Pattern Energy Group Inc. - FORM 10-Q

Pattern Energy Group Inc. - FORM 10-Q - August 10, 2015

Attached files

Attached files

Pattern Energy Group Inc. Reports

file	filename
EX-32 - EX-32 - Pattern Energy Group Inc.	d949705dex32.htm
EX-31.2 - EX-31.2 - Pattern Energy Group Inc.	d949705dex312.htm
EX-31.1 - EX-31.1 - Pattern Energy Group Inc.	d949705dex311.htm

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 June 30, 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.

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 August 5, 2015, there were 74,672,596 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 JUNE 30, 2015

TABLE OF CONTENTS


	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	5
	Consolidated Balance Sheets as of June 30, 2015 (unaudited) and December 31, 2014	5
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2015 and 2014 (unaudited)	6
	Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2015 and 2014 (unaudited)	7
	Consolidated Statements of Stockholders’ Equity for the Six Months Ended June 30, 2015 and 2014 (unaudited)	8
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 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	40
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	52
Item 4.	Controls and Procedures	52

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 6.	Exhibits	57
	Signatures	58

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)


	June 30,			December 31,
	2015			2014
Assets
Current assets:
Cash and cash equivalents	$	82,936		$	101,656
Restricted cash		26,283			7,945
Trade receivables		48,363			35,759
Related party receivable		820			671
Reimbursable interconnection costs		1,286			2,532
Derivative assets, current		18,415			18,506
Current net deferred tax assets		307			318
Prepaid expenses and other current assets		26,041			27,954
Deferred financing costs, current, net of accumulated amortization of $4,340 and $3,493 as of June 30, 2015 and December 31, 2014, respectively		1,903			1,747

Total current assets		206,354			197,088
Restricted cash		17,142			39,745
Turbine advances		60,893			79,637
Construction in progress		338,906			26,195
Property, plant and equipment, net of accumulated depreciation of $429,939 and $278,291 as of June 30, 2015 and December 31, 2014, respectively		2,812,203			2,350,856
Unconsolidated investments		147,644			29,079
Derivative assets		50,354			49,369
Deferred financing costs		4,838			5,166
Net deferred tax assets		6,927			5,474
Finite-lived intangible assets, net of accumulated amortization of $1,077 and $154 as of June 30, 2015 and December 31, 2014, respectively		101,082			1,257
Other assets		31,646			11,421

Total assets	$	3,777,989		$	2,795,287

Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities	$	29,273		$	24,793
Accrued construction costs		42,115			20,132
Related party payable		881			5,757
Accrued interest		5,423			3,634
Dividends payable		24,563			15,734
Derivative liabilities, current		19,788			16,307
Revolving credit facility		250,000			50,000
Current portion of long-term debt, net of financing costs of $10,166 and $11,868 as of June 30, 2015 and December 31, 2014, respectively		332,226			109,693
Current net deferred tax liabilities		149			149
Current portion of contingent liabilities		11,468			4,000

Total current liabilities		715,886			250,199
Long-term debt, net of financing costs of $22,883 and $24,887 as of June 30, 2015 and December 31, 2014, respectively		1,369,135			1,304,165
Derivative liabilities		27,495			17,467
Asset retirement obligations		38,940			29,272
Net deferred tax liabilities		23,872			20,418
Contingent liabilities		1,189			175
Finite-lived intangible liability, net of accumulated amortization of $434 and $0 as of June 30, 2015 and December 31, 2014, respectively		59,866			—
Other long-term liabilities		9,576			8,857

Total liabilities		2,245,959			1,630,553

Temporary equity - noncontrolling interests		35,000			—
Equity:
Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 69,237,919 and 62,062,841 shares outstanding as of June 30, 2015 and December 31, 2014, respectively		693			621
Additional paid-in capital		874,015			723,938
Accumulated loss		(50,208	)		(44,626	)
Accumulated other comprehensive loss		(50,634	)		(45,068	)
Treasury stock, at cost; 36,523 and 25,465 shares of Class A common stock as of June 30, 2015 and December 31, 2014, respectively		(1,027	)		(717	)

Total equity before noncontrolling interest		772,839			634,148
Noncontrolling interest		724,191			530,586

Total equity		1,497,030			1,164,734

Total liabilities, temporary equity, and equity	$	3,777,989		$	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 June 30,						Six months ended June 30,
	2015			2014			2015			2014
Revenue:
Electricity sales	$	82,945		$	66,053		$	137,929		$	119,924
Energy derivative settlements		5,928			3,983			12,097			6,718
Unrealized loss on energy derivative		(6,002	)		(6,549	)		(3,030	)		(14,282	)
Related party revenue		872			949			1,675			1,462
Other revenue		928			503			866			734

Total revenue		84,671			64,939			149,537			114,556

Cost of revenue:
Project expense		27,981			16,700			53,227			32,774
Depreciation and accretion		34,342			21,284			63,398			42,461

Total cost of revenue		62,323			37,984			116,625			75,235

Gross profit		22,348			26,955			32,912			39,321

Operating expenses:
General and administrative		8,870			6,288			15,091			10,191
Related party general and administrative		1,621			1,383			3,429			2,663

Total operating expenses		10,491			7,671			18,520			12,854

Operating income		11,857			19,284			14,392			26,467

Other expense:
Interest expense		(18,943	)		(15,807	)		(36,861	)		(30,428	)
Interest rate derivative settlements		(960	)		(1,035	)		(1,919	)		(2,052	)
Unrealized gain (loss) on derivatives		5,138			(2,942	)		2,697			(6,665	)
Equity in earnings (losses) in unconsolidated investments		13,801			(3,688	)		10,719			(16,236	)
Related party income		756			444			1,424			1,072
Net (loss) gain on transactions		(1,305	)		14,537			(2,589	)		14,537
Other (expense) income, net		(1,084	)		439			(1,408	)		606

Total other expense		(2,597	)		(8,052	)		(27,937	)		(39,166	)

Net income (loss) before income tax		9,260			11,232			(13,545	)		(12,699	)
Tax provision		3,603			4,065			2,857			2,033

Net income (loss)		5,657			7,167			(16,402	)		(14,732	)
Net loss attributable to noncontrolling interest		(8,660	)		(4,032	)		(10,820	)		(11,042	)

Net income (loss) attributable to controlling interest	$	14,317		$	11,199		$	(5,582	)	$	(3,690	)

Earnings per share information:
Net income (loss) attributable to controlling interest	$	14,317		$	11,199		$	(5,582	)	$	(3,690	)
Cash dividends declared on Class A common shares		(24,380	)		(14,981	)		(48,003	)		(26,138	)
Deemed dividends on Class B common shares		—			(7,457	)		—			(7,457	)

Net loss attributable to common stockholders	$	(10,063	)	$	(11,239	)	$	(53,585	)	$	(37,285	)

Weighted average number of shares:
Class A common stock - Basic		68,943,707			41,174,697			67,426,286			38,331,595
Class A common stock - Diluted		69,147,260			41,510,219			67,426,286			53,886,595
Class B common stock - Basic and diluted		—			15,555,000			—			15,555,000
Earnings (loss) per share
Class A common stock:
Basic earnings (loss) per share	$	0.21		$	0.17		$	(0.08	)	$	(0.01	)

Diluted earnings (loss) per share	$	0.21		$	0.16		$	(0.08	)	$	(0.07	)

Class B common stock:
Basic and diluted earnings (loss) per share	$	—		$	0.28		$	—		$	(0.21	)

Dividends declared per Class A common share	$	0.35		$	0.32		$	0.71		$	0.63

Deemed dividends per Class B common share	$	—		$	0.48		$	—		$	0.48

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Consolidated Statements of Comprehensive Income (Loss)

(In thousands of U.S. Dollars)

(Unaudited)


	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014
Net income (loss)	$	5,657		$	7,167		$	(16,402	)	$	(14,732	)

Other comprehensive income (loss):
Foreign currency translation, net of zero tax impact		(498	)		4,221			(9,692	)		(869	)

Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax (provision) benefit of ($628), $66, $56 and $66, respectively		10,100			(8,896	)		(657	)		(17,989	)
Reclassifications to net loss, net of tax impact of $168, $37, $341 and $37, respectively		3,465			3,349			6,956			6,520

Total change in effective portion of change in fair market value of derivatives		13,565			(5,547	)		6,299			(11,469	)
Proportionate share of equity investee’s derivative activity:
Effective portion of change in fair market value of derivatives, net of tax (provision) benefit of ($7), $560, $859, and $1,805, respectively		20			(1,205	)		(2,382	)		(4,283	)
Reclassifications to net loss, net of tax impact of $206, $0, $377, and $0, respectively		571			—			1,045			—

Total change in effective portion of change in fair market value of derivatives		591			(1,205	)		(1,337	)		(4,283	)

Total other comprehensive income (loss), net of tax		13,658			(2,531	)		(4,730	)		(16,621	)

Comprehensive income (loss)		19,315			4,636			(21,132	)		(31,353	)

Less comprehensive loss attributable to noncontrolling interest:
Net loss attributable to noncontrolling interest		(8,660	)		(4,032	)		(10,820	)		(11,042	)

Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax (provision) benefit of ($188), $20, $17 and $20, respectively		955			(1,149	)		(985	)		(1,884	)
Reclassifications to net loss, net of tax impact of $50, $11, $102 and $11, respectively		905			876			1,821			1,705

Total change in effective portion of change in fair market value of derivatives		1,860			(273	)		836			(179	)

Comprehensive loss attributable to noncontrolling interest		(6,800	)		(4,305	)		(9,984	)		(11,221	)

Comprehensive income (loss) attributable to controlling interest	$	26,115		$	8,941		$	(11,148	)	$	(20,132	)

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
																	Accumulated																		Accumulated
									Additional								Other																		Other
	Class A Common Stock				Class B Common Stock				Paid-in					Accumulated			Comprehensive			Treasury Stock												Accumulated			Comprehensive						Total
	Shares		Amount		Shares		Amount		Capital			Capital		Loss			Loss			Shares			Amount			Total			Capital			Income (Loss)			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
Issuance of Class A common stock related to the public offering, net of issuance costs		10,810,810		108						286,671																	286,779															286,779
Issuances of Class A common stock under equity incentive award plan		173,287		2		—		—		(2	)		—		—			—			—			—			—			—			—			—			—			—
Issuance of Class A common stock upon exercise of stock options		10,001								220																	220															220
Repurchase of shares for employee tax withholding		—		—		—		—		—			—		—			—			(1,904	)		(55	)		(55	)		—			—			—			—			(55	)
Stock-based compensation		—		—		—		—		2,175			—		—			—			—			—			2,175			—			—			—			—			2,175
Refund of issuance costs related to the IPO		—		—		—		—		163			—		—			—			—			—			163			—			—			—			—			163
Dividends declared on Class A common stock		—		—		—		—		(26,138	)		—		—			—			—			—			(26,138	)		—			—			—			—			(26,138	)
Sale of Class A membership interests in Panhandle 1		—		—		—		—		—					—			—			—			—			—			210,250			—			—			210,250			210,250
Acquisition of AEI ownership in E1 Arrayan		—		—		—		—		—					—			—			—			—			—			35,259			—			—			35,259			35,259
Distribution to noncontrolling interest		—		—		—		—		—					—			—			—			—			—			(1,470	)		—			—			(1,470	)		(1,470	)
Net loss		—		—		—		—		—			—		(3,690	)		—			—			—			(3,690	)		—			(11,042	)		—			(11,042	)		(14,732	)
Other comprehensive (loss) income, net of tax		—		—		—		—		—			—		—			(16,442	)		—			—			(16,442	)		—			—			(179	)		(179	)		(16,621	)

Balances at June 30, 2014		46,525,818	$	465		15,555,000	$	156	$	752,501		$	—	$	(17,026	)	$	(24,795	)		(2,838	)	$	(79	)	$	711,222		$	334,256		$	7,559		$	(9,203	)	$	332,612		$	1,043,834

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		—		—		196,089			—		—			—			—			—			196,159			—			—			—			—			196,159
Issuance of Class A common stock under equity incentive award plan		186,136		2						(2	)										—			—
Repurchase of shares for employee tax withholding		—		—		—		—		—			—		—			—			(11,058	)		(310	)		(310	)		—			—			—			—			(310	)
Stock-based compensation		—		—		—		—		1,989			—		—			—			—			—			1,989			—			—			—			—			1,989
Dividends declared on Class A common stock		—		—		—		—		(48,003	)		—		—			—			—			—			(48,003	)		—			—			—			—			(48,003	)
Issuance of dividend equivalents upon vesting of deferred restricted stock units		—		—		—		—		4					—			—			—			—			4			—			—			—			—			4
Acquisition of Post Rock		—		—		—		—		—					—			—			—			—			—			205,100			—			—			205,100			205,100
Distribution to noncontrolling interest		—		—		—		—		—			—		—			—			—			—			—			(1,511	)		—			—			(1,511	)		(1,511	)
Net loss		—		—		—		—		—			—		(5,582	)		—			—			—			(5,582	)		—			(10,820	)		—			(10,820	)		(16,402	)
Other comprehensive (loss) income, net of tax		—		—		—		—		—			—		—			(5,566	)		—			—			(5,566	)		—			—			836			836			(4,730	)

Balances at June 30, 2015		69,274,442	$	693		—	$	—	$	874,015		$	—	$	(50,208	)	$	(50,634	)		(36,523	)	$	(1,027	)	$	772,839		$	733,128		$	(928	)	$	(8,009	)	$	724,191		$	1,497,030

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Consolidated Statements of Cash Flows

(In thousands of U.S. Dollars)

(Unaudited)


	Six months ended June 30,
	2015			2014
Operating activities
Net loss	$	(16,402	)	$	(14,732	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion		63,841			42,461
Loss on disposal of equipment		347			—
Amortization of financing costs		3,636			2,848
Unrealized loss on derivatives		333			20,947
Stock-based compensation		1,989			2,175
Net gain on transactions		—			(16,526	)
Deferred taxes		2,616			2,033
Equity in (earnings) losses in unconsolidated investments		(10,719	)		16,236
Unrealized loss on exchange rate changes		823			—
Changes in operating assets and liabilities:
Trade receivables		(4,924	)		(13,895	)
Prepaid expenses and other current assets		3,441			20,253
Other assets (non-current)		(99	)		(305	)
Accounts payable and other accrued liabilities		615			348
Related party receivable/payable		(7	)		(1,053	)
Income taxes payable/receivable		—			128
Accrued interest payable		689			(11	)
Contingent liabilities		1,151			—
Long-term liabilities		1,270			(85	)

Net cash provided by operating activities		48,600			60,822

Investing activities
Cash paid for acquisitions, net of cash acquired		(404,377	)		(163,589	)
Decrease in restricted cash		25,277			1,316
Increase in restricted cash		(6,966	)		(2	)
Capital expenditures		(216,499	)		(544	)
Distribution from unconsolidated investments		13,847			—
Contribution to unconsolidated investments		—			(1,880	)
Reimbursable interconnection receivable		1,246			1,417
Other assets		(6,074	)		1,236

Net cash used in investing activities		(593,546	)		(162,046	)

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Consolidated Statements of Cash Flows

(In thousands of U.S. Dollars)

(Unaudited)


	Six months ended June 30,
	2015			2014
Financing activities
Proceeds from public offering, net of expenses		196,591			287,943
Repurchase of shares for employee tax withholding		(310	)		(55	)
Dividends paid		(39,170	)		(22,170	)
Payment for deferred equity issuance costs		(2,204	)		—
Capital distributions - noncontrolling interest		(1,511	)		(1,470	)
Decrease in restricted cash		18,532			13,508
Increase in restricted cash		(21,718	)		(8,840	)
Refund of deposit for letters of credit		3,425			—
Payment for deferred financing costs		(5,614	)		(542	)
Proceeds from revolving credit facility		250,000			—
Repayment of revolving credit facility		(50,000	)		—
Repayment of VAT facility		—			(14,840	)
Proceeds from construction loan		206,184			—
Repayment of long-term debt		(25,383	)		(22,096	)

Net cash provided by financing activities		528,822			231,438

Effect of exchange rate changes on cash and cash equivalents		(2,596	)		255

Net change in cash and cash equivalents		(18,720	)		130,469
Cash and cash equivalents at beginning of period		101,656			103,569

Cash and cash equivalents at end of period	$	82,936		$	234,038

Supplemental disclosure
Cash payments for interest expenses, net of capitalized interest	$	24,447		$	27,296
Acquired property, plant and equipment from acquisitions		579,712			671,068
Schedule of non-cash activities
Change in fair value of designated interest rate swaps		6,299			(20,344	)
Change in property, plant and equipment		21,094			(40,729	)
Non-cash deemed dividends on Class B convertible common stock		—			7,457

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. The Company is not authorized to reissue shares of Class B common stock.

On May 14, 2014, the Company completed an underwritten public offering of its Class A common stock resulting in a reduction of Pattern Development’s interest in the Company 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 transactions with Pattern Development after May 14, 2014 are recognized at fair value on the measurement date in accordance with the Accounting Standard Codification (“ASC”) 805 – Business Combinations. On February 9, 2015, the Company completed an underwritten public offering of its Class A common stock, resulting in a further reduction of Pattern Development’s interest in the Company from 35% to 25% causing it to no longer be entitled to certain approval rights pursuant to the Shareholder Approval Rights Agreement dated October 2, 2013.

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”), Logan’s Gap Wind LLC (“Logan’s Gap”) and Fowler Ridge IV Wind Farm LLC (“Amazon Wind Farm (Fowler Ridge)”). 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”), Panhandle B Member 2 LLC (“Panhandle 2”), Lost Creek Wind, LLC (“Lost Creek”) and Post Rock Wind Power Project, LLC (“Post Rock”), and noncontrolling interests in South Kent Wind LP (“South Kent”), Grand Renewable Wind LP (“Grand”) and K2 Wind Ontario Limited Partnership (“K2”). 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.

2. Summary of Significant Accounting Policies

As of June 30, 2015, the Company has added the following significant accounting policies to the significant accounting policies described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014: change in depreciable lives of property, plant and equipment, asset acquisitions, temporary equity – noncontrolling interests, finite-lived intangible assets 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 June 30, 2015, the results of operations, comprehensive income (loss), and cash flows for the three and six months ended June 30, 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 and six months ended June 30, 2015, the effect of this change reduced depreciation expense by $3.7 million and $7.3 million, respectively, increased net income (loss) by $3.5 million and $6.9 million, net of tax, respectively, and increased Class A basic and diluted earnings per share by $0.03 for the three months ended June 30, 2015 and decreased Class A basic and diluted loss per share by $0.05 for the six months ended June 30, 2015.

Acquisitions

Business Combinations

The Company accounts for acquisitions of a controlling interest in entities that include inputs and processes and have the ability to create outputs as business combinations. 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. Transaction costs are expensed to the consolidated statements of operations in the period of acquisition.

Asset Acquisitions

When the Company acquires assets and liabilities that do not constitute a business, the fair value of the purchase consideration, including transaction costs of the asset acquisition, is assumed to be equal to the fair value of the net assets acquired and is allocated to the individual assets and liabilities assumed based on their relative fair values. Contingent consideration associated with the acquisition is generally recognized when the contingency is resolved. No goodwill is recognized in an asset acquisition.

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, Panhandle 2, Lost Creek and Post Rock 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 income (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.

Temporary Equity – Noncontrolling Interests

In connection with the May 15, 2015 acquisition of Lost Creek, the Company recorded $35.0 million in temporary equity –noncontrolling interests in the consolidated balance sheets related to the Class A membership interests in Lost Creek Wind Holdco. Refer to Note 3 – Acquisitions – Business Combinations – Wind Capital Group Acquisition for detail. The Class A membership interests hold a put option to sell the Class A shares to the Company, on April l5, 2020, at a specified amount. In accordance with ASC 480-10 –S99 – Accounting for Redeemable Equity Interests, equity instruments with redemption features that are not solely within the control of the issuer are to be classified outside of permanent equity and presented as “temporary equity” on the consolidated balance sheets, appearing after liabilities and before equity. As of June 30, 2015, the noncontrolling interest is presented at fair value in temporary equity.

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 2015, Standard & Poor’s Rating Services (“S&P”) further downgraded the credit rating of the Puerto Rico Electric Power Authority (“PREPA”) from CCC to CCC-. Through June 30, 2015, Moody’s Investor Service’s credit rating of PREPA remains unchanged at Caa3. As of June 30, 2015 and August 10, 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 and six months ended June 30, 2015 and 2014, respectively, and the related maximum amount of credit loss based on their respective percentages of total trade receivables for the three and six months ended June 30, 2015:


	Revenue												Trade Receivables
	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014			2015			2014			2015			2014
San Diego Gas & Electric		25.10	%		35.28	%		18.77	%		27.98	%		31.91	%		45.29	%		31.91	%		45.29	%
Manitoba Hydro		8.28	%		12.77	%		11.28	%		15.98	%		3.58	%		7.25	%		3.58	%		7.25	%

The Independent Electricity System Operator (“IESO”) is the customer for each of the Company’s Grand, K2 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 purchasers, including IESO, and face a concentration of credit risk from IESO as a customer.

The Company’s interest rate derivative instruments are placed with counterparties that are creditworthy institutions. An additional derivative instrument arises from an arrangement with 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.

Finite-Lived Intangible Assets

Finite-lived intangible assets include PPAs, easements, land options and mining rights. PPA’s obtained through acquisitions are valued at the time of acquisition and the difference between the contract price and the estimated fair value results in an intangible asset or an intangible liability. If the contract price is higher than the estimated fair value, the Company will recognize an intangible asset. If the contract price is lower than the estimated fair value, the Company will recognize an intangible liability. Easements, land options and mining rights are recognized at cost.

The Company amortizes intangible assets and liabilities associated with PPAs using the straight-line method over the remaining term of the related PPA, ranging from approximately 15-17 years. The Company amortizes easements, land options and mining rights using the straight-line method over the term of their estimated useful lives, which represents the term of the easements and land option and mining rights agreements, ranging from eleven months to twenty years. The Company periodically evaluates whether events or changes in circumstances have occurred that indicate the carrying amount of finite-lived intangible assets may not be recoverable, or information indicates that impairment may exist.

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 (loss) or cash flows.

Recently Issued Accounting Standards

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-11, “Simplifying the Measurement of Inventory” which changes the measurement principle for inventory from the lower of cost or market to the lower of cost and net realizable value. Net realizable value is defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments do not apply to inventory that is measured using last-in, first-out or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first out or average cost. ASU 2015-11 is effective for annual reporting periods beginning after December 15, 2016 and interim periods within those fiscal years. The amendments in this update should be applied prospectively. Early adoption is permitted as of the beginning of an interim or annual reporting period. The adoption of the provisions of ASU 2015-11 is not expected to have a material impact on the Company’s consolidated financial statements.

In April 2015, the FASB issued 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 June 30, 2015. As a result, the Company reclassified $33.0 million and $36.8 million in total deferred financing costs to long-term debt, of which $10.2 million and $11.9 million have been reclassified to current portion of long-term debt, as of June 30, 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. In June 2015, the FASB voted to defer the effective date by one year, with early adoption permitted as of the original effective date. The Company is currently assessing the future impact of this update on its consolidated financial statements.

3. Acquisitions

Business Combinations

Wind Capital Group Acquisition

On May 15, 2015, pursuant to a Purchase and Sale Agreement, the Company acquired 100% of the membership interests in Lost Creek Wind Finco, LLC (“Lost Creek Finco”) from Wind Capital Group LLC, an unrelated third party, and 100% of the membership interests in Lincoln County Wind Project Holdco, LLC (“Lincoln County Holdco”) from Lincoln County Wind Project Finco, LLC, an unrelated third party. Lost Creek Finco owns 100% of the Class B membership interests in Lost Creek Wind Holdco, LLC, (“Lost Creek Wind Holdco”) a company which owns a 100% interest in the Lost Creek wind project. Lincoln County Holdco owns 100% of the Class B membership interests in Post Rock Wind Power Project, LLC, a company which owns a 100% interest in the Post Rock wind project. The acquisition of 100% of the membership interests in Lost Creek Finco and Lincoln County Holdco was for an aggregate consideration of approximately $242.0 million, paid at closing. The Company also assumed certain project level indebtedness and ordinary course performance guarantees securing project obligations. Lost Creek is a 150 MW wind project in King City, Missouri, and Post Rock is a 201 MW wind project in Ellsworth and Lincoln Counties, Kansas.

The Company acquired assets and operating contracts for Lost Creek and Post Rock, including assumed liabilities. The identifiable assets 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 fair value of the assets acquired and liabilities assumed in connection with the acquisition are as follows (in thousands):


	May 15, 2015
Cash and cash equivalents	$	3,501
Restricted cash, current		16,379
Trade receivables		7,910
Prepaid expenses and other current assets		1,676
Property, plant and equipment		541,300
Finite-lived intangible assets, net of accumulated amortization		97,400
Other assets		19,935
Accounts payable and other accrued liabilities		(2,588	)
Accrued interest		(951	)
Derivative liabilities, current		(4,236	)
Current portion of long-term debt, net of financing costs		(7,463	)
Finite-lived intangible liabilities, net of accumulated amortization		(60,300	)
Asset retirement obligations		(6,994	)
Long-term debt, net of financing costs		(108,838	)
Derivative & other long-term liabilities, less current portion		(14,631	)

Total consideration before temporary equity and noncontrolling interests		482,100
Less: temporary equity		(35,000	)
Less: noncontrolling interests		(205,100	)

Total consideration after temporary equity and noncontrolling interests	$	242,000

Current assets and accounts payable and other accrued liabilities were recorded at carrying value, which is representative of the fair value on the date of acquisition. Property, plant and equipment, finite-lived intangible asset, finite-lived intangible liability and debt were recorded at fair value estimated using the income approach. The fair values of other assets, derivatives and asset retirement obligations were recorded at fair value using a combination of market data, operational data and discounted cash flows and were adjusted by a discount rate factor reflecting current market conditions at the time of acquisition.

The noncontrolling interest in Post Rock was recorded at fair value estimated using a discounted cash flow approach, adjusted for a discount rate reflecting the estimated return on investment required by participants in the tax equity market. The noncontrolling interest in Lost Creek was recorded at fair value estimated using the purchase price from a purchase agreement executed on May 15, 2015 between the Company and the tax equity investor.

The accounting for this acquisition is preliminary. The fair value estimates for the assets acquired and liabilities assumed were based on preliminary calculations and valuations, and the estimates and assumptions are subject to change as additional information is obtained for the estimates during the measurement period (up to one year from the acquisition date).

The Company incurred $1.9 million of transaction-related expenses which were recorded in net (loss) gain on transactions in the consolidated statements of operations for the three and six month period ended June 30, 2015, respectively.

The Company also entered into an agreement to purchase 100% of the Class A membership interests in Lost Creek Wind Holdco for an aggregate consideration of approximately $35.0 million, subject to various closing conditions. If the closing conditions are not satisfied or waived by September 30, 2015, then each of the parties has a right to terminate the agreement, provided they are not in breach of its terms. Refer to Note 22, Subsequent Events, for disclosure on the acquisition of the Class A membership interests in Lost Creek Wind Holdco.

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 accounting for the Panhandle 1 acquisition was completed as of March 31, 2015 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of November 10, 2014 as well as adjustments made through March 31, 2015, when the allocation became final. 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	)
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.

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.

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 accounting for the Logan’s Gap acquisition was completed as of March 31, 2015 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 19, 2014, as well as adjustments made through March 31, 2015, when the allocation became final. 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 third quarter of 2015.

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 accounting for the Panhandle 1 acquisition was completed as of December 31, 2014 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of June 30, 2014, as well as adjustments made through December 31, 2014, when the allocation became final. 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.

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 accounting for the AEI El Arrayán acquisition was completed as of December 31, 2014 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of June 25, 2014, as well as adjustments made through December 31, 2014, when the allocation became final. 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.

Supplemental pro forma data

The unaudited pro forma statement of operations data below gives effect to the Lost Creek, Post Rock, Panhandle 1 and El Arrayán acquisitions as if they had occurred on January 1, 2014. The pro forma net income (loss) for the three and six month periods ended June 30, 2015 was adjusted to exclude nonrecurring transaction related expenses of $1.5 million and $1.9 million, respectively. The pro forma net loss for the three and six months ended June 30, 2014 was adjusted to exclude nonrecurring transaction related expenses of $2.5 million and $2.5 million, respectively. In addition, the 2014 pro forma net loss was adjusted to exclude a nonrecurring $17.9 million gain on acquisition of El Arrayán. The unaudited pro forma data is presented for illustrative purposes only and is not intended to be indicative of actual results that would have been achieved had these acquisitions been consummated as of January 1, 2014. The unaudited pro forma data should not be considered representative of the Company’s future financial condition or results of operations.


	Three months ended June 30,						Six months ended June 30,
Unaudited pro forma data (in thousands)	2015			2014			2015			2014
Pro forma total revenue	$	92,196		$	82,559		$	170,800		$	149,406
Pro forma total expenses		86,865			94,065			188,725			185,951

Pro forma net income (loss)		5,331			(11,506	)		(17,925	)		(36,545	)
Less: pro forma net loss attributable to noncontrolling interest		(10,233	)		(6,810	)		(17,612	)		(16,313	)

Pro forma net income (loss) attributable to controlling interest	$	15,564		$	(4,696	)	$	(313	)	$	(20,232	)

Prior to the acquisition of AEI El Arrayán, the project’s net loss was recorded in equity in (losses) earnings in unconsolidated investments in the consolidated statement of operations. From January 1, 2014 to June 25, 2014, the Company recorded net loss of $0.4 million in equity in (losses) earnings on unconsolidated investments related to El Arrayán.

The following table presents the amounts included in the consolidated statements of operations for Lost Creek and Post Rock since their respective dates of acquisition:


	Three months ended			Six months ended
Unaudited data (in thousands)	June 30, 2015			June 30, 2015
Total revenue	$	5,172		$	5,172
Total expenses		6,350			6,350

Net loss		(1,178	)		(1,178	)
Less: net loss attributable to noncontrolling interest		(800	)		(800	)

Net loss attributable to controlling interest	$	(378	)	$	(378	)

Asset Acquisition

Amazon Wind Farm (Fowler Ridge)

On April 29, 2015, the Company acquired 100% of the membership interests in Fowler Ridge IV Wind Farm 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, in addition to $0.5 million of capitalized transaction expenses, 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.

The Company acquired certain assets and assumed certain liabilities of Amazon Wind Farm (Fowler Ridge), including various operating contracts, deferred development costs, tangible assets, real property interests, governmental approvals and other assets. The fair value of the purchase consideration, including transaction costs of the asset acquisition, is allocated to the relative fair value of the individual assets and liabilities. The preliminary fair value of the assets acquired and liabilities assumed in connection with the Amazon Wind Farm (Fowler Ridge) acquisition are as follows (in thousands):


	April 29, 2015
Prepaid expenses and other current assets	$	1,753
Deferred financing costs, current		2,132
Turbine advances		4,000
Construction in progress		34,412
Finite-lived intangible assets, net of accumulated amortization		2,247
Accrued construction costs		(6,549	)

Total consideration	$	37,995

In connection with the acquisition, the Company may make additional contingent payments of up to $29.1 million, consisting of a $25.1 million fixed amount and up to $4.0 million, as calculated based on final budget to actual amounts, both of which are payable to Pattern Development upon tax equity funding.

The Company also acquired a $5.0 million contingent obligation, which was paid subsequent to the close of construction financing, and assumed an estimated $7.3 million contingent liability required to connect the project into an existing transmission line. The estimated contingent payment was accrued when it became probable that the event would occur, upon close of construction financing.

In addition, the Company acquired an agreement between Pattern Development and an unrelated third party, whereby the unrelated third party is entitled to 1% of the gross revenue received by the project under the PPA, which is estimated to be approximately $2.6 million over 13 years.

Equity Method Investments

On June 17, 2015, the Company acquired from Pattern Development a one-third equity interest in K2 for approximately $128.0 million, in addition to $0.4 million of capitalized transaction expenses, plus assumed estimated proportionate debt at term conversion of approximately $221.8 million, U.S. dollar equivalent. K2 is a joint venture established to develop, construct and own a wind power project located in Ontario, Canada. The project has a 20-year PPA and commenced commercial operations in May 2015. The Company’s investment in K2 was funded through general corporate funds and borrowings under the revolving credit facility. The Company is a noncontrolling investor in K2 but does have significant influence over K2. Accordingly, the investment is accounted for under the equity method of accounting.

As of the acquisition date the carrying value of the Company’s investment in K2 was $111.6 million higher than the Company’s underlying equity in the net assets of K2. This equity method basis difference was comprised of $57.9 million related to property, plant and equipment and $53.7 million related to the PPA. In accordance with ASC 323, Equity Method Investments, the basis difference related to the property, plant and equipment will be amortized over the estimated economic useful life of the underlying long-lived assets. The basis difference related to the PPA will be amortized over the remaining term of the PPA. The accounting for the acquisition is preliminary. The basis differences were based on preliminary calculations and valuations, and the estimates and assumptions are subject to change as additional information is obtained.

4. Prepaid Expenses and Other Current Assets

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


	June 30,		December 31,
	2015		2014
Prepaid expenses	$	13,138	$	15,275
Prepaid construction costs		3,605		5,155
Sales tax		62		786
Other current assets:
Deposit for letters of credit		—		3,425
Deposit for acquisition of Class A membership interest		3,500		—
Deferred equity issuance costs		4,616		2,331
Other		1,120		982

Prepaid expenses and other current assets	$	26,041	$	27,954

5. Property, Plant and Equipment

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


	June 30,			December 31,
	2015			2014
Operating wind farms	$	3,237,603		$	2,624,640
Furniture, fixtures and equipment		4,232			4,366
Land		307			141

Subtotal		3,242,142			2,629,147
Less: accumulated depreciation		(429,939	)		(278,291	)

Property, plant and equipment, net	$	2,812,203		$	2,350,856

The Company recorded depreciation expense related to property, plant and equipment of $33.2 million and $62.5 million for the three and six months ended June 30, 2015, respectively, and recorded $20.9 million and $41.8 million of depreciation expense for the same periods in the prior year.

The cash grants in lieu of investment tax credits received from the U.S. Department of the Treasury for Ocotillo, Santa Isabel and Spring Valley reduced depreciation expense recorded in the consolidated statements of operations by approximately $2.9 million and $5.7 million for the three and six months ended June 30, 2015, respectively, and reduced depreciation expense by $3.2 million and $6.3 million for the same periods in the prior year.

6. Finite-Lived Intangible Assets and Liability

The following presents the major components of the finite-lived intangible assets and liability (in thousands):


	June 30, 2015
	Weighted Average Remaining Life		Gross			Accumulated Amortization			Net
Intangible assets
Power purchase agreement		15	$	97,400		$	(837	)	$	96,563
Other intangible assets		17		4,759			(240	)		4,519

Total intangible assets			$	102,159		$	(1,077	)	$	101,082

Intangible liability
Power purchase agreement		17	$	(60,300	)	$	434		$	(59,866	)


	December 31, 2014
	Weighted Average Remaining Life		Gross			Accumulated Amortization			Net
Other intangible assets		17	$	1,411		$	(154	)	$	1,257

The Company amortizes the PPA asset and PPA liability in electricity sales in the consolidated statements of operations and recorded $0.8 million and ($0.4) million, respectively, for each of the three and six months ended June 30, 2015.

The following table presents estimated future amortization expense for the next five years related to PPAs and other intangible assets:


	Power		Other
	purchase		intangible
Year ended December 31,	agreements		assets
2015	$	1,543	$	97
2016		3,049		276
2017		3,031		351
2018		3,031		276
2019		3,031		276
Thereafter		23,012		3,243

7. Unconsolidated Investments

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


					Percentage of Ownership
	June 30,		December 31,		June 30,			December 31,
	2015		2014		2015			2014
South Kent	$	9,991	$	17,360		50.0	%		50.0	%
Grand		12,792		11,719		45.0	%		45.0	%
K2		124,861		—		33.3	%		N/A

Unconsolidated investments	$	147,644	$	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%. Refer to 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.

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 May 2015. Refer to Note 3, Acquisitions, for disclosure on the acquisition of K2.

The following table summarizes the aggregated operating results of the unconsolidated joint ventures for the three and six months ended June 30, 2015 and 2014, respectively (in thousands):


	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015		2014
Revenue	$	42,155		$	27,179		$	86,786	$	28,696

Cost of revenue		15,361			10,333			27,676		11,072
Operating expenses		2,908			1,747			5,314		1,704
Other (income) expense		(6,842	)		23,059			28,449		49,546

Net income (loss)	$	30,728		$	(7,960	)	$	25,347	$	(33,626	)

Significant Equity Method Investees

The following table presents summarized statements of operations information for the three and six months ended June 30, 2015 and 2014, in thousands, as required for each of the Company’s significant equity method investees, South Kent and Grand, pursuant to Regulation S-X Rule 10-01(b)(1). :

South Kent


	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015		2014
Revenue	$	20,210		$	25,358		$	52,746	$	26,875

Cost of revenue		6,733			10,333			15,122		11,072
Operating expenses		1,152			1,613			2,707		1,462
Other (income) expense		(9,208	)		17,446			19,432		39,225

Net income (loss)	$	21,533		$	(4,034	)	$	15,485	$	(24,884	)

Grand


	Three months ended June 30,					Six months ended June 30,
	2015		2014			2015		2014
Revenue	$	14,683	$	—		$	26,778	$	—

Cost of revenue		5,429		—			9,355		—
Operating expenses		1,182		133			2,033		241
Other expense		562		2,858			7,213		7,238

Net income (loss)	$	7,510	$	(2,991	)	$	8,177	$	(7,479	)

8. Accounts Payable and Other Accrued Liabilities

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


	June 30,		December 31,
	2015		2014
Accounts payable	$	1,066	$	673
Other accrued liabilities		11,360		7,892
Warranty settlement payments		1,706		639
LTSA upgrades liability		814		680
Turbine operations and maintenance payable		705		1,310
Land lease rent payable		955		2,115
Payroll liabilities		3,182		4,453
Property tax payable		7,815		4,625
Sales tax payable		1,670		2,406

Accounts payable and other accrued liabilities	$	29,273	$	24,793

9. Revolving Credit Facility

As of June 30, 2015 and December 31, 2014, outstanding loan balances under the $350.0 million revolving credit facility were $250.0 million and $50.0 million, respectively. In addition, as of June 30, 2015 and December 31, 2014, letters of credit of $49.2 million and $45.1 million, respectively, were issued under the revolving credit facility.

10. Long-term Debt

The Company’s long-term debt, which consists of limited recourse or nonrecourse indebtedness, is presented below, as of June 30, 2015 and December 31, 2014 (in thousands):


	As of June 30, 2015
				Unamortized						Contractual			Effective			Contractual
	Principal			Financing Cost			Net			Interest Rate			Interest Rate			Interest Type	Maturity
Hatchet Ridge term loan	$	220,152		$	(2,409	)	$	217,743			1.43	%		1.43	%	Imputed	December 2032
Gulf Wind term loan		154,076			(4,011	)		150,065			3.28	%		6.59	%⁽¹⁾	Variable	March 2020
St. Joseph term loan		172,550			(843	)		171,707			5.88	%		5.95	%	Fixed	May 2031
Spring Valley term loan		164,344			(5,905	)		158,439			2.65	%		5.51	%⁽¹⁾	Variable	June 2030
Santa Isabel term loan		111,746			(4,066	)		107,680			4.57	%		4.57	%	Fixed	September 2033
El Arrayán commercial term loan		98,354			(91	)		98,263			2.94	%		5.64	%⁽¹⁾	Variable	March 2029
El Arrayán EKF term loan		108,190			(101	)		108,089			5.56	%		5.56	%	Fixed	March 2029
Ocotillo commercial term loan		221,075			(6,408	)		214,667			2.03	%		3.92	%⁽¹⁾	Variable	August 2020
Ocotillo development term loan		102,780			(2,979	)		99,801			2.38	%		4.55	%⁽¹⁾	Variable	August 2033
Logan’s Gap construction loan		183,642			(2,341	)		181,301			1.57	%		1.57	%⁽¹⁾	Variable	December 2015
Amazon Wind (Fowler Ridge) construction loan		81,233			(3,895	)		77,338			1.62	%		1.62	%⁽¹⁾	Variable	December 2015
Lost Creek term loan		114,786			—			114,786			3.15	%		6.52	%⁽¹⁾	Variable	March 2021

		1,732,928			(33,049	)		1,699,879
Add: unamortized premium		1,482			—			1,482
Less: current portion (including construction loans)		(342,392	)		10,166			(332,226	)

	$	1,392,018		$	(22,883	)	$	1,369,135


	As of December 31, 2014
				Unamortized						Contractual			Effective			Contractual
	Principal			Financing Cost			Net			Interest Rate			Interest Rate			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 (including construction loans)		(121,561	)		11,868			(109,693	)

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

(1)	Includes impact of interest rate derivatives. Refer to Note 12, 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 and six months ended June 30, 2015 and 2014 (in thousands):


	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014
Interest and commitment fees incurred	$	18,136		$	13,850		$	34,568		$	27,307
Capitalized interest, commitment fees, and letter of credit fees		(2,258	)		(597	)		(3,573	)		(1,880	)
Letter of credit fees incurred		1,172			1,100			2,233			2,153
Amortization of financing costs		1,893			1,454			3,633			2,848

Interest expense	$	18,943		$	15,807		$	36,861		$	30,428

Gulf Wind

On June 26, 2015, the Company received a one-month extension of the scheduled term loan principal repayment of approximately $5.6 million, due on June 30, 2015, until July 31, 2015. The scheduled interest payment of approximately $2.6 million due on June 30, 2015 was paid on schedule as required by the Credit Agreement. Subsequent to June 30, 2015, the Company acquired the noncontrolling interest in the Gulf Wind project and prepaid the outstanding balance of the Gulf Wind project’s term loan facility. Refer to Note 22, Subsequent Events, for additional information.

Lost Creek

On October 22, 2009, Lost Creek entered into a $231.5 million credit facility that provided construction financing, a letter of credit facility and a term loan facility. In 2010, the construction facility was partially repaid through proceeds from a $107.7 million government grant and the remaining $123.3 million was repaid through a term loan. The letter of credit facility was released upon achieving commercial operations. On April 5, 2011, Lost Creek entered into an Amended and Restated Credit Agreement (“Amended Credit Agreement”), replacing the existing credit facility. The existing term loan was refinanced and increased by $23.0 million, for an aggregate term loan of $144.0 million, maturing on March 31, 2021. In connection with the term loan, Lost Creek entered into interest rate swaps for the term of the loan to hedge its exposure to variable interest over the term of the facility and to hedge its exposure to re-financing rate risk.

The term loan is a LIBOR loan and accrues interest at LIBOR plus an applicable margin of 2.5% during the period commencing on the effective date of the term loan and increasing by 0.25% on every third anniversary of the effective date of the term loan, ending on the day prior to the ninth anniversary date.

Collateral under the Lost Creek Amended Credit Agreement includes a collateral account agreement that requires proceeds from the sale of energy from the Lost Creek wind project be remitted directly to the depositary agent of the Amended Credit Agreement to provide for debt service payments and operating costs required under the Amended Credit Agreement.

The Amended Credit Agreement is subject to certain covenants, including limitations on additional indebtedness, limitations on liens, requirements for periodic financial and operational information, and compliance with certain required financial ratios. The Amended Credit Agreement also contains voluntary prepayment provisions which provide for the right to prepay the term loan without premium or penalty and contains mandatory prepayments for such events as upwind array events. As of June 30, 2015, there has been no requirement to make any such mandatory prepayments of amounts borrowed under the term loan. Additionally, the Amended Credit Agreement restricts payment of dividends, distributions, and returns of capital to affiliates of Lost Creek unless provided by the Amended Credit Agreement.

Amazon Wind Farm (Fowler Ridge)

On April 29, 2015, Amazon Wind Farm (Fowler Ridge) entered into a $199.1 million construction loan facility and $22.5 million of letter of credit facilities, as required by the PPA and renewable energy credit agreement. Under the financing agreement, the construction loan facility will be repaid at the earlier of commercial operations or February 29, 2016, the scheduled maturity date, through capital contributions from both the equity investors and the Company. The Company also entered into a Letter of Credit, Reimbursement and Loan Agreement pursuant to which the $11.2 million REC letter of credit facility expires on April 29, 2016 and the $11.3 million PPA letter of credit facility expires on April 29, 2020.

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

11. 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 the end of its estimated economic useful life. 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, during the six months ended June 30, 2015, 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 June 30, 2015 and 2014 (in thousands):


	Six months ended June 30,
	2015			2014
Beginning asset retirement obligations	$	29,272		$	20,834
Net additions during the year		10,811			4,912
Foreign currency translation adjustment		(177	)		5
Adjustment related to change in useful life		(1,907	)		—
Accretion expense		941			643

Ending asset retirement obligations	$	38,940		$	26,394

12. 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)			YTD Gain (Loss)
										Recognized into			Recognized into
Derivative Type	Quantity		Maturity Dates	Current Portion			Long-Term Portion			Income			Income
June 30, 2015
Interest rate swaps		6	6/30/2030	$	(3,212	)	$	4,467		$	5,239		$	2,135
Interest rate cap		1	12/31/2024		—			330			(54	)		(22	)
Energy derivative		1	4/30/2019		18,131			43,314			(6,002	)		(3,030	)
Foreign currency forward contracts		13	Various through 3/31/2017		284			107			(240	)		391
Interest rate swaps		5	9/30/2015		(1,634	)		—			(7	)		(7	)
Interest rate swaps		5	3/31/2021		(552	)		(849	)		81			81

				$	13,017		$	47,369		$	(983	)	$	(452	)

December 31, 2014
Interest rate swaps		6	6/30/2030	$	(3,403	)	$	2,523		$	(5,040	)	$	(11,339	)
Interest rate cap		1	12/31/2024		—			352			(29	)		(329	)
Energy derivative		1	4/30/2019		18,506			45,969			7,265			(3,878	)

				$	15,103		$	48,844		$	2,196		$	(15,546	)

June 30, 2014
Interest rate swaps		6	6/30/2030	$	(3,842	)	$	7,897		$	(2,855	)	$	(6,404	)
Interest rate cap		1	12/31/2024		—			420			(87	)		(261	)
Energy derivative		1	4/30/2019		12,449			41,622			(6,549	)		(14,282	)

				$	8,607		$	49,939		$	(9,491	)	$	(20,947	)

Designated Derivative Instruments Classified as Assets (Liabilities):


											For the period ended
					Fair Market Value						QTD Gain (Loss)			YTD Gain (Loss)
Derivative Type	Quantity		Maturity Dates		Current Portion			Long-Term Portion			Recognized in OCI			Recognized into OCI
June 30, 2015
Interest rate swaps		6		6/30/2033	$	(1,863	)	$	2,136		$	3,884		$	1,665
Interest rate swaps		3		3/31/2032		(1,747	)		(2,357	)		2,152			770
Interest rate swaps		7		3/15/2020		(4,466	)		(6,332	)		1,664			836
Interest rate swaps		2		6/28/2030		(4,247	)		(5,322	)		4,928			2,091
Interest rate swaps		5		9/30/2027		(2,067	)		(12,161	)		868			868
Interest rate swaps		5		9/30/2027		—			(474	)		69			69

					$	(14,390	)	$	(24,510	)	$	13,565		$	6,299

December 31, 2014
Interest rate swaps		6		6/30/2033	$	(1,917	)	$	525		$	(3,722	)	$	(8,912	)
Interest rate swaps		3		3/31/2032		(1,822	)		(3,338	)		(1,863	)		(1,983	)
Interest rate swaps		7		3/15/2020		(4,719	)		(6,915	)		(425	)		1,094
Interest rate swaps		2		6/28/2030		(4,446	)		(7,214	)		(3,889	)		(9,869	)

					$	(12,904	)	$	(16,942	)	$	(9,899	)	$	(19,670	)

June 30, 2014
Interest rate swaps		6		6/30/2033	$	(2,105	)	$	4,869		$	(1,998	)	$	(4,756	)
Interest rate swaps		3		3/31/2032		(1,915	)		(673	)		(116	)		(116	)
Interest rate swaps		7		3/15/2020		(5,136	)		(7,943	)		(377	)		(351	)
Interest rate swaps		2		6/28/2030		(4,806	)		(3,230	)		(3,056	)		(6,246	)

					$	(13,962	)	$	(6,977	)	$	(5,547	)	$	(11,469	)

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 and six months ended June 30, 2015 and 2014, respectively. The Company reclassified $1.3 million and $2.6 million related to cash settlements into net loss from accumulated other comprehensive loss during the three and six months ended

June 30, 2015, respectively, and $1.4 million and $2.8 million for the same periods in the prior year. The Company estimates that $4.5 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months. Subsequent to June 30, 2015, the Company terminated the interest rate swaps. Refer to Note 22, Subsequent Events, for additional information.

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 immaterial unrealized losses for each of the three and six months ended June 30, 2015, respectively, and $0.1 million and $0.3 million for the same periods in the prior year, in unrealized loss on derivatives, net in the consolidated statements of operations. Subsequent to June 30, 2015, the Company terminated the interest rate cap. Refer to Note 22, Subsequent Events, for additional information.

In 2010, Gulf Wind acquired an energy derivative instrument to manage its exposure to variable electricity prices. The energy price swap fixes the price of approximately 58% of its electricity generation through April 2019. The energy derivative instrument is a derivative but did not meet the criteria required to adopt hedge accounting. The energy derivative instrument’s fair value as of June 30, 2015 and December 31, 2014 was $61.4 million and $64.5 million, respectively. Gulf Wind recognized unrealized losses of $6.0 million and $3.0 million for the three and six months ended June 30, 2015, respectively, and unrealized losses of $6.5 million and $14.3 million for the same periods in the prior year, 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 and six months ended June 30, 2015 and 2014, respectively. The Company reclassified $1.2 million and $2.4 million related to cash settlements into net loss from accumulated other comprehensive loss during the three and six months ended June 30, 2015, respectively, and $1.3 million and $2.5 million for the same periods in the prior year. The Company estimates that $4.2 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months.

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 and six months ended June 30, 2015 and 2014, respectively. The Company reclassified $0.5 million and $1.1 million related to cash settlements into net loss from accumulated other comprehensive loss during each of the three and six months ended June 30, 2015, respectively, and $0.5 million and $1.0 million for the same periods in the prior year. The Company estimates that $1.9 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months. 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 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 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 and six months ended June 30, 2015 and 2014, respectively. The Company reclassified $0.4 million and $0.9 million related to cash settlements into net loss from accumulated other comprehensive loss, net of tax, during the three and six months ended June 30, 2015, respectively. The Company reclassified $0.2 million, net of tax, related to cash settlements into net loss from accumulated other comprehensive income for each of the three and six months ended June 30, 2014. The Company estimates that $1.7 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months.

Lost Creek

In September 2010, Lost Creek entered into interest rate swaps with its lenders to manage exposure to its interest rate risk on its long-term debt and anticipated refinancing. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 3.77% for the initial five-year period of the term loan. Lost Creek also entered into interest rate swaps to exchange variable interest rate payments for fixed interest rate payments of approximately 5.10%, for the anticipated refinancing of the balloon payment in 2015, over a 12-year period. In April 5, 2011, Lost Creek entered into an amended and restated credit facility to increase the term loan by $23.0 million to an aggregate term loan of $144.0 million. As a result, Lost Creek entered into additional interest rate swaps on the additional loan amount of $23.0 million, exchanging variable interest rate payments for fixed interest payments of 3.51% over a 10-year period and exchanging variable interest rate payments for fixed interest rate payments of 5.58% for the anticipated refinancing of the balloon payment of the amended term loan in March 2021 through September 2027.

As a result of the Wind Capital acquisition, interest rate swaps related to the anticipated refinancing of the term loan were designated as cash flow hedges. During the three and six months ended June 30, 2015, the Company recorded ineffectiveness of $0.1 million, respectively, related to the designated cash flow hedges. The interest rate swaps related to the initial long-term debt maturing in September 2015 and additional term loan maturing in March 2021 have been de-designated as they do not qualify for cash flow hedge accounting.

During the three and six months ended June 30, 2015, there were no cash settlements related to the designated derivatives at Lost Creek. The Company estimates that $2.1 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months.

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. In 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 June 30, 2015, the total notional amount of foreign currency forward contracts outstanding was C$57.6 million and the total fair value of these contracts was $0.4 million. For the three and six months ended June 30, 2015, the Company recognized a change in fair value of the foreign currency forward contracts of $(0.2) million and $0.4 million, respectively, in unrealized loss on derivatives, net in the consolidated statement of operations.

13. Accumulated Other Comprehensive Loss

The following tables summarize the changes in the accumulated other comprehensive loss balance by component, net of tax, for the six months ended June 30, 2015 and 2014 (in thousands):


				Effective Portion of			Proportionate
	Foreign			Change in Fair Value			Share of Equity
	Currency			of Derivatives			Investee’s OCI			Total
Balances at December 31, 2014	$	(19,338	)	$	(26,672	)	$	(7,903	)	$	(53,913	)
Other comprehensive loss before reclassifications		(9,692	)		(657	)		(2,382	)		(12,731	)
Amounts reclassified from accumulated other comprehensive loss		—			6,956			1,045			8,001

Net current period other comprehensive loss		(9,692	)		6,299			(1,337	)		(4,730	)

Balances at June 30, 2015	$	(29,030	)	$	(20,373	)	$	(9,240	)	$	(58,643	)


				Effective Portion of			Proportionate
	Foreign			Change in Fair Value			Share of Equity
	Currency			of Derivatives			Investee’s OCI			Total
Balances at December 31, 2013	$	(8,463	)	$	(7,002	)	$	(1,912	)	$	(17,377	)
Other comprehensive loss before reclassifications		(869	)		(17,989	)		(4,283	)		(23,141	)
Amounts reclassified from accumulated other comprehensive loss		—			6,520			—			6,520

Net current period other comprehensive loss		(869	)		(11,469	)		(4,283	)		(16,621	)

Balances at June 30, 2014	$	(9,332	)	$	(18,471	)	$	(6,195	)	$	(33,998	)

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.

14. Fair Value Measurements

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, dividends payable and current portion of contingent liabilities. Based on the nature and short maturity of these instruments, their fair value is approximated using carrying cost and they are presented in the Company’s financial statements at carrying cost. The fair values of cash 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
June 30, 2015
Interest rate swaps	$	—	$	(40,680	)	$	—		$	(40,680	)
Interest rate cap		—		330			—			330
Energy derivative		—		—			61,445			61,445
Foreign currency forward contracts		—		391			—			391
Contingent liabilities		—		—			(1,320	)		(1,320	)

	$	—	$	(39,959	)	$	60,125		$	20,166

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 six months ended June 30, 2015 and 2014, respectively. There were no transfers between Level 2 and Level 3 during the periods presented.


	Energy Derivative
	Six months ended June 30,
	2015			2014
Balances, beginning of period	$	64,475		$	68,353
Settlements		(12,097	)		(6,718	)
Change in fair value		9,067			(7,564	)

Balances, end of period	$	61,445		$	54,071

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 six months ended June 30, 2015 and 2014, respectively. There were no transfers between Level 2 and Level 3 during the periods presented.


	Contingent Liabilities
	Six months ended June 30,
	2015			2014
Balances, beginning of period	$	(175	)	$	—
Payments		—			—
Change in estimate		(1,145	)		—

Balances, end of period	$	(1,320	)	$	—

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 June 30, 2015 and December 31, 2014, but for which fair value is disclosed.


	As reflected on		Fair Value
	the balance sheet		Level 1		Level 2		Level 3		Total
June 30, 2015
Long-term debt, including current portion	$	1,701,361	$	—	$	1,656,070	$	—	$	1,656,070

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.

15. 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.

16. Stockholders’ Equity

Common Stock

On February 9, 2015, the Company completed an underwritten public 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.

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:

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

Noncontrolling Interests

The following table presents the noncontrolling interest balances, reported in stockholders’ equity in the consolidated balance sheets, by project, as of June 30, 2015 and December 31, 2014 (in thousands):


					Noncontrolling Ownership Percentage
	June 30,		December 31,		June 30,			December 31
	2015		2014		2015			2014
Gulf Wind	$	94,946	$	97,061		60	%		60	%
El Arrayán		34,531		35,624		30	%		30	%
Panhandle 1		200,875		205,333		21	%		21	%
Panhandle 2		189,539		192,568		19	%		19	%
Post Rock		204,300		—		40	%		N/A

Noncontrolling interest	$	724,191	$	530,586

17. Stock-based Compensation

On April 10, 2015, the Company granted between 0% and 150% of the “Target” (56,844) restricted stock awards (“RSAs”) to certain senior management personnel which vest at the later of three-year performance period (January 1, 2015 – December 31, 2017), or the end of the requisite service period, which shall be no later than March 15, 2018, in accordance with the level of Total Shareholder Return achieved relative to a peer group during the specified period. Following the date of grant, rights to dividends will accrue on the maximum number of shares and may be forfeited if the market or service conditions are not achieved.

The Company measures the fair value of the RSA’s at the grant date using a Monte Carlo simulation model and recognizes stock-based compensation over the longer of the requisite service period or performance period. For the three and six months ended June 30, 2015, the total stock-based compensation expense for market-based restricted stock awards was approximately $0.2 million.

Total stock-based compensation expense related to restricted stock awards, restricted stock units and stock options for the three and six months ended June 30, 2015 was $1.2 million and $2.0 million, respectively, and $1.6 million and $2.2 million for the same periods in the prior year, respectively.

18. Earnings (Loss) per Share

The Company computes basic earnings (loss) per share using net income (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 earnings (loss) per share using net income (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 and six months ended June 30, 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.

The computations for Class A basic and diluted earnings (loss) per share are as follows (in thousands except share data):


	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014
Numerator for basic and diluted earnings (loss) per share:
Net income (loss) attributable to controlling interest	$	14,317		$	11,199		$	(5,582	)	$	(3,690	)
Less: dividends declared on Class A common shares		(24,380	)		(14,981	)		(48,003	)		(26,138	)
Less: deemed dividends on Class B common shares		—			(7,457	)		—			(7,457	)

Net loss attributable to common stockholders	$	(10,063	)	$	(11,239	)	$	(53,585	)	$	(37,285	)
Denominator for earnings (loss) per share:
Weighted average number of shares:
Class A common stock—basic		68,943,707			41,174,697			67,426,286			38,331,595
Add dilutive effect of:
Stock options		67,564			107,979			59,517			100,814
Restricted stock awards		126,558			227,543			115,079			227,543
Restricted stock units		9,431			—			16,703			—
Class B common stock		—			15,555,000			—			15,555,000

Class A common stock—fully diluted		69,147,260			57,065,219			67,617,585			54,214,952
Less: antidilutive securities
Stock options		—			—			(59,517	)		(100,814	)
Restricted stock awards		—			—			(115,079	)		(227,543	)
Restricted stock units		—			—			(16,703	)		—
Class B common stock		—			(15,555,000	)		—			—

Class A common stock—diluted (excluding antidilutive securities)		69,147,260			41,510,219			67,426,286			53,886,595
Class B common stock—basic and diluted		—			15,555,000			—			15,555,000
Calculation of basic and diluted earnings (loss) per share:
Class A common stock:
Dividends	$	0.35		$	0.36		$	0.71		$	0.68
Undistributed loss		(0.15	)		(0.20	)		(0.79	)		(0.69	)

Basic earnings (loss) per share	$	0.21		$	0.17		$	(0.08	)	$	(0.01	)
Class A common stock:
Diluted earnings (loss) per share	$	0.21		$	0.16		$	(0.08	)	$	(0.07	)

Class B common stock:
Deemed dividends	$	—		$	0.48		$	—		$	0.48
Undistributed loss		—			(0.20	)		—			(0.69	)

Basic and diluted earnings (loss) per share	$	—		$	0.28		$	—		$	(0.21	)

Dividends declared per Class A common share	$	0.35		$	0.32		$	0.71		$	0.63

Deemed dividends per Class B common share	$	—		$	0.48		$	—		$	0.48

19. 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 June 30,					Six months ended June 30,					June 30,		December 31,
	2015		2014			2015		2014			2015		2014
United States	$	66,955	$	54,065		$	114,730	$	90,387		$	2,275,556	$	1,784,219
Canada		9,344		11,024			21,097		24,308			210,568		233,690
Chile		8,372		(150	)		13,710		(139	)		326,079		332,947

Total	$	84,671	$	64,939		$	149,537	$	114,556		$	2,812,203	$	2,350,856

20. 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 June 30, 2015, under the terms of the PPAs, the Company issued irrevocable letters of credit totaling $88.6 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 June 30, 2015, the Company issued irrevocable letters of credit totaling $115.1 million, of which $49.2 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 June 30, 2015, total outstanding lease commitments were $305.7 million. During the three and six months ended June 30, 2015, the Company recorded rent expense of $2.7 million and $5.1 million, respectively, in project expense in the consolidated statements of operations. During the three and six months ended June 30, 2014, the Company recorded rent expense of $1.8 million and $3.7 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 June 30, 2015, outstanding commitments with these third party contractors were $367.1 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 $13.9 million as of June 30, 2015. The Company also has construction-related open commitments of $148.7 million as of June 30, 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 $8.1 million over approximately the next 20 years to local community and government organizations surrounding certain wind farms.

Purchase and Sales Agreements

On April 29, 2015, the Company acquired 100% of the membership interests in Fowler Ridge IV Wind Farm LLC through the acquisition of Fowler Ridge IV B Member LLC from Pattern Development. Subject to the terms of this agreement, the Company may make additional contingent payments of up to $29.1 million, consisting of a $25.1 million fixed amount and up to $4.0 million as calculated based on final budget to actual amounts, both of which are payable to Pattern Development upon tax equity funding.

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 $4.0 million based on the exchange rate as of June 30, 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 June 30, 2015, the Company recorded liabilities of $0.5 million associated with bonuses payable to the turbine manufacturers. No such liability was recorded as of June 30, 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 June 30, 2015, the Company accrued a 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 June 30, 2015, the Company recorded liabilities of $0.8 million associated with bonuses payable to service providers.

Contingent Liabilities

In December 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.

In June 2015, the Company recorded a $7.3 million contingent payment, payable to third-parties, required to connect the Amazon Wind Farm (Fowler Ridge) into an existing transmission line. The estimated contingent payment was accrued when it became probable that the future event would occur, upon close of construction financing. The payment is due upon energization of the transmission line.

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, Panhandle 2, Logan’s Gap and Amazon Wind (Fowler Ridge) 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 and eligibility of production tax credits. 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.

21. 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’s Chief Executive Officer also serves as the Chief Executive Officer of Pattern Development. 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 June 30,						Six months ended June 30,
	2015			2014			2015			2014
Related party general and administrative	$	1,621		$	1,383		$	3,429		$	2,663
Related party income		(756	)		(444	)	$	(1,424	)		(1,072	)

Total	$	865		$	939		$	2,005		$	1,591

As of June 30, 2015 and December 31, 2014, the amounts payable to Pattern Development for bilateral management service cost reimbursements were $0.9 million and $0.8 million, respectively. In addition, the Company had a related party receivable of zero and $0.1 million as of June 30, 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 June 17, 2015, the Company acquired a one-third equity interest in K2 from Pattern Development for a purchase price of approximately $128.0 million, plus assumed estimated proportionate debt at term conversion of approximately $221.8 million, U.S. dollar equivalent. This represents a 90 MW interest in the 270 MW wind project, located in the Township of Ashfield-Colborne-Wawanosh, Ontario.

On April 29, 2015, the Company acquired 100% of the membership interests in Fowler Ridge IV Wind Farm LLC through the acquisition of Fowler Ridge IV B Member LLC from Pattern Development for a purchase price of approximately $37.5 million, paid at closing, in addition to $0.5 million of capitalized transaction expenses. In addition, the Company has contingent payments of up to $29.1 million to Pattern Development payable upon tax equity funding. Amazon Wind Farm (Fowler Ridge) is a 150 MW wind project located in Benton County, Indiana.

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, in addition to 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, K2 and El Arrayán, prior to the Company’s acquisition of the controlling interest of El Arrayán on June 25, 2014, in addition to various Pattern Development subsidiaries. Management fees of $0.9 million and $1.7 million were recorded as related party revenue in the consolidated statements of operations for the three and six months ended June 30, 2015, respectively, and $1.0 million and $1.5 million for the same periods in the prior year. A related party receivable of $0.8 million and $0.7 million was recorded in the consolidated balance sheets as of June 30, 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.

22. Subsequent Events

On July 30, 2015, the Company acquired 100% of the Class A membership interests in Lost Creek Wind Holdco for a cash purchase price of approximately $35.2 million, less an initial deposit of $3.5 million, pursuant to a Purchase Agreement dated May 15, 2015.

On July 30, 2015, subsequent to the acquisitions of the noncontrolling interests in the Gulf Wind project, the Company prepaid 100% of the outstanding balance of the Gulf Wind project’s term loan of $154.1 million, resulting in a loss on debt settlement of approximately $4.0 million and terminated the related interest rate swaps with an aggregate fair value of $11.2 million and interest rate cap with a fair value of $0.2 million, resulting in a total net loss of $11.0 million.

On July 28, 2015, the Company acquired Pattern Development’s 40% interest in the Gulf Wind project for a cash purchase price of approximately $13.0 million. Concurrently, the Company acquired MetLife Capital, Limited Partnership’s (“MetLife Capital”) membership interest in the Gulf Wind project for a cash purchase price of approximately $72.8 million. As a result of the acquisitions, the Company owns 100% of the membership interests in the Gulf Wind project.

On July 28, 2015, the Company completed an underwritten public offering of its Class A common stock. In total, 5,435,000 shares of its Class A common stock were sold. The Company has granted the underwriters a 30-day option to purchase up to an additional $18.8 million, or 815,250 shares of its Class A common stock, solely to cover over-allotments, if any. Net proceeds generated for the Company were approximately $120.2 million after deduction of underwriting discounts, commissions and transaction expenses. Concurrently, the Company issued $225.0 million aggregate principal amount of 4.00% Convertible Senior Notes due 2020 (“2020 4.00% Notes”). The Company has granted initial purchasers of the notes offering a 30-day option to purchase up to an additional $33.8 million aggregate principal amount of notes solely to cover over-allotments, if any. Net proceeds generated for the Company were approximately $218.8 million, after deducting the initial purchasers’ discount, commissions and transaction expenses. The 2020 4.00% Notes bear interest at a rate of 4.00% per year, payable semiannually in arrears on January 15 and July 15, beginning on January 15, 2016. The notes will mature on July 15, 2020, unless earlier repurchased or converted. The notes are guaranteed on a senior unsecured basis by a subsidiary of the Company.

On July 21, 2015, the Company declared an increased dividend for the third quarter, payable on October 30, 2015, to holders of record on September 30, 2015, in the amount of $0.3630 per Class A share, or $1.452 on an annualized basis. This is a three percent increase from the second quarter 2015 dividend of $0.3520.

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 and six months ended June 30, 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 located in the United States, Canada and Chile that use proven, best-in-class technology and have a total owned capacity of 2,282 MW, including the interests in the Gulf Wind project we acquired in July 2015. These projects consist of 14 operating projects with two projects under construction. Our construction projects, the Logan’s Gap project, which we acquired from Pattern Development in December 2014 and the Amazon Wind Farm (Fowler Ridge) project, which we acquired from Pattern Development 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. The credit rating of one of our counterparties, PREPA, was downgraded in 2014 and further downgraded in 2015. 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. Eighty-nine 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 15 years (inclusive of our acquisition of the membership interests in the Gulf Wind project).

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 Class A 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 5,900 MW pipeline of development projects, all of which are subject to our right of first offer. We target achieving a total owned capacity of 5,000 MW by year end 2019 through a combination of acquisitions from Pattern Development and other third parties capitalizing on the large and fragmented global wind power market.

Recent Developments

On July 30, 2015, we acquired 100% of the Class A membership interests in Lost Creek Wind Holdco (the “Lost Creek Tax Equity Buyout”) for a cash purchase price of approximately $35.2 million, less an initial deposit of $3.5 million, pursuant to a Purchase Agreement dated May 15, 2015.

On July 30, 2015, subsequent to the acquisitions of the noncontrolling interests in the Gulf Wind project, we prepaid 100% of the outstanding balance of the Gulf Wind project’s term loan of $154.1 million, resulting in a loss on debt settlement of approximately $4.0 million and terminated the related interest rate swaps with an aggregate fair value amount of $0 million and interest rate cap with a fair value of $0.2 million, resulting in a total net loss of $11.0 million. Previously, on June 26, 2015, in anticipation of our acquisition of the noncontrolling interests in the Gulf Wind project, we received a one-month extension of the scheduled term loan principal repayment of approximately $5.6 million, due on June 30, 2015, until July 31, 2015. The scheduled interest payment of approximately $2.6 million due on June 30, 2015 was paid on schedule as required by the credit agreement.

On July 28, 2015, we acquired Pattern Development’s 40% interest in the Gulf Wind project for a cash purchase price of approximately $13.0 million. Concurrently, we acquired MetLife Capital, Limited Partnership’s (“MetLife Capital”) membership interest in the Gulf Wind project for a cash purchase price of approximately $72.8 million. As a result of the acquisitions, we own 100% of the membership interests in the Gulf Wind project.

On July 28, 2015, we completed an underwritten public offering of our Class A common stock. In total, 5,435,000 shares of our Class A common stock were sold. We granted the underwriters a 30-day option to purchase up to an additional $18.8 million, or 815,250 shares of our Class A common stock, solely to cover over-allotments. Net proceeds generated to us were approximately $120.2 million after deduction of underwriting discounts, commissions and transaction expenses. Concurrently, we issued $225.0 million aggregate principal amount of 4.00% Convertible Senior Notes due 2020 (“2020 4.00% Notes”). We have granted initial purchasers of the notes offering a 30-day option to purchase up to an additional $33.8 million aggregate principal amount of notes solely to cover over-allotments, if any. Net proceeds generated for us were approximately $218.8 million, after deducting the initial purchasers’ discount, commissions and transaction expenses. The 2020 4.00% Notes bear interest at a rate of 4.00% per year, payable semiannually in arrears on January 15 and July 15, beginning on January 15, 2016. The notes will mature on July 15, 2020, unless earlier repurchased or converted. The notes are guaranteed on a senior unsecured basis by one of our subsidiaries.

On July 21, 2015, we declared an increased dividend for the third quarter, payable on October 30, 2015, to holders of record on September 30, 2015, in the amount of $0.3630 per Class A share, or $1.452 on an annualized basis. This is a three percent increase from the second quarter 2015 dividend of $0.3520.

On July 13, 2015, our Grand project entered into settlement agreements with Samsung C&T Canada Ltd. (a subsidiary of Samsung C&T Corporation), the project construction provider, to settle claims for cost increases and schedule relief in the construction of the Grand project asserted by the project construction provider against Grand and the third party owner of an adjacent 100 MW solar project that jointly owns transmission facilities with Grand that were constructed by the project construction provider, on the one hand, and claims asserted by Grand and the solar project owner against the project construction provider, on the other hand. The settlement agreements provide for a net payment by Grand of C$14.3 million.

On July 3, 2015, we amended our Bilateral Management Services Agreement with Pattern Development to change the terms upon which the employees of Pattern Development and its subsidiaries may become our employees (the “Reintegration Event”). The Reintegration Event is no longer conditioned upon our achievement of $2.5 billion in market capitalization. Instead, we have the option, exercisable at any time until January 1, 2017, to require the Reintegration Event to occur.

On June 17, 2015, we acquired a one-third limited partnership interest in K2 Wind Ontario Limited Partnership (“K2”), as well as 100% of the issued and outstanding shares in Pattern K2 GP Holdings Inc., from Pattern Development, pursuant to a Purchase and Sale Agreement, for a consideration of approximately $128.0 million, paid at closing, in addition to $0.4 million of capitalized transaction expenses, plus assumed estimated proportionate debt at term conversion of approximately $221.8 million. K2 has completed construction of the wind power project which has achieved commercial operations. K2 now operates the approximately 270 MW wind power project located in the Township of Ashfield-Colborne-Wawanosh, Ontario. K2 consists of 140 Siemens 2.3 MW wind turbines and operates under a 20-year power sale agreement with the IESO. As a result of the acquisition, we directly own a one-third limited partnership interest in K2 and 25% of the issued and outstanding shares of K2 Wind Ontario Inc., the general partner, and indirectly hold a 0.0025% general partnership interest in K2.

On May 15, 2015, pursuant to a Purchase and Sale Agreement and for an aggregate consideration of approximately $242.0 million, paid at closing, we acquired: (1) from Wind Capital Group, LLC, an unrelated third party, 100% of the membership interests in Lost Creek Wind Finco, LLC, which owns 100% of the Class B membership interests in Lost Creek Wind Holdco, LLC, which owns 100% of the membership interests in Lost Creek Wind, LLC, which owns and operates a 150 MW wind power project in King City, Missouri; and (2) from Lincoln County Wind Project Finco, LLC, an unrelated third party, 100% of the membership interests in Lincoln County Wind Project Holdco, LLC, which owns 100% of the Class B membership interests in Post Rock Wind Power Project, LLC, which owns and operates a 201 MW wind power project in Ellsworth and Lincoln Counties, Kansas. We also assumed certain project-level indebtedness and ordinary course performance guarantees securing project obligations. Lost Creek operates with General Electric wind turbines and achieved commercial operations in May 2010. It has a power sale agreement with Associated Electric Cooperative Incorporated (rated AA) expiring in 2030. Post Rock, in which we have 120 MW owned capacity, operates with General Electric wind turbines and achieved commercial operations in October 2012. It has a power sale agreement with Westar (rated BBB+) expiring in 2032.

On April 29, 2015, we acquired 100% of the membership interests in Fowler Ridge IV Wind Farm 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, in addition to $0.5 million of capitalized transaction expenses, and contingent payments of up to $29.1 million, payable upon tax equity funding. The 150 MW wind project (of which we have 116 MW owned capacity) named Amazon Wind Farm (Fowler Ridge), located in Benton County, Indiana, is expected to reach commercial operation in late 2015. The project consists of 65 Siemens 2.3 wind turbines and has a power sale agreement with Amazon (not rated) expiring in 2028. The power sale agreement provides for 50% of the energy to be delivered starting on the targeted commercial operations date (December 31, 2015), increasing to 100% 18 months later.

On April 6, 2015, we announced an increase to our growth target for cash available for distribution per Class A share to a compound annual growth rate of 12-15% for the three-year period following 2014. The growth target was increased due to the acquisitions of K2, Lost Creek and Post Rock described above, the advancement in the development of our Identified ROFO Projects described below and the expansion of Pattern Development’s development pipeline.

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

Q3 2015

200

164

Amazon Wind Farm (Fowler Ridge)

Indiana

Q2 2015

Q4 2015

150

116

350

280

Since March 2015, we have added seven 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 June 24, 2015, we announced the addition of the following six projects to our Identified ROFO Projects list:

•

398 MW of a 497 MW New Mexico/California wind power project based in Curry County, New Mexico. The project, which is being built in multiple phases, will deliver wind power directly into California. The project is at an advanced stage of development. Terms of the 20-year/25-year power sale agreements for multiple phases have been agreed upon and are in final documentation.

•

63 MW of the 125 MW Tsugaru wind power project located in Aomori, Japan. The project, which is in late-stage development, has qualified for a power sale agreement under Japan’s Feed-In Tariff law.

•

31 MW of the 33 MW Ohorayama wind power project located in Kochi, Japan. The project has qualified for a 20-year power sale agreement with Shikoku Electric Power Company.

•

17 MW of the 42 MW Futtsu Solar project under construction in Chiba, Japan. This solar power project has a 20-year power sale agreement with Tokyo Electric Power Company.

•

12 MW of the 12 MW Otsuki wind power facility located in Kochi, Japan. This operational facility has a 12-year power sale agreement with Shikoku Electric Power Company.

•

5 MW of the 14 MW Kanagi Solar project under construction in Shimane, Japan. This solar power project has a 20-year power sale agreement with Chugoku Electric Power Company.

•

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

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 certain of 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⁾
Armow	In construction	Ontario		2014		2015		PPA		180		90
Meikle	In construction	British Columbia		2015		2016		PPA		185		180
Conejo Solar	In construction	Chile		2015		2016		PPA		104		84
Belle River	Securing final permits	Ontario		2016		2017		PPA		100		50
Henvey Inlet	Late stage development	Ontario		2016		2017		PPA		300		150
Mont Sainte-Marguerite	Late stage development	Québec		2016		2017		PPA		147		147
North Kent	Late stage development	Ontario		2016		2017		PPA		100		43
New Mexico/California	Late stage development	New Mexico		2016		2016/2017		PPA		497		398
Tsugaru	Late stage development	Japan		2015		2018		PPA		125		63
Ohorayama	Late stage development	Japan		2015		2017		PPA		33		31
Kanagi Solar	In construction	Japan		2014		2016		PPA		14		5
Futtsu Solar	In construction	Japan		2014		2016		PPA		42		17
Otsuki	Operational	Japan		2009		2016		PPA		12		12

										1,839		1,270

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

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

(3)

Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of 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.

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 (loss) 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. Adjusted EBITDA and cash available for distribution are non-GAAP financial measures which management believes may assist investors in evaluating the Company’s financial performance and its ability to pay dividends. 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 (loss) 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 (loss) and other traditional measures of operating results, the results of our operations without regard to periodic, and sometimes material, fluctuations in the market value of such assets or liabilities.

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


	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014
Net income (loss)	$	5,657		$	7,167		$	(16,402	)	$	(14,732	)
Plus:
Interest expense, net of interest income		18,715			15,525			36,414			29,943
Tax provision		3,603			4,065			2,857			2,033
Depreciation, amortization and accretion		34,785			21,284			63,841			42,461

EBITDA	$	62,760		$	48,041		$	86,710		$	59,705

Unrealized loss on energy derivative		6,002			6,549			3,030			14,282
Interest rate derivative settlements		960			1,035			1,919			2,052
Unrealized (gain) loss on derivatives, net		(5,138	)		2,942			(2,697	)		6,665
Net loss (gain) on transactions		1,305			(14,537	)		2,589			(14,537	)
Plus, proportionate share from equity accounted investments:
Interest expense, net of interest income		5,181			4,944			10,619			5,197
Tax provision		—			102			—			102
Depreciation, amortization and accretion		4,991			4,537			9,500			4,724
Unrealized (gain) loss on interest rate and currency derivatives, net		(9,240	)		5,236			1,894			17,831
Realized loss on interest rate and currency derivatives		—			—			—			22

Adjusted EBITDA	$	66,821		$	58,849		$	113,564		$	96,043

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 cash available for distribution is net cash provided by operating activities. The following table is a reconciliation of our net cash provided by operating activities to cash available for distribution for the periods presented (unaudited and in thousands):


	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014
Net cash provided by operating activities	$	32,361		$	44,417		$	48,600		$	60,822
Changes in operating assets and liabilities		2,521			(12,336	)		(2,136	)		(5,685	)
Other		(148	)		—			(292	)		—
Network upgrade reimbursement		618			618			1,236			1,236
Release of restricted cash to fund project and general and administrative costs		1,501			7			1,501			61
Operations and maintenance capital expenditures		(283	)		(40	)		(321	)		(94	)
Transaction costs for acquisitions		1,357			1,128			1,777			1,128
Distributions from unconsolidated investment		7,771			—			13,847			—
Less:
Distributions to noncontrolling interests		(763	)		(1,470	)		(1,511	)		(1,470	)
Principal payments paid from operating cash flows		(16,948	)		(16,266	)		(25,383	)		(22,096	)

Cash available for distribution	$	27,987		$	16,058		$	37,318		$	33,902

Results of Operations

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

The following table presents selected operating performance metrics for the periods presented (unaudited):


	Three months ended June 30,
	2015		2014		Change			% Change
Proportional MWh sold		1,201,940		769,619		432,321			56.2	%
Average realized electricity price per MWh	$	82	$	100	$	(18	)		-18.0	%

Proportional MWh sold and average realized electricity price. Our proportional MWh sold for the three months ended June 30, 2015 was 1,201,940 MWh, as compared to 769,619 MWh for the three months ended June 30, 2014, an increase of 432,321, or 56.2%. This increase in proportional MWh sold was primarily attributable to the commencement of commercial operations at both Panhandle 1 and El Arrayán in June 2014 and Panhandle 2 in November 2014 and the acquisition of Lost Creek and Post Rock in May 2015. Our average realized electricity price was approximately $82 per MWh for the three months ended June 30, 2015 as compared to approximately $100 per MWh for the three months ended June 30, 2014. The $18 per MWh decrease in the average realized electricity price was due to lower PPA pricing related to Panhandle 1 and Panhandle 2 projects and the impact of foreign exchange on revenue denominated in the Canadian dollar at St. Joseph, partially offset by higher PPA pricing related to El Arrayán and Grand. Low wind levels in the second quarter of 2015 resulted in a 10% negative variance in our production compared to our long-term expectation after adjusting for certain production losses, which are unrelated to wind and are compensated by contractual counterparties.

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


	Three months ended June 30,
	2015			2014			$ Change			% Change
Revenue	$	84,671		$	64,939		$	19,732			30.4	%

Project expense		27,981			16,700			11,281			67.6	%
Depreciation and accretion		34,342			21,284			13,058			61.4	%

Total cost of revenue		62,323			37,984			24,339			64.1	%

Gross profit		22,348			26,955			(4,607	)		-17.1	%

General and administrative		8,870			6,288			2,582			41.1	%
Related party general and administrative		1,621			1,383			238			17.2	%

Total operating expenses		10,491			7,671			2,820			36.8	%

Operating income		11,857			19,284			(7,427	)		-38.5	%
Total other expense		(2,597	)		(8,052	)		5,455			-67.7	%

Net income before income tax		9,260			11,232			(1,972	)		-17.6	%
Tax provision		3,603			4,065			(462	)		-11.4	%

Net income		5,657			7,167			(1,510	)		-21.1	%
Net loss attributable to noncontrolling interest		(8,660	)		(4,032	)		(4,628	)		114.8	%

Net income attributable to controlling interest	$	14,317		$	11,199		$	3,118			27.8	%

Adjusted EBITDA	$	66,821		$	58,849		$	7,972			13.5	%

Revenue. Revenue for the three months ended June 30, 2015 was $84.7 million as compared to $64.9 million for the three months ended June 30, 2014, an increase of $19.7 million, or 30.4%. This increase in revenue was primarily attributable to increased electricity sales due to the commencement of commercial operations at El Arrayán, Panhandle 1, and Panhandle 2 at various times in 2014 and the acquisition of Lost Creek and Post Rock in the second quarter of 2015.

We also realized an increase of $1.9 million in energy derivative settlements during the second 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.

Cost of revenue. Cost of revenue for the three months ended June 30, 2015 was $62.3 million as compared to $38.0 million for the three months ended June 30, 2014, an increase of $24.3 million, or 64.1%. The increase in cost of revenue was primarily attributable to the commencement of commercial operations at Panhandle 1, Panhandle 2, and El Arrayán at various times in 2014 and the acquisition of Lost Creek and Post Rock in the second quarter of 2015. 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 June 30, 2015 were $10.5 million as compared to $7.7 million for the three months ended June 30, 2014, an increase of $2.8 million, or 36.8%. The increase in operating expenses was primarily attributable to increases in general and administrative expense to support new projects acquired in 2014 and 2015 and acquisition-related activity in the second quarter of 2015.

Other expense. Other expense for the three months ended June 30, 2015 was $2.6 million compared to $8.1 million for the three months ended June 30, 2014, a decrease of $5.5 million, or 67.7%. The decrease in other expense was primarily attributable to a $17.5 million favorable variance between equity in earnings from unconsolidated investments of $13.8 million in the second quarter of 2015 and equity in losses from unconsolidated investments of $3.7 million in the second quarter of 2014, which is primarily a result of unrealized gains from the valuation of interest rate derivatives on the unconsolidated investees’ financial statements. In addition, we recorded a $5.1 million unrealized gain on derivatives in the second quarter of 2015 compared to a $2.9 million loss in the second quarter of 2014 primarily related to the valuation of interest rate derivatives at Ocotillo. The changes in unrealized gains and losses on interest rate derivatives were due to an increase in the forward interest rate curve in the second quarter of 2015 compared to a decrease in the forward interest rate curve in the second quarter of 2014. Offsetting these decreases to other expense in the second quarter of 2015 was the absence of an $18.0 million gain recorded in net gain on transactions in the second quarter of 2014, related to our acquisition of an additional 38.5% interest in the El Arrayán project. In addition, interest expense increased by $3.1 million primarily related to debt at El Arrayán and Lost Creek, and the revolving credit facility in the second quarter of 2015, partially offset by a decrease in interest expense at Ocotillo due to the repricing of the debt in the fourth quarter of 2014.

Tax provision. The tax provision was $3.6 million for the three months ended June 30, 2015 compared to $4.1 million for the three months ended June 30, 2014, a decrease of $0.5 million, or 11.4%. The tax provision in the second quarter of 2015 was the result of recording deferred tax liabilities on equity in earnings in unconsolidated investments at South Kent, Grand, and K2, tax expense at our Canadian and Puerto Rican operations, and foreign withholding taxes on intercompany transactions in certain foreign jurisdictions, partially offset by recognizing a deferred tax asset on losses at El Arrayán. The expense provision in the second quarter of 2014 was primarily the result of recording a discrete expense on a gain related to the fair value re-measurement of our initial 31.5% interest in El Arrayán.

Net loss attributable to noncontrolling interest. The net loss attributable to noncontrolling interest was $8.7 million for the three months ended June 30, 2015 compared to $4.0 million for the three months end June 30, 2014, an increase of $4.6 million, or 114.8%, primarily due to net loss attributable to noncontrolling interests from Panhandle 1 and Panhandle 2, which commenced commercial operations at various times in 2014 and Lost Creek and Post Rock, both of which were acquired in the second quarter of 2015, partially offset by an increase in derivative hedge settlements at Gulf Wind.

Adjusted EBITDA. Adjusted EBITDA for the three months ended June 30, 2015 was $66.8 million compared to $58.8 million for the same period in the prior year, an increase of $8.0 million, or 13.5%. 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 and the acquisition of Lost Creek and Post Rock in the second quarter of 2015.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

The following table presents selected operating performance metrics for the periods presented (unaudited):


	Six months ended June 30,
	2015		2014		Change			% Change
Proportional MWh sold		2,131,323		1,315,909		815,414			62.0	%
Average realized electricity price per MWh	$	80	$	98	$	(18	)		-18.4	%

Proportional MWh sold and average realized electricity price. Our proportional MWh sold for the six months ended June 30, 2015 was 2,131,323 MWh, as compared to 1,315,909 MWh for the six months ended June 30, 2014, an increase of 815,414, or 62.0%. This increase in proportional MWh sold was primarily attributable to the commencement of commercial operations at both Panhandle 1 and El Arrayán in June 2014 and Panhandle 2 at various times in 2014, and the acquisition of Lost Creek and Post Rock in the second quarter 2015. Our average realized electricity price was approximately $80 per MWh for the first six months of 2015 as compared to approximately $98 per MWh for the first six months of 2014. The $18 per MWh decrease in the average realized electricity price was due to lower PPA pricing related to Panhandle 1 and Panhandle 2 projects and the impact on foreign exchange on revenue denominated in the Canadian dollar at St. Joseph, partially offset by higher PPA pricing related to El Arrayán, South Kent, and Grand. Low wind levels in the first six months of 2015 resulted in a 15% negative variance in our production compared to our long-term expectation after adjusting for certain production losses, which are unrelated to wind and are compensated by contractual counterparties.

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


	Six months ended June 30,
	2015			2014			$ Change			% Change
Revenue	$	149,537		$	114,556		$	34,981			30.5	%

Project expense		53,227			32,774			20,453			62.4	%
Depreciation and accretion		63,398			42,461			20,937			49.3	%

Total cost of revenue		116,625			75,235			41,390			55.0	%

Gross profit		32,912			39,321			(6,409	)		-16.3	%

General and administrative		15,091			10,191			4,900			48.1	%
Related party general and administrative		3,429			2,663			766			28.8	%

Total operating expenses		18,520			12,854			5,666			44.1	%

Operating income		14,392			26,467			(12,075	)		-45.6	%
Total other expense		(27,937	)		(39,166	)		11,229			-28.7	%

Net loss before income tax		(13,545	)		(12,699	)		(846	)		6.7	%
Tax provision		2,857			2,033			824			40.5	%

Net loss		(16,402	)		(14,732	)		(1,670	)		11.3	%
Net loss attributable to noncontrolling interest		(10,820	)		(11,042	)		222			-2.0	%

Net loss attributable to controlling interest	$	(5,582	)	$	(3,690	)	$	(1,892	)		51.3	%

Adjusted EBITDA	$	113,564		$	96,043		$	17,521			18.2	%

Revenue. Revenue for the six months ended June 30, 2015 was $149.5 million as compared to $114.6 million for the six months ended June 30, 2014, an increase of $35.0 million, or 30.5%. This increase in revenue was primarily attributable to increased electricity sales due to the commencement of commercial operations at El Arrayán, Panhandle 1 and Panhandle 2 at various times in 2014 and the acquisition of Lost Creek and Post Rock in the second quarter of 2015.

In addition, unrealized loss on the valuation of the Gulf energy derivative in the first six months of 2015 decreased $11.3 million in the first six months of 2015 compared to the first six months of 2014 and energy derivative settlements increase $5.4 million in the first six months of 2015 compared to the first six months of 2014. The value of our energy derivative, and the amount of unrealized gain or loss we record, increases and decreases due to our monthly derivative settlements and changes in forward electricity prices, which are derived from and impacted by changes in forward natural gas prices.

Cost of revenue. Cost of revenue for the six months ended June 30, 2015 was $116.6 million as compared to $75.2 million for the six months ended June 30, 2014, an increase of $41.4 million, or 55.0%. The increase in cost of revenue was primarily attributable to the commencement of commercial operations at Panhandle 1, Panhandle 2, and El Arrayán at various times in 2014 and Lost Creek and Post Rock in the second quarter of 2015. 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 six months ended June 30, 2015 were $18.5 million as compared to $12.9 million for the six months ended June 30, 2014, an increase of $5.7 million, or 44.1%. The increase in operating expenses was primarily attributable to increases in general and administrative expense to support new projects acquired in 2014 and 2015, and increases in acquisition-related activity in the first six months of 2015.

Other expense. Other expense for the six months ended June 30, 2015 was $27.9 million compared to $39.2 million for the six months ended June 30, 2014, a decrease of $11.2 million, or 28.7%. The decrease in other expense was primarily attributable to a $26.9 million favorable variance between equity in earnings from unconsolidated investments of $10.7 million in the first six months of 2015 and equity in losses from unconsolidated investments of $16.2 million in the first six months of 2014, which is primarily a result of unrealized gains from the valuation of interest rate derivatives on the unconsolidated investees’ financial statements. In addition, we recorded a $2.7 million unrealized gain on derivatives in the first six months of 2015 compared to a $6.7 million loss in the first six months of 2014 primarily related to the valuation of interest rate derivatives at Ocotillo. The changes in unrealized gains and losses on interest rate derivatives were due to an increase in the forward interest rate curve in the first six months of 2015 compared to a decrease in the forward interest rate curve in the first six months of 2014. Offsetting these decreases to other expense was the absence of a $18.0 million gain recorded in net gain on transactions in the first six months of 2014 related to our acquisition of an additional 38.5% interest in the El Arrayán project. In addition, interest expense increased by $6.4 million primarily related to debt at El Arrayán and Lost Creek and the revolving credit facility in the second quarter of 2015, partially offset by a decrease in interest expense at Ocotillo due to the repricing of the debt in the fourth quarter of 2014.

Tax provision. The tax provision was $2.9 million for the six months ended June 30, 2015 compared to $2.0 million for the six months ended June 30, 2014, an increase of $0.9 million, or 40.5%. The tax provision for the first six months of 2015 was attributable to the recognition of deferred tax liabilities on equity earnings in unconsolidated investments at South Kent, Grand, and K2, tax expense at our Canadian and Puerto Rican operations, and foreign withholding taxes on intercompany transactions in certain foreign jurisdictions, partially offset by the recognition of a deferred tax asset on losses at El Arrayán. The expense provision for the first six months of 2014 was related to the fair value re-measurement of our initial 31.5% interest in El Arrayán, partially offset by the recognition of equity in losses in unconsolidated investments, which were primarily related to undesignated interest rate derivatives.

Net loss attributable to noncontrolling interest. The net loss attributable to noncontrolling interest was $10.8 million for the six months ended June 30, 2015 compared to $11.0 million for the six months end June 30, 2014, a decrease of $0.2 million, or 2.0%. The increase in net loss attributable to noncontrolling interest was primarily related to a decrease in unrealized loss on energy derivative and a $5.4 million increase in derivative hedge settlements at Gulf Wind in the first six months of 2015 compared to the first six months of 2014. 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 and Lost Creek and Post Rock, both of which were acquired in the second quarter of 2015.

Adjusted EBITDA. Adjusted EBITDA for the six months ended June 30, 2015 was $113.6 million compared to $96.0 million for the same period in the prior year, an increase of $17.5 million, or 18.2%. 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 and the acquisitions of Lost Creek and Post Rock in the second quarter of 2015. In addition, we recorded an increase of $5.4 million in energy derivative settlements at Gulf in the first six months of 2015 compared to the first six months of 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 June 30, 2015 and December 31, 2014, our available liquidity was as follows (in millions):


	June 30, 2015		December 31, 2014
Unrestricted cash	$	82.9	$	101.7
Restricted cash		43.4		47.7
Revolver availability		50.7		254.9
Project facilities:
Post construction use		97.9		90.5
Construction use		203.1		188.4

	$	478.0	$	683.2

We believe that throughout 2015 and 2016, we will have sufficient liquid assets, cash flows from operations, borrowings available under our revolving credit facility as well as funds provided by tax equity investors, 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. Below is a summary of our cash flows for each period (in millions):


	June 30, 2015			June 30, 2014
Net cash provided by operating activities	$	48.6		$	60.8
Net cash (used in) provided by investing activities		(593.5	)		(162.0	)
Net cash provided by (used in) financing activities		528.8			231.4
Effect of exchange rate changes		(2.6	)		0.3

Net change in cash and cash equivalents	$	(18.7	)	$	130.5

Net Cash Provided by Operating Activities

Net cash provided by operating activities was $48.6 million for the six months ended June 30, 2015 as compared to $60.8 million for the six months ended June 30, 2014, a decrease of $12.2 million, or 20.1%. This is primarily related to decreases in electricity production attributable to lower wind levels across the western United States and Texas, partially offset by additional electricity revenue from commercial operations at Panhandle 1, El Arrayán, Panhandle 2, which commenced operations at various times in 2014, and Lost Creek, which was acquired in the second quarter of 2015.

Net Cash (Used in) Provided by Investing Activities

Net cash used in investing activities was $593.5 million for the six months ended June 30, 2015, consisted primarily of $404.4 million of acquisitions, net of cash acquired, which includes $238.5 million for both Lost Creek and Post Rock, $37.5 million for Fowler Ridge and $128.4 million for an unconsolidated investment in K2, in addition to, $216.5 million for capital expenditures, including $195.6 million related to the construction at Logan’s Gap and Fowler Ridge. These increases were partially offset by $13.8 million of distributions from unconsolidated investments. Net cash used in investing activities was $162.0 million for the six months ended June 30, 2014, which consisted primarily of $163.6 million used to acquire Panhandle 1 and a 38.5% interest in El Arrayán, net of acquired cash.

Net Cash Provided by (Used in) Financing Activities

Net cash provided by financing activities for the six months ended June 30, 2015 was $528.8 million, which consisted of $250.0 million drawn from our revolving credit facility, proceeds of $206.2 million from construction debt related Logan’s Gap and Fowler Ridge, $196.9 million of net proceeds from our February 2015 equity offering, net of expenses, partially offset by $39.2 million of dividend payments, $50.0 million repayment of our revolving credit facility, and $25.4 million in repayments of debt. Net cash provided by financing activities for the six months ended June 30, 2014 was $231.4 million, which consisted of $287.9 million of net proceeds from our May 2014 equity offering, net of expenses, and a $4.7 million net decrease in restricted cash at our Santa Isabel project, offset by $22.2 million of dividend payments and $36.9 million of loan repayments.

Cash Available for Distribution

Cash available for distribution was $28.0 million for the three months ended June 30, 2015 as compared to $16.1 million for the three months ended June 30, 2014, an increase of $11.9 million, or 74.3%. This increase was primarily due to additional electricity sales from the commencement of commercial operations at Panhandle 1, El Arrayán, and Panhandle 2 at various times in 2014 and the acquisition of Lost Creek and Post Rock in the second quarter of 2015. In addition, we received a $7.8 million cash distribution from unconsolidated investments during the three months ended June 30, 2015 compared to the same period in the prior year. Cash available for distribution was also impacted by a $1.9 million increase in energy derivative settlements. These increases to cash available for distribution are partially offset by increases in project expenses of $11.3 million, operating expenses of $2.8 million and interest expense of $3.1 million, primarily from the commencement of operations at Panhandle 1, El Arrayán and Panhandle 2, and the acquisition of Lost Creek and Post Rock.

Cash available for distribution was $37.3 million for the six months ended June 30, 2015 as compared to $33.9 million for the same period in the prior year, an increase of $3.4 million, or 9.1%. This increase was primarily due to additional electricity sales from the commencement of commercial operations at Panhandle 1, El Arrayán, and Panhandle 2 at various times in 2014 and the acquisitions of Lost Creek and Post Rock in the second quarter of 2015. In addition, we received a $13.8 million cash distribution from unconsolidated investments in the first six months of 2015 compared to none in the first six months of 2014. Cash available for distribution was also impacted by a $5.4 million increase in energy derivative settlements. These increases were partially offset increases in project expenses of $20.5 million, operating expenses of $5.7 million, interest expense of $6.4 million and principal payments from operating cash of $3.3 million, primarily from the commencement of operations at Panhandle 1, El Arrayán and Panhandle 2, and the acquisition of Lost Creek and Post Rock.

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 July 21, 2015, we increased our dividend to $0.3630 per share, or $1.452 per share on an annualized basis, commencing with respect to dividends paid on October 30, 2015 to holders of record on September 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:

Third Quarter

0.3630

July 21, 2015

September 30, 2015

October 30, 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 the remainder of 2015, we expect to make capital expenditures of $181.4 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 payments to Pattern Development in the amount of $37.5 million in connection with the Amazon Wind Farm (Fowler Ridge) acquisition, $128.0 million in connection with the K2 acquisition and $242.0 million to unrelated third parties to acquire Lost Creek Wind and Post Rock Wind. In addition, in July 2015, we acquired the noncontrolling interests in the Gulf Wind project for $85.8 million and acquired 100% of the Class A membership interests in Lost Creek Wind Holdco for approximately $35.2 million.

Although we have no commitments to make any acquisitions, 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.

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 and six months ended June 30, 2015, the effect of this change reduced depreciation expense by $3.7 million and $7.3 million, respectively, increased net income (loss) by $3.5 million and $6.9 million, net of tax, respectively, and increased Class A basic and diluted earnings per share by $0.03 for the three months ended June 30, 2015 and decreased Class A basic and diluted loss per share by $0.05 for the six months ended June 30, 2015.

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 10, Long-term Debt, and Note 20, 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 June 30, 2015 (in thousands):


						Our Portion of
	Total		Percentage of			Unconsolidated
	Project Debt		Ownership			Project Debt
South Kent	$	518,231		50.0	%	$	259,116
Grand		281,979		45.0	%		126,891
K2		577,845		33.3	%		192,610

Unconsolidated investments - debt	$	1,378,055				$	578,617

Off-Balance Sheet Arrangements

As of June 30, 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 income (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 167,368 MWh of electricity sales during the six months ended June 30, 2015 that were not subject to power sale agreements and were subject to spot market pricing. A hypothetical increase or decrease of $4.44 per MWh (or an approximately 10% change) in these spot market prices would have increased or decreased consolidated net loss by $0.7 million for the six months ended June 30, 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 $0.3 million for the six months ended June 30, 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 six months ended June 30, 2015, our financial results included C$14.7 million in net income 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 increased or decreased consolidated net loss by $3.4 million for the six months ended June 30, 2015.

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 June 30, 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 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2015. There have been no material changes in our risk factors as described in such documents, 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.

Risks Related to Our Financial Activities

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

Our consolidated indebtedness, including the revolving credit facility, as of June 30, 2015 is approximately $2.0 billion, or approximately 57.0% of our total capitalization of $3.5 billion at such date. In addition, on July 28, 2015, we consummated the sale of $225.0 million aggregate principal amount of our 4.00% Convertible Senior Notes due 2020, or the notes. In addition, we have granted the initial purchasers of the notes offering a 30-day option to purchase up to an additional $33.8 million aggregate principal amount of notes solely to cover over-allotments, if any. Despite our current consolidated debt levels, we or our subsidiaries may still incur substantially more debt or take other actions which would intensify the risks discussed.

Approximately $756.3 million of our consolidated indebtedness as of June 30, 2015 represents project-level debt that matures through 2021. We do not have available cash or short-term liquid investments sufficient to repay all of this medium-term indebtedness and we have not obtained commitments for refinancing this debt. Therefore, we may not be able to extend the maturity of this indebtedness or to otherwise successfully refinance current maturities if the project finance markets deteriorate substantially or we choose not to raise corporate-level debt in place of project-level debt. Refinancing such indebtedness may force us to accept then-prevailing market terms that are less favorable than the existing indebtedness. If, for any reason, we are unable to refinance the existing indebtedness, those projects may be in default of their existing obligations, which may result in a foreclosure on the project collateral and loss of the project. Any such events could have a material adverse effect on our business, financial condition and results of operations.

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

•

failure to comply with the covenants in the agreements governing these obligations could result in an event of default under those agreements, which could be difficult to cure, or result in our bankruptcy;

•

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

•

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

•

our substantial debt service obligations make us vulnerable to adverse changes in general economic, credit and capital markets, industry and competitive conditions and adverse changes in government regulation and place us at a disadvantage compared with competitors with less debt.

Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. If we do not comply with our obligations under our debt instruments, we may be required to refinance all or part of our existing debt, borrow additional amounts or sell securities, which we may not be able to do on favorable terms or at all. In addition, increases in interest rates and changes in debt covenants may reduce the amounts that we can borrow, reduce our cash flows and increase the equity investment we may be required to make to complete construction of our projects. These increases could cause some of our projects to become economically unattractive. If we are unable to raise additional capital or generate sufficient operating cash flow to repay our indebtedness, we could be in default under our lending agreements and could be required to delay construction of our wind power projects, reduce overhead costs, reduce the scope of our projects or abandon or sell some or all of our projects, all of which could have a material adverse effect on our business, financial condition and results of operations.

The conditional conversion feature of the notes we have issued, if triggered, may adversely affect our financial condition and operating results.

The notes we issued in July 2015 have a conditional conversion feature. In the event the conditional conversion feature of the notes is triggered, holders of notes will be entitled to convert the notes at any time during specified periods at their option. If one or more holders elect to convert their notes, unless we elect to satisfy our conversion obligation by delivering solely our Class A shares (other than paying cash in lieu of delivering any fractional share), we would be required to settle a portion or all of our conversion obligation through the payment of cash, which could adversely affect our liquidity. In addition, even if holders do not elect to convert their notes, we could be required under applicable accounting rules to reclassify all or a portion of the outstanding principal of the notes as a current rather than long-term liability, which would result in a material reduction of our net working capital.

The accounting method for convertible debt securities that may be settled in cash, such as the notes we issued in July 2015, could have a material effect on our reported financial results.

FASB ASC Subtopic 470-20 (“FASB ASC 470-20”), Debt with Conversion and Other Options, could require an entity to separately account for the liability and equity components of convertible debt instruments (such as the notes) that may be settled entirely or partially in cash upon conversion in a manner that reflects the issuer’s non-convertible debt interest rate. Accordingly, the equity component of the notes we issued in July 2015 may be required to be included in the additional paid-in capital section of shareholders’ equity on our consolidated balance sheet at the issuance date, and the value of the equity component is treated as original issue discount for purposes of accounting for the debt component of the notes. As a result, we may be required to recognize a greater amount of non-cash interest expense in our consolidated income statements in the current and future periods presented as a result of the amortization of the discounted carrying value of the notes to their principal amount over the term of the notes. We may report lower net income (or greater net losses) in our consolidated financial results because FASB ASC 470-20 will require interest to include both the current period’s amortization of the original issue discount and the instrument’s cash coupon. This could adversely affect our reported or future consolidated financial results, the trading price of our Class A shares and the trading price of the notes.

In addition, under certain circumstances, in calculating earnings per share, convertible debt instruments (such as the notes) that may be settled entirely or partly in cash are currently accounted for utilizing the treasury stock method, the effect of which is that our Class A shares issuable upon conversion of the notes, if any, are not included in the calculation of diluted earnings per share except to the extent that the conversion value of the notes exceeds their principal amount. Under the treasury stock method, diluted earnings per share is calculated as if the number of our Class A shares that would be necessary to settle such excess, if we elected to settle such excess in shares, were issued. We cannot be sure that the accounting standards will in the future continue to permit the use of the treasury stock method. If we are unable to use the treasury stock method in accounting for the shares issuable upon conversion of the notes, if any, then our diluted consolidated earnings per share would be adversely affected.

Provisions in the indenture for the notes we issued in July 2015 may deter or prevent a business combination that may be favorable to you.

If a fundamental change occurs prior to the maturity date of the notes we issued in July 2015, holders of the notes will have the right, at their option, to require us to repurchase all or a portion of their notes. In addition, if a make-whole fundamental change occurs prior to the maturity date of the notes, we will in some cases be required to increase the conversion rate for a holder that elects to convert its notes in connection with such make-whole fundamental change. Furthermore, the indenture for the notes prohibits us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity assumes our obligations under the notes and the indenture. These and other provisions in the indenture for such notes could deter or prevent a third party from acquiring us even when the acquisition may be favorable to you.

Risks Related to Our Projects

Our operations are subject to numerous environmental, health and safety laws and regulations.

Our projects are subject to numerous environmental, health and safety laws and regulations in each of the jurisdictions in which our projects operate or will operate. These laws and regulations require our projects to obtain and maintain permits and approvals, undergo environmental impact assessments and review processes and implement environmental, health and safety programs and procedures to control risks associated with the siting, construction, operation and decommissioning of power projects. For example, to obtain permits some projects are, in certain cases, required to undertake programs to protect and maintain local endangered or threatened species. If such programs are not successful, our projects could be subject to increased levels of mitigation, penalties or revocation of our permits.

Violations of environmental and other laws, regulations and permit requirements, including certain violations of laws protecting wetlands, migratory birds, bald and golden eagles and threatened or endangered species, may also result in criminal sanctions or injunctions. In addition, if our projects do not comply with applicable laws, regulations or permit requirements, or if there are endangered or threatened species fatalities at our projects, we may be required to pay penalties or fines or curtail or cease operations of the affected projects. For example, in connection with a permit we obtained at our Spring Valley wind facility, we had to adopt a mitigation plan with respect to injuries and fatalities to golden eagles, and were required to establish a process in the event of incidents, including reporting to the U.S. Fish and Wildlife Service. We have followed such required processes in connection with three golden eagle incidents since January 1, 2013, and, in addition, we have filed an application for an eagle take permit which is under consideration by the U.S. Fish and Wildlife Service. No assurances can be given that our application for an eagle take permit will be approved, or that we will not be required to implement increased levels of mitigation, or face penalties, fines, or other measures as a result of prior or future golden eagle incidents at our Spring Valley facility or any of our other wind facilities.

Certain environmental laws impose liability on current and previous owners and operators of real property for the cost of removal or remediation of hazardous substances, even if the owner or operator did not know of, or was not responsible for, the release of such hazardous substances. In addition to actions brought by governmental agencies, private plaintiffs may also bring claims arising from the presence of hazardous substances on a property or exposure to such substances. Our projects’ liabilities at properties we own or operate arising from past releases of, or exposure to, hazardous substances could have a material adverse effect on our business, financial condition and results of operations.

Environmental, health and safety laws, regulations and permit requirements may change or become more stringent. Any such changes could require our projects to incur additional material costs or cause our projects to suffer adverse consequences. For example, the Ministry of Environment in Ontario has established regulatory requirements governing noise restrictions for wind farms which are an integral part of the permitting framework for our projects in that jurisdiction. In the event of changes in either the regulatory requirements or permitting framework, there is risk that our projects that were designed for compliance within the existing framework and requirements for noise could still be evaluated by regulators as noncompliant. These risks are enhanced because testing for compliance with noise requirements is technically complex, carries some degree of uncertainty, and does not have significant precedent in that market. In the event of a determination of noncompliance, there is risk that the necessary mitigation, which would likely need to occur during periods of higher wind speeds, could require curtailment of energy production at the facility, with a resulting reduction in revenues.

Our projects’ costs of complying with current and future environmental, health and safety laws, regulations and permit requirements (including any change in noise regulations), and any liabilities, fines or other sanctions resulting from violations of them, could have a material adverse effect on our business, financial condition and results of operations.

ITEM 6. EXHIBITS


Exhibit No.		Description

2.1		Purchase and Sale Agreement, by and between Pattern Energy Group Inc., Pattern Renewables Development Company LLC, and (as guarantor for certain obligations) Pattern Energy Group LP dated April 29, 2015 (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed May 4, 2015).

2.2		Purchase and Sale Agreement, by and between Wind Capital Group, LLC, Lincoln County Wind Project Finco, LLC and Pattern Energy Group Inc., dated April 1, 2015 (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed May 18, 2015).

2.3		Purchase and Sale Agreement between Pattern Canada Finance Company ULC and Pattern Energy Group LP dated April 4, 2015 (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed June 22, 2015).

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)).

4.2		Indenture, dated July 28, 2015, among Pattern Energy Group Inc., as issuer, Pattern US Finance Company LLC, as subsidiary guarantor, and Deutsche Bank Trust Company Americas, as trustee, related to 4.00% Convertible Senior Notes due 2020 (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 28, 2015).

10.1		Employment Agreement between Pattern Energy Group Inc. and Michael J. Lyon dated October 2, 2013 (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed May 7, 2015).

10.2		First Amendment to Bilateral Management Services Agreement between Pattern Energy Group Inc. and Pattern Energy Group LP dated July 3, 2015 (Incorporated by reference to the Exhibit 10.1 to the Company’s Current Report on Form 8-K filed July 7, 2015).

10.3		Purchase Agreement between Pattern Gulf Wind Equity 2 LLC, as seller, and Pattern Gulf Wind Equity LLC, as buyer, dated July 20, 2015 (Incorporated by reference to the Exhibit 10.1 to the Company’s Current Report on Form 8-K filed July 21, 2015).

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.

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