on a large scale;
efficiency and capital cost improvements in wind, solar and other renewable energy technologies, enabling wind and other forms of renewable energy to compete successfully in more markets;
environmental and social factors supporting increasing levels of wind, solar and other renewable technologies in the generation mix;
regulatory barriers increase the time, cost and difficulty of permitting new fossil fuel-fired facilities, notably coal, and nuclear facilities;
decommissioning of aging coal-fired and nuclear facilities is expected to leave a gap in electricity supply; and
policy initiatives to include such externalities as the cost of carbon pollution, methane leakage and water usage in conventional fossil fuel-fired electricity generation will increase costs of conventional generation.
In general, we continue to believe that there will be additional acquisition opportunities in the United States in the short term and that the longer-term growth trend will continue.
Our Outlook
Our projects are generally unaffected by short-term trends given that 89% of the electricity to be generated by our projects is to be sold under our fixed-price power sale agreements, which have a weighted average remaining life of approximately 14 years.
Our near-term growth strategy will focus on wind power projects, but will also include evaluation of solar power opportunities, and is largely insulated from the short-term trends. In September 2014, we announced the addition of our first solar project, the 104 MW Conejo Solar photovoltaic power project in Chile to our list of Identified ROFO projects, and in June of 2015 we added two Japanese solar projects to that list. We expect that most of our short-term growth will come from opportunities to acquire the Identified ROFO Projects, but we will evaluate unaffiliated third-party asset acquisition opportunities, as well.
Factors Affecting our Operational Results
The primary factors that will affect our financial results are (i) acquisitions and construction projects, (ii) integration with Pattern Development, (iii) electricity sales and energy derivative settlements of our operating projects, (iv) impact of derivative instruments, (v) project operations, and (vi) debt financing.
Acquisitions and Construction Projects
We construct our projects under fixed-price and fixed-schedule contracts with major equipment suppliers and experienced balance-of-plant construction companies. During 2015, we acquired Post Rock and Lost Creek, increased our interest in Gulf Wind, and, completed construction of Logan's Gap and Amazon Wind Farm Fowler Ridge, which increased operating capacity by 720 MW. During 2014, five of our construction projects achieved commercial operation and contributed 602 MW of additional operating capacity. In addition, in 2015, we acquired a one-third equity interest in K2 which increased our proportional capacity by 90 MW for a total proportional operating capacity of 292 MW for equity method investments. The acquisition of these projects significantly impacted our operating results and earnings from equity method investments. Our aggregate owned capacity is 2,282 MW.

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We expect that the acquisition of operational and construction-ready power projects from Pattern Development and other third parties will contribute to our operational results. Below is a summary of the Identified ROFO Projects that we expect to acquire from Pattern Development in connection with our Project Purchase Right:
 
 
 
 
 
 
 
 
 
 
 
 
Capacity (MW)
Identified
ROFO Projects
 
Status
 
Location
 
Construction
Start
(1)
 
Commercial
Operations
(2)
 
Contract
Type
 
Rated (3)
 
Pattern
Development-
Owned
(4)
Armow
 
Operational
 
Ontario
 
2014
 
2015
 
PPA
 
180

 
90

Meikle
 
In construction
 
British Columbia
 
2015
 
2016
 
PPA
 
180

 
180

Conejo Solar
 
In construction
 
Chile
 
2015
 
2016
 
PPA
 
104

 
84

Belle River
 
Securing final permits
 
Ontario
 
2016
 
2017
 
PPA
 
100

 
50

Henvey Inlet
 
Late stage development
 
Ontario
 
2016
 
2017
 
PPA
 
300

 
150

Mont Sainte-Marguerite
 
Late stage development
 
Québec
 
2016
 
2017
 
PPA
 
147

 
147

North Kent
 
Late stage development
 
Ontario
 
2016
 
2017
 
PPA
 
100

 
43

Broadview projects
 
Late stage development
 
New Mexico
 
2016
 
2017
 
PPA
 
324

 
259

Grady
 
Late stage development
 
New Mexico
 
2016
 
2017
 
PPA
 
220

 
176

Tsugaru
 
Late stage development
 
Japan
 
2015
 
2018
 
PPA
 
126

 
63

Ohorayama
 
Late stage development
 
Japan
 
2015
 
2017
 
PPA
 
33

 
31

Kanagi Solar
 
In construction
 
Japan
 
2014
 
2016
 
PPA
 
14

 
6

Futtsu Solar
 
Operational
 
Japan
 
2014
 
2016
 
PPA
 
42

 
19

 
 
 
 
 
 
 
 
 
 
 
 
1,870

 
1,298

(1)
Represents date of actual or anticipated commencement of construction.
(2)
Represents date of actual or anticipated commencement of commercial operations.
(3)
Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of wind and other conditions, a project or a turbine will not operate at its rated capacity at all times and the amount of electricity generated may be less than its rated capacity.
(4)
Pattern Development-owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW multiplied by Pattern Development’s percentage ownership interest in the distributable cash flow of the project.
Integration with Pattern Development
Our future net operating results should not be materially affected by the employee transfer, should it occur, as the consequential increase in general and administrative expense should be substantially or entirely offset by a reduction in related party general and administrative expense and an increase in related party other income. If the employee transfer should occur, there can be no assurance that Pattern Development’s business activity will remain constant, decrease or increase. Separately, we and the equity owners of Pattern Development have begun discussions regarding a potential investment by us in a portion of the business of Pattern Development. There can be no assurance that any such transaction would in fact occur and at this time, the timing, structure, value and funding of any such transaction, should it occur, is uncertain.
Electricity Sales and Energy Derivative Settlements of our Operating Projects
Our electricity sales and energy derivative settlements are primarily determined by the price of electricity and any environmental attributes we sell under our power sale agreements and the amount of electricity that we produce, which is in turn principally the result of the wind conditions at our project sites and the performance of our equipment. We base our estimates of each project’s capacity to generate electricity on the findings of our internal and external experts’ long-term meteorological studies, which include on-site data collected from equipment on the property and relevant reference wind data from other sources, as well as specific equipment power curves and estimates for the performance of our equipment over time. Eighty-nine percent of the electricity to be generated across our projects is currently committed under long-term, fixed-price power sale agreements which have a weighted average remaining contract life of approximately 14 years.
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

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exceeded 75% of the time. Similarly, the P25 output level would be exceeded 25% of the time. We often use P95, P90 and P75 production levels to plan ahead for low-wind years, while recognizing that we should also have corresponding high-wind years.
In addition to annual P50 variability, we also expect seasonal variability to occur. Variability increases as the period of review shortens, so it is likely that we will experience more variability in monthly or quarterly production than we do for annual production. Therefore, our periodic cash flow and payout ratios will also reflect more variability during periods shorter than a year. As a result, we use cash reserves to help manage short term production and cash flow variability.
When analyzed together, a portfolio’s probability of exceeding a specific output level changes when all the projects are considered as a portfolio instead of on a stand-alone basis. Due to the geographical separation between our projects, the uncertainty variables and wind speed correlations are diverse enough across the portfolio to provide 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 93% of the aggregate P50 output level (which is unaffected by the portfolio effect), while the P75 output level, when taking into account the portfolio effect, is approximately 96% of our aggregate P50 output level. On a portfolio basis, our P90 and P95 production estimates for the annual electricity generation of our sixteen projects are approximately 92% and 89%, respectively, of our estimated P50 output levels. The portfolio effect results in an improvement in the production stability across the portfolio. A greater diversity of projects in the portfolio has the effect of increasing the frequency of occurrences aggregated around the expected result (probability level).
Our electricity generation is also dependent on the equipment that we use. We have selected high-quality equipment with a goal of having a concentration of turbines from top manufacturers. With a combination of high-quality equipment and scale and in-house operating capability, we have structured our projects such that we may expect high availability and long-term production from the equipment, develop operating expertise and experience, which can be shared among our operators, obtain a high level of attention and focus from the manufacturers and common operating practices. Given our manufacturers’ global fleet sizes and strong balance sheets, the warranties that we secure for our turbines and our operating approach described below, we are confident in our expectations for reliable long-term turbine operation.
Impact of Derivative Instruments
Where possible, we have sought to protect ourselves against electricity and interest rate exposures with a relatively longer term hedging strategy. We expect to hedge exposure to foreign currency exchange rates in the future over shorter periods of time. Accordingly, we have experienced in the past, and expect to record in the future, substantial volatility in the components of our net income that relate to the mark-to-market adjustments on our undesignated energy and interest rate derivatives.
We believe that mark-to-market adjustments that we make to the fair value of our derivative assets and liabilities are generally mirrored by changes in the economic value of the related operating or financial assets, such as our wind projects and our project loans, for which the application of accounting principles generally accepted in the United States ("U.S. GAAP") does not permit us to record such economic gains and losses. For this reason, and because one of our principal financial objectives is to produce stable and sustainable cash available for distribution, we believe that the economic value to our shareholders reflected in these derivative instruments, outweighs the risk of volatility in net income that we expect to report. Accordingly, we believe it is useful to investors to consider supplemental financial measures that we report, such as adjusted EBITDA, where we have subtracted and added back, as applicable, the unrealized gains and losses arising from mark-to-market adjustments on our derivative instruments, and cash available for distribution.
Project Operations
Our ability to generate electricity in an efficient and cost-effective manner is impacted by our ability to maintain the operating capacity of our projects. We use reliable and proven wind turbines and other equipment for each of our projects.
For the years ended December 31, 2015 and 2014, our turbine availability across our projects was 97.3% and 95.7%, respectively. For the years ended December 31, 2015 and 2014, Gulf Wind had higher than normal downtime due primarily to blade and other warranty issues which were compensated by the manufacturer. The fleet excluding Gulf Wind but including several new sites that achieved commercial operation in 2015 and 2014, had an average turbine availability of 98.2% and 97.2%, respectively, which is in line with industry standards for original investment projections reviewed by independent engineering firms.
See Item 1 "Business—Organization of Our Business—Operations and Maintenance." To accomplish this level of availability, 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

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minimized. In addition, for sites with power prices that vary during different periods, we schedule work to avoid known or anticipated high price periods.
Debt Financing
We intend to use a portion of our revenue from electricity sales to cover our subsidiaries’ interest expense and principal payments on borrowings under their respective project financing facilities. Our interest expense primarily reflects (i) imputed interest on the lease financing of our Hatchet Ridge project, (ii) periodic interest on the term loan financing arrangements, including the effects of interest rate swaps, at our other operating projects, (iii) interest on our convertible senior notes and (iv) interest on short-term loan facilities, including any borrowings under our revolving credit facility.
We believe that our projects have been financed on average with stronger coverage ratios than is typical in our industry. A debt service coverage ratio is generally defined as a project’s operating cash flows divided by scheduled payments of principal and interest for a period. While we believe that the commercial bank market generally seeks a minimum average annual debt service coverage ratio for wind power projects, based on P50 output levels, of between 1.4 and 1.5 to 1.0, our projects, on a portfolio basis, have an expected average annual debt service coverage ratio over the remaining scheduled loan amortization periods of approximately 1.7 to 1.0.