Pattern Energy Group Inc. - FORM 10-Q

Pattern Energy Group Inc. - FORM 10-Q - May 7, 2015

Attached files

Attached files

Pattern Energy Group Inc. Reports

file	filename
EX-32 - EX-32 - Pattern Energy Group Inc.	d892774dex32.htm
EX-31.2 - EX-31.2 - Pattern Energy Group Inc.	d892774dex312.htm
EX-10.1 - EX-10.1 - Pattern Energy Group Inc.	d892774dex101.htm
EX-31.1 - EX-31.1 - Pattern Energy Group Inc.	d892774dex311.htm
EXCEL - IDEA: XBRL DOCUMENT - Pattern Energy Group Inc.	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2015.

¨	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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark 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 x

As of May 1, 2015, there were 69,238,565 shares of Class A common stock outstanding with par value of $0.01 per share.

PATTERN ENERGY GROUP INC.

REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2015

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements	5
	Consolidated Balance Sheets as of March 31, 2015 (unaudited) and December 31, 2014	5
	Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014 (unaudited)	6
	Consolidated Statements of Comprehensive Loss for the Three Months Ended March 31, 2015 and 2014 (unaudited)	7
	Consolidated Statements of Stockholders’ Equity for the Three Months Ended March 31, 2015 and 2014 (unaudited)	8
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014 (unaudited)	9
	Notes to Consolidated Financial Statements (unaudited)	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	41
Item 4.	Controls and Procedures	42

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 6.	Exhibits	44
	Signatures	45

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q (“Form 10-Q”) may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. 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 actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

•

our ability to complete construction of our construction projects and transition them into financially successful operating projects;

•

our ability to complete the acquisition of power projects;

•

fluctuations in supply, demand, prices and other conditions for electricity, other commodities and 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 potential expiration or extension of the U.S. federal PTC, ITC and potential reductions in 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.”

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see Part II, “Item 1A. Risk Factors” in this report and our Annual Report on Form 10-K for the year ended December 31, 2014.

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.

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

Pattern Energy Group Inc.

Consolidated Balance Sheets

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

(Unaudited)


	March 31, 2015			December 31, 2014
Assets
Current assets:
Cash and cash equivalents	$	243,330		$	101,656
Restricted cash		6,247			7,945
Trade receivables		35,020			35,759
Related party receivable		549			671
Reimbursable interconnection costs		1,909			2,532
Derivative assets, current		19,258			18,506
Current net deferred tax assets		307			318
Prepaid expenses and other current assets		14,280			27,954
Deferred financing costs, current, net of accumulated amortization of $3,888 and $3,493 as of March 31, 2015 and December 31, 2014, respectively		1,756			1,747

Total current assets		322,656			197,088

Restricted cash		23,133			39,745
Turbine advances		110,941			79,637
Construction in progress		57,163			26,195
Property, plant and equipment, net of accumulated depreciation of $302,354 and $278,291 as of March 31, 2015 and December 31, 2014, respectively		2,300,505			2,350,856
Unconsolidated investments		14,756			29,079
Derivative assets		49,204			49,369
Deferred financing costs		4,764			5,166
Net deferred tax assets		11,097			5,474
Other assets		14,335			12,678

Total assets	$	2,908,554		$	2,795,287

Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities	$	25,248		$	24,793
Accrued construction costs		11,843			20,132
Related party payable		1,188			5,757
Accrued interest		1,237			3,634
Dividends payable		23,779			15,734
Derivative liabilities, current		16,498			16,307
Revolving credit facility		—			50,000
Current portion of long-term debt, net of financing costs of $9,585 and $11,868 as of March 31, 2015 and December 31, 2014, respectively		160,422			109,693
Current net deferred tax liabilities		149			149
Current portion of contingent liabilities		4,000			4,000

Total current liabilities		244,364			250,199

Long-term debt, net of financing costs of $23,841 and $24,887 as of March 31, 2015 and December 31, 2014, respectively		1,280,029			1,304,165
Derivative liabilities		25,109			17,467
Asset retirement obligations		28,721			29,272
Net deferred tax liabilities		23,500			20,418
Contingent liabilities		761			175
Other long-term liabilities		9,460			8,857

Total liabilities		1,611,944			1,630,553

Equity:
Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 69,088,306 and 62,088,306 shares issued as of March 31, 2015 and December 31, 2014, respectively; 69,052,752 and 62,062,841 shares outstanding as of March 31, 2015 and December 31, 2014, respectively		691			621
Additional paid-in capital		897,220			723,938
Accumulated loss		(64,525	)		(44,626	)
Accumulated other comprehensive loss		(62,432	)		(45,068	)
Treasury stock, at cost; 35,554 and 25,465 shares of Class A common stock as of March 31, 2015 and December 31, 2014, respectively		(998	)		(717	)

Total equity before noncontrolling interest		769,956			634,148
Noncontrolling interest		526,654			530,586

Total equity		1,296,610			1,164,734

Total liabilities and equity	$	2,908,554		$	2,795,287

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Consolidated Statements of Operations

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

(Unaudited)


	Three months ended March 31,
	2015			2014
Revenue:
Electricity sales	$	54,984		$	53,871
Energy derivative settlements		6,169			2,735
Unrealized gain (loss) on energy derivative		2,972			(7,733	)
Related party revenue		803			513
Other revenue, net		(62	)		231

Total revenue		64,866			49,617

Cost of revenue:
Project expense		25,246			16,074
Depreciation and accretion		29,056			21,177

Total cost of revenue		54,302			37,251

Gross profit		10,564			12,366

Operating expenses:
General and administrative		6,221			3,903
Related party general and administrative		1,808			1,280

Total operating expenses		8,029			5,183

Operating income		2,535			7,183

Other income (expense):
Interest expense		(17,918	)		(14,621	)
Interest rate derivative settlements		(959	)		(1,017	)
Unrealized loss on derivatives, net		(2,441	)		(3,723	)
Equity in losses in unconsolidated investments		(3,082	)		(12,548	)
Related party income		668			628
Net loss on transactions		(1,284	)		—
Other (expense) income, net		(324	)		167

Total other expense		(25,340	)		(31,114	)

Net loss before income tax		(22,805	)		(23,931	)
Tax benefit		(746	)		(2,032	)

Net loss		(22,059	)		(21,899	)
Net loss attributable to noncontrolling interest		(2,160	)		(7,010	)

Net loss attributable to controlling interest	$	(19,899	)	$	(14,889	)

Earnings per share information:
Cash dividends declared on Class A common shares		(23,624	)		(11,179	)

Net loss attributable to common stockholders	$	(43,523	)	$	(26,068	)

Weighted average number of shares:
Class A common stock - Basic		65,892,005			35,533,166
Class A common stock - Diluted		65,892,005			51,421,931
Class B common stock - Basic and diluted		N/A			15,555,000

Earnings (loss) per share
Class A common stock:
Basic loss per share	$	(0.30	)	$	(0.20	)

Diluted loss per share	$	(0.30	)	$	(0.29	)

Class B common stock:
Basic and diluted loss per share		N/A		$	(0.51	)

Cash dividends declared per Class A common share	$	0.34		$	0.31

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Consolidated Statements of Comprehensive Loss

(In thousands of U.S. Dollars)

(Unaudited)


	Three months ended March 31,
	2015			2014
Net loss	$	(22,059	)	$	(21,899	)

Other comprehensive loss:
Foreign currency translation, net of tax impact of $0 and $0, respectively		(9,194	)		(5,090	)

Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax benefit of $684 and $0, respectively		(10,757	)		(2,751	)
Reclassifications to net loss, net of tax impact of $173 and $0, respectively		3,491			(3,171	)

Total change in effective portion of change in fair market value of derivatives		(7,266	)		(5,922	)
Proportionate share of equity investee’s derivative activity:
Effective portion of change in fair market value of derivatives, net of tax benefit of $866 and $1,245, respectively		(2,402	)		(3,078	)
Reclassifications to net loss, net of tax impact of $171 and $0, respectively		474			—

Total change in effective portion of change in fair market value of derivatives		(1,928	)		(3,078	)

Total other comprehensive loss, net of tax		(18,388	)		(14,090	)

Comprehensive loss		(40,447	)		(35,989	)

Less comprehensive (loss) income attributable to noncontrolling interest:
Net loss attributable to noncontrolling interest		(2,160	)		(7,010	)

Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax benefit of $205 and $0, respectively		(1,940	)		923
Reclassifications to net loss, net of tax impact of $52 and $0, respectively		916			(829	)

Total change in effective portion of change in fair market value of derivatives		(1,024	)		94

Comprehensive loss attributable to noncontrolling interest		(3,184	)		(6,916	)

Comprehensive loss attributable to controlling interest	$	(37,263	)	$	(29,073	)

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Consolidated Statement of Stockholders’ Equity

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

(Unaudited)


	Controlling Interest																										Noncontrolling Interest
	Class A Common Stock				Class B Common Stock				Additional Paid-in			Accumulated			Accumulated Other Comprehensive			Treasury Stock												Accumulated			Accumulated Other Comprehensive						Total
	Shares		Amount		Shares		Amount		Capital			Loss			Loss			Shares			Amount			Total			Capital			Income			Loss			Total			Equity
Balances at December 31, 2013		35,531,720	$	355		15,555,000	$	156	$	489,412		$	(13,336	)	$	(8,353	)		(934	)	$	(24	)	$	468,210		$	90,217		$	18,601		$	(9,024	)	$	99,794		$	568,004

Issuances of Class A common stock under equity incentive award plan		173,287		2		—		—		(2	)		—			—			—			—			—			—			—			—			—			—
Repurchase of shares for employee tax withholding		—		—		—		—		—			—			—			(939	)		(26	)		(26	)		—			—			—			—			(26	)
Stock-based compensation		—		—		—		—		533			—			—			—			—			533			—			—			—			—			533
Refund of issuance costs related to the IPO		—		—		—		—		125			—			—			—			—			125			—			—			—			—			125
Dividends declared on Class A common stock		—		—		—		—		(11,157	)		—			—			—			—			(11,157	)		—			—			—			—			(11,157	)
Net loss		—		—		—		—		—			(14,889	)		—			—			—			(14,889	)		—			(7,010	)		—			(7,010	)		(21,899	)
Other comprehensive (loss) income, net of tax		—		—		—		—		—			—			(14,184	)		—			—			(14,184	)		—			—			94			94			(14,090	)

Balances at March 31, 2014		35,705,007	$	357		15,555,000	$	156	$	478,911		$	(28,225	)	$	(22,537	)		(1,873	)	$	(50	)	$	428,612		$	90,217		$	11,591		$	(8,930	)	$	92,878		$	521,490

Balances at December 31, 2014		62,088,306	$	621		—	$	—	$	723,938		$	(44,626	)	$	(45,068	)		(25,465	)	$	(717	)	$	634,148		$	529,539		$	9,892		$	(8,845	)	$	530,586		$	1,164,734

Issuance of Class A common stock related to the public offering, net of issuance costs		7,000,000		70		—		—		196,091			—			—			—			—			196,161			—			—			—			—			196,161
Repurchase of shares for employee tax withholding		—		—		—		—		—			—			—			(10,089	)		(281	)		(281	)		—			—			—			—			(281	)
Stock-based compensation		—		—		—		—		815			—			—			—			—			815			—			—			—			—			815
Dividends declared on Class A common stock		—		—		—		—		(23,624	)		—			—			—			—			(23,624	)		—			—			—			—			(23,624	)
Distribution to noncontrolling interest		—		—		—		—		—			—			—			—			—			—			(748	)		—			—			(748	)		(748	)
Net loss		—		—		—		—		—			(19,899	)		—			—			—			(19,899	)		—			(2,160	)		—			(2,160	)		(22,059	)
Other comprehensive loss, net of tax		—		—		—		—		—			—			(17,364	)		—			—			(17,364	)		—			—			(1,024	)		(1,024	)		(18,388	)

Balances at March 31, 2015		69,088,306	$	691		—	$	—	$	897,220		$	(64,525	)	$	(62,432	)		(35,554	)	$	(998	)	$	769,956		$	528,791		$	7,732		$	(9,869	)	$	526,654		$	1,296,610

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Consolidated Statements of Cash Flows

(In thousands of U.S. Dollars)

(Unaudited)


	Three months ended March 31,
	2015			2014
Operating activities
Net loss	$	(22,059	)	$	(21,899	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and accretion		29,056			21,177
Loss on disposal of equipments		354			—
Amortization of financing costs		1,743			1,395
Unrealized loss (gain) on derivatives		(531	)		11,456
Stock-based compensation		815			533
Deferred taxes		(878	)		(2,032	)
Equity in losses (earnings) in unconsolidated investments		3,082			12,548
Changes in operating assets and liabilities:
Trade receivables		288			(6,357	)
Prepaid expenses and other current assets		5,207			4,027
Other assets (non-current)		(80	)		(122	)
Accounts payable and other accrued liabilities		(688	)		(5,021	)
Related party receivable/payable		565			(155	)
Accrued interest payable		(2,374	)		855
Contingent liabilities		593			—
Long-term liabilities		1,146			—

Net cash provided by operating activities		16,239			16,405

Investing activities
Decrease in restricted cash		21,042			300
Increase in restricted cash		(5,055	)		(1	)
Capital expenditures		(63,956	)		314
Distribution from unconsolidated investments		6,076			—
Contribution to unconsolidated investments		—			(1,283	)
Reimbursable interconnection receivable		623			1,418
Other assets (non-current)		—			618

Net cash (used in) provided by investing activities		(41,270	)		1,366

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Consolidated Statements of Cash Flows

(In thousands of U.S. Dollars)

(Unaudited)


	Three months ended March 31,
	2015			2014
Financing activities
Proceeds from public offering, net of expenses	$	196,923		$	(135	)
Repurchase of shares for employee tax withholding		(281	)		(26	)
Dividends paid		(15,578	)		(11,082	)
Capital distributions - noncontrolling interest		(748	)		—
Decrease in restricted cash		8,763			4,668
Increase in restricted cash		(12,062	)		(7,707	)
Refund of deposit for letters of credit		3,425			—
Payment for deferred financing costs		(4	)		(589	)
Repayment of revolving credit facility		(50,000	)		—
Proceeds from short-term debt		47,595			—
Repayment of long-term debt		(8,435	)		(5,830	)

Net cash provided by (used in) financing activities		169,598			(20,701	)

Effect of exchange rate changes on cash and cash equivalents		(2,893	)		(296	)

Net change in cash and cash equivalents		141,674			(3,226	)
Cash and cash equivalents at beginning of period		101,656			103,569

Cash and cash equivalents at end of period	$	243,330		$	100,343

Supplemental disclosure
Cash payments for interest expenses, net of capitalized interest	$	18,442		$	12,398
Schedule of non-cash activities
Amortization of deferred financing costs - included as construction in progress		2,515			—
Change in property, plant and equipment		(23,061	)		(9,897	)

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Notes to Consolidated Financial Statements

(Unaudited)

1.	Organization

Pattern Energy Group Inc. (“Pattern Energy” or the “Company”) was organized in the state of Delaware on October 2, 2012. Pattern Energy issued 100 shares on October 17, 2012 to Pattern Renewables LP, a 100% owned subsidiary of Pattern Energy Group LP (“Pattern Development”). On September 24, 2013, Pattern Energy’s charter was amended, and the number of shares that Pattern Energy is authorized to issue was increased to 620,000,000 total shares; 500,000,000 of which are designated Class A common stock, 20,000,000 of which were designated Class B common stock, and 100,000,000 of which are designated Preferred Stock. On December 31, 2014, the Company’s outstanding Class B common stock was converted into Class A common stock on a one-for-one basis. Shares of Class B common stock converted into shares of Class A common stock were retired and the Company was not authorized to reissue shares of Class B common stock.

Pattern Energy is an independent energy generation company focused on constructing, owning and operating energy projects with long-term energy sales contracts located in the United States, Canada and Chile. The Company consists of the consolidated operations of certain entities and assets contributed by, or purchased principally from, Pattern Development. The Company owns 100% of Hatchet Ridge Wind, LLC (“Hatchet Ridge”), St. Joseph Windfarm Inc. (“St. Joseph”), Spring Valley Wind LLC (“Spring Valley”), Pattern Santa Isabel LLC (“Santa Isabel”), Ocotillo Express LLC (“Ocotillo”) and Logan’s Gap B Member LLC (“Logan’s Gap”). The Company owns a controlling interest in Pattern Gulf Wind Holdings LLC (“Gulf Wind”), Parque Eólico El Arrayán SpA (“El Arrayán”), Panhandle Wind Holdings LLC (“Panhandle 1”) and Panhandle B Member 2 LLC (“Panhandle 2”), and noncontrolling interests in South Kent Wind LP (“South Kent”) and Grand Renewable Wind LP (“Grand”). The principal business objective of the Company is to produce stable and sustainable cash flows through the generation and sale of energy and to selectively grow its project portfolio.

May 2014 Public Offering

On May 14, 2014, the Company completed an underwritten public offering, or “May 2014 offering,” of its Class A common stock. In total, 21,117,171 shares of its Class A common stock were sold. Of this amount, the Company issued and sold 10,810,810 shares of Class A common stock and Pattern Development, the selling stockholder, sold 10,306,361 shares of Class A common stock, including 2,754,413 shares upon exercise in full of the underwriters’ overallotment option. Net proceeds generated for the Company were approximately $286.8 million after deduction of underwriting discounts and commissions and transaction expenses. The Company did not receive any proceeds from the sale of the shares sold by Pattern Development. As a result of the May 2014 Offering, Pattern Development’s interest in the Company was reduced from approximately 63% to 35%. Consequently, the Company is no longer subject to ASC 805-50-30-5, Transactions between Entities under Common Control. All future transactions with Pattern Development will be recognized at fair value on the measurement date in accordance with ASC 805 – Business Combinations.

February 2015 Public Offering

On February 9, 2015, the Company completed an underwritten public offering, or the “February 2015 offering,” of its Class A common stock. In total, 12,000,000 shares of the Company’s Class A common stock were sold. Of this amount, the Company issued and sold 7,000,000 shares of its Class A common stock and Pattern Development, the selling stockholder, sold 5,000,000 shares of Class A common stock. The Company received net proceeds of approximately $196.2 million after deducting underwriting discounts and commissions and estimated offering expenses payable by the Company. The Company did not receive any proceeds from the sale of shares sold by Pattern Development. As a result of the February 2015 offering, Pattern Development’s interest in the Company decreased from 35% to 25% and it is no longer entitled to certain approval rights pursuant to the Shareholder Approval Rights Agreement dated October 2, 2013.

2.	Summary of Significant Accounting Policies

As of March 31, 2015, there have been no material changes to the Company’s significant accounting policies as compared to the significant accounting policies described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, with the exception of the change in depreciable lives of property, plant and equipment, the capitalization of indirect development and construction costs and change in presentation of deferred financing costs within short-term and long-term debt, as described below.

Basis of Presentation and Principles of Consolidation

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

Unaudited Interim Financial Information

The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and Article 10 of Regulation S-X issued by the U.S. Securities and Exchange Commission (“SEC”). Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, the interim financial information reflects all adjustments of a normal recurring nature, necessary for a fair presentation of the Company’s financial position at March 31, 2015, the results of operations, comprehensive loss, and cash flows for the three months ended March 31, 2015 and 2014, respectively. The consolidated balance sheet at December 31, 2014 has been derived from the audited financial statements at that date, but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements. This Form 10-Q should be read in conjunction with the consolidated financial statements and accompanying notes contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Use of Estimates

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

Change in Depreciable Lives of Property, Plant and Equipment

The Company periodically reviews the estimated economic useful lives of its fixed assets. In 2015, this review indicated that the expected economic useful lives of certain wind farms were longer than the estimated economic useful lives used for depreciation purposes in the Company’s financial statements. As a result, effective January 1, 2015, the Company changed its estimate of the economic useful lives of wind farms for which construction began after 2011, from 20 to 25 years. All other wind farms continue to depreciate over an estimated economic useful life of 20 years. For the three months ended March 31, 2015, the effect of this change reduced depreciation expense by $3.6 million, decreased net loss by $3.4 million, net of tax and decreased Class A basic and diluted loss per share by $0.02.

Capitalization of Indirect Development and Construction Costs

The Company capitalizes certain indirect costs incurred during the development stage when management concludes that a project’s likelihood of completion is probable. During the construction phase, substantially all applicable indirect costs are capitalized. Such costs include salaries, bonuses, benefits, and travel and facilities costs of employees whose time was spent on the project through the development and construction phase. Indirect costs incurred to bring a newly constructed project to commercial operation and subsequent to commercial operation are treated as period costs and are expensed when incurred. For the three months ended March 31, 2015, the Company did not capitalize any indirect development and construction costs.

Acquisitions

Business Combinations

When the Company acquires a controlling interest, the purchase is accounted for using the acquisition method, and the fair value of purchase consideration is allocated to the tangible and intangible assets acquired and liabilities assumed based on their estimated fair values. The excess, if any, of the fair value of purchase consideration over the fair values of these identifiable assets and liabilities is recorded as goodwill. Conversely, the excess, if any, of the net fair values of identifiable assets and liabilities over the fair value of purchase consideration is recorded as gain. Such valuations require management to make significant estimates and assumptions, especially with respect to intangible assets. These estimates and assumptions are inherently uncertain, and as a result, actual results may differ from estimates. Significant estimates include, but are not limited to, future expected cash flows, useful lives and discount rates. During the measurement period, which is one year from the acquisition date, we may record adjustments to the assets acquired and liabilities assumed, with a corresponding offset to either goodwill or gain, depending on whether the fair value of purchase consideration is in excess of or less than net assets acquired. Upon the conclusion of the measurement period, any subsequent adjustments are recorded to earnings.

Equity Method Investments

When the Company acquires a noncontrolling interest the investment is accounted for using the equity method of accounting and is initially recognized at cost.

Noncontrolling Interests

Noncontrolling interests represent the portion of the Company’s net income (loss), net assets and comprehensive income (loss) that is not allocable to the Company and is calculated based on ownership percentage, for applicable projects.

For the noncontrolling interests at the Company’s Gulf Wind, Panhandle 1 and Panhandle 2 projects, the Company has determined that the operating partnership agreements do not allocate economic benefits pro rata to its two classes of investors and has determined that the appropriate methodology for calculating the noncontrolling interest balance that reflects the substantive profit sharing arrangement is a balance sheet approach using the hypothetical liquidation at book value (HLBV) method.

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

Concentrations of Credit Risk

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

The Company sells electricity and environmental attributes, including renewable energy credits, primarily to creditworthy utilities under long-term, fixed-priced Power Sale Arrangements (“PPAs”) and, in some cases, through individual renewable energy credits sale agreements. During 2014, Standard & Poor’s Rating Services (“S&P”) and Moody’s Investor Service (“Moody’s”) downgraded the credit rating of the Puerto Rico Electric Power Authority (“PREPA”) from BBB and Baa3, to CCC and Caa3, respectively. As of March 31, 2015 and May 7, 2015, PREPA was current with respect to payments due under the PPA.

The following table presents significant customers who accounted for the following percentages of total revenues during the three months ended March 31, 2015 and 2014, respectively, and the related maximum amount of credit loss based on their respective percentages of total trade receivables as of March 31, 2015 and 2014, respectively:


	Revenue						Trade Receivables
	Three months ended March 31,						As of March 31,
	2015			2014			2015			2015
Manitoba Hydro		15.7	%		20.0	%		9.9	%		13.1	%
NV Energy, Inc.		11.7	%		12.5	%		5.9	%		11.7	%
Pacific Gas & Electric		11.1	%		14.5	%		6.2	%		10.9	%
PREPA		10.5	%		12.3	%		13.5	%		16.2	%
Credit Suisse		10.0	%		4.8	%		7.5	%		3.1	%
San Diego Gas & Electric		9.5	%		18.9	%		16.1	%		34.6	%

The Independent Electricity System Operator (“IESO”) is the customer for both the Company’s Grand and South Kent projects. The Company accounts for these projects under the equity method of accounting and as a result, the Company’s ownership interest in these projects is recorded in equity in losses of unconsolidated investments and not in revenue. As such, IESO is not included in the foregoing table of significant customers. However, we rely on a limited number of key power purchases, including IESO, and face a concentration of credit risk from IESO as a customer.

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

Reclassification

Certain prior period balances have been reclassified to conform to current period presentation of the Company’s consolidated financial statements and accompanying notes. Such reclassifications did not have an impact on consolidated net income or cash flows.

Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-03, “Interest – Imputation of Interest” to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. ASU 2015-03 is effective for public companies for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years and should be applied retrospectively. Early adoption is permitted for financial statements that have not been previously issued. Upon transition, an entity is required to comply with the applicable disclosures for a change in accounting principle. The Company adopted this standard in April 2015 and applied the change in accounting principle to the consolidated financial statements as of March 31, 2015. As a result, the Company reclassified $33.4 million and $36.8 million in total deferred financing costs to long-term debt, of which $9.6 million and $11.9 million have been reclassified to current portion of long-term debt, as of March 31, 2015 and December 31, 2014, respectively, on the Company’s consolidated balance sheets. Deferred financing costs related to the Company’s revolving credit facility remains classified as an asset on the Company’s consolidated balance sheets. The adoption of ASU 2015-03 had no impact on the Company’s results of operations and cash flows.

In February 2015, the FASB issued ASU 2015-02, “Consolidation: Amendments to the Consolidation Analysis” to modify the analysis that companies must perform in order to determine whether a legal entity should be consolidated. ASU 2015-02 simplifies current guidance by reducing the number of consolidation models; eliminating the risk that a reporting entity may have to consolidate based on a fee arrangement with another legal entity; placing more weight on the risk of loss in order to identify the party that has a controlling financial interest; reducing the number of instances that related party guidance needs to be applied when determining the party that has a controlling financial interest; and changing rules for companies in certain industries that ordinarily employ limited partnership or VIE structures. ASU 2015-02 is effective for public companies for fiscal years beginning after December 15, 2015 and interim periods within those fiscal periods. Early adoption on a modified retrospective or full retrospective basis is permitted. The Company is currently assessing the future impact of this update on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers”. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016. Early adoption is not permitted. The guidance permits companies to either apply the requirements retrospectively to all prior periods presented, or apply the requirements in the year of adoption, through a cumulative adjustment. The Company is currently assessing the future impact of this update on its consolidated financial statements.

3.	Acquisitions

El Arrayán Acquisition

On June 25, 2014, the Company acquired 100% of the issued and outstanding common stock of AEI El Arrayán Chile SpA (“AEI El Arrayán”), an entity holding a 38.5% indirect interest in El Arrayán, for a total purchase price of $45.3 million, pursuant to the terms of a Stock Purchase Agreement. The Company owned a 31.5% indirect interest in El Arrayán prior to acquiring the additional 38.5% interest in order to obtain majority control (70%) of the project, as a part of its growth strategy. El Arrayán is a 115 MW wind power project company, located in Ovalle, Chile, which achieved commercial operations on June 4, 2014.

Prior to the acquisition, the Company accounted for the investment under the equity method of accounting. Because the Company acquired an additional 38.5% indirect interest in El Arrayán, in accordance with ASC 805 Business Combinations, the acquisition was accounted for as a “business combination achieved in stages”. Accordingly, the Company remeasured the previously held equity interest in El Arrayán and adjusted it to fair value based on the Company’s existing equity interest in the fair value of the underlying assets and liabilities of El Arrayán. The fair value of the Company’s equity interest at the acquisition date was $37.0 million (31.5% of

implied equity value of $117.5 million per below). The difference between the fair value of the Company’s ownership in El Arrayán and the Company’s carrying value of its investment of $19.1 million resulted in a gain of $17.9 million recorded in net gain on transactions in the consolidated statements of operations for the year ended December 31, 2014. The Company recognized additional deferred tax liability due to differences in accounting and tax bases resulting from the Company’s existing ownership interest in El Arrayán, which has been included in the consolidated statements of operations. The Company now holds a 70% controlling interest in the wind project and consolidates the accounts of El Arrayán.

The Company acquired the assets and operating contracts for AEI El Arrayán, including assumed liabilities. The identifiable assets acquired and liabilities assumed were recorded at their fair values.

The consolidated fair value of the assets acquired and liabilities assumed in connection with the AEI El Arrayán acquisition are as follows (in thousands):


	Consolidated interest June 25, 2014
Cash and cash equivalents	$	713
Trade receivables		3,829
VAT receivable		17,031
Prepaid expenses and other current assets		174
Restricted cash, non-current		10,392
Property, plant and equipment		341,417
Intangible assets		1,121
Net deferred tax assets		5,455
Accounts payable and other accrued liabilities		(6,830	)
Accrued construction costs		(9,495	)
Accrued interest		(2,592	)
Derivative liabilities, current		(1,942	)
Current portion of long-term debt		(16,586	)
Long-term debt		(209,295	)
Derivative liabilities, non-current		(501	)
Asset retirement obligation		(2,354	)
Net deferred tax liabilities		(13,001	)

Total consideration		117,536

Less: non-controlling interest		(35,259	)

Controlling interest	$	82,277

Current assets, restricted cash, deferred tax assets, current liabilities, accrued construction costs, debt, accrued interest and deferred tax liabilities were recorded at carrying value, which is representative of the fair value on the date of acquisition. Derivative liabilities were recorded at fair value. Property, plant and equipment were recorded at the cost of construction plus the developer’s profit margin, which represents fair value. The asset retirement obligation was recorded at fair value using a combination of market data, operational data and discounted cash flows and was adjusted by a discount rate factor reflecting then current market conditions.

The Company recognized deferred tax liabilities due to differences in accounting and tax bases resulting from the Company’s acquisition of incremental interest in El Arrayán and the remeasurement of the project’s remaining noncontrolling interest at fair value.

Panhandle 1 Acquisition

On June 30, 2014, the Company acquired 100% of the Class B membership interests in the Panhandle 1 wind project, representing a 79% initial ownership interest in the project’s distributable cash flow, through the acquisition of Panhandle Wind Holdings LLC, from Pattern Development, for a purchase price of approximately $124.4 million. The 218 MW wind project, located in Carson County, Texas, achieved commercial operations on June 25, 2014.

Prior to the closing, certain tax equity investors made capital contributions to acquire 100% of the Class A membership interests in Panhandle 1 and have been admitted as noncontrolling members in the entity, with a 21% initial ownership interest in the project’s distributable cash flow. The Company has determined that the operating partnership agreement does not allocate economic benefits pro rata to its two classes of investors and will use the HLBV method to calculate the noncontrolling interest balance that reflects the substantive profit sharing arrangement.

The Company acquired the assets and operating contracts for Panhandle 1, including assumed liabilities. The identifiable assets acquired and liabilities assumed were recorded at their fair values, which corresponded to the sum of the cash purchase price and the initial balance of the other investors’ noncontrolling interests.

The consolidated fair value of the assets acquired and liabilities assumed in connection with the Panhandle 1 acquisition are as follows (in thousands):


	June 30, 2014
Cash and cash equivalents	$	1,038
Trade receivables		1,850
Prepaid expenses and other current assets		71
Restricted cash, non-current		14,293
Property, plant and equipment		332,953
Accounts payable and other accrued liabilities		(148	)
Accrued construction costs		(12,806	)
Related party payable		(44	)
Asset retirement obligation		(2,557	)

Total consideration before non-controlling interest		334,650

Less: tax equity noncontrolling interest contributions		(210,250	)

Total consideration after non-controlling interest	$	124,400

Current assets, restricted cash, current liabilities, accrued construction costs and related party payable were recorded at carrying value, which is representative of the fair value on the date of acquisition.

Property, plant and equipment were recorded at the cost of construction plus the developer’s profit margin, which represents fair value. The asset retirement obligation was recorded at fair value using a combination of market data, operational data and discounted cash flows and was adjusted by a discount rate factor reflecting then current market conditions.

Panhandle 2 Acquisition

On November 10, 2014, the Company acquired 100% of the membership interests in the Panhandle 2 wind project through the acquisition of Panhandle B Member 2 LLC, from Pattern Development, for a purchase price of approximately $123.8 million.

Subsequent to the closing, certain tax equity investors made capital contributions to acquire 100% of the Class A membership interests in Panhandle 2 and were admitted as noncontrolling members in the entity and the Company received 100% of the Class B membership interests, resulting in the tax equity investors and the Company holding initial ownership interests of 19% and 81%, respectively, in the project’s distributable cash flows. The 182 MW wind project, located in Carson County, Texas, achieved commercial operations on November 7, 2014. The Company has determined that the operating partnership agreement does not allocate economic benefits pro rata to its two classes of investors and will use the HLBV method to calculate the noncontrolling interest balance that reflects the substantive profit sharing arrangement.

The Company acquired the assets and operating contracts for Panhandle 2, including assumed liabilities. The identifiable assets acquired and liabilities assumed were recorded at their fair values which corresponded to the sum of the cash purchase price. The short-term debt presented in the table below consists of a construction loan that was repaid in full following the acquisition.

The consolidated fair value of the assets acquired and liabilities assumed in connection with the Panhandle 2 acquisition are as follows (in thousands):


	November 10, 2014
Cash and cash equivalents	$	240
Trade receivables		1,156
Prepaid expenses and other current assets		28,997
Property, plant and equipment		315,109
Accrued construction costs		(24,197	)


	November 10, 2014
Related party payable		(121	)
Short-term debt		(195,351	)
Asset retirement obligation		(2,003	)

Total consideration	$	123,830

Current assets, accrued construction costs and related party payable were recorded at carrying value, which is representative of the fair value on the date of acquisition. In addition, the short-term debt was recorded at carrying value, representative of the fair value, which was repaid immediately after acquisition.

Logan’s Gap Acquisition

On December 19, 2014, the Company acquired 100% of the membership interests in the Logan’s Gap wind project, through the acquisition of Logan’s Gap B Member LLC, from Pattern Development, for a purchase price of approximately $15.1 million and an assumed contingent liability to a third party in the amount of $8.0 million associated with the close of construction financing and the achievement of either commercial operation or tax equity funding. The wind project is currently under construction and is located in Comanche County, Texas. The construction of the project is being financed primarily by construction debt and Pattern Energy equity. Following construction, it is expected that institutional tax equity investors will invest in the project, pursuant to an executed equity commitment agreement, so that the construction loan will be paid off such that long term financing for the project will be equity based. Upon tax equity funding, it is expected that the Company and the institutional tax equity investors will have initial ownership interests of 82% and 18%, respectively, in the project’s distributable cash flows.

The Company acquired the assets and operating contracts for Logan’s Gap, including assumed liabilities. The identifiable assets acquired and liabilities assumed were recorded at their fair values which corresponded to the sum of the cash purchase price. The consolidated fair value of the assets acquired and liabilities assumed in connection with the Logan’s Gap acquisition are as follows (in thousands):


	December 19, 2014
Cash and cash equivalents	$	2
Restricted cash, current		5,003
Prepaid expenses and other current assets		1,790
Deferred financing costs, current		2,882
Construction in progress		23,821
Property, plant and equipment		116
Other assets		80
Accrued construction costs		(5,617	)
Current portion of contingent liabilities		(7,975	)
Related party payable		(5,003	)

Total consideration	$	15,099

Current assets, current liabilities, property, plant and equipment, other assets, accrued construction costs and related party payable were recorded at carrying value, which is representative of the fair value on the date of acquisition. Construction in progress was recorded at fair value which is representative of the development effort, including the developer’s profit, and contracts acquired on the date of acquisition.

The Company recorded $8.0 million in contingent obligations, payable to a third party, at fair value upon acquisition. Of this amount, $4.0 million was paid in December 2014, upon construction financing, and the remaining $4.0 million liability is payable upon the earlier of commercial operations or tax equity funding, which is expected to occur in the fourth quarter of 2015.

4.	Prepaid Expenses and Other Current Assets

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


	March 31, 2015		December 31, 2014
Prepaid expenses	$	9,758	$	15,275
Prepaid construction costs		1,622		5,155
Sales tax		40		786
Other current assets:
Deposit for letters of credit		—		3,425
Deferred equity issuance costs		1,846		2,331
Other		1,014		982

Prepaid expenses and other current assets	$	14,280	$	27,954

5.	Property, Plant and Equipment

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


	March 31, 2015			December 31, 2014
Operating wind farms	$	2,599,331		$	2,624,640
Furniture, fixtures and equipment		3,387			4,366
Land		141			141

Subtotal		2,602,859			2,629,147
Less: accumulated depreciation		(302,354	)		(278,291	)

Property, plant and equipment, net	$	2,300,505		$	2,350,856

The Company recorded depreciation expense related to property, plant and equipment of $29.2 million and $20.8 million for the three months ended March 31, 2015 and 2014, respectively.

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

The Cash Grants received for Ocotillo, Santa Isabel and Spring Valley reduced depreciation expense recorded in the consolidated statements of operations by approximately $2.7 million and $3.2 million for the three months ended March 31, 2015 and 2014, respectively.

6.	Unconsolidated Investments

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


					Percentage of Ownership
	March 31, 2015		December 31, 2014		March 31, 2015			December 31, 2014
South Kent	$	7,075	$	17,360		50.0	%		50.0	%
Grand		7,681		11,719		45.0	%		45.0	%

Unconsolidated investments	$	14,756	$	29,079

South Kent

The Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. The project has a 20-year PPA, and commenced commercial operations in March 2014.

Grand

The Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. The project has a 20-year PPA and commenced commercial operations in December 2014.

El Arrayán

On June 25, 2014, the Company increased its total ownership interest in El Arrayán to 70%. See Note 3, Acquisitions, for disclosure on the acquisition of El Arrayán. As such, the Company has consolidated the operations of El Arrayán as of the acquisition date and is no longer accounting for this investment under the equity method of accounting. For the three months ended March 31, 2014, the Company recognized a loss of $0.3 million in equity in losses on unconsolidated investments in the consolidated statements of operations.

The following table summarizes the aggregated operating results of the unconsolidated joint ventures for the three months ended March 31, 2015 and 2014, respectively (in thousands):


	Three months ended March 31,
	2015			2014
Revenue	$	44,631		$	1,517

Cost of revenue		12,315			739
Operating expenses		2,406			(43	)
Other expense		35,291			26,487

Net loss		(5,381	)		(25,666	)

Significant Equity Method Investees

The following table presents summarized statements of operations information for the three months ended March 31, 2015 and 2014, in thousands, as required for each of the Company’s significant equity method investees, pursuant to Regulation S-X Rule 10-01(b)(1):


	South Kent						Grand
	Three months ended March 31,						Three months ended March 31,
	2015			2014			2015		2014
Revenue	$	32,536		$	1,517		$	12,095	$	—

Cost of revenue		8,389			739			3,926		—
Operating expenses		1,555			(151	)		851		108
Other expense		28,640			21,779			6,651		4,380

Net (loss) income	$	(6,048	)	$	(20,850	)	$	667	$	(4,488	)

7.	Accounts Payable and Other Accrued Liabilities

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


	March 31, 2015		December 31, 2014
Accounts payable	$	304	$	673
Other accrued liabilities		11,039		7,892
Warranty settlement payments		1,825		639
LTSA upgrades liability		691		680
Turbine operations and maintenance payable		2,522		1,310
Land lease rent payable		884		2,115
Payroll liabilities		2,141		4,453
Property tax payable		3,214		4,625
Sales tax payable		2,628		2,406

Accounts payable and other accrued liabilities	$	25,248	$	24,793

8.	Revolving Credit Facility

In December 2014, the Company entered into an Amended and Restated Credit and Guaranty Agreement which increased the available borrowings under a prior revolving credit agreement from $145.0 million to $350.0 million. Simultaneously, the Panhandle 1, Panhandle 2, South Kent and Grand projects were added to the collateral pool that supports the revolving credit facility.

Collateral for the revolving credit facility consists of the Company’s membership interests in certain of the Company’s holding company subsidiaries. The revolving credit facility contains a broad range of covenants that, subject to certain exceptions, restrict the Company’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business.

As of March 31, 2015 and December 31, 2014, letters of credit of $48.4 million and $45.1 million, respectively, have been issued under the revolving credit facility and the outstanding loan balances were zero and $50.0 million, respectively, for those same periods.

9.	Long-term Debt

The Company’s long-term debt, which consists of limited recourse or nonrecourse indebtedness, is presented below, as of March 31, 2015 and December 31, 2014 (in thousands):


	As of March 31, 2015
	Principal			Unamortized Financing Cost			Net			Contractual Interest Rate			Effective Interest Rate			Contractual Interest Type	Maturity
Hatchet Ridge term loan	$	228,288		$	(2,478	)	$	225,810			1.43	%		1.43	%	Imputed	December 2032
Gulf Wind term loan		154,076			(4,184	)		149,892			3.26	%		6.59	%⁽¹⁾	Variable	March 2020
St. Joseph term loan		171,773			(855	)		170,918			5.88	%		5.95	%	Fixed	May 2031
Spring Valley term loan		166,220			(6,068	)		160,152			2.63	%		5.51	%⁽¹⁾	Variable	June 2030
Santa Isabel term loan		111,815			(4,152	)		107,663			4.57	%		4.57	%	Fixed	September 2033
El Arrayán commercial term loan		98,354			(93	)		98,261			2.92	%		5.64	%⁽¹⁾	Variable	March 2029
El Arrayán EKF term loan		108,190			(103	)		108,087			5.56	%		5.56	%	Fixed	March 2029
Ocotillo commercial term loan		222,175			(6,681	)		215,494			2.01	%		3.92	% ⁽¹⁾	Variable	August 2020
Ocotillo development term loan		106,700			(3,209	)		103,491			2.36	%		4.55	% ⁽¹⁾	Variable	August 2033
Logan’s Gap construction loan		106,286			(5,603	)		100,683			1.65	%		1.65	%	Variable	December 2015

		1,473,877			(33,426	)		1,440,451
Less: current portion		(170,007	)		9,585			(160,422	)

	$	1,303,870		$	(23,841	)	$	1,280,029


	As of December 31, 2014
	Principal			Unamortized Financing Cost			Net			Contractual Interest Rate			Effective Interest Rate			Contractual Interest Type	Maturity
Hatchet Ridge term loan	$	228,288		$	(2,546	)	$	225,742			1.43	%		1.43	%	Imputed	December 2032
Gulf Wind term loan		156,122			(4,360	)		151,762			3.23	%		6.59	%⁽¹⁾	Variable	March 2020
St. Joseph term loan		189,472			(960	)		188,512			5.88	%		5.95	%	Fixed	May 2031
Spring Valley term loan		167,261			(6,232	)		161,029			2.62	%		5.51	%⁽¹⁾	Variable	June 2030
Santa Isabel term loan		112,609			(4,240	)		108,369			4.57	%		4.57	%	Fixed	September 2033
El Arrayán commercial term loan		99,665			(94	)		99,571			2.92	%		5.64	%⁽¹⁾	Variable	March 2029
El Arrayán EKF term loan		109,630			(103	)		109,527			5.56	%		5.56	%	Fixed	March 2029
Ocotillo commercial term loan		222,175			(7,021	)		215,154			1.98	%		3.92	% ⁽¹⁾	Variable	August 2020
Ocotillo development term loan		106,700			(3,372	)		103,328			2.33	%		4.55	% ⁽¹⁾	Variable	August 2033
Logan’s Gap construction loan		58,691			(7,827	)		50,864			1.64	%		1.64	%	Variable	December 2015

		1,450,613			(36,755	)		1,413,858
Less: current portion		(121,561	)		11,868			(109,693	)

	$	1,329,052		$	(24,887	)	$	1,304,165

(1)	Includes impact of interest rate derivatives. Refer to Note 11, Derivative Instruments, for discussion of interest rate derivatives.

The following table presents a reconciliation of interest expense presented in the Company’s consolidated statements of operations for the three months ended March 31, 2015 and 2014 (in thousands):


	Three months ended March 31,
	2015			2014
Interest and commitment fees incurred	$	16,487		$	13,457
Capitalized interest, commitment fees, and letter of credit fees		(1,318	)		(1,283	)
Letter of credit fees incurred		1,006			1,052
Amortization of financing costs		1,743			1,395

Interest expense	$	17,918		$	14,621

10.

Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated cost of decommissioning the turbines, removing above-ground installations and restoring the sites at a date that is 20 years from the commencement of commercial operations of the facility. Effective January 1, 2015, the Company changed its estimate of the useful lives of wind farms for which construction began after 2011, from 20 years to 25 years. As a result, the Company recorded a one-time adjustment of $1.9 million to reduce the carrying balance of the asset retirement obligations to reflect the change in estimate associated with the timing of the original undiscounted cash flows.

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligations as of March 31, 2015 and 2014 (in thousands):


	Three months ended March 31,
	2015			2014
Beginning asset retirement obligations	$	29,272		$	20,834
Net additions during the year		1,101			—
Foreign currency translation adjustment		(212	)		(99	)
Adjustment related to change in useful life		(1,907	)		—
Accretion expense		467			347

Ending asset retirement obligations	$	28,721		$	21,082

11.

Derivative Instruments

The Company employs derivative instruments to manage its exposure to fluctuations in currency exchange rates, interest rates and electricity prices. The Company’s objectives for holding these derivative instruments include reducing, eliminating and efficiently managing the economic impact of these exposures as effectively as possible.

The following tables present the amounts that are recorded in the Company’s financial statements (in thousands):

Undesignated Derivative Instruments Classified as Assets (Liabilities):


									For the period ended
			Fair Market Value						QTD Gain (Loss)
Derivative Type	Quantity	Maturity Dates	Current Portion			Long-Term Portion			Recognized into Income
March 31, 2015
Interest rate swaps	6	6/30/2030	$	(3,310	)	$	(674	)	$	(3,104	)
Interest rate cap	1	12/31/2024		—			384			32
Energy derivative	1	4/30/2019		18,931			48,516			2,972
Foreign currency forward contracts	7	Various through 1/31/2017		327			304			631

			$	15,948		$	48,530		$	531

December 31, 2014
Interest rate swaps	6	6/30/2030	$	(3,403	)	$	2,523		$	(5,040	)
Interest rate cap	1	12/31/2024		—			352			(29	)
Energy derivative	1	4/30/2019		18,506			45,969			7,265

			$	15,103		$	48,844		$	2,196

March 31, 2014
Interest rate swaps	6	6/30/2030	$	(3,916	)	$	10,826		$	(3,549	)
Interest rate cap	1	12/31/2024		—			507			(174	)
Energy derivative	1	4/30/2019		11,906			48,714			(7,733	)

			$	7,990		$	60,047		$	(11,456	)


Designated Derivative Instruments Classified as Assets (Liabilities):

									For the period ended
			Fair Market Value						QTD Gain (Loss)
Derivative Type	Quantity	Maturity Dates	Current Portion			Long-Term Portion			Recognized in OCI
March 31, 2015
Interest rate swaps	6	6/30/2033	$	(1,889	)	$	(1,722	)	$	(2,219	)
Interest rate swaps	3	3/31/2032		(2,308	)		(4,745	)		(1,382	)
Interest rate swaps	7	3/15/2020		(4,618	)		(7,844	)		(828	)
Interest rate swaps	2	6/28/2030		(4,373	)		(10,124	)		(2,837	)

			$	(13,188	)	$	(24,435	)	$	(7,266	)

December 31, 2014
Interest rate swaps	6	6/30/2033	$	(1,917	)	$	525		$	(3,722	)
Interest rate swaps	3	3/31/2032		(1,822	)		(3,338	)		(1,863	)
Interest rate swaps	7	3/15/2020		(4,719	)		(6,915	)		(425	)
Interest rate swaps	2	6/28/2030		(4,446	)		(7,214	)		(3,889	)

			$	(12,904	)	$	(16,942	)	$	(9,899	)

March 31, 2014
Interest rate swaps	6	6/30/2033	$	(2,126	)	$	6,888			(2,758	)
Interest rate swaps	7	3/15/2020		(5,250	)		(7,452	)		26
Interest rate swaps	2	6/28/2030		(4,913	)		(68	)		(3,190	)

			$	(12,289	)	$	(632	)	$	(5,922	)

Gulf Wind

In 2010, Gulf Wind entered into interest rate swaps with each of its lenders to manage exposure to interest rate risk on its long-term debt. The fixed interest rate is set at 6.6% for years two through eight and 7.1% and 7.6% for the last two years of the loan term, respectively. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three months ended March 31, 2015 and 2014, respectively. The Company reclassified $1.3 million and $1.4 million related to cash settlements into net loss from accumulated other comprehensive loss during the three months ended March 31, 2015 and 2014, respectively.

In 2010, Gulf Wind also entered into an interest rate cap to manage exposure to future interest rates when its long-term debt is expected to be refinanced at the end of the ten-year term. The cap protects the Company if future interest rates exceed approximately 6.0%. The cap has an effective date of March 31, 2020, terminates on December 31, 2024, and has a notional amount of $42.1 million, which reduces quarterly during its term. The cap is a derivative but does not qualify for hedge accounting and has not been designated. The Company recognized an immaterial unrealized gain and a $0.2 million unrealized loss for each of the three months ended March 31, 2015 and 2014, respectively, in unrealized loss on derivatives, net in the consolidated statements of operations.

In 2010, Gulf Wind acquired an energy derivative instrument to manage its exposure to variable electricity prices. The energy price swap fixes the price of approximately 58% of its electricity generation through April 2019. The energy derivative instrument is a derivative but did not meet the criteria required to adopt hedge accounting. The energy derivative instrument’s fair value as of March 31, 2015 and December 31, 2014 was $67.4 million and $64.5 million, respectively. Gulf Wind recognized an unrealized gain of $3.0 million and an unrealized loss of $7.7 million for the three months ended March 31, 2015 and 2014, respectively, in unrealized loss on energy derivative in the consolidated statement of operations.

Spring Valley

In 2011, Spring Valley entered into interest rate swaps with its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 5.5% for the first four years of its term debt and increases by 0.25% every four years, thereafter. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three months ended March 31, 2015 and 2014, respectively. The Company reclassified $1.2 million and $1.3 million related to cash settlements into net loss from accumulated other comprehensive loss during the three months ended March 31, 2015 and 2014, respectively.

Ocotillo

In October 2012, Ocotillo entered into interest rate swaps with its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 2.5% and 2.2% for the development bank term loans and the commercial bank term loans, respectively. The fixed interest rate payments of the commercial bank term loan will increase by 0.25% on the fourth anniversary of the closing date. The interest rate swaps for the development bank loans qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three months ended March 31, 2015 and 2014, respectively. The Company reclassified $0.5 million related to cash settlements into net loss from accumulated other comprehensive loss during each of the three months ended March 31, 2015 and 2014. The interest rate swaps for the commercial bank loans are undesignated derivatives that are used to mitigate exposure to variable interest rate debt.

El Arrayán

In May 2012, El Arrayán entered into three interest rate swap agreements with its lenders to manage exposure to interest rate risk on its long term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 3.4% for the first two years of its term debt and subsequently increased to 5.8%, and increases by 0.25% on every fourth anniversary of the closing date, thereafter. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three months ended March 31, 2015 and 2014, respectively. The Company reclassified $0.5 million related to cash settlements into net loss from accumulated other comprehensive loss, net of tax impact of $0.2 million during the three months ended March 31, 2015. No amounts were reclassified from accumulated other comprehensive loss during the three months ended March 31, 2014.

Foreign Currency Forward Contracts

In January 2015, the Company established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in the Company’s cash flow, which may have an adverse impact to our short-term liquidity or financial condition. A majority of the Company’s power sale agreements and operating expenditures are transacted in U.S.

dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. During the first quarter of 2015, the Company entered into foreign currency forward contracts to mitigate the currency exchange rate risk on Canadian dollar denominated cash flows. These instruments have an initial maturity ranging from five to twenty-three months. The foreign currency forward contracts are considered non-designated derivative instruments and are not used for trading or speculative purposes.

As of March 31, 2015, the total notional amount of foreign currency forward contracts outstanding was C$42.8 million and the total fair value of these contracts was $0.6 million. For the three months ended March 31, 2015, the Company recognized a change in fair value of the foreign currency forward contracts of $0.6 million in unrealized loss on derivatives, net in the consolidated statement of operations.

12.

Accumulated Other Comprehensive Loss

The following tables summarize the changes in the accumulated other comprehensive loss balance by component, net of tax, for the three months ended March 31, 2015 and 2014 (in thousands):


	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI			Total
Balances at December 31, 2014	$	(19,338	)	$	(26,672	)	$	(7,903	)	$	(53,913	)
Other comprehensive loss before reclassifications		(9,194	)		(10,757	)		(2,402	)		(22,353	)
Amounts reclassified from accumulated other comprehensive loss		—			3,491			474			3,965

Net current period other comprehensive loss		(9,194	)		(7,266	)		(1,928	)		(18,388	)

Balances at March 31, 2015	$	(28,532	)	$	(33,938	)	$	(9,831	)	$	(72,301	)


	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI			Total
Balances at December 31, 2013	$	(8,463	)	$	(7,002	)	$	(1,912	)	$	(17,377	)
Other comprehensive loss before reclassifications		(5,090	)		(2,751	)		(3,078	)		(10,919	)
Amounts reclassified from accumulated other comprehensive loss		—			(3,171	)		—			(3,171	)

Net current period other comprehensive loss		(5,090	)		(5,922	)		(3,078	)		(14,090	)

Balances at March 31, 2014	$	(13,553	)	$	(12,924	)	$	(4,990	)	$	(31,467	)

Amounts reclassified from accumulated other comprehensive loss into income for the effective portion of change in fair value of derivatives is recorded to interest expense in the consolidated statements of operations. Amounts reclassified from accumulated other comprehensive loss into income for the Company’s proportionate share of equity investee’s other comprehensive loss is recorded to equity in losses in unconsolidated investments in the consolidated statements of operations.

13.

Fair Value Measurements

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

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

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

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

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

Short-term financial instruments consist principally of cash and cash equivalents, restricted cash, trade receivables, related party receivable/payable, reimbursable interconnection costs, accounts payable and other accrued liabilities, accrued construction costs,

accrued interest and dividends payable. Based on the nature and short maturity of these instruments, their fair value is approximated using carrying cost and they are presented in the Company’s financial statements at carrying cost. The fair values of cash and cash equivalents and restricted cash are classified as Level 1 in the fair value hierarchy. The fair values of trade receivables, related party receivable/payable, reimbursable interconnection costs, accounts payable and other accrued liabilities, accrued construction costs, accrued interest and dividends payable are classified as Level 2 in the fair value hierarchy.

The Company’s financial assets and (liabilities) which require fair value measurement on a recurring basis are classified within the fair value hierarchy as follows (in thousands):


	Fair Value
	Level 1		Level 2			Level 3			Total
March 31, 2015
Interest rate swaps	$	—	$	(41,607	)	$	—		$	(41,607	)
Interest rate cap		—		384			—			384
Energy derivative		—		—			67,447			67,447
Foreign currency forward contracts		631		—			—			631
Contingent liabilities		—		—			(761	)		(761	)

	$	631	$	(41,223	)	$	66,686		$	26,094

December 31, 2014
Interest rate swaps	$	—	$	(30,726	)	$	—		$	(30,726	)
Interest rate cap		—		352			—			352
Energy derivative		—		—			64,475			64,475
Contingent liabilities		—		—			(175	)		(175	)

	$	—	$	(30,374	)	$	64,300		$	33,926

Level 2 Inputs

Derivative instruments subject to remeasurement are presented in the financial statements at fair value. The Company’s interest rate swaps and interest rate cap were valued by discounting the net cash flows using the forward LIBOR curve with the valuations adjusted by the Company’s credit default hedge rate. The Company’s foreign currency forward contracts were valued using the income approach based on the present value of the forward rates less the contract rates, multiplied by the notional amounts. There were no transfers between Level 1 and Level 2 during the periods presented.

Level 3 Inputs

Energy Derivative

The energy derivative instrument is valued by discounting the projected net cash flows over the remaining life of the derivative instrument using forward energy curves adjusted by a nonperformance risk factor. The significant unobservable input in calculating the fair value of the energy derivative instrument is forward electricity prices, which are derived from and impacted by changes in forward natural gas prices. Significant increases or decreases in this unobservable input would result in a significantly lower or higher fair value measurement.

The following table presents a reconciliation of the energy derivative contract measured at fair value, in thousands, on a recurring basis using significant unobservable inputs (Level 3) for the three months ended March 31, 2015 and 2014, respectively. There were no transfers between Level 2 and Level 3 during the periods presented.


	Energy Derivative
	Three months ended March 31,
	2015			2014
Balances, beginning of period	$	64,475		$	68,353
Settlements		(6,169	)		(2,735	)
Change in fair value		9,141			(4,998	)

Balances, end of period	$	67,447		$	60,620

Contingent Liabilities

The Company’s contingent liabilities relate to turbine availability guarantees associated with long-term turbine service arrangements with its turbine service and maintenance providers. Pursuant to these guarantees, if a turbine operates at less than minimum availability during the guarantee period, the service provider is obligated to pay, as liquidated damages, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, pursuant to certain of these guarantees, if a turbine operates at more than a specified availability during the guarantee period, the Company has an obligation to pay a bonus to the service provider. The fair value of the contingent liabilities is based on actual and forecasted data. The significant unobservable inputs in calculating the fair value of the contingent liabilities are the forecasted turbine availability percentages.

The following table presents a reconciliation of contingent liabilities measured at fair value, in thousands, on a recurring basis using significant unobservable inputs (Level 3) for the three months ended March 31, 2015 and 2014, respectively. There were no transfers between Level 2 and Level 3 during the periods presented.


	Contingent Liabilities
	Three months ended March 31,
	2015			2014
Balances, beginning of period	$	(175	)	$	—
Payments		—			—
Change in estimate		(586	)		—

Balances, end of period	$	(761	)	$	—

The following table presents the carrying amount and fair value, in thousands, and the fair value hierarchy of the Company’s financial liabilities that are not measured at fair value in the consolidated balance sheets as of March 31, 2015 and December 31, 2014, but for which fair value is disclosed.


	As reflected on the balance sheet		Fair Value
	As reflected on the balance sheet		Level 1		Level 2		Level 3		Total
March 31, 2015
Long-term debt, including current portion	$	1,440,451	$	—	$	1,412,058	$	—	$	1,412,058

December 31, 2014
Long-term debt, including current portion	$	1,413,858	$	—	$	1,416,744	$	—	$	1,416,744

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

14.

Income Taxes

The Company accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The Company recognizes deferred tax assets to the extent that the Company believes these assets are more likely than not to be realized. In making such a determination, the Company considers all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning and results of recent operations. If the Company determines that it would be able to realize deferred tax assets in the future in excess of their net recorded amount, it would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.

The Company files income tax returns in various jurisdictions and is subject to examination by various tax authorities. The Company records uncertain tax positions in accordance with ASC 740 on the basis of a two-step process whereby (1) the Company determines whether it is more likely than not that the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, the Company recognizes the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with the related tax authority. The Company has a policy to classify interest and penalties associated with uncertain tax positions together with the related liability, and the expenses incurred related to such accruals, if any, are included as a component of income tax expense.

15.

Stockholders’ Equity

Dividends

The following table presents cash dividends declared on Class A common stock for the periods presented:

Dividends
Per Share

Declaration Date

Record Date

Payment Date

2015:

First Quarter

0.3420

February 24, 2015

March 31, 2015

April 30, 2015

Noncontrolling Interests

The following table presents the noncontrolling interest balances, reported in stockholders’ equity in the consolidated balance sheets, by project, as of March 31, 2015 and December 31, 2014 (in thousands):


					Noncontrolling Ownership Percentage
	March 31, 2015		December 31, 2014		March 31, 2015			December 31 2014
	March 31, 2015		December 31, 2014		March 31, 2015			December 31 2014
Gulf Wind	$	98,294	$	97,061		60	%		60	%
El Arrayán		34,209		35,624		30	%		30	%
Panhandle 1		203,512		205,333		21	%		21	%
Panhandle 2		190,639		192,568		19	%		19	%

Noncontrolling interest	$	526,654	$	530,586

16.

Stock-based Compensation

The Company accounts for stock-based compensation related to stock options granted to employees by estimating the fair value of the stock option awards using the Black-Scholes option-pricing model and amortizing the fair value over the applicable vesting period. The Company accounts for stock-based compensation related to restricted stock awards and deferred restricted stock units by measuring the fair value of the restricted stock awards and units using the stock price at the grant date and amortizing the fair value on a straight-line basis over the applicable vesting period.

Total stock-based compensation expense for the three months ended March 31, 2015 and 2014 was $0.8 million and $0.5 million, respectively.

17.

Loss per Share

The Company computes basic loss per share using net loss attributable to controlling interest to Class A common stockholders and the weighted average number of Class A common shares outstanding during the period. The Company computes diluted loss per share using net loss attributable to controlling interest to Class A common stockholders and the weighted average number of common shares outstanding plus potentially dilutive securities outstanding for the period.

Potentially dilutive securities are determined by applying the treasury stock method to the assumed exercise of in-the-money stock options and the assumed vesting of outstanding restricted stock awards and release of restricted stock units.

On December 31, 2014, the Company’s Class B common stock was converted to Class A common stock on a one-to-one basis. For the three months ended March 31, 2014, the Company computed Class A and Class B basic loss per share using the two-class method and computed diluted loss per share for Class A and Class B common stock using either the two-class method or the if-converted method, whichever was more dilutive.

For the three months ended March 31, 2015, 50,046 stock options, 8,478 restricted stock awards and 13,861 restricted stock units were excluded from the computation of diluted loss per share as their impact would have been antidilutive. For the three months ended March 31, 2014, all potentially dilutive securities were included in the computation of diluted loss per share.

The computations for Class A basic and diluted loss per share are as follows:


	Three months ended March 31, 2015			Three months ended March 31, 2014
Numerator for basic and diluted loss per share:
Net loss attributable to controlling interest	$	(19,899	)	$	(14,889	)
Less: dividends declared		(23,624	)		(11,179	)

Undistributed loss	$	(43,523	)	$	(26,068	)

Denominator for basic and diluted loss per share:
Weighted average number of shares:

Class A common stock - basic		65,892,005			35,533,166
Add dilutive effect of:
Stock options		50,046			95,219
Restricted stock awards		8,478			238,546
Restricted stock units		13,861			—
Class B common stock		—			15,555,000

Class A common stock - fully diluted		65,964,390			51,421,931
Less: antidilutive securities
Stock options		(50,046	)		—
Restricted stock awards		(8,478	)		—
Restricted stock units		(13,861	)		—

Class A common stock - diluted (excluding antidilutive securities)		65,892,005			51,421,931
Class B common stock - basic and diluted		N/A			15,555,000
Calculation of basic and diluted loss per share:
Class A common stock:
Dividends	$	0.36		$	0.31
Undistributed loss		(0.66	)		(0.51	)

Basic loss per share	$	(0.30	)	$	(0.20	)

Class A common stock:
Diluted loss per share	$	(0.30	)	$	(0.29	)

Class B common stock:
Basic and diluted loss per share		N/A		$	(0.51	)

Cash dividends declared per Class A common share	$	0.34		$	0.31

18.

Geographic Information

The table below provides information, by country, about the Company’s combined operations. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located (in thousands):


	Revenue				Property, Plant and Equipment, net
	Three months ended March 31,				March 31, 2015		December 31, 2014
	2015		2014		March 31, 2015		December 31, 2014
United States	$	47,775	$	36,252	$	1,760,231	$	1,784,219
Canada		11,753		13,286		210,733		233,690
Chile		5,338		79		329,541		332,947

Total	$	64,866	$	49,617	$	2,300,505	$	2,350,856

19.

Commitments and Contingencies

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

Power Sale Agreements

The Company has various PPAs that terminate from 2025 to 2039. The terms of the PPAs generally provide for the annual delivery of a minimum amount of electricity at fixed prices and in some cases include price escalation over the term of the respective PPAs. As of March 31, 2015, under the terms of the PPAs, the Company issued irrevocable letters of credit totaling $57.2 million to ensure its performance for the duration of the PPAs.

Project Finance Agreements

The Company has various project finance agreements that obligate the Company to provide certain reserves to enhance its credit worthiness and facilitate the availability of credit. As of March 31, 2015, the Company issued irrevocable letters of credit totaling $110.4 million, of which $48.4 million was from the Company’s revolving credit facility, to ensure performance under these various project finance agreements.

Land Leases

The Company has entered into various long-term land lease agreements. As of March 31, 2015, total outstanding lease commitments were $219.3 million. During the three months ended March 31, 2015 and 2014, the Company recorded rent expense of $2.4 million and $1.9 million, respectively, in project expense in the consolidated statements of operations.

Service and Maintenance Agreements

The Company has entered into service and maintenance agreements with third party contractors to provide operations and maintenance services, modifications and upgrades for varying periods over the next eleven years. Based on the terms of these agreements, the third party contractors will receive a daily base fee per turbine that may, or may not, be subject to periodic price adjustments for inflation, over the terms of the agreements. As of March 31, 2015, outstanding commitments with these third party contractors were $364.9 million, including an estimated annual price adjustment for inflation of 2%, where applicable, payable over the full term of these agreements.

Purchase, Construction and Other Commitments

The Company has entered into various commitments with service providers related to the Company’s projects and operations of its business. Outstanding commitments with these vendors, excluding turbine operations and maintenance commitments were $15.1 million as of March 31, 2015. The Company also has construction-related open commitments of $116.8 million as of March 31, 2015. In addition, the Company has a commitment to purchase $6.3 million of wind turbine spare parts from a third party contractor under a maintenance and service agreement.

The Company has total commitments of $6.6 million over approximately the next 20 years to local community and government organizations surrounding certain wind farms.

Purchase and Sales Agreements

On December 20, 2013, the Company acquired a 45.0% equity interest in Grand from Pattern Development. Subject to the terms of this agreement, to the extent that the project makes a special distribution as result of construction cost underruns, the Company may make an additional contingent payment of up to C$5.0 million, or $3.9 million based on the exchange rate as of March 31, 2015, as calculated based on final budget to actual amounts and distributions payable to Pattern Development upon term conversion.

Turbine Availability Warranties

The Company has various turbine availability warranties from its turbine manufacturers. Pursuant to these warranties, if a turbine operates at less than minimum availability during the warranty period, the turbine manufacturer is obligated to pay, as liquidated damages, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, pursuant to certain of these warranties, if a turbine operates at more than a specified availability during the warranty period, the Company has an obligation to pay a bonus to the turbine manufacturer. As of March 31, 2015, the Company recorded liabilities of $0.1 million associated with bonuses payable to the turbine manufacturers. No such liability was recorded as of March 31, 2014.

In 2013, the Company entered into warranty settlements with a turbine manufacturer for blade related wind turbine outages. The warranty settlements provide for total liquidated damage payments of approximately $21.9 million for the year ended December 31, 2013. During the year ended December 31, 2013, the Company received payments of $24.1 million in connection with these warranty settlements. As of March 31, 2015, the Company recorded an accrued liability of $1.7 million related to the maximum potential future refund of liquidated damage payments to this turbine manufacturer. The warranty settlements received, net of the maximum potential future refund to the wind turbine manufacturer, has been recorded as other revenue in the consolidated statements of operations.

Long-Term Service Guarantees

The Company has service guarantees from its turbine service and maintenance providers. These service guarantees are associated with long-term turbine service arrangements which commenced on various dates in 2014 and will commence on various dates in 2015 for certain wind projects. Pursuant to these guarantees, if a turbine operates at less than minimum availability during the guarantee period, the service provider is obligated to pay, as liquidated damages, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, pursuant to certain of these guarantees, if a turbine operates at more than a specified availability during the guarantee period, the Company has an obligation to pay a bonus to the service provider. As of March 31, 2015, the Company recorded liabilities of $0.7 million associated with bonuses payable to service providers.

Contingent Liabilities

In 2014, the Company recorded a contingent obligation, payable to a third party, related to the acquisition of Logan’s Gap. Pursuant to the agreement, the Company is obligated to pay an additional $4.0 million upon the earlier of commercial operations or tax equity funding, which is expected to occur in the fourth quarter of 2015.

Indemnity

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

The Company is party to certain indemnities for the benefit of the Spring Valley, Santa Isabel, Ocotillo, Panhandle 1 and Panhandle 2 project finance lenders and tax equity partners. These indemnity obligations consist principally of indemnities that protect the project finance lenders from the potential effect of any recapture by the U.S. Department of the Treasury of any amount of the Cash Grants previously received by the projects. The Cash Grant indemnity obligations guarantee amounts of any Cash Grant made to each of the respective projects that may subsequently be recaptured. In addition, the Company is also party to an indemnity of its Ocotillo project finance lenders in connection with certain legal matters, which is limited to the amount of certain related costs and expenses.

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

20.

Related Party Transactions

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

Management Services Agreement and Shared Management

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

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

The following table presents net bilateral management service cost reimbursements included in the consolidated statements of operations (in thousands):


	Three months ended March 31,
	2015			2014
Related party general and administrative	$	1,808		$	1,280
Related party income		(668	)		(628	)

Total	$	1,140		$	652

As of March 31, 2015 and December 31, 2014, the amounts payable to Pattern Development for bilateral management service cost reimbursements were $1.2 million and $0.8 million, respectively. In addition, the Company had a related party receivable of zero and $0.1 million as of March 31, 2015 and December 31, 2014, respectively, for IPO cost reimbursements due from Pattern Development.

Letters of Credit, Indemnities and Guarantees

Pattern Development agreed to guarantee $14.0 million of El Arrayán’s payment obligations to a lender that has provided a $20.0 million credit facility for financing of El Arrayán’s recoverable, construction-period value-added tax payments. The remaining $6.0 million of the credit facility has been guaranteed by another investor in El Arrayán.

Purchase and Sales Agreements

On December 19, 2014, the Company acquired 100% of the membership interests in Logan’s Gap from Pattern Development, for a purchase price of approximately $15.1 million. In addition, the Company has a contingent payment of up to $4.0 million to an unrelated third party at the earlier of commercial operations or tax equity funding. Logan’s Gap is a 164 MW wind project located in Comanche County, Texas.

On November 10, 2014, the Company completed its acquisition of 100% of the Class B membership interests in the Panhandle 2 wind project, representing a 81% initial ownership interest in the project’s distributable cash flow, through the acquisition of Panhandle B Member 2, from Pattern Development, for a purchase price of approximately $123.8 million, which includes debt assumed of $195.4 million that was repaid immediately after acquisition. This represents a 147 MW interest in the 182 MW wind project, located in Carson County, Texas.

On September 5, 2014, the Company exercised its right to acquire the name “Pattern” and the Pattern logo from Pattern Development pursuant to a Service Mark Purchase and Sale Agreement for a purchase price of $1. The Company granted to Pattern Development a license to use the name “Pattern” and the Pattern logo.

On June 30, 2014, the Company acquired 100% of the Class B membership interests in the Panhandle 1 wind project, representing a 79% initial ownership interest in the project’s distributable cash flow, through the acquisition of Panhandle Wind Holdings LLC, from Pattern Development, for a purchase price of approximately $124.4 million. This represents a 172 MW interest in the 218 MW wind project, located in Carson County, Texas.

On June 25, 2014, the Company acquired a 100% equity interest in AEI El Arrayán, an entity holding a 38.5% indirect interest in El Arrayán, for a total purchase price of approximately $45.3 million. The Company owned a 31.5% indirect interest in El Arrayán prior to acquiring the additional 38.5% interest in order to obtain majority control, or 70% interest, in the project. El Arrayán is a 115 MW wind power project, located in Ovalle, Chile.

Management Fees

The Company provides management services and receives a fee for such services under agreements with its joint venture investees, South Kent, Grand, and prior to its acquisition of the controlling interest of El Arrayán on June 25, 2014, in addition to various Pattern Development subsidiaries. Management fees of $0.8 million and $0.5 million were recorded as related party revenue in the consolidated statements of operations for the three months ended March 31, 2015 and 2014, respectively. A related party receivable of $0.5 million and $0.7 million was recorded in the consolidated balance sheets as of March 31, 2015 and December 31, 2014,

respectively. Subsequent to the acquisition of control of El Arrayán, Panhandle 1 and Panhandle 2, the related management fees are eliminated upon consolidation. Additionally, the Company eliminates the intercompany profit from management fees related to its ownership interest in the joint ventures.

21.

Subsequent Events

On April 29, 2015, the Company acquired 100% of the membership interests in Fowler Ridge IV Wind LLC through the acquisition of Fowler Ridge IV B Member LLC from Pattern Development, pursuant to a Purchase and Sale Agreement, for a purchase price of approximately $37.5 million, paid at closing, and contingent payments of up to $29.1 million, payable upon tax equity funding. The 150 MW wind project named Amazon Wind Farm (Fowler Ridge), located in Benton County, Indiana, is expected to reach commercial operation in late 2015.

On April 4, 2015, the Company entered into an agreement with Pattern Development to acquire a one-third limited partnership interest in K2, a 270 MW wind project located in the Township of Ashfield-Colborne Wawanosh, Ontario, as well as 100% of the issued and outstanding shares in Pattern K2 GP Holdings Inc., for approximately $128.0 million, subject to certain adjustments, plus assumed estimated proportionate debt at term conversion of approximately $218.0 million. If the closing of the acquisition occurs before the project reaches commercial operation, the Company will directly own a one-third limited partnership interest in K2 and directly own 25% of the issued and outstanding shares of K2 Wind Ontario Inc., the general partner, and indirectly hold a 0.0025% partnership interest in K2. If the closing of the acquisition occurs after the project reaches commercial operation, the Company will directly own a one-third limited partnership interest in K2 and directly own one-third of the issued and outstanding shares of K2 Wind Ontario Inc., the general partner, and indirectly hold a 0.0033% partnership interest in K2.

On April 1, 2015, the Company entered into an agreement with Wind Capital Group, LLC (“Wind Capital”) and Lincoln County Wind Project Finco, LLC (“Lincoln County Wind”) to acquire interests in a 150 MW wind project in King City, Missouri, from Wind Capital and a 201 MW wind project in Ellsworth and Lincoln Counties, Kansas, from Lincoln County Wind, for aggregate consideration of approximately $244.0 million, subject to certain adjustments. The Company will assume certain ordinary course performance guarantees securing project obligations.

ITEM 2.

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 audited consolidated financial statements and related notes thereto included as part of our Annual Report on Form 10-K for the year ended December 31, 2014 and our unaudited consolidated financial statements for the three months ended March 31, 2015 and other disclosures (including the disclosures under “Part II. Item 1A. Risk Factors”) included in this Quarterly Report on Form 10-Q. Our consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles and are presented in U.S. dollars. Unless the context provides otherwise, references herein to “we,” “our,” “us,” “our company” and “Pattern Energy” refer to Pattern Energy Group Inc., a Delaware corporation, together with its consolidated subsidiaries.

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, including three that we agreed to acquire in April 2015, located in the United States, Canada and Chile that use proven, best-in-class technology and have a total owned capacity of 2,112 MW. These projects consist of thirteen operating projects with three projects under construction. Our construction projects, the Logan’s Gap project, which we acquired from Pattern Development in December 2014, the K2 project, in which we agreed to acquire a one-third interest, in April 2015, and the Amazon Wind Farm (Fowler Ridge) project, which we acquired in April 2015, are scheduled to commence commercial operations prior to the end of 2015. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price power sale agreement with a creditworthy counterparty. One of our counterparties, PREPA, has been downgraded. Refer to Item 1A “Risk Factors – Our projects rely on a limited number of key power purchasers. The power purchaser for our Santa Isabel project has been downgraded” of our Form 10-K for the year ended December 31, 2014. Ninety-two percent of the electricity to be generated by our projects will be sold under these power sale agreements, which have a weighted average remaining contract life of approximately 16 years.

We intend to maximize long-term value for our stockholders in an environmentally responsible manner and with respect for the communities in which we operate. Our business is built around the core values of creating a safe, high-integrity and exciting work environment; applying rigorous analysis to all aspects of our business; and proactively working with our stakeholders in addressing environmental and community concerns. Our financial objectives, which we believe will maximize long-term value for our stockholders, are to produce stable and sustainable cash available for distribution, selectively grow our project portfolio and our dividend and maintain a strong balance sheet and flexible capital structure.

Our growth strategy is focused on the acquisition of operational and construction-ready power projects from Pattern Development and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per share over time. We expect our continuing relationship with Pattern Development, a leading developer of renewable energy and transmission projects, will be an important source of growth for our business. In addition, we expect opportunities in Japan and Mexico will form part of our growth strategy. Currently, Pattern Development has a 4,500 MW pipeline of development projects, all of which are subject to our right of first offer.

Recent Developments

On April 29, 2015, we acquired 100% of the membership interests in Fowler Ridge IV Wind LLC through the acquisition of Fowler Ridge IV B Member LLC, from Pattern Development, pursuant to a Purchase and Sale Agreement, for a purchase price of approximately $37.5 million, paid at closing, and contingent payments of up to $29.1 million, payable upon tax equity funding. The 150 MW wind project named Amazon Wind Farm (Fowler Ridge), located in Benton County, Indiana, is expected to reach commercial operation in late 2015.

On April 4, 2015, we entered into an agreement with Pattern Development to acquire a one-third limited partnership interest in K2, a 270 MW wind project located in the Township of Ashfield-Colborne Wawanosh, Ontario, as well as 100% of the issued and outstanding shares in Pattern K2 GP Holdings Inc., for approximately $128.0 million, subject to certain adjustments, plus assumed estimated proportionate debt at term conversion of approximately $218.0 million. If the closing of the acquisition occurs before the project reaches commercial operation, we will directly own a one-third limited partnership interest in K2 and directly own 25% of the issued and outstanding shares of K2 Wind Ontario Inc., the general partner, and indirectly hold a 0.0025% partnership interest in K2. If the closing of the acquisition occurs after the project reaches commercial operation, we will directly own a one-third limited partnership interest in K2 and directly own one-third of the issued and outstanding shares of K2 Wind Ontario Inc., the general partner, and indirectly hold a 0.0033% partnership interest in K2.

On April 1, 2015, we entered into an agreement with Wind Capital and Lincoln County Wind, unrelated third parties, to acquire interests in a 150 MW wind project (“Lost Creek Wind”) in King City, Missouri, from Wind Capital and a 201 MW wind project (“Post Rock Wind”) in Ellsworth and Lincoln Counties, Kansas, from Lincoln County Wind, for aggregate consideration of approximately $244.0 million, subject to certain adjustments. In addition, in connection with the closing, we will assume certain ordinary course performance guarantees securing project obligations.

On February 19, 2015, we announced that Pattern Development has signed a joint venture agreement with CEMEX Energia, a subsidiary of CEMEX, S.A.B. de C.V. to jointly develop renewable energy projects throughout Mexico. Pattern Development and CEMEX Energia have set a goal of developing 1,000 MW of renewable generation in Mexico over the next five years. Pattern Development’s 4,500 MW pipeline of development projects also includes 1,000 MW of Mexican wind and solar power projects, all of which are subject to our purchase rights.

On February 9, 2015, we completed a follow-on offering of our Class A common stock. In total, 12,000,000 shares of Class A common stock were sold. Of this amount, we issued and sold 7,000,000 shares of our Class A common stock and Pattern Development, the selling stockholder, sold 5,000,000 shares of Class A common stock. We received net proceeds of approximately $196.2 million after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We intend to use the net proceeds from the offering for working capital and general corporate purposes, including investment in one or more acquisition opportunities from Pattern Development, or third parties, and the potential repayment of outstanding indebtedness under our existing revolving credit facility. We did not receive any proceeds from the sale of shares sold by Pattern Development.

On January 28, 2015, we announced that Pattern Development acquired a majority stake in Green Power Investment Corporation (“GPI”), based in Tokyo, Japan. GPI has 1,000 MW of wind and solar projects in various stages of development, spread across a number of existing near and longer term development projects. Pattern Development’s expected interest in the GPI projects is included in its 4,500 MW pipeline of development projects, all of which are subject to our purchase rights.

The following table sets forth each of our construction projects as well as their respective power capacities and our anticipated date of their commencement of commercial operations:

Projects

Location

Construction
Start

Commercial
Operations

Rated

Owned

Logan’s Gap

Texas

Q4 2014

Q4 2015

200

164

Ontario

Q1 2014

Q2 2015

270

Amazon Wind Farm (Fowler Ridge)

Indiana

Q2 2015

Late 2015

150

116

620

370

Since December 2014, we have added three new identified Right of First Offer Projects (“Identified ROFO Projects”) to our list of projects that we expect to acquire from Pattern Development in connection with our purchase rights:

•

On April 21, 2015, Pattern Development announced that it had entered into a 20-year PPA with the Independent Electricity System Operator in Ontario in connection with a 100 MW wind power project proposed to be built in Chatham-Kent, Ontario. Pattern Development expects to retain an owned capacity in the project of approximately 43 MW. The project is expected to begin commercial operation in late 2017.

•

On February 13, 2015, Pattern Development announced that it had entered into a 25-year PPA with Hydro-Québec in connection with a 147 MW wind power project proposed to be built in the Chaudière-Appalaches region, approximately 50 kilometers south of Québec City. Pattern Development expects to retain the full interest in the Mont Sainte-Marguerite Wind project. The project is expected to begin commercial operation in late 2017.

•

On January 20, 2015, Pattern Development announced that it had entered into a 13-year PPA with a subsidiary of Amazon.com in connection with a 150 MW wind power project proposed to be built in Indiana. Subsequent to being placed on the list of Identified ROFO Projects and subsequent to the end of the first quarter, we acquired such project from Pattern Development. Refer to “Recent Developments” above.

Below is a summary of our Identified ROFO Projects that we expect to acquire from Pattern Development in connection with our purchase right. For additional discussion on the Identified ROFO Projects, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Recent Transactions”, in our Annual Report on Form 10-K for the year ended December 31, 2014.


						Capacity (MW)
Identified ROFO Projects	Status	Location	Construction Start ⁽¹⁾	Commercial Operations ⁽²⁾	Contract Type	Rated⁽³⁾		Pattern Development- Owned ⁽⁴⁾
Gulf Wind ⁽⁵⁾	Operational	Texas	2008	2009	Hedge		283		76
Armow	In construction	Ontario	2014	2015	PPA		180		90
Meikle	Ready for financing	British Columbia	2015	2016	PPA		185		185
Conejo Solar	Ready for financing	Chile	2015	2016	PPA		104		73
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	Late 2016	Late 2017	PPA		100		43

							1,399		814

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

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

(3)

Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of wind and other conditions, a project or a turbine will not operate at its rated capacity at all times and the amount of electricity generated will be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors discussed elsewhere in this Form 10-Q.

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

(5)	We have a call right to acquire Pattern Development’s retained interest in the Gulf Wind project, at fair market value, at any time between October 2, 2014 and October 2, 2015.

Corporate Developments

In January 2015, we established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in our cash flow, which may have an adverse impact to our short-term liquidity or financial condition. A majority of our power sale agreements and operating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. During the first quarter of 2015, we entered into foreign currency forward contracts, with an aggregate notional amount of $42.8 million, to mitigate the currency exchange rate risk on Canadian dollar denominated cash flows. These instruments have an initial maturity ranging from five to twenty-three months. The foreign currency forward contracts are considered non-designated derivative instruments and are not used for trading or speculative purposes.

On April 6, 2015, we announced an increase to our growth target for cash available for distribution per share to a compound annual growth rate of 12-15% for the three year period following 2014.

Key Metrics

We regularly review a number of financial measurements and operating metrics to evaluate our performance, measure our growth and make strategic decisions. In addition to traditional U.S. GAAP performance and liquidity measures, such as revenue, cost of revenue, net income and cash provided by (used in) operating activities, we also consider proportional MWh sold, average realized electricity price and Adjusted EBITDA in evaluating our operating performance and cash available for distribution as supplemental liquidity measures. Each of these key metrics is discussed below.

Proportional MWh Sold and Average Realized Electricity Price

The number of MWh sold and the average realized price per MWh sold are the operating metrics that determine our revenue, as well as the revenue of our unconsolidated investments. Proportional MWh sold for any period presented, represents the sum of the product of (i) the number of MWh sold by each of our projects multiplied by (ii) our percentage interest in each projects’ distributable cash flow. For any period presented, average realized electricity price represents (i) the sum of the products of: (a) total revenue from electricity sales and energy derivative settlements at each of our projects and (b) our percentage interest in each project’s distributable cash flow divided by (ii) our proportional MWh sold.

Adjusted EBITDA

We define Adjusted EBITDA as net income before net interest expense, income taxes and depreciation and accretion, including our proportionate share of net interest expense, income taxes and depreciation and accretion of joint venture investments that are accounted for under the equity method. Adjusted EBITDA also excludes the effect of certain mark-to-market adjustments and infrequent items not related to normal or ongoing operations, such as early payment of debt and realized derivative gain or loss from refinancing transactions, and gain or loss related to acquisitions or divestitures. In calculating Adjusted EBITDA, we exclude mark-to-market adjustments to the value of our derivatives because we believe that it is useful for investors to understand, as a supplement to net income and other traditional measures of operating results, the results of our operations without regard to periodic, and sometimes material, fluctuations in the market value of such assets or liabilities.

Adjusted EBITDA is a non-U.S. GAAP measure. The most directly comparable U.S. GAAP measure to adjusted EBITDA is net loss. The following table reconciles net loss to Adjusted EBITDA for the periods presented (unaudited and in thousands):


	Three months ended March 31,
	2015			2014
Net loss	$	(22,059	)	$	(21,899	)
Plus:
Interest expense, net of interest income		17,699			14,418
Tax benefit		(746	)		(2,032	)
Depreciation and accretion		29,056			21,177

EBITDA	$	23,950		$	11,664

Unrealized (gain) loss on energy derivative		(2,972	)		7,733
Unrealized loss on derivatives, net		2,441			3,723
Interest rate derivative settlements		959			1,017
Net loss on transactions		1,284			—
Plus, proportionate share from equity accounted investments:
Interest expense, net of interest income		5,438			253
Depreciation and accretion		4,509			187
Unrealized loss on interest rate and currency derivatives, net		11,134			12,595
Realized loss on interest rate and currency derivatives		—			22

Adjusted EBITDA	$	46,743		$	37,194

Cash Available for Distribution

We define cash available for distribution as net cash provided by operating activities as adjusted for certain other cash flow items that we associate with our operations. It is a non-U.S. GAAP measure of our ability to generate cash to service our dividends. Our definition of cash available for distribution has been modified from prior periods to include distributions from unconsolidated investments to the extent such distributions were derived from operating cash flows. Cash available for distribution represents cash provided by operating activities as adjusted to (i) add or subtract changes in operating assets and liabilities, (ii) subtract net deposits into restricted cash accounts, which are required pursuant to the cash reserve requirements of financing agreements, to the extent they are paid from operating cash flows during a period, (iii) subtract cash distributions paid to noncontrolling interests, (iv) subtract scheduled project-level debt repayments in accordance with the related loan amortization schedule, to the extent they are paid from operating cash flows during a period, (v) subtract non-expansionary capital expenditures, to the extent they are paid from operating cash flows during a period, (vi) add cash distributions received from unconsolidated investments, to the extent such distributions were derived from operating cash flows and (vii) add or subtract other items as necessary to present the cash flows we deem representative of our core business operations.

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


	Three months ended March 31,
	2015			2014
Net cash provided by operating activities	$	16,239		$	16,405
Changes in operating assets and liabilities		(4,657	)		6,773
Other		(144	)		(122	)
Network upgrade reimbursement		618			618
Release of restricted cash to fund general and administrative costs		—			54
Operations and maintenance capital expenditures		(38	)		(54	)
Transaction costs for acquisitions		420			—
Distributions from unconsolidated investment		6,076			—
Less:
Distributions to noncontrolling interests		(748	)		—
Principal payments paid from operating cash flows		(8,435	)		(5,830	)

Cash available for distribution	$	9,331		$	17,844

Results of Operations

Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

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


	Three months ended March 31,
	2015			2014			$ Change			% Change
Revenue	$	64,866		$	49,617		$	15,249			31	%

Project expense		25,246			16,074			(9,172	)		-57	%
Depreciation and accretion		29,056			21,177			(7,879	)		-37	%

Total cost of revenue		54,302			37,251			(17,051	)		-46	%

Gross profit		10,564			12,366			(1,802	)		-15	%

General and administrative		6,221			3,903			(2,318	)		-59	%
Related party general and administrative		1,808			1,280			(528	)		-41	%

Total operating expenses		8,029			5,183			(2,846	)		-55	%

Operating income		2,535			7,183			(4,648	)		-65	%
Total other expense		(25,340	)		(31,114	)		5,774			19	%

Net loss before income tax		(22,805	)		(23,931	)		1,126			5	%
Tax benefit		(746	)		(2,032	)		(1,286	)		-63	%

Net loss		(22,059	)		(21,899	)		(160	)		-1	%
Net loss attributable to noncontrolling interest		(2,160	)		(7,010	)		(4,850	)		-69	%

Net loss attributable to controlling interest	$	(19,899	)	$	(14,889	)	$	(5,010	)		-34	%

Proportional MWh sold and average realized electricity price. Our proportional MWh sold for the three months ended March 31, 2015 was 929,420 MWh, as compared to 546,290 MWh for the three months ended March 31, 2014, an increase of 383,130, or 70.1%. This increase in proportional MWh sold was primarily attributable to the commencement of commercial operations at both El Arrayán and Panhandle 1 in June 2014, Panhandle 2 in November 2014 and at our unconsolidated investments, South Kent in March

2014 and Grand in December 2014. Our average realized electricity price was approximately $83 per MWh for the three months ended March 31, 2015 as compared to approximately $94 per MWh for the three months ended March 31, 2014. The $11 per MWh decrease in the average realized electricity price was due to lower PPA pricing related to Panhandle 1 and Panhandle 2 projects partially offset by higher PPA pricing related to El Arrayán, South Kent, and Grand. Overall, production for the first quarter was impacted by low wind levels which were independently reported to be 20%, or more, below normal across the western United States and Texas. These wind levels resulted in a 20% negative variance in our production in the three months ended March 31, 2015 compared to our long-term expectation.

Revenue. Revenue for the three months ended March 31, 2015 was $64.9 million as compared to $49.6 million for the three months ended March 31, 2014, an increase of $15.3 million, or 31.0%. This increase in revenue was primarily attributable to increased electricity sales due to the commencement of commercial operations at Panhandle 1, El Arrayán and Panhandle 2 at various times in 2014. We also realized a $3.0 million gain on valuation of the Gulf Wind energy derivative during the three months ended March 31, 2015, compared to a $7.7 million loss in the prior period, in addition to an increase of $3.4 million in energy derivative settlements during the first quarter of 2015. The value of our energy derivative, and the amount of unrealized gain or loss we record, increases and decreases due to our monthly derivative settlements and changes in forward electricity prices, which are derived from and impacted by changes in forward natural gas prices. These increases to revenue were partially offset by decreases in electricity production attributable to lower wind levels across the western United States and Texas.

Cost of revenue. Cost of revenue for the three months ended March 31, 2015 was $54.3 million as compared to $37.3 million for the three months ended March 31, 2014, an increase of $17.0 million, or 45.6%. The increase in cost of revenue was primarily attributable to the commencement of commercial operations at Panhandle 1, El Arrayán and Panhandle 2 at various times in 2014. As each new project commences commercial operations, we incur new incremental and ongoing costs for maintenance and services agreements, property taxes, insurance, land lease, depreciation and other costs associated with managing, operating and maintaining the facility, including adding site employees and other operations staff.

Operating expenses. Operating expenses for the three months ended March 31, 2015 were $8.0 million as compared to $5.2 million for the three months ended March 31, 2014, an increase of $2.8 million, or 54.9%. The increase in operating expenses was primarily attributable to general and administrative expense to support new projects acquired in 2014 and increases in acquisition-related activity.

Other expense. Other expense for the three months ended March 31, 2015 was $25.3 million compared to $31.1 million for the three months ended March 31, 2014, an increase of $5.8 million, or 18.6%. The decrease in other expense was primarily attributable to a $9.5 million decrease in equity in losses in unconsolidated investments as a result of lower unrealized loss on interest rate derivatives recognized on the unconsolidated investees’ financial statements. In addition, we recorded a decrease of $1.3 million in unrealized loss on derivatives related to the valuation of interest rate derivatives at Ocotillo, partially offset by an unrealized gain on the valuation of foreign currency forward contracts. The changes in unrealized loss on interest rate derivatives were due to an increase in the forward interest rate curve during the three months ended March 31, 2015, compared to the three months ended March 31, 2014. Offsetting these decreases in losses was an increase in interest expense of $3.3 million primarily related to debt from El Arrayán, in addition to $1.3 million in transaction-related costs incurred during the first quarter of 2015. No transaction-related costs were recorded in the comparable quarter of 2014.

Tax benefit. The tax benefit was $0.7 million for the three months ended March 31, 2015 compared to $2.0 million for the same period in the prior year. The benefit for the three months ended March 31, 2015 was primarily the result of recognizing a deferred tax asset on equity losses in unconsolidated investments at South Kent and Grand, which was primarily related to unrealized losses on derivatives and recognizing a deferred tax asset on losses in El Arrayán, partially offset by tax expense at our Canadian and Puerto Rican operations, and foreign withholding taxes on intercompany transactions in certain foreign jurisdictions.

Net loss attributable to noncontrolling interest. The net loss attributable to noncontrolling interest was $2.2 million for the three months ended March 31, 2015 compared to $7.0 million for the three months end March 31, 2014, a decrease of $4.8 million, or 69.2%. The decrease in net loss attributable to noncontrolling interest was primarily related to an unrealized gain on energy derivative for the three months ended March 31, 2015, compared to unrealized loss on energy derivative for the three months ended March 31, 2014, in addition to an increase in derivative hedge settlements at Gulf Wind. These decreases were partially offset by net loss attributable to noncontrolling interests from Panhandle 1, Panhandle 2 and El Arrayán, all of which commenced commercial operations at various times in 2014.

Adjusted EBITDA. Adjusted EBITDA for the three months ended March 31, 2015 was $46.7 million compared to $37.2 million for the same period in the prior year, an increase of $9.5 million, or 25.7%. The increase in Adjusted EBITDA was primarily attributable to the commencement of commercial operations at South Kent, Grand, Panhandle 1, Panhandle 2, and El Arrayán at various times in 2014. These increases were partially offset by decreases in electricity production attributable to lower wind levels across the western United States and Texas.

Liquidity and Capital Resources

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

The principal indicators of our liquidity are our restricted and unrestricted cash balances and availability under our credit agreements. As of March 31, 2015, our available liquidity was $805.5 million, including unrestricted cash on hand of $243.3 million, restricted cash on hand of $29.4 million, $301.6 million available under our revolving credit agreement (which can be increased, subject to certain conditions, pursuant to the agreement) and $231.3 million available under project financings consisting of $90.5 million for post construction use and $140.8 million for construction use.

We believe that throughout 2015 and 2016, we will have sufficient liquid assets, cash flows from operations, and borrowings available under our revolving credit facility to meet our financial commitments, debt service obligations, contingencies and anticipated required capital expenditures, without taking into account capital required for additional project acquisitions. Additionally, we believe that our construction projects have been sufficiently capitalized, or that we have sufficient liquidity, such that we will not need to seek additional financing arrangements in order to complete construction and achieve commercial operations at the projects. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corresponding adverse effect on our borrowing capacity. In connection with our future capital expenditures and other investments, including any project acquisitions that we may make, we may, from time to time, issue debt or equity securities.

Cash Flows

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

Net Cash Provided by Operating Activities

Net cash provided by operating activities was $16.2 million for the three months ended March 31, 2015 as compared to $16.4 million for the same period in the prior year, a decrease of $0.2 million, or 1.2%. This is primarily related to additional electricity revenue from commercial operations at Panhandle 1, El Arrayán and Panhandle 2 which commenced operations at various times in 2014, partially offset by decreases in electricity production attributable to lower wind levels across the western United States and Texas.

Net Cash (Used in) Provided by Investing Activities

Net cash used in investing activities was $41.3 million for the three months ended March 31, 2015, consisted primarily of $63.9 million for capital expenditures, including $47.4 million related to the construction at Logan’s Gap. This was partially offset by a $16.0 million release of restricted cash due to the payment of construction reserves and $6.1 million of distributions from unconsolidated investments. Net cash provided by investing activities was $1.4 million for the three months ended March 31, 2014, which consisted primarily of $1.4 million receipt related to our reimbursable interconnection receivable.

Net Cash Provided by (Used in) Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2015 was $169.6 million, which consisted of $196.9 million of net proceeds from our equity offering, net of expenses, and proceeds of $47.6 million from short-term debt related to the construction of Logan’s Gap, partially offset by $15.6 million of dividend payments and a $50.0 million repayment of our revolving credit facility. Net cash used in financing activities for the three months ended March 31, 2014 was $20.7 million, which was primarily attributable to an $11.1 million dividend payment, $3.0 million increase in restricted cash, and $5.8 million of loan repayments.

Cash Available for Distribution

Cash available for distribution was $9.3 million for the three months ended March 31, 2015 as compared to $17.8 million for the same period in the prior year, a decrease of $8.5 million, or 47.7%. This decrease was primarily the result of decreases in electricity production attributable to lower wind levels across the western United States and Texas and increases of $9.2 million in project expenses, primarily from the commencement of operations at Panhandle 1, El Arrayán and Panhandle 2, $2.8 million in operating expenses, $3.3 million in interest expense and $2.6 million in principal payments from operating cash. The decrease was partially offset by additional electricity sales from the commencement of commercial operations at Panhandle 1, El Arrayán, and Panhandle 2 and a $6.1 million cash distribution from unconsolidated investments.

Cash Dividends to Investors

We intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A common stock. On November 26, 2013, we announced the initiation of a quarterly dividend on our Class A common stock. On April 20, 2015, the Company increased its dividend to $0.3520 per share, or $1.408 per share on an annualized basis, commencing with respect to dividends paid on July 30, 2015 to holders of record on June 30, 2015. The following table sets forth the dividends declared on shares of Class A common stock for the periods indicated.

Dividends
Per Share

Declaration Date

Record Date

Payment Date

2015:

Second Quarter

0.3520

April 20, 2015

June 30, 2015

July 30, 2015

First Quarter

0.3420

February 24, 2015

March 31, 2015

April 30, 2015

2014:

Fourth Quarter

0.3350

October 29, 2014

December 31, 2014

January 30, 2014

Third Quarter

0.3280

August 1, 2014

September 30, 2014

October 30, 2014

Second Quarter

0.3220

April 30, 2014

June 30, 2014

July 30, 2014

First Quarter

0.3125

February 26, 2014

March 31, 2014

April 30, 2014

We established our initial quarterly dividend level based on a targeted cash available for distribution payout ratio of 80% both prior to and following the Class B common stock 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 share of Class A common stock over time. We may in the future raise capital and make investments in new power projects upon or near the commencement of construction of such projects and therefore prior to the expected commencement of operations of the new projects, which could result in a passage of time of twelve or more months before we begin to receive any cash flow contributions from such projects to our cash available for distribution. In connection with these investments, we may increase our dividends prior to the receipt of such cash flow contributions, which would likely cause our payout ratio to temporarily exceed our targeted run-rate payout ratio. However, the determination of the amount of cash dividends to be paid to holders of our Class A common stock will be made by our Board of Directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant. Refer to Item 1A “Risk Factors—Risks Related to Ownership of our Class A Shares—Risks Regarding our Cash Dividend Policy” of our Annual Report on Form 10-K for the year ended December 31, 2014.

We expect to pay a quarterly dividend on or about the 30th day following each fiscal quarter to holders of record of our Class A common stock on the last day of such quarter.

Capital Expenditures and Investments

All capital expenditures and investments to date were either funded by us, Pattern Development or by project finance lenders under project-level credit facilities. For 2015, we expect to make capital expenditures of $314.5 million at our owned construction projects – Logan’s Gap and Amazon Wind Farm (Fowler Ridge).

We expect to make investments in additional projects. We have made a cash payment to Pattern Development in the amount of $37.5 million in connection with the Amazon Wind Farm (Fowler Ridge) acquisition. We have agreed to make a cash payment to Pattern Development in the amount of $128.0 million, subject to certain price adjustments, at the time of the acquisition of K2 which we expect to occur in May 2015. We have also agreed to make a cash payment to unrelated third parties in the amount of $244.0 million, subject to certain adjustments, to acquire Lost Creek Wind and Post Rock Wind. We expect to consummate such acquisition and make such payment in May 2015. Although we have no commitments to make any acquisitions, other than the acquisitions of K2 and Wind Capital, we consider it reasonably likely that we may have the opportunity to acquire certain other Pattern Development projects under our purchase rights within the next 24 month period.

We believe that we will have sufficient cash and revolving credit facility capacity to complete the funding of the Logan’s Gap and Amazon Wind Farm (Fowler Ridge) construction commitments, but this may be affected by any other acquisitions or investments that we make. We also have a call right to purchase Pattern Development’s interest in the Gulf Wind project at fair market value, which is exercisable during the period from October 2, 2014 to October 2, 2015. To the extent that we make any such investments or acquisitions, we will evaluate capital markets and other corporate financing sources available to us at the time.

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

For the year ending December 31, 2015, we budgeted $0.5 million for operational capital expenditures and $1.5 million for expansion capital expenditures.

Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014, except as set forth below.

Change in Depreciable Lives of Property, Plant and Equipment

We periodically review the estimated economic useful lives of our fixed assets. In 2015, our review indicated that the expected economic useful lives of certain wind farms were longer than the estimated economic useful lives used for depreciation purposes in our financial statements. As a result, effective January 1, 2015, we changed our estimate of the economic useful lives of wind farms for which construction began after 2011, from 20 to 25 years. All other wind farms continue to depreciate over an estimated economic useful life of 20 years. For the three months ended March 31, 2015, the effect of this change in estimate reduced depreciation expense by $3.6 million, decreased net loss by $3.4 million, net of tax and decreased Class A basic and diluted loss per share by $0.02.

Contractual Obligations

We have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to our capital expenditure programs, as disclosed in the Annual Report on Form 10-K for the year ended December 31, 2014. See also Note 9, Long-term Debt, and Note 19, Commitments and Contingencies, in the consolidated financial statements for additional discussion of contractual obligations.

Below is a summary of our proportion of debt in unconsolidated investments, as of March 31, 2015 (in thousands):


	Total Project Debt		Percentage of Ownership			Our Portion of Unconsolidated Project Debt
South Kent	$	529,585		50.0	%	$	264,793
Grand		282,696		45.0	%		127,213

Unconsolidated investments - debt	$	812,281				$	392,006

Off-Balance Sheet Arrangements

As of March 31, 2015, we had no off-balance sheet arrangements and have not entered into any transactions involving uncombined, limited purpose entities or commodity contracts.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have significant exposure to commodity prices, interest rates and foreign currency exchange rates, as described below. To mitigate these market risks, we have entered into multiple derivatives. We have not applied hedge accounting treatment to all of our

derivatives, therefore we are required to mark some of our derivatives to market through earnings on a periodic basis, which will result in non-cash adjustments to our consolidated net loss and may result in volatility in our earnings, in addition to potential cash settlements for any losses.

Commodity Price Risk

We manage our commodity price risk for electricity sales through the use of long-term power sale agreements with creditworthy counterparties. Our financial results reflect approximately 70,218 MWh of electricity sales during the three months ended March 31, 2015 that were not subject to power sale agreements and were subject to spot market pricing. A hypothetical increase or decrease of $4.26 per MWh (or an approximately 10% change) in these spot market prices would have increased or decreased consolidated net loss by $0.3 million, respectively, for the three months ended March 31, 2015.

Interest Rate Risk

We use a variety of derivative instruments to manage our exposure to fluctuations in interest rates, including interest rate swaps and interest rate caps, primarily in the context of our project-level indebtedness. We generally match the tenor and amount of these instruments to the tenor and amount, respectively, of the related debt financing. We also will have exposure to changes in interest rates with respect to our revolving credit agreement to the extent that we make draws under that facility. A hypothetical increase or decrease in short-term interest rates by 100 basis points would have increased or decreased consolidated net loss by $0.1 million for the three months ended March 31, 2015.

Foreign Currency Risk

We use foreign currency forward contracts to manage our exposure to fluctuations in foreign currency exchange rates. Our wind power projects are located in the United States, Canada and Chile. As a result, our financial results could be significantly affected by factors such as changes in foreign currency exchange rates or weak economic conditions in the foreign markets in which we operate. When the U.S. dollar strengthens against foreign currencies, the relative value in revenue earned in the respective foreign currency decreases. When the U.S. dollar weakens against foreign currencies, the relative value in revenue earned in the respective foreign currency increases. A majority of our power sale agreements and operating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. For the three months ended March 31, 2015, our financial results included C$0.4 million in losses from our St. Joseph project and our equity in losses at our South Kent and Grand projects. A hypothetical increase or decrease of 10% in exchange rates between the Canadian and U.S. dollar would have resulted in an immaterial change to our consolidated net loss.

ITEM 4.

CONTROLS AND PROCEDURES

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

Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2015.

There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Management continuously reviews disclosure controls and procedures, and internal control over financial reporting, and accordingly may, from time to time, make changes aimed at enhancing their effectiveness to ensure that our systems evolve with our business.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

We are subject, from time to time, to routine legal proceedings and claims arising out of the normal course of business. There has been no material change in the nature of our legal proceedings from the description provided in our Annual Report on Form 10-K for the year ended December 31, 2014.

ITEM 1A.

RISK FACTORS

In addition to the other information set forth in this report, you should consider the risks described under the caption “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2014. There have been no material changes in our risk factors as described in the Annual Report on Form 10-K for the year ended December 31, 2014, except as set forth below.

Our business, financial condition and operating results can be affected by a number of factors, whether currently known or unknown, including but not limited to those described below, any one or more of which could, directly or indirectly, cause our actual results of operations and financial condition to vary materially from past, or from anticipated future, results of operations and financial condition. Any of these factors, in whole or in part, could materially and adversely affect our business, financial condition, results of operations and the price of the Class A common stock.

The following discussion of risk factors contains forward-looking statements. These risk factors may be important to understanding any statement in this Form 10-Q or elsewhere. The following information should be read in conjunction with the consolidated financial statements and related notes in Part I, Item 1, “Financial Statements” and Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q.

Because of the following factors, as well as other factors affecting our financial condition and operating results, past financial performance should not be considered to be a reliable indicator of future performance, and investors should not use historical trends to anticipate results or trends in future periods.

We may not consummate the agreements we have entered into to acquire three wind facilities which may adversely affect our growth strategy. In addition, even if consummated, no assurances can be given that the facilities acquired will operate to the level we intend them to contribute to our growth.

We have entered into an agreement with Wind Capital Group, LLC (“WCG”) to acquire two operational wind power facilities. We have also agreed to acquire the K2 Wind facility from Pattern Development. Closing the acquisition of these three wind power facilities would add 360 MW of owned capacity to our portfolio, an increase of 22%.

Our growth strategy depends upon the acquisition of attractive power projects developed by both third parties and Pattern Development. While we believe each of these wind facilities are attractive to grow our business, no assurances can be given that such acquisitions will be consummated. The obligations to consummate the transactions contemplated by the acquisition agreement for the facilities from WCG are subject to the satisfaction or waiver of various conditions, including, among others, (1) the accuracy of representations and warranties, (2) the receipt of all governmental approvals, and the termination or expiration of waiting periods imposed by any governmental authorities, necessary for the consummation of the transactions contemplated thereby, (3) the receipt of all necessary consents, (4) in the case of the Company, no material adverse effect shall have occurred, and (5) in the case of sellers, the Company’s replacement of certain ordinary course performance guarantees securing project obligations with parent guarantees, letters of credit, bonds, indemnities or other credit assurance of a comparable and sufficient nature that satisfies the requirements of the counterparties. Similarly, the obligations to consummate the transactions contemplated by the acquisition agreement for the K2 are subject to the satisfaction or waiver of various conditions, including, among others, (1) no violation of governmental rules, and no order of any court or administrative agency being in effect which restrains or prohibits the transactions contemplated by such agreement and (2) the accuracy of representations and warranties. No assurances can be given that each of such conditions will be satisfied or waived, in which event the transactions may not be consummated.

In addition, even if consummated, no assurances can be given that the facilities acquired will operate to the level we intend them to contribute to our growth. The integration of any of the facilities, but particularly the facilities acquired from WCG which is our largest acquisition of assets from a third-party since our initial public offering, may be unpredictable, subject to delays, or changed circumstances which may adversely affect the ability of such facilities to contribute to our growth in the manner we intend.

ITEM 6.

EXHIBITS


Exhibit No.		Description

3.1		Amended and Restated Certificate of Incorporation of Pattern Energy Group Inc. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1/A dated September 20, 2013 (Registration No. 333-190538)).

3.2		Amended and Restated Bylaws of Pattern Energy Group Inc. (Incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).

4.1		Form of Class A Stock Certificate (Incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).

10.1		Employment Agreement between Pattern Energy Group Inc. and Michael J. Lyon dated October 2, 2013

31.1		Certifications of the Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certifications of the Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32*		Certifications of the Company’s Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Pattern Energy Group Inc.

Dated: May 7, 2015

/s/ Michael M. Garland

Michael M. Garland

President and Chief Executive Officer