Pattern Energy Group Inc. - FORM 10-Q

Pattern Energy Group Inc. - FORM 10-Q - August 5, 2014

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Attached files

Pattern Energy Group Inc. Reports

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EXCEL - IDEA: XBRL DOCUMENT - Pattern Energy Group Inc.	Financial_Report.xls
EX-31.2 - EX-31.2 - Pattern Energy Group Inc.	d745733dex312.htm
EX-32 - EX-32 - Pattern Energy Group Inc.	d745733dex32.htm
EX-31.1 - EX-31.1 - Pattern Energy Group Inc.	d745733dex311.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, 2014.

¨	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 July 28, 2014, there were 46,511,899 shares of Class A common stock outstanding, $0.01 par value, and 15,555,000 shares of Class B common stock outstanding, $0.01 par value.

PATTERN ENERGY GROUP INC.

REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2014

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	5
	Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	5
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013	6
	Consolidated Statements of Comprehensive Loss for the Three and Six Months Ended June 30, 2014 and 2013	7
	Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2014	8
	Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	9
	Notes to Consolidated Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	40

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 6.	Exhibits	44
	Signatures	45

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

•

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

•

our ability to complete the acquisition of power projects;

•

fluctuations in supply, demand, prices and other conditions for electricity, other commodities and RECs;

•

our electricity generation, our projections thereof and factors affecting production, including wind and other conditions, other weather conditions, availability and curtailment;

•

changes in law, including applicable tax laws;

•

public response to and changes in the local, state, provincial and federal regulatory framework affecting renewable energy projects, including the potential expiration or extension of the U.S. federal PTC, ITC, and the related U.S. Treasury grants 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 wind 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;

•

our expectations regarding the time during which we will be an emerging growth company under the Jumpstart Our Business Startups (“JOBS”) Act;

•

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, currency exchange rate fluctuations and general economic conditions;

•

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, 2013.

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,
	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	234,038		$	103,569
Trade receivables		40,620			20,951
Related party receivable		759			167
Reimbursable interconnection costs		38			1,455
Derivative assets, current		12,449			13,937
Current deferred tax assets		573			573
Prepaid expenses and other current assets		10,913			13,927

Total current assets		299,390			154,579
Restricted cash		44,387			32,636
Property, plant and equipment, net of accumulated depreciation of $223,144 and $179,778 as of June 30, 2014 and December 31, 2013, respectively		2,105,937			1,476,142
Unconsolidated investments		65,353			107,055
Derivative assets		54,808			82,167
Deferred financing costs, net of accumulated amortization of $19,059 and $16,225 as of June 30, 2014 and December 31, 2013, respectively		33,533			35,792
Net deferred tax assets		6,889			2,017
Other assets		13,673			13,243

Total assets	$	2,623,970		$	1,903,631

Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities	$	23,523		$	15,550
Accrued construction costs		21,670			3,204
Related party payable		918			1,245
Accrued interest		2,273			495
Dividend payable		15,071			11,103
Derivative liabilities, current		17,804			16,171
Current portion of long-term debt		58,896			48,851

Total current liabilities		140,155			96,619
Long-term debt		1,377,159			1,200,367
Derivative liabilities		11,846			7,439
Asset retirement obligations		26,394			20,834
Net deferred tax liabilities		22,523			9,930
Other long-term liabilities		2,059			438

Total liabilities		1,580,136			1,335,627

Equity:
Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 46,525,818 and 35,531,720 shares issued as of June 30, 2014 and December 31, 2013, respectively; 46,522,980 and 35,530,786 shares outstanding as of June 30, 2014 and December 31, 2013, respectively		465			355
Class B common stock, $0.01 par value per share: 20,000,000 shares authorized; 15,555,000 shares issued and outstanding as of June 30, 2014 and December 31, 2013		156			156
Additional paid-in capital		752,501			489,412
Accumulated loss		(17,026	)		(13,336	)
Accumulated other comprehensive loss		(24,795	)		(8,353	)
Treasury stock, at cost; 2,838 and 934 shares of Class A common stock as of June 30, 2014 and December 31, 2013, respectively		(79	)		(24	)

Total equity before noncontrolling interest		711,222			468,210
Noncontrolling interest		332,612			99,794

Total equity		1,043,834			568,004

Total liabilities and equity	$	2,623,970		$	1,903,631

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,
	2014			2013			2014			2013
Revenue:
Electricity sales	$	66,053		$	47,351		$	119,924		$	92,583
Energy derivative settlements		3,983			4,809			6,718			10,217
Unrealized loss on energy derivative		(6,549	)		(5,078	)		(14,282	)		(11,881	)
Related party revenue		1,017			263			1,462			263
Other revenue		503			11,367			734			11,367

Total revenue		65,007			58,712			114,556			102,549

Cost of revenue:
Project expense		16,700			14,492			32,774			27,469
Depreciation and accretion		21,284			17,998			42,461			40,564

Total cost of revenue		37,984			32,490			75,235			68,033

Gross profit		27,023			26,222			39,321			34,516

Operating expenses:
General and administrative		6,288			205			10,191			349
Related party general and administrative		1,383			2,699			2,663			5,361

Total operating expenses		7,671			2,904			12,854			5,710

Operating income		19,352			23,318			26,467			28,806

Other income (expense):
Interest expense		(15,807	)		(16,832	)		(30,428	)		(33,474	)
Equity in (losses) earnings in unconsolidated investments		(3,688	)		13,368			(16,236	)		3,343
Interest rate derivative settlements		(1,035	)		—			(2,052	)		—
Unrealized (loss) gain on derivatives		(2,942	)		8,202			(6,665	)		10,133
Related party income		376			—			1,072			—
Net gain on transactions		14,537			7,200			14,537			7,200
Other income, net		439			1,044			606			1,802

Total other (expense) income		(8,120	)		12,982			(39,166	)		(10,996	)

Net income (loss) before income tax		11,232			36,300			(12,699	)		17,810
Tax provision (benefit)		4,065			(7,688	)		2,033			(7,394	)

Net income (loss)		7,167			43,988			(14,732	)		25,204
Net loss attributable to noncontrolling interest		(4,032	)		(359	)		(11,042	)		(3,938	)

Net income (loss) attributable to controlling interest	$	11,199		$	44,347		$	(3,690	)	$	29,142

Weighted average number of shares:
Class A common stock - Basic		41,174,697						38,331,595
Class A common stock - Diluted		57,065,219						54,214,953
Class B common stock - Basic and diluted		15,555,000						15,555,000
Earnings (loss) per share
Class A common stock:
Basic earnings per share	$	0.30					$	0.13

Diluted earnings (loss) per share	$	0.20					$	(0.07	)

Class B common stock:
Basic and diluted loss per share	$	(0.07	)				$	(0.55	)

Cash dividends declared per Class A common share	$	0.32					$	0.63

2013 pro forma information:
Unaudited pro forma net income after tax:
Net income before income tax										$	17,810
Pro forma tax provision											674

Pro forma net income										$	17,136

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Consolidated Statements of Comprehensive Loss

(In thousands of U.S. Dollars)

(Unaudited)


	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Net income (loss)	$	7,167		$	43,988		$	(14,732	)	$	25,204

Other comprehensive (loss) income:
Foreign currency translation, net of tax impact of $0, $0, $0 and $0, respectively		4,221			(3,836	)		(869	)		(7,327	)
Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax benefit of $29, $0, $29 and $0, respectively		(2,161	)		23,021			(4,912	)		30,946
Reclassifications to net income (loss), net of tax impact of $0, $0, $0 and $0, respectively		(3,386	)		(2,754	)		(6,557	)		(5,359	)

Total change in effective portion of change in fair market value of derivatives		(5,547	)		20,267			(11,469	)		25,587
Proportionate share of equity investee’s other comprehensive (loss) income activity, net of tax benefit (provision) of $560, ($315), $1,805 and ($334), respectively		(1,205	)		1,258			(4,283	)		1,601

Total other comprehensive (loss) income, net of tax		(2,531	)		17,689			(16,621	)		19,861

Comprehensive income (loss)		4,636			61,677			(31,353	)		45,065

Less comprehensive (loss) income attributable to noncontrolling interest:
Net loss attributable to noncontrolling interest		(4,032	)		(359	)		(11,042	)		(3,938	)
Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax impact of $0, $0, $0 and $0, respectively		614			3,333			1,537			4,524
Reclassifications to net loss, net of tax impact of $0, $0, $0 and $0, respectively		(887	)		(487	)		(1,716	)		(948	)

Total change in effective portion of change in fair market value of derivatives		(273	)		2,846			(179	)		3,576

Comprehensive (loss) income attributable to noncontrolling interest		(4,305	)		2,487			(11,221	)		(362	)

Comprehensive income (loss) attributable to controlling interest	$	8,941		$	59,190		$	(20,132	)	$	45,427

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Consolidated Statements of Stockholders’ Equity

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

(Unaudited)


	Controlling Interest																								Noncontrolling Interest
																			Accumulated												Accumulated
										Additional						Accumulated			Other									Accumulated			Other
	Class A Common Stock					Class B Common Stock				Paid-in						Income			Comprehensive									Income			Comprehensive						Total
	Shares			Amount		Shares		Amount		Capital			Capital			(Deficit)			Income (Loss)			Total			Capital			(Deficit)			Income (Loss)			Total			Equity
Balances at January 1, 2013		100		$	—		—	$	—	$	1		$	545,471		$	2,903		$	(34,264	)	$	514,111		$	74,177		$	12,366		$	(11,242	)	$	75,301		$	589,412
Contribution		—			—		—		—		—			32,677			—			—			32,677			—			—			—			—			32,677
Distribution		—			—		—		—		—			(104,634	)		—			—			(104,634	)		(1,426	)		—			—			(1,426	)		(106,060	)
Additional paid-in capital		—			—		—		—		2			—			—			—			2												—			2
Net income (loss)		—			—		—		—		—			—			30,295			—			30,295			—			(690	)		—			(690	)		29,605
Other comprehensive income, net of tax		—			—		—		—		—			—			—			20,633			20,633			—			—			3,559			3,559			24,192

Balances at October 1, 2013		100			—		—		—		3			473,514			33,198			(13,631	)		493,084			72,751			11,676			(7,683	)		76,744			569,828
Interest in Gulf Wind retained by Pattern Development		—			—		—		—		—			(18,332	)		(13,122	)		2,870			(28,584	)		18,332			13,122			(2,870	)		28,584			—
Assumption of liabilities related to Contribution Transactions		—			—		—		—		—			(4,207	)		—			—			(4,207	)		—			—			—			—			(4,207	)
Issuance of common stock for Contribution Transactions		19,445,000			194		15,555,000		156		470,701			(450,975	)		(20,076	)		—			—			—			—			—			—			—
Deemed distribution for Contribution Transactions		—			—		—		—		(232,640	)		—			—			—			(232,640	)											—			(232,640	)
Issuance of Class A common stock related to the IPO, net of issuance costs		16,000,000			160		—		—		316,882			—			—			—			317,042			—			—			—			—			317,042
Issuance of Class A restricted common stock		83,183			1		—		—		155			—			—			—			156			—			—			—			—			156
Issuance of Class A common stock		3,437			—		—		—		93			—			—			—			93						—			—			—			93
Repurchase of shares for employee tax withholding		(934	)		—		—		—		(24	)		—			—			—			(24	)		—			—			—			—			(24	)
Stock-based compensation		—			—		—		—		263			—			—			—			263			—			—			—			—			263
Dividends declared on Class A common stock		—			—		—		—		(11,103	)		—			—			—			(11,103	)		—			—			—			—			(11,103	)
Acquisition from Pattern Development		—			—		—		—		(54,942	)		—			—			(2,910	)		(57,852	)		—			—			—			—			(57,852	)
Distribution to noncontrolling interest		—			—		—		—		—			—			—			—			—			(866	)		—			—			(866	)		(866	)
Net loss		—			—		—		—		—			—			(13,336	)		—			(13,336	)		—			(6,197	)		—			(6,197	)		(19,533	)
Other comprehensive income, net of tax		—			—		—		—		—			—			—			5,318			5,318			—			—			1,529			1,529			6,847

Balances at December 31, 2013		35,530,786		$	355		15,555,000	$	156	$	489,388		$	—		$	(13,336	)	$	(8,353	)	$	468,210		$	90,217		$	18,601		$	(9,024	)	$	99,794		$	568,004
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
Issuance of Class A restricted common stock		173,287			2		—		—		1,868			—			—			—			1,870			—			—			—			—			1,870
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		—			—		—		—		305			—			—			—			305			—			—			—			—			305
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 El 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, net of tax		—			—		—		—		—			—			—			(16,442	)		(16,442	)		—			—			(179	)		(179	)		(16,621	)

Balances at June 30, 2014		46,522,980		$	465		15,555,000	$	156	$	752,422		$	—		$	(17,026	)	$	(24,795	)	$	711,222		$	334,256		$	7,559		$	(9,203	)	$	332,612		$	1,043,834

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,
	2014			2013
Operating activities
Net (loss) income	$	(14,732	)	$	25,204
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and accretion		42,461			40,564
Amortization of financing costs		2,848			4,071
Unrealized loss on derivatives		20,947			1,748
Stock-based compensation		2,175			—
Net gain on transactions		(16,526	)		(7,200	)
Deferred taxes		2,033			(7,396	)
Equity in earnings (losses) in unconsolidated investments		16,236			(3,343	)
Changes in operating assets and liabilities:
Trade receivables		(13,895	)		(5,512	)
Reimbursable interconnection receivable		—			(904	)
Prepaid expenses and other current assets		20,253			(12,116	)
Other assets (non-current)		(305	)		(234	)
Accounts payable and other accrued liabilities		348			954
Related party receivable/payable		(1,053	)		(283	)
Income taxes payable/receivable		128			—
Accrued interest payable		(11	)		235
Long term liabilities		(85	)		5,869

Net cash provided by operating activities		60,822			41,657

Investing activities
Receipt of ITC Cash Grant		—			173,446
Cash paid for acquisitions, net of cash acquired		(163,589	)		—
Proceeds from sale of investments		—			14,254
Decrease in restricted cash		1,316			2,893
Increase in restricted cash		(2	)		(13,976	)
Capital expenditures		(544	)		(111,062	)
Deferred development costs		—			(528	)
Distribution from unconsolidated investments		—			10,463
Contribution to unconsolidated investments		(1,880	)		(6,524	)
Reimbursable interconnection receivable		1,417			(6,674	)
Other assets (non-current)		1,236			1,122

Net cash (used in) provided by investing activities		(162,046	)		63,414

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,
	2014			2013
Financing activities
Proceeds from public offering, net of expenses	$	287,943		$	—
Repurchase of shares for employee tax withholding		(55	)		—
Dividends paid		(22,170	)		—
Capital contributions - Pattern Development		—			27,018
Capital distributions - Pattern Development		—			(92,174	)
Capital distributions - noncontrolling interest		(1,470	)		(1,168	)
Decrease in restricted cash		13,508			8,763
Increase in restricted cash		(8,840	)		(116,654	)
Payment for deferred financing costs		(542	)		(257	)
Proceeds from revolving credit facility		—			56,000
Repayments of short-term debt		(14,840	)		—
Proceeds from long-term debt		—			117,987
Repayment of long-term debt		(22,096	)		(21,815	)
Repayment of construction and grant loans		—			(57,470	)

Net cash provided by (used in) financing activities		231,438			(79,770	)

Effect of exchange rate changes on cash and cash equivalents		255			(1,100	)

Net change in cash and cash equivalents		130,469			24,201
Cash and cash equivalents at beginning of period		103,569			17,574

Cash and cash equivalents at end of period	$	234,038		$	41,775

Supplemental disclosure
Cash payments for interest and commitment fees	$	26,963		$	29,710
Acquired PP&E for El Arrayan and Panhandle 1		671,068			—
Schedule of non-cash activities
Change in fair value of interest rate swaps		(20,344	)		35,636
Change in fair value of contingent liabilities		—			8,001
Capitalized interest		1,880			858
Capitalized commitment fee		—			39
Change in property, plant and equipment		(40,729	)		(145,060	)
Transfer of capitalized assets to South Kent joint venture		—			49,275
Non-cash distribution to Pattern Development		—			(3,283	)

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 are designated Class B common stock, and 100,000,000 of which are designated Preferred Stock.

Pattern Energy is an independent energy generation company focused on constructing, owning and operating energy projects with long-term energy sales contracts located in the United States, Canada and Chile. The Company consists of the consolidated operations of certain entities and assets contributed by, or purchased 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”) and Ocotillo Express LLC (“Ocotillo”). The Company owns a controlling interest in Pattern Gulf Wind Holdings LLC (“Gulf Wind”), Parque Eólico El Arrayán SpA (“El Arrayán”) and Panhandle Wind Holdings LLC (“Panhandle 1”), and noncontrolling interests in South Kent Wind LP (“South Kent”) and Grand Renewable Wind LP (“Grand”) and has agreed to acquire a controlling interest in Panhandle B Member 2 LLC (“Panhandle 2”). 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 our project portfolio.

Initial Public Offering and Contribution Transactions

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

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

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

May 2014 Public Offering

On May 14, 2014, the Company completed an underwritten public offering of its Class A common stock. In total, 21,117,171 shares of its Class A common stock were sold. Of this amount, the Company sold 10,810,810 shares of Class A common stock and Pattern Development, the selling stockholder, sold 10,306,361 shares of Class A common stock, including 2,754,413 shares upon exercise in full of the underwriters’ overallotment option. Net proceeds generated for the Company were approximately $288.7 million before deduction of transaction expenses of approximately $2.0 million. The Company did not receive any proceeds from the sale of the shares sold by Pattern Development.

As a result of the sale of the shares held by Pattern Development, its ownership interest in the Company was reduced from approximately 63% to 35%. Consequently, the Company is no longer subject to ASC 805-50-30-5, Transactions between Entities under Common Control. All future transactions with Pattern Development will be recognized at fair value on the measurement date in accordance with ASC 805 – Business Combinations.

Basis of Presentation

Pattern Energy was formed by Pattern Development for the purpose of an IPO. For periods prior to October 2, 2013, Pattern Energy was a shell company, with expenses of less than $10,000 for 2013 and 2012. In accordance with ASC 805-50-30-6, the historical financial statements of Pattern Energy’s predecessor, which consist of the combined financial statements of a combination of entities and assets contributed by Pattern Development to Pattern Energy, are consolidated with Pattern Energy from the beginning of the earliest period presented.

Unaudited Interim Financial Information

The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“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, 2014, the results of operations, comprehensive income, and cash flows for the three and six months ended June 30, 2014 and 2013, respectively. The consolidated balance sheet at December 31, 2013 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, 2013.

2.	Summary of Significant Accounting Policies

As of June 30, 2014, there have been no material changes to the Company’s significant accounting policies as compared to the significant accounting policies described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013.

Principles of Consolidation

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

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent 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.

Unaudited Pro Forma Income Tax

In order to present the tax effect of the Contribution Transactions, the Company has presented a pro forma income tax provision, for the six months ended June 30, 2014, as if the Contribution Transactions occurred effective January 1, 2012 and as if the Company were under control of a Subchapter C-Corporation for U.S. federal income tax purposes.

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 using the equity method of accounting.

For the noncontrolling interests at the Company’s Gulf Wind and Panhandle 1 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.

The following table presents the noncontrolling interest balances, reported in stockholders’ equity in the consolidated balance sheets by project as of June 30, 2014 and December 31, 2013 (in thousands):


					Percentage of Ownership
Project	June 30, 2014		December 31, 2013		June 30, 2014			December 31, 2013
Gulf Wind	$	87,257	$	99,794		60	%		60	%
El Arrayan		35,105		—		30	%		N/A
Panhandle 1		210,250		—		21	%		N/A

	$	332,612	$	99,794

Concentrations of Credit Risk

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

The Company sells electricity and environmental attributes, including renewable energy credits, primarily to creditworthy utilities and other off-takers under long-term, fixed-priced Power Sale Arrangements (“PPAs”). During the second quarter of 2014, Standard & Poor’s Rating Services (“S&P”) and Moody’s Investor Service (“Moody’s”) downgraded the credit rating of the Puerto Rico Electric Power Authority (PREPA) to BB from BBB and to Ba3 from Ba2, respectively. In July 2014, Moody’s further reduced the credit rating to Caa2 and S&P twice reduced their credit rating to CCC. As of June 30, 2014 and August 5, 2014, PREPA was current with respect to payments due under the PPA. The next payment will be due from PREPA under the PPA on approximately August 18, 2014.

The following table presents significant customers who accounted for the following percentages of total revenues during the three and six months ended June 30, 2014 and 2013, respectively:


	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Manitoba Hydro		12.76	%		14.69	%		15.98	%		16.50	%
San Diego Gas & Electric		35.25	%		13.81	%		27.98	%		16.32	%
Pacific Gas & Electric Company		8.81	%		12.32	%		11.36	%		12.78	%
Electric Reliability Council of Texas		12.26	%		13.53	%		12.47	%		12.50	%
NV Energy, Inc.		11.25	%		11.98	%		11.80	%		11.37	%
PREPA		10.20	%		5.18	%		11.11	%		7.96	%

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

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 have no effect on previously reported balance sheet subtotals, results of operations or retained earnings.

Recently Issued Accounting Standards

In June 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-12, “Compensation – Stock Compensation” which requires an entity to treat a performance target that affects vesting that could be achieved after an employee completes the requisite service period as a performance condition. The performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. ASU 2014-12 is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted either prospectively or retrospectively to all prior periods presented. The Company is currently assessing the future impact of this update on its consolidated financial statements.

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

In July 2013, the FASB issued ASU 2013-11, “Income Taxes – Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists” which requires an entity to present an unrecognized tax benefit as a reduction to a deferred tax asset in the financial statements for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in certain circumstances where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose. When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. As a result of the JOBS Act enacted in April 2012, emerging growth companies can elect to delay the adoption of new or revised accounting standards for public companies until those standards would otherwise apply to private companies and as such, ASU 2013-11 will be effective on January 1, 2015 for the Company. The Company is currently assessing the future impact of this update, but it does not anticipate a material impact on its financial condition, results of operations or cash flows.

In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” to amend the reporting of reclassifications out of accumulated other comprehensive income (“AOCI”) to require an entity to report the effect of significant reclassifications out of AOCI on the respective line items in net income if the amount reclassified is required under U.S. GAAP to be reclassified in its entirety to net income in the same reporting period. An entity shall provide this information together in one location, either on the face of the statement where net income is presented, or as a separate disclosure in the notes to the financial statements. The new disclosure requirements relating to this update are prospective and effective for interim and annual periods beginning after December 15, 2012, with early adoption permitted. For nonpublic companies, ASU 2013-02 is effective for fiscal years beginning after December 15, 2013. As a result of the JOBS Act enacted in April 2012, emerging growth companies can elect to delay the adoption of new or revised accounting standards for public companies until those standards would otherwise apply to private companies, as such, the Company adopted ASU 2013-02 on January 1, 2014. As this update only requires additional disclosures, adoption of this standard did not have a material impact on the Company’s financial condition, results of operations or cash flows. See Note 11, Accumulated Other Comprehensive Loss, for disclosures on the effect of significant reclassifications out of AOCI on the respective line items on its consolidated statements of operations.

3.	Acquisition

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. This represents a 172 MW interest in the 218 MW wind project, located in Carson County, Texas, which achieved commercial operations on June 25, 2014. Panhandle 1 is one of the Initial ROFO projects described in the Company’s S-1 Registration Statement (Registration No. 333-190538) and was acquired as part of the Company’s previously disclosed growth strategy.

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 an ownership percentage of 21%, based on their initial interest in the project’s distributable cash flow. The Company has determined that the operating partnership agreement does not allocate economic benefits pro rata to its two classes of investors and will use the HLBV method to calculate the noncontrolling interest balance that reflects the substantive profit sharing arrangement.

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

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


	June 30, 2014
Cash and cash equivalents	$	1,038
Trade receivables		1,850
Prepaid expenses and other current assets		71
Restricted cash		14,293
Property, plant and equipment		331,308
Accounts payable and other accrued liabilities		(148	)
Accrued construction costs		(11,161	)
Related party payable		(44	)
Asset retirement obligation		(2,557	)

Total consideration before non-controlling interest		334,650

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

Total consideration after non-controlling interest	$	124,400

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

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

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 $0.7 million of transaction-related expense which was recorded in net gain on transactions in the consolidated statement of operations for the three and six months ended June 30, 2014.

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 “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 that recently completed construction of its wind facility which is fully operational.

Prior to the acquisition, the Company accounted for the investment under the equity method of accounting. As 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 statement of operations for the three and six months ended June 30, 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 statement of operations. The Company now holds a 70% controlling interest in the wind project and consolidates the accounts of El Arrayán.

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

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


	June 25, 2014
Cash and cash equivalents	$	713
Trade receivables		3,829
Related party receivable		56
VAT receivable		17,031
Prepaid expenses and other current assets		174
Restricted cash		10,392
Property, plant and equipment		339,760
Intangible assets		1,121
Deferred tax assets		5,455
Accounts payable and other accrued liabilities		(6,830	)
Accrued construction costs		(8,355	)
Related party payable		(56	)
Derivative liabilities, current		(1,942	)
Current portion of long-term debt		(705	)
Short-term debt		(15,881	)
Accrued interest		(2,076	)
Long-term debt		(209,295	)
Derivative liabilities, non-current		(501	)
Asset retirement obligation		(2,354	)
Deferred tax liabilities		(13,001	)

Total consideration		117,535

Less: non-controlling interest		(35,260	)

Controlling interest	$	82,275

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.

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.

preliminary estimates that are not finalized relate to the fair value of debt for which the Company is accumulating and analyzing additional market information and the fair value of property, plant and equipment for which the Company is finalizing inputs, assumptions and methodologies.

The Company incurred $0.4 million of transaction-related expenses which were recorded in net gain on transaction expenses in the consolidated statement of operations for the three and six months ended June 30, 2014.

Supplemental pro forma data (unaudited)

The unaudited pro forma statement of operations data below gives effect to the Panhandle 1 and AEI El Arrayán acquisition as if it had occurred on January 1, 2013. 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, 2013. 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)	2014			2013			2014			2013
Pro forma total revenue	$	67,421		$	58,712		$	116,970		$	102,549
Pro forma total expenses		63,081			15,362			135,767			77,496

Pro forma net loss		4,340			43,350			(18,797	)		25,053
Less: pro forma net loss attributable to noncontrolling interest		(4,313	)		(662	)		(11,419	)		(4,074	)

Pro forma net loss attributable to controlling interest	$	8,653		$	44,012		$	(7,378	)	$	29,127

Prior to the acquisition, net loss was recorded in equity in earnings on 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 earnings on unconsolidated investments related to El Arrayán.

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,
	2014		2013
Prepaid expenses	$	5,286	$	10,132
Sales tax		2,135		50
Interconnection network upgrade receivable		2,502		2,512
Other current assets		990		1,233

Prepaid expenses and other current assets	$	10,913	$	13,927

5.	Property, Plant and Equipment

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


	June 30,			December 31,
	2014			2013
Operating wind farms	$	2,325,025		$	1,652,119
Furniture, fixtures and equipment		3,973			3,785
Land		83			16

Subtotal		2,329,081			1,655,920
Less: accumulated depreciation		(223,144	)		(179,778	)

Property, plant and equipment, net	$	2,105,937		$	1,476,142

The Company recorded depreciation expense related to property, plant and equipment of $20.9 million and $41.8 million for the three months and six months ended June 30, 2014, respectively, and recorded $17.7 million and $40.0 million of depreciation expense for the same periods in the prior year.

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

The Cash Grants received for Ocotillo, Santa Isabel and Spring Valley reduced depreciation expense recorded in the consolidated statements of operations by approximately $3.2 million and $6.3 million for the three and six months ended June 30, 2014, respectively, and reduced depreciation expense by $5.6 million and $6.6 million for the same periods in the prior year.

6.	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,
	2014		2013		2014			2013
South Kent	$	47,089	$	59,488		50.0	%		50.0	%
El Arrayán		—		21,103		N/A			31.5	%
Grand		18,264		26,464		45.0	%		45.0	%

Unconsolidated investments	$	65,353	$	107,055

On June 25, 2014, the Company increased its total ownership interest in El Arrayán to 70%. See Note 3, Acquisitions, for disclosure on the acquisition of El Arrayán. As such, the Company has consolidated the operations of El Arrayán as of the acquisition date and is no longer accounting for this investment under the equity method of accounting.

The following summarizes the aggregated operating results of the unconsolidated joint ventures for the three and six months ended June 30, 2014 and 2013, respectively (in thousands):


	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Revenue	$	27,179		$	—		$	28,696		$	—
Other (income) expense		35,139			(26,511	)		62,322			(6,787	)

Net loss	$	(7,960	)	$	26,511		$	(33,626	)	$	6,787

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 construction in September 2013.

South Kent

Significant Subsidiary – South Kent

The following table presents summarized statements of operations information as required for significant equity method investees, pursuant to Regulation S-X Rule 10-01(b)(1):


	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Revenue	$	25,358		$	—		$	26,875		$	—

Operating expenses
Assets operation		1,879			—			2,241			—
General and administrative expenses		1,614			508			1,463			894
Depreciation, amortization		8,453			12			8,830			12
Other income and expenses		(393	)		—			—			—

Operating income (loss)		13,805			(520	)		14,341			(906	)
Unrealized (loss) gain on derivatives		(8,041	)		28,282			(29,427	)		8,251
Other expense		(9,798	)		(186	)		(9,798	)		(157	)

Net (loss) income	$	(4,034	)	$	27,576		$	(24,884	)	$	7,188

7.	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,
	2014		2013
Accounts payable	$	1,298	$	168
Other accrued liabilities		9,102		7,282
Warranty settlement payments		1,455		2,187
Payroll liabilities		2,771		2,162
Property tax payable		3,394		3,490
Sales tax payable		5,503		261

Accounts payable and other accrued liabilities	$	23,523	$	15,550

8.	Long-term Debt

The Company’s long-term debt which consists of limited recourse or nonrecourse indebtedness is presented below (in thousands):


	June 30, 2014			December 31, 2013			Interest Rate as of						Interest Type	Maturity
							June 30, 2014			December 31, 2013
							June 30, 2014			December 31, 2013
Hatchet Ridge term loan	$	232,741		$	239,865			1.43	%		1.43	%	Imputed	December 2032
Gulf Wind term loan		159,024			166,448			3.23	%		3.23	%	Variable	March 2020
St. Joseph term loan		210,388			215,330			5.88	%		5.88	%	Fixed	May 2031
Spring Valley term loan		170,777			173,110			2.62	%		2.63	%	Variable	June 2030
Santa Isabel term loan		114,381			115,721			4.57	%		4.57	%	Fixed	September 2033
El Arrayán commercial term loan		100,000			—			2.90	%		N/A		Variable	March 2029
El Arrayán EKF term loan		110,000			—			5.56	%		N/A		Fixed	March 2029
Ocotillo commercial term loan		230,944			230,944			2.98	%		3.00	%	Variable	August 2020
Ocotillo development term loan		107,800			107,800			2.33	%		2.35	%	Variable	August 2033

		1,436,055			1,249,218
Less: current portion		(58,896	)		(48,851	)

	$	1,377,159		$	1,200,367

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


	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Interest and commitment fees incurred	$	13,850		$	14,655		$	27,307		$	28,720
Capitalized interest, commitment fees, and letter of credit fees		(597	)		(478	)		(1,880	)		(897	)
Letter of credit fees		1,100			814			2,153			1,580
Amortization of financing costs		1,454			1,841			2,848			4,071

Interest expense	$	15,807		$	16,832		$	30,428		$	33,474

El Arrayán

In May 2012, El Arrayán entered into a first lien senior secured credit agreement (“El Arrayán Credit Agreement”) which provides up to approximately $225.0 million in borrowings. Current borrowings under the El Arrayán Credit Agreement were used to finance the construction of the El Arrayán wind project and are comprised of a commercial tranche of up to $100.0 million and an export credit agency tranche provided by Eksport Kredit Fonden of Denmark (“EKF Tranche”) of up to $110.0 million, and letter of credit facility in an amount of up to $15.0 million. The construction loan converts into a term loan upon completion of construction of El Arrayán and certain other specified conditions. The project commenced commercial operations in June 2014 and term conversion is pending satisfaction of the remaining specified conditions. The financing is non-recourse to El Arrayán.

The commercial tranche construction and term loans are, with certain exceptions, LIBOR loans and accrue interest at LIBOR plus 2.75% per annum from the closing until the sixth anniversary of closing, 3.00% from the sixth anniversary to the tenth anniversary of

closing, 3.25% from the tenth anniversary to the fourteenth anniversary of closing, and 3.50% after the fourteenth anniversary of closing. The EKF Tranche construction loans accrue interest at a fixed rate of 3.30% and the EKF Tranche term loans accrue interest at a fixed rate of 5.56%, in each case, plus a margin of 0.25% from the sixth anniversary to the tenth anniversary of the closing, 0.50% from the tenth anniversary to the fourteenth anniversary of closing, and 0.75% after the fourteenth anniversary of closing.

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

Value Added Tax (VAT) Facility

In addition to the El Arrayán Credit Agreement, in May 2012, El Arrayán entered into a $20 million VAT facility with Corpbanca. Under the VAT facility El Arrayán may borrow funds to pay for VAT payments due from the project. Drawdowns of the VAT facility must be repaid no later than 180 days. The VAT facility has an interest rate of Chilean Interbank Rate plus 1.00% and terminates in 2016. El Arrayán is also required to pay a commitment fee on the undrawn portion of the VAT facility. As of June 30, 2014, the outstanding balance on the VAT facility was $1.0 million.

Revolving Credit Facility

In November 2012, certain of the Company’s subsidiaries entered into a $120.0 million revolving working capital facility with a four-year term, comprised of a revolving loan facility and a letter of credit facility (collectively, the “revolving credit facility”). The revolving credit facility has an “accordion feature” under which the Company had the right to increase available borrowings by up to $35.0 million if the Company’s lenders or other additional lenders are willing to lend on the same terms and meet certain other conditions.

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

In March 2014, the Company exercised the accordion feature by increasing available borrowings by an additional $25.0 million, resulting in an aggregate facility amount of $145.0 million. Simultaneously, the Ocotillo project was added to the collateral pool that supports the revolving credit facility.

As of June 30, 2014 and December 31, 2013, letters of credit of $47.7 million and $44.8 million, respectively, have been issued and loans of $56.0 million were drawn and repaid during 2013. As of June 30, 2014 and December 31, 2013, there were no outstanding balances on the revolving credit facility.

9.	Asset Retirement Obligations

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

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligations as of June 30, 2014 and 2013 (in thousands):


	Six months ended June 30,
	2014		2013
Beginning asset retirement obligations	$	20,834	$	19,056
Additions during the period		4,912		508
Foreign currency translation adjustment		5		(129	)
Accretion expense		643		559

Ending asset retirement obligations	$	26,394	$	19,994

10.

Derivative Instruments

The Company employs a variety of derivative instruments to manage its exposure to fluctuations in interest rates and electricity prices. The following tables present the amounts that are recorded in the Company’s financial statements (in thousands):

Undesignated Derivative Instruments Classified as Assets (Liabilities):


Derivative Type	Quantity	Maturity Dates		As of					For the period ended
				Fair Market Value					QTD Gain (Loss)			YTD Gain (Loss)
				Current Portion			Long-Term Portion		Recognized into Income			Recognized into Income
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	)

December 31, 2013
Interest rate swaps	6		6/30/2030	$	(3,899	)	$	14,358	$	4,585		$	15,367
Interest rate cap	1		12/31/2024		—			681		107			234
Energy derivative	1		4/30/2019		13,937			54,416		(6,050	)		(11,272	)

				$	10,038		$	69,455	$	(1,358	)	$	4,329

June 30, 2013
Interest rate swaps	6		6/30/2030	$	(3,893	)	$	9,036	$	8,165		$	10,051
Interest rate cap	1		12/31/2024		—			529		37			82
Energy derivative	1		4/30/2019		15,534			52,210		(5,078	)		(11,881	)

				$	11,641		$	61,775	$	3,124		$	(1,748	)

Designated Derivative Instruments Classified as Assets (Liabilities):


					As of						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 in OCI
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	)

December 31, 2013
Interest rate swaps		6		6/30/2033	$	(2,105	)	$	9,625		$	3,117		$	10,434
Interest rate swaps		7		3/15/2020		(5,289	)		(7,439	)		2,129			9,398
Interest rate swaps		2		6/28/2030		(4,878	)		3,087			4,143			17,043

					$	(12,272	)	$	5,273		$	9,389		$	36,875

June 30, 2013
Interest rate swaps		6		6/30/2033	$	(2,082	)	$	5,675		$	5,111		$	6,507
Interest rate swaps		7		3/15/2020		(5,388	)		(9,592	)		5,874			7,145
Interest rate swaps		2		6/28/2030		(4,892	)		(2,013	)		9,282			11,935

					$	(12,362	)	$	(5,930	)	$	20,267		$	25,587

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, 2014 and 2013, respectively. The Company reclassified $1.4 million and $2.8 million related to cash settlements, into earnings from accumulated other comprehensive loss during the three and six months ended June 30, 2014, respectively, and $1.5 million and $2.8 million for the same periods in the prior year.

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 unrealized losses of $0.1 million and $0.3 million for the three months and six months ended June 30, 2014, respectively, in unrealized (loss) gain on derivatives in the consolidated statements of operations. The Company recognized an immaterial unrealized gain for the three months ended June 30, 2013 and a $0.1 million unrealized gain for the six months ended June 30, 2013.

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, 2014 and December 31, 2013 was $54.1 million and $68.4 million, respectively. Gulf Wind recognized losses of $6.5 million, and $14.3 million for the three and six months ended June 30, 2014, respectively and $5.1 million and $11.9 million for the same periods in the prior year, in unrealized loss on energy derivative in the consolidated statements of operations.

Spring Valley

In 2011, Spring Valley entered into interest rate swaps with its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 5.5% for the first four years of its term debt and increases by 0.25% every four years, thereafter. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three and six months ended June 30, 2014 and 2013, respectively. The Company reclassified $1.3 million and $2.5 million related to cash settlements, into earnings from accumulated other comprehensive loss during the three and six months ended June 30, 2014, respectively, and $1.3 million and $2.5 million for the same periods in the prior year.

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 4.6% and 4.9% 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, 2014 and 2013, respectively. The Company reclassified $0.5 million and $1.0 million related to cash settlements, into earnings from accumulated other comprehensive loss during the three and six months ended June 30, 2014, respectively. No amounts were reclassified from accumulated other comprehensive loss during the same periods in the prior year. The interest rate swaps for the commercial bank loans are undesignated derivatives that are used to mitigate exposure to variable interest rate debt.

El Arrayán

In May 2012, El Arrayán entered into three interest rate swap agreements with its lenders to manage exposure to interest rate risk on its long term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 3.4% for the first two years of its term debt and subsequently increased to 5.8%, and increases by 0.25% on every fourth anniversary of the closing date, thereafter. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three and six months ended June 30, 2014 and 2013, respectively. The Company reclassified $0.2 million and $0.2 million related to cash settlements, into earnings from accumulated other comprehensive loss during the three and six months ended June 30, 2014, respectively.

11.

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, 2014 and 2013 (in thousands):


	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI			Total
Balances at December 31, 2013	$	(8,463	)	$	(7,002	)	$	(1,912	)	$	(17,377	)
Other comprehensive loss before reclassifications		(869	)		(4,912	)		(4,283	)		(10,064	)
Amounts reclassified from accumulated other comprehensive loss		—			(6,557	)		—			(6,557	)
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	)



	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI			Total
Balances at December 31, 2012	$	(154	)	$	(43,877	)	$	(1,475	)	$	(45,506	)
Other comprehensive (loss) income before reclassifications		(7,327	)		30,946			1,601			25,220
Amounts reclassified from accumulated other comprehensive loss		—			(5,359	)		—			(5,359	)
Net current period other comprehensive (loss) income		(7,327	)		25,587			1,601			19,861

Balances at June 30, 2013	$	(7,481	)	$	(18,290	)	$	126		$	(25,645	)

Amounts reclassified from accumulated other comprehensive loss into income for 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.

12.

Fair Value Measurements

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

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

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

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

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

Short-term financial instruments consist principally of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and other accrued liabilities. Based on the nature and short maturity of these instruments, their fair value is approximated using carrying cost and they are presented in the Company’s financial statements at carrying cost. The fair values of cash and cash equivalents and restricted cash are classified as Level 1 in the fair value hierarchy. The fair values of accounts receivable, accounts payable and other accrued liabilities 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, 2014
Interest rate swaps	$	—	$	(16,884	)	$	—	$	(16,884	)
Interest rate cap		—		420			—		420
Energy derivative		—		—			54,071		54,071

	$	—	$	(16,464	)	$	54,071	$	37,607

December 31, 2013
Interest rate swaps	$	—	$	3,460		$	—	$	3,460
Interest rate cap		—		681			—		681
Energy derivative		—		—			68,353		68,353

	$	—	$	4,141		$	68,353	$	72,494

Level 2 Inputs

Derivative instruments subject to remeasurement are presented in the financial statements at fair value. The interest rate swaps and interest rate cap were valued by discounting the net cash flows using the forward LIBOR curve with the valuations adjusted by the counterparties’ credit default hedge rate. There were no transfers between Level 1 and Level 2 during the periods presented.

Level 3 Inputs

The fair value of the contingent liabilities is based upon the time of realization and the probability of the contingent event. An unobservable discount rate of 7% was used to determine the present value of the contractual liabilities and an unobservable probability factor of 75% was assigned to the contingent event prior to realization after considering contract terms, land rights, interconnect network, and environmental permits. The significant primary unobservable input used for contingent liabilities is the probability factor. Significant increases or decreases in this unobservable input would result in a significantly lower or higher fair value measurement.

The energy derivative instrument was 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 contingent liabilities and the energy derivative contract measured at fair value, in thousands, on a recurring basis using significant unobservable inputs (Level 3) for the three and six months ended June 30, 2014 and 2013, respectively. There were no transfers between Level 2 and Level 3 during the periods presented.


	Contingent Liabilities					Energy Derivative
	Six months ended June 30,					Six months ended June 30,
	2014		2013			2014			2013
Balances, beginning of period	$	—	$	(8,001	)	$	68,353		$	79,625
Settlements		—		8,001			(6,718	)		(10,217	)
Change in fair value, net of settlements		—		—			(7,564	)		(1,664	)

Balances, end of period	$	—	$	—		$	54,071		$	67,744

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, 2014 and December 31, 2013, but for which fair value is disclosed.


	As reflected on the balance sheet		Fair Value
	As reflected on the balance sheet		Level 1		Level 2		Level 3		Total
June 30, 2014
Long-term debt	$	1,436,055	$	—	$	1,371,824	$	—	$	1,371,824

December 31, 2013
Long-term debt	$	1,249,218	$	—	$	1,165,119	$	—	$	1,165,119

Long term debt is presented on the consolidated balance sheets at amortized cost, including El Arrayán which may be adjusted if its fair value is determined to be different than amortized cost, once the accounting for the acquisition has been finalized. 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.

13.

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.

14.

Stock-based Compensation

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

Total stock-based compensation expense for the three and six months ended June 30, 2014 was $1.6 million and $2.2 million, respectively. No such expense was recorded during the three and six months ended June 30, 2013.

15.

Earnings (Loss) per Share

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

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

Diluted EPS is computed by dividing net income attributable to common stockholders by the weighted-average number of common shares and potentially dilutive common shares outstanding, for each respective class of stock. Potentially dilutive common stock

includes the dilutive effect of the common stock underlying in-the-money stock options and is calculated based on the average share price for each period using the treasury stock method. Potentially dilutive common stock also reflects the dilutive effect of unvested restricted stock awards.

Class B common stock is a contingently convertible security which is convertible to Class A common stock on a one-to-one basis on the later of December 31, 2014 or commencement of commercial operations of the South Kent wind project. The computation of diluted EPS of Class A common stock would include the impact of the conversion of the Class B common stock, if dilutive for Class A common stock, using the if-converted method once the contingency surrounding the conversion has been met. On March 28, 2014, commercial operations commenced at the South Kent wind project and as a result, the outstanding Class B common stock will be converted to Class A common stock on December 31, 2014.

In periods of net loss, the loss is allocated by first considering any dividends declared or accumulated to Class A common stock. While Class B common stock is not entitled to dividends, because it has the same voting, liquidation and residual rights as Class A common stock, the remaining undistributed loss is allocated equally per share to weighted average Class A and Class B common stock outstanding during the year. For the three and six months ended June 30, 2014, all potentially dilutive securities were included in the diluted EPS calculation.

The computations for basic and diluted earnings (loss) per share are as follows:


	Three months ended			Six months ended
	June 30, 2014			June 30, 2014
Numerator for basic and diluted earnings (loss) per share:
Net income (loss) attributable to controlling interest	$	11,199		$	(3,690	)
Less: dividends declared		(14,981	)		(26,138	)

Undistributed loss	$	(3,782	)	$	(29,828	)
Denominator for earnings (loss) per share:
Weighted average number of shares:
Class A common stock - basic		41,174,697			38,331,595
Add dilutive effect of:
Stock options		107,979			100,814
Restricted stock awards		227,543			227,543
Class B common stock		15,555,000			15,555,000

Class A common stock - diluted		57,065,219			54,214,953
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	$	0.36		$	0.68
Undistributed loss		(0.07	)		(0.55	)

Basic earnings per share	$	0.30		$	0.13

Class A common stock:

Diluted earnings (loss) per share	$	0.20		$	(0.07	)

Class B common stock:

Basic and diluted loss per share	$	(0.07	)	$	(0.55	)

16.

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,
	2014			2013		2014			2013		2014		2013
United States	$	54,133		$	47,881	$	90,387		$	80,988	$	1,506,885	$	1,210,319
Canada		11,024			10,831		24,308			21,561		259,152		265,823
Chile		(150	)		—		(139	)		—		339,900		—

Total	$	65,007		$	58,712	$	114,556		$	102,549	$	2,105,937	$	1,476,142

17.

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, 2014, under the terms of the PPAs, the Company issued irrevocable letters of credit totaling $57.2 million to ensure its performance for the duration of the PPAs.

Project Finance Agreements

The Company has various project finance agreements which obligate the Company to provide certain reserves to enhance its credit worthiness and facilitate the availability of credit. As of June 30, 2014, the Company issued irrevocable letters of credit totaling $151.8 million, of which $47.6 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, 2014, total outstanding lease commitments were $107.9 million. 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. During the three and six months ended June 30, 2013, the Company recorded rent expense of $1.7 million and $3.3 million, respectively, in project expense in the consolidated statements of operations.

Operations and Maintenance

The Company has entered into service and maintenance agreements with third party contractors to provide operations and maintenance services and incremental improvements for varying periods over the next twelve years. As of June 30, 2014, outstanding commitments with these vendors were $281.2 million, payable over the full term of these agreements.

Purchase Commitments

The Company has entered into various commitments with service providers related to the Company’s projects and operations of its business. Outstanding commitments with these vendors, excluding turbine operations and maintenance commitments were $6.0 million as of June 30, 2014.

Purchase and Sales Agreements

On December 20, 2013, the Company entered into an agreement with Pattern Development to acquire approximately 81% of the ownership interest in Panhandle 2, a 182 MW wind project being built in Carson County, Texas, for approximately $122.9 million in cash. The acquisition, which includes assumption by the Company of certain tax indemnities, is expected to close in fourth quarter of 2014 upon completion of construction, and the Company expects to fund the purchase with available cash and credit facilities.

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 will make an additional contingent payment of up to $4.7 million to Pattern Development in 2014.

Turbine Availability Warranties

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, 2014, the Company recorded an accrued liability of $1.5 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, have been recorded as other revenue in the consolidated statements of operations.

Indemnity

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

The Company is party to certain indemnities for the benefit of the Spring Valley, Santa Isabel and Ocotillo project finance lenders. These indemnity obligations consist principally of indemnities that protect the project finance lenders from the potential effect of any recapture by the U.S. Department of the Treasury, or “U.S. Treasury,” of any amount of the ITC cash grants previously received by the projects. The ITC cash grant indemnity obligations guarantee amounts of any cash grant made to each of the respective projects that may subsequently be recaptured. In addition, the Company is also party to an indemnity of 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 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 up to a maximum amount of $7.2 million.

18.

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, where certain of the Company’s executive officers, including its Chief Executive Officer, will also serve as executive officers of Pattern Development and devote their time to both the Company and Pattern Development as is prudent in carrying out their executive responsibilities and fiduciary duties. The Company refers to the employees who will serve as executive officers of both the Company and Pattern Development as the “shared PEG executives.” The shared PEG executives will have responsibilities for both the Company and Pattern Development and, as a result, these individuals will not devote all of their time to the Company’s business. Under the terms of the Management Services Agreement, Pattern Development is required to reimburse the Company for an allocation of the compensation paid to such executives reflecting the percentage of time spent providing services to Pattern Development.

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


	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Project expense	$	—		$	668		$	—		$	1,224
Related party general and administrative		1,383			2,699			2,663			5,361
Related party income
Management Services Agreement income		(444	)		—			(1,072	)		—
Management Operation and Maintenance Agreement income		68			—			—			—

Related party income		(376	)		—			(1,072	)		—
Other income, net		—			(373	)		—			(534	)

Net expenses	$	1,007		$	2,994		$	1,591		$	6,051

Prior to the Contribution Transactions, the Company had purchase arrangements with Pattern Development under which the latter purchased various services and supplies on behalf of the Company and received reimbursement for these purchases. The amounts payable to Pattern Development for these purchases were $0.7 million and $1.2 million as of June 30, 2014 and December 31, 2013, respectively.

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 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 30, 2014, the Company acquired a 79% ownership interest in Panhandle 1 from Pattern Development for approximately $124.4 million, following the commencement of operations on June 25, 2014.

On December 20, 2013, the Company entered into an agreement with Pattern Development to acquire approximately 81% of the ownership interest in Panhandle 2, a 182 MW wind project being built in Carson County, Texas, for approximately $122.9 million in cash. The acquisition is expected to close in the fourth quarter of 2014 upon completion of construction, and the Company expects to fund the purchase with available cash and credit facilities.

On December 20, 2013, the Company acquired a 45.0% equity interest in Grand from Pattern Development. Subject to the terms of this agreement, the Company may make an additional contingent payment of up to $4.7 million, as calculated based on final budget to actual amounts and distributions payable upon conversion of construction financing, to Pattern Development in 2014.

Puerto Rico Electric Power Authority (PREPA)

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

Management Fees

The Company provides management services and receives a fee for such services under agreements with El Arrayán, Panhandle 1 and its joint venture investees, South Kent and Grand, in addition to various Pattern Development subsidiaries. Management fees of $1.0 million and $1.5 million were recorded as related party revenue in the consolidated statements of operations for the three and six months ended June 30, 2014, respectively, and $0.3 million for the same periods in the prior year. A related party receivable of $0.8 million and $0.2 million was recorded in the consolidated balance sheets as of June 30, 2014 and December 31, 2013, respectively. Subsequent to the acquisition of control of El Arrayán and Panhandle 1, 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.

19.

Subsequent Events

On July 1, 2014, Moody’s further downgraded its credit rating of PREPA to Caa2, and on July 9, 2014 and July 31, 2014, S&P further downgraded its credit rating of PREPA to B- and CCC respectively. In addition, on July 7, 2014, PREPA announced that it had reached a standstill agreement with certain of its lenders not to exercise remedies as a result of credit downgrades and other events, and may delay certain, currently due payments to these lenders until July 31, 2014. Such standstill was recently extended until August 14, 2014, while PREPA continues discussions with its lenders. As of August 5, 2014, PREPA was current with respect to payments due under the PPA. The next payment under the PPA will be due from PREPA on approximately August 18, 2014.

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, 2013 and our unaudited consolidated financial statements for the three and six months ended June 30, 2014 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 eleven wind power projects located in the United States, Canada and Chile that use proven, best-in-class technology and have a total owned capacity of 1,472 MW, including the Panhandle 2 project, which we expect to acquire prior to the end of 2014. These projects consist of nine operating projects and two projects under construction that are both scheduled to commence commercial operations prior to the end of 2014. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price power sale agreement with a creditworthy counterparty (one of our counterparties, PREPA, has recently been downgraded — See “Part II—Item 1A. Risk Factors”). Ninety-one 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 17 years.

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

Our growth strategy is focused on the acquisition of operational and construction-ready power projects from Pattern Development and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per share over time. We expect our continuing relationship with Pattern Development, a leading developer of renewable energy and transmission projects, will be an important source of growth for our business. In addition, opportunities in new geographic markets, such as Japan and Mexico, could form part of our growth strategy.

Recent Developments

In June 2014, we acquired a 79% ownership interest in the 218 MW Panhandle 1 project from Pattern Development for a purchase price of approximately $124.4 million, following the completion of construction and commencement of commercial operations on June 25, 2014.

In June 2014, we increased our net ownership interest in the 115 MW El Arrayán project to 70% and our owned operating capacity by an additional 44 MW. The project was completed in early June and is now fully operational. Prior to the acquisition, our net ownership interest in the El Arrayán wind project was 31.5%.

In May 2014, we completed a follow-on offering of our Class A common stock. In total, 21,117,171 shares of our Class A common stock were sold. Of this amount, we sold 10,810,810 shares of Class A common stock and Pattern Development, a selling stockholder, sold 10,306,361 shares of Class A common stock, including 2,754,413 shares upon exercise in full of the underwriters’ overallotment option. Net proceeds generated for us were approximately $288.7 million before deduction of transaction expenses of approximately $2.0 million. We did not receive any proceeds from the sale of the shares sold by Pattern Development.

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

Panhandle 2⁽¹⁾

Texas

Q4 2013

Q4 2014

182

147

Grand

Ontario

Q3 2013

Q4 2014

149

331

214

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

We have recently encountered potential cost increases and delays in the construction of Grand, and are in discussions with Samsung C&T Canada Ltd. (a subsidiary of Samsung C&T Corporation), the project construction provider, regarding this matter. See “Part II. Item 1A. Risk Factors”.

In addition, below is a summary of the Right of First Offer Projects (“ROFO Projects”) that we expect to acquire from Pattern Development in connection with our project purchase rights in the coming six to twenty-four months. For additional discussion on the 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, 2013.

On August 5, 2014 Pattern Development announced that it had acquired the Logan’s Gap project, a 200 MW wind project proposed to be built in Comanche County, Texas. Logan’s Gap has a 10-year Power Purchase Agreement with Wal-Mart Stores, Inc. for approximately 60% of the expected production for the project. Pattern Development expects to arrange both construction and tax equity financing in the fourth quarter of 2014 and expects to retain an owned interest in the project of approximately 160 MW. Logan’s Gap is expected to begin commercial operation in late 2015.


									Capacity (MW)
Identified ROFO Projects	Status	Location	Construction Start ⁽¹⁾		Commercial Operations ⁽²⁾		Contract Type		Rated ⁽³⁾		Pattern Development- Owned ⁽⁴⁾
Gulf Wind	Operational	Texas		2008		2009		Hedge		283		76
K2	In construction	Ontario		2014		2015		PPA		270		90
Armow	Ready for financing	Ontario		2014		2015		PPA		180		90
Meikle	Ready for financing	British Columbia		2015		2016		PPA		185		185
Logan’s Gap	Ready for financing	Texas		2014		2015		PPA		200		160

										1,118		601

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

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

(3)

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

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

Key Metrics

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

Proportional MWh Sold and Average Realized Electricity Price

The number of MWh sold and the average realized price per MWh sold are the operating metrics that determine our revenue, as well as the revenue of our unconsolidated investments. As a result of the commencement of commercial operations at our South Kent, El Arrayán and Panhandle 1 projects, each of which is a partially owned project, we believe it is appropriate to focus on our proportional interest in the production of our project interests. Accordingly, we are reporting proportional MWh sold (in lieu of MWh sold, which we have previously reported) and revising our calculation of average realized electricity price to reflect our proportional interest in both revenues and MWh sold. Additionally, as a result we only include in these reported figures our proportional interest in the production at our Gulf Wind project where, previously, the noncontrolling interest in the production was included in our determination of MWh sold and average realized electricity price. Proportional MWh sold for any period presented, represents the sum of the

product of (i) the number of MWh sold by each of our projects multiplied by (ii) our percentage interest in each projects’ distributable cash flow. For any period presented, average realized electricity price represents (i) the sum of the products of: (a) total revenue from electricity sales and energy derivative settlements at each of our projects and (b) our percentage interest in each project’s distributable cash flow divided by (ii) our proportional MWh sold.

Adjusted EBITDA

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

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net income (loss)	$	7,167		$	43,988		$	(14,732	)	$	25,204
Plus:
Interest expense, net of interest income		15,525			15,788			29,943			31,672
Tax provision (benefit)		4,065			(7,688	)		2,033			(7,394	)
Depreciation and accretion		21,284			17,998			42,461			40,564

EBITDA	$	48,041		$	70,086		$	59,705		$	90,046

Unrealized loss on energy derivative		6,549			5,078			14,282			11,881
Unrealized loss (gain) on derivatives		2,942			(8,202	)		6,665			(10,133	)
Interest rate derivative settlements		1,035			—			2,052			—
Net gain on transactions		(14,537	)		(7,200	)		(14,537	)		(7,200	)
Plus, proportionate share from equity accounted investments:
Interest expense, net of interest income		4,944			(50	)		5,197			(52	)
Tax provision (benefit)		102			(12	)		102			(48	)
Depreciation and accretion		4,537			10			4,724			11
Unrealized loss (gain) on interest rate and currency derivatives		5,236			(13,731	)		17,831			(3,948	)
Realized (gain) loss on interest rate and currency derivatives		—			(14	)		22			(153	)

Adjusted EBITDA	$	58,849		$	45,965		$	96,043		$	80,404

Cash Available for Distribution

We define cash available for distribution as net cash provided by operating activities as adjusted for certain other cash flow items that we associate with our operations. It is a non-U.S. GAAP measure of our ability to generate cash to service our dividends. Cash available for distribution represents cash provided by (used in) operating activities as adjusted to (i) add or subtract changes in operating assets and liabilities, (ii) subtract net deposits into restricted cash accounts, which are required pursuant to the cash reserve requirements of financing agreements, to the extent they are paid from operating cash flows during a period, (iii) subtract cash distributions paid to noncontrolling interests, which currently reflects the cash distributions to our joint venture partners in our Gulf Wind project in accordance with the provisions of its governing partnership agreement and will in the future reflect distribution to other joint venture partners, (iv) subtract scheduled project-level debt repayments in accordance with the related loan amortization schedule, to the extent they are paid from operating cash flows during a period, (v) subtract non-expansionary capital expenditures, to the extent they are paid from operating cash flows during a period, and (vi) add or subtract other items as necessary to present the cash flows we deem representative of our core business operations.

The following table presents cash available for distribution for the periods presented and is unaudited (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net cash provided by operating activities	$	44,417		$	33,266		$	60,822		$	41,657
Changes in current operating assets and liabilities		(12,336	)		(938	)		(5,685	)		11,757
Network upgrade reimbursement		618			618			1,236			618
Release of restricted cash to fund general and administrative costs		7			—			61			—
Operations and maintenance capital expenditures		(40	)		(156	)		(94	)		(375	)
Transaction costs for acquisitions		1,128			—			1,128			—
Less:
Distributions to noncontrolling interests		(1,470	)		(1,000	)		(1,470	)		(1,168	)
Principal payments paid from operating cash flows		(16,266	)		(15,584	)		(22,096	)		(21,815	)

Cash available for distribution	$	16,058		$	16,206		$	33,902		$	30,674

Results of Operations

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

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


	Three months ended June 30,
	2014			2013			$ Change			% Change
Revenue	$	65,007		$	58,712		$	6,295			11	%

Project expense		16,700			14,492			2,208			15	%
Depreciation and accretion		21,284			17,998			3,286			18	%

Total cost of revenue		37,984			32,490			5,494			17	%

Gross profit		27,023			26,222			801			3	%

General and administrative		6,288			205			6,083			2967	%
Related party general and administrative		1,383			2,699			(1,316	)		-49	%

Total operating expenses		7,671			2,904			4,767			164	%

Operating income		19,352			23,318			(3,966	)		-17	%
Total other (expense) income		(8,120	)		12,982			(21,102	)		163	%

Net income before income tax		11,232			36,300			(25,068	)		69	%
Tax provision (benefit)		4,065			(7,688	)		11,753			-153	%

Net income		7,167			43,988			(36,821	)		84	%
Net loss attributable to noncontrolling interest		(4,032	)		(359	)		(3,673	)		-1023	%

Net income attributable to controlling interest	$	11,199		$	44,347		$	(33,148	)		75	%

Proportional MWh sold and average realized electricity price. Our proportional MWh sold in the three months ended June 30, 2014 was 769,619 MWh, as compared to 496,763 proportional MWh sold in the three months ended June 30, 2013. This increase in proportional MWh sold during 2014 as compared to 2013 was primarily attributable to an increase in production at Ocotillo and Santa Isabel and also to the commencement of commercial operations at South Kent in March 2014. Our average realized electricity price was approximately $95 per MWh in the three months ended June 30, 2014 as compared to approximately $85 per MWh in the three months ended June 30, 2013. The average realized electricity price in 2014 was higher than the comparable period in 2013 because the pricing terms under the South Kent and El Arrayán PPAs are each higher than our overall average realized price applicable in 2013.

Wind conditions have improved at our project sites on average compared to recent quarters and, as a result, the electricity production at our fleet was close to its long-term average during the three months ended June 30, 2014. Excluding our newly operational project, South Kent, the production was less than 2% below the expected long-term average during this period. South Kent experienced some startup issues that are common for new power projects which are being addressed by Siemens.

Revenue. Revenue for the three months ended June 30, 2014 was $65.0 million compared to $58.7 million for the three months ended June 30, 2013, an increase of $6.3 million, or approximately 11%. This increase in revenue for the three months ended June 30, 2014 as compared to the prior year was primarily attributable to the commencement of commercial operations on the final 42 megawatts at Ocotillo in July 2013.

Cost of revenue. Cost of revenue for the three months ended June 30, 2014 was $38.0 million compared to $32.5 million for the three months ended June 30, 2013, an increase of $5.5 million, or approximately 17%. The increase in cost of revenue during 2014 as compared to 2013 was attributable principally to the commencement of commercial operations on the final 42 megawatts at Ocotillo in July 2013, higher property taxes at Hatchet Ridge, and increases in depreciation expense in 2014, due to receipt of Ocotillo and Santa Isabel ITC grants during the second quarter of 2013. As each new project commences commercial operations, we incur new incremental and ongoing costs for maintenance and services agreements, property taxes, insurance, land lease and other costs associated with managing, operating and maintaining the facility, including adding site employees and other operations staff.

Operating expenses. Operating expenses for the three months ended June 30, 2014 were $7.7 million compared to $2.9 million for the three months ended June 30, 2013, an increase of $4.8 million, or approximately 164%. The increase in operating expenses during 2014 as compared to 2013 was attributable to project acquisition activities and increased costs related to being a public company, and includes $1.6 million of stock-based compensation expense. After the Contribution Transactions and the initial public offering in 2013, the Company has direct payroll costs and employee-related, audit and consulting expenses, and other administrative expenses, that were previously allocated to the Company from Pattern Development, and which were reflected in related party general and administrative expense.

Other expense. Other expense for the three months ended June 30, 2014 was $8.1 million compared to other income of $13.0 million for the three months ended June 30, 2013. The decrease of $21.1 million in other expense during 2014 as compared to 2013 was primarily attributable to a $11.1 million increase in unrealized loss on interest rate derivatives at the Ocotillo project. In addition, we had a $17.1 million increase in equity in losses in unconsolidated investments which was primarily related to unrealized loss on interest rate derivatives on the unconsolidated investee’s financial statements. A decrease in the forward interest rate curve during the three months ended June 30, 2014 increased both of these unrealized losses. Offsetting these increased losses is a $7.3 million increase in net gain on transactions, principally related to our acquisition of an additional 38.5% interest in our El Arrayán project.

Tax provision. The tax provision was a $4.1 million expense for the three months ended June 30, 2014 compared to a $7.7 million benefit for the same period in the prior year. The expense provision for the three months ended June 30, 2014 was primarily the result of recording a discrete expense on the gain related to the fair value remeasurement of our original 31.5% interest in El Arrayán. The benefit for the three months ended June 30, 2013 was primarily the result of recognizing a deferred tax asset related to the basis difference for the receipt of the Internal Revenue Code Section 1603 grant at Santa Isabel.

Noncontrolling interest. The net loss attributable to noncontrolling interest was $4.0 million for the three months ended June 30, 2014 compared to a $0.4 million net loss attributable to noncontrolling interest for the three months ended June 30, 2013. The higher loss allocation for the three months ended June 30, 2014 is primarily attributable to the period over period increase in Gulf Wind’s unrealized loss on energy derivative and lower electricity sales during the three months ended June 30, 2014 as well as the retention by Pattern Development of an approximate 27% interest in Gulf Wind in connection with the Contribution Transactions which occurred on October 2, 2013.

Adjusted EBITDA. Adjusted EBITDA for the three months ended June 30, 2014 was $58.8 million compared to $46.0 million for the same period in the prior year, an increase of $12.8 million. The increase in Adjusted EBITDA during 2014 as compared to 2013 was primarily attributable to the commencement of commercial operation at South Kent in March 2014.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

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


	Six months ended June 30,
	2014			2013			$ Change			% Change
Revenue	$	114,556		$	102,549		$	12,007			12	%

Project expense		32,774			27,469			5,305			19	%
Depreciation and accretion		42,461			40,564			1,897			5	%

Total cost of revenue		75,235			68,033			7,202			11	%

Gross profit		39,321			34,516			4,805			14	%

General and administrative		10,191			349			9,842			2820	%
Related party general and administrative		2,663			5,361			(2,698	)		-50	%

Total operating expenses		12,854			5,710			7,144			125	%

Operating income		26,467			28,806			(2,339	)		-8	%
Total other expense		(39,166	)		(10,996	)		(28,170	)		-256	%

Net (loss) income before income tax		(12,699	)		17,810			(30,509	)		171	%
Tax provision (benefit)		2,033			(7,394	)		9,427			-127	%

Net (loss) income		(14,732	)		25,204			(39,936	)		158	%
Net loss attributable to noncontrolling interest		(11,042	)		(3,938	)		(7,104	)		-180	%

Net (loss) income attributable to controlling interest	$	(3,690	)	$	29,142		$	(32,832	)		113	%

Proportional MWh sold and average realized electricity price. Our proportional MWh sold in the six months ended June 30, 2014 was 1,315,908 MWh, as compared to 965,383 proportional MWh sold in the six months ended June 30, 2013. This increase in proportional MWh sold during 2014 as compared to 2013 was primarily attributable to an increase in production at Ocotillo and Santa Isabel and also to the commencement of commercial operations at South Kent in March 2014. Our average realized electricity price was approximately $93 per MWh in the six months ended June 30, 2014 as compared to approximately $86 per MWh in the six months ended June 30, 2013. The average realized electricity price in 2014 was higher than the comparable period in 2013 because the pricing terms under the South Kent and El Arrayán PPAs are each higher than our overall average realized price applicable in 2013.

Revenue. Revenue for the six months ended June 30, 2014 was $114.6 million compared to $102.5 million for the six months ended June 30, 2013, an increase of $12.1 million, or approximately 12%. This increase in revenue for the six months ended June 30, 2014 as compared to the prior year was primarily attributable to the commencement of commercial operations on the final 42 megawatts at Ocotillo in July 2013. During the six months ended June 30, 2014, we recorded a $14.3 million unrealized loss on energy derivative compared to an $11.9 million unrealized loss on energy derivative in 2013. 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, 2014 was $75.2 million compared to $68.0 million for the six months ended June 30, 2013, an increase of $7.2 million, or approximately 11%. The increase in cost of revenue during 2014 as compared to 2013 was attributable principally to the commencement of commercial operations on the final 42 megawatts at Ocotillo in July 2013, higher property taxes at Hatchet Ridge, and increases in depreciation expense in 2014, due to receipt of Ocotillo and Santa Isabel ITC grants during the second quarter of 2013. As each new project commences commercial operations, we incur new incremental and ongoing costs for maintenance and services agreements, property taxes, insurance, land lease and other costs associated with managing, operating and maintaining the facility, including adding site employees and other operations staff.

Operating expenses. Operating expenses for the six months ended June 30, 2014 were $12.9 million compared to $5.7 million for the six months ended June 30, 2013, an increase of $7.1 million, or approximately 125%. The increase in operating expenses during 2014 as compared to 2013 was attributable to project acquisition activities and increased costs related to being a public company, and includes $2.2 million of stock-based compensation expense. After the Contribution Transactions and the initial public offering in 2013, the Company has direct payroll costs and employee-related, audit and consulting expenses, and other administrative expenses, that were previously allocated to the Company from Pattern Development, and which were reflected in related party general and administrative expense.

Other expense. Other expense for the six months ended June 30, 2014 was $39.2 million compared to $11.0 million for the six months ended June 30, 2013. The increase of $28.2 million in other expense during 2014 as compared to 2013 was primarily attributable to a $16.8 million increase in unrealized loss on interest rate derivatives at the Ocotillo project. In addition, we had a $19.6 million increase in equity in losses in unconsolidated investments which was primarily related to unrealized loss on interest rate derivatives on the unconsolidated investee’s financial statements. A decrease in the forward interest rate curve during the six months ended June 30, 2014 increased both of these unrealized losses. Offsetting these increased losses is a $7.3 million increase in net gain on transactions, principally related to our acquisition of an additional 38.5% interest in our El Arrayán project.

Tax provision. The tax provision was a $2.0 million expense for the six months ended June 30, 2014 compared to a $7.4 million benefit for the same period in the prior year. The expense provision for the six months ended June 30, 2014 was related to the fair value remeasurement of our original 31.5% interest in El Arrayán, offset by recognizing equity in losses in unconsolidated investments which were primarily related to interest rate swaps that are not designated as hedges. The benefit for the six months ended June 30, 2014 was primarily the result of recognizing a deferred tax asset related to the basis difference for the receipt of the Internal Revenue Code Section 1603 grant at Santa Isabel.

Noncontrolling interest. The net loss attributable to noncontrolling interest was $11.0 million for the six months ended June 30, 2014 compared to a $3.9 million net loss attributable to noncontrolling interest for the six months ended June 30, 2013. The higher loss allocation for the six months ended June 30, 2014 is primarily attributable to the period over period increase in Gulf Wind’s unrealized loss on energy derivative and lower electricity sales during the six months ended June 30, 2014 as well as the retention by Pattern Development of an approximate 27% interest in Gulf Wind in connection with the Contribution Transactions which occurred on October 2, 2013.

Adjusted EBITDA. Adjusted EBITDA for the six months ended June 30, 2014 was $96.0 million compared to $80.4 million for the same period in the prior year, an increase of $15.6 million. The increase in Adjusted EBITDA during 2014 as compared to 2013 was primarily attributable to the commencement of commercial operation at South Kent in March 2014.

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, 2014, our available liquidity was $470.3 million, including unrestricted cash on hand of $234.0 million, restricted cash on hand of $44.4 million, $97.4 million available under our revolving credit agreements and $94.5 million available under project financings for standby credit support at our projects.

We believe that throughout 2014, we will have sufficient liquid assets, cash flows from operations, and borrowings available under our revolving credit facility to meet our financial commitments, debt service obligations, contingencies and anticipated required capital expenditures for at least the next 24 months, without taking into account capital required for additional project acquisitions. Additionally, we believe that our construction projects have been sufficiently capitalized such that we will not need to seek additional financing arrangements in order to complete construction and achieve commercial operations at these projects. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corresponding adverse effect on our borrowing capacity. In connection with our future capital expenditures and other investments, including any project acquisitions that we may make in addition to our acquisition of Panhandle 2, for which we have committed $122.9 million, 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 investing activities and net cash provided by financing activities as well as cash available for distribution to evaluate our periodic cash flow results.

Net Cash Provided by Operating Activities

Net cash provided by operating activities was $60.8 million for the six months ended June 30, 2014 as compared to $41.7 million for the same period in the prior year. This $19.1 million increase in cash provided by operating activities was primarily the result of a $17.4 million increase in cash provided by changes in operating assets and liabilities, inclusive of acquired assets and liabilities at El Arrayán.

Net Cash (Used in) Provided by Investing Activities

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 investing activities was $63.4 million for the six months ended June 30, 2013, which consisted primarily of $173.4 million of ITC grant proceeds at Ocotillo and Santa Isabel and $14.3 million of proceeds from the sale of investments and tax credits, offset by $111.1 million of capital expenditures, primarily at Ocotillo and Santa Isabel, and $6.7 million for interconnection network upgrades, primarily at Hatchet Ridge and Ocotillo.

Net Cash Provided by (Used in) Financing Activities

Net cash provided by financing activities for the six months ended June 30, 2014 was $231.4 million, which consisted of $288.7 million of net proceeds from our May equity offering (reduced by $0.8 million paid transaction costs) 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. Net cash used in financing activities for the six months ended June 30, 2013 was $79.8 million, which was primarily attributable to the $57.5 million repayment of our Santa Isabel grant loan, $21.8 million repayment of our long-term debt, $116.7 million increase in restricted cash balances primarily at Ocotillo and $92.2 million distributions to Pattern Development, offset by the $118.0 million of loan borrowings at Santa Isabel and Ocotillo and a $56.0 million loan draw under our revolving credit facility.

Cash Available for Distribution

Cash available for distribution was $16.1 million for the three months ended June 30, 2014 as compared to $16.2 million for the same period in the prior year. This decrease in cash available for distribution was primarily the result of a $7.8 million increase in total revenue, exclusive of unrealized loss on energy derivative, offset by an aggregate $7.0 million increase in project and operating expenses.

Cash available for distribution was $33.9 million for the six months ended June 30, 2014 as compared to $30.7 million for the same period in the prior year. This $3.2 million increase in cash available for distribution was primarily the result of a $14.4 million increase in total revenue, exclusive of the unrealized loss on energy derivative, offset by an aggregate $12.4 million increase in project and operating expenses.

Although we commenced commercial operation at each of the South Kent, El Arrayán and Panhandle 1 projects during the first six months of 2014, they did not provide any meaningful contribution to our cash available for distribution during the first half of the year; however, we do expect each project to contribute to cash available for distribution in the second half of the year.

Cash Dividends to Investors

We intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A shares. Our quarterly dividend was initially set at $0.3125 per Class A share, or $1.25 per Class A share on an annualized basis, and has been increased to a current level of $0.328 per Class A share, or $1.312 per Class A share on an annualized basis. This amount may be changed in the future without advance notice. 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 Conversion Event, after considering the annual cash available for distribution that we expect our projects will be able to generate following the commencement of commercial operations at all of our construction projects and with due regard to retaining a portion of the cash available for distribution to grow our business. We intend to grow our business primarily through the acquisition of operational and construction-ready power projects, which, we believe, will facilitate the growth of our cash available for distribution and enable us to increase our dividend per Class A share over time. However, the determination of the amount of cash dividends to be paid to holders of our Class A shares will be made by our Board of Directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant. 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, 2013.

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

On August 1, 2014, we declared our third quarter 2014 dividend, payable on October 30, 2014, to holders of record on September 30, 2014, in the amount of $0.328 per Class A share, which represents $1.312 on an annualized basis.

Capital Expenditures and Investments

All capital expenditures and investments in 2013 were either funded by Pattern Development or by project finance lenders under project-level credit facilities. For 2013, total capital expenditures were $123.5 million. For 2014, we do not expect to make capital expenditures at our current construction projects as these projects have been or are held in joint ventures for which we use the equity method of accounting.

We expect to make investments in additional projects. We have agreed to make a cash payment to Pattern Development in the amount of $122.9 million, subject to certain price adjustments based on final project size, design and modeling assumptions, at the time of the Panhandle 2 acquisition, which we expect to occur in the fourth quarter of 2014. In addition, we are in advanced discussions regarding potential acquisitions of certain wind power projects. Although we have no commitments to make any acquisitions, other than the acquisition of Panhandle 2, we consider it reasonably likely that we may have the opportunity to acquire certain other Pattern Development projects under our purchase rights within the 24 month period following December 31, 2013.

We believe that we will have sufficient cash and revolving credit facility capacity to complete the Panhandle 2 acquisition, but this may be affected by any other acquisitions or investments that we make prior to the Panhandle 2 acquisition. To the extent that we make any such investments or acquisitions, we will evaluate capital markets and other corporate financing sources available to us at the time.

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

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

Critical Accounting Policies and Estimates

There have been no changes in our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013.

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, 2013. See also Note 8, Long-term Debt, and Note 17, 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, 2014 (in thousands):


	Total Project Debt		Percentage of Ownership			Our Portion of Unconsolidated Project Debt
South Kent	$	593,899		50.0	%	$	296,950
Grand		239,005		45.0	%		107,552

Total	$	832,904				$	404,502

Off-Balance Sheet Arrangements

As of June 30, 2014, 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 earnings and may result in volatility in our earnings, in addition to potential cash settlements for any losses.

Commodity Price Risk

We manage our commodity price risk for electricity sales through the use of long-term power sale agreements with creditworthy counterparties. Our financial results reflect approximately 439,895 MWh of electricity sales during the six months ended June 30,

2014 that were not subject to power sale agreements and were subject to spot market pricing. A hypothetical increase or decrease of $3.65 per MWh (or an approximately 10% change) in these spot market prices would have increased or decreased earnings by $0.5 million, respectively, for the six months ended June 30, 2014.

Interest Rate Risk

We use a variety of derivative instruments to manage our exposure to fluctuations in interest rates, including interest rate swaps and interest rate caps, primarily in the context of our project-level indebtedness. We generally match the tenor and amount of these instruments to the tenor and amount, respectively, of the related debt financing. We also will have exposure to changes in interest rates with respect to our revolving credit agreement to the extent that we make draws under that facility. A hypothetical increase or decrease in short-term interest rates by 1% would not have changed our earnings for the six months ended June 30, 2014.

Foreign Currency Risk

We manage our foreign currency risk through the consideration of forward exchange rate derivatives. Certain of our power sale agreements are U.S. dollar denominated and others are Canadian dollar denominated. We did not enter into forward exchange rate derivatives to manage our exposure to Canadian dollar denominated revenues at our St. Joseph project in the past. Our financial results include approximately $26.7 million of revenue that was earned pursuant to Canadian dollar denominated power sale arrangements. A hypothetical increase or decrease of US$0.10 per Canadian dollar would increase or decrease our earnings by $0.8 million for the six months ended June 30, 2014.

ITEM 4. CONTROLS AND PROCEDURES

Based on their evaluation, required by paragraph (b) of Rules 13a-15 or 15d-15, promulgated by the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Company’s principal executive officer and principal financial officer have concluded that, because of a material weakness existing in internal control over financial reporting as of June 30, 2014, the Company’s disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, are not effective at a reasonable assurance level to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, as of June 30, 2014. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurances 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.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

Management determined that the Company did not maintain effective controls over the calculation and reporting of earnings per share. Specifically, the Company identified deficiencies with respect to design and operation of controls over the methodology used to calculate Class A diluted earnings per share, which resulted in a material weakness in internal control over financial reporting. The Company has since modified its procedures with respect to the process of calculating earnings per share, including additional instruction to the Company’s accounting staff on the calculation of diluted earnings per share. Management considers the steps underway will be sufficient to remediate the material weakness noted above.

Based on the performance of additional procedures by management designed to ensure the reliability of financial reporting, management believes the consolidated financial statements included in this report are fairly stated in all material respects.

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 its systems evolve with its business.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is 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 the Company’s legal proceedings from the description provided in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Form 10-K”), except that with respect to the legal proceedings at Ocotillo, the plaintiffs have appealed the state lawsuit that had been dismissed on January 28, 2014. Additional information with respect to such litigation can be found in the 2013 Form 10-K under “Item 3. Legal Proceedings – Ocotillo”.

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 Company’s 2013 Form 10-K. There have been no material changes in the Company’s risk factors as described in the 2013 Form 10-K, except as set forth below.

The business, financial condition and operating results of the Company 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 the Company’s 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 the Company’s business, financial condition, results of operations and Class A share price.

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 the Company’s financial condition and operating results, past financial performance should not be considered to be a reliable indicator of future performance, and investors should not use historical trends to anticipate results or trends in future periods.

We may be unable to complete our current and any future construction projects on time, and our construction costs could increase to levels that make a project too expensive to complete or make the return on our investment in that project less than expected.

There may be delays or unexpected developments in completing our current and any future construction projects, which could cause the construction costs of these projects to exceed our expectations. Most of our construction projects are constructed under fixed-price and fixed-schedule contracts with construction and equipment suppliers. However, these contracts provide for limitations on the liability of these contractors to pay us liquidated damages for cost overruns and construction delays. We may suffer significant construction delays or construction cost increases as a result of underperformance of these contractors and equipment suppliers, as well as other suppliers, to our projects. For example, we have recently received claims for cost increases and schedule relief in the construction of Grand that could be significant, and we are in ongoing discussions with Samsung C&T Canada Ltd. (a subsidiary of Samsung C&T Corporation), the project construction provider with whom we have a fixed-price and fixed-schedule contract, regarding the validity of these claims for schedule relief and cost increase. While we currently believe we can resolve these claims and maintain a Q4 2014 commercial operation date for the project, no assurances can be given that we can resolve these claims favorably, the commercial operation date of the project will not be delayed beyond Q4 2014, we will not have to bear increased costs associated with these construction issues, or a substantial delay to the commercial operation date will not have an adverse effect under our financing arrangements or other project agreements.

Additionally, various other factors could contribute to construction-cost overruns and construction delays, including:

•

inclement weather conditions;

•

failure to receive turbines or other critical components and equipment necessary to maintain the operating capacity of our projects, in a timely manner or at all;

•

failure to complete interconnection to transmission networks, which relies on several third parties, including interconnection facilities provided by local utilities;

•

failure to maintain all necessary rights to land access and use;

•

failure to receive quality and timely performance of third-party services;

•

failure to maintain environmental and other permits or approvals;

•

failure to meet domestic content requirements;

•

appeals of environmental and other permits or approvals that we hold;

•

lawful or unlawful protests by or work stoppages resulting from local community objections to a project;

•

shortage of skilled labor on the part of our contractors;

•

adverse environmental and geological conditions; and

•

force majeure or other events out of our control.

Any of these factors could give rise to construction delays and construction costs in excess of our expectations. These circumstances could prevent our construction projects from commencing operations or from meeting our original expectations about how much electricity they will generate or the returns they will achieve. In addition, substantial delays could cause defaults under our financing agreements or under PPAs that require completion of project construction by a certain date at specified performance levels or could result in the loss or reduction of expected tax benefits. Our inability to transition our construction projects into financially successful operating projects would have a material adverse effect on our business, financial condition and results of operations and our ability to pay dividends.

Our projects rely on a limited number of key power purchasers. The power purchaser for our Santa Isabel project has been downgraded.

There are a limited number of possible power purchasers for electricity and RECs produced in a given geographic location. Because our projects depend on sales of electricity and RECs to certain key power purchasers, our projects are highly dependent upon these power purchasers fulfilling their contractual obligations under their respective PPAs. Our projects’ power purchasers may not comply with their contractual payment obligations or may become subject to insolvency or liquidation proceedings during the term of the relevant contracts and, in such event, we may not be able to find another purchaser on similar or favorable terms or at all. In addition, we are exposed to the creditworthiness of our power purchasers and there is no guarantee that any power purchaser will maintain its credit rating, if any. To the extent that any of our projects’ power purchasers are, or are controlled by, governmental entities, our projects may also be subject to legislative or other political action that impairs their contractual performance. Failure by any key power purchasers to meet their contractual commitments or the insolvency or liquidation of one or more of our power purchasers could have a material adverse effect on our business, financial condition and results of operations.

For example, our 101 MW Santa Isabel project located on the south coast of Puerto Rico sells 100% of its electricity generation including environmental attributes to PREPA under a 20-year PPA. The credit ratings of PREPA and the Commonwealth of Puerto Rico were downgraded in each of February 2014, June 2014 and July 2014. As of August 1, 2014, the credit rating of PREPA was Caa2, CCC, and CC by each of Moody’s, Standard & Poor’s, and Fitch, respectively, which ratings are all below investment grade. In addition, in June 2014, Puerto Rico enacted legislation purportedly to establish a regime for public corporations in Puerto Rico like PREPA to restructure their debt and other obligations. The validity of such legislation is being challenged in U.S. federal court. On July 7, 2014, PREPA announced that it had reached a standstill agreement with certain of its lenders not to exercise remedies as a result of credit downgrades and other events, and it may delay certain currently due payments to these lenders until July 31, 2014. Such standstill was recently extended until August 14, 2014 while PREPA continues discussions with the lenders. While as of August 5, 2014, PREPA is current with respect to payments due under the PPA, a failure by PREPA to perform its payment obligations under the PPA, or a restructuring of its obligations under judicially determined valid legislation, may affect its obligations under the PPA which could have a material adverse effect on our business, financial condition and results of operations.

Natural events and operational problems may cause our power production to fall below our expectations.

Our electricity generation levels depend upon our ability to maintain the working order of our wind turbines and the balance of the plant. A natural disaster, severe weather, accident, failure of major equipment, shortage of or inability to acquire critical replacement or spare parts, failure in the operation of any future transmission facilities that we may acquire, including the failure of interconnection to available electricity transmission or distribution networks, could damage or require us to shut down our turbines or related equipment and facilities, impeding our ability to maintain and operate our facilities and decreasing electricity generation levels and our revenues. For example, our Ocotillo and Santa Isabel (Siemens) and Gulf Wind (MHI) projects have experienced certain blade failures in the last two years. We believe the Siemens blade failures have been fully addressed. Since commercial operation of Gulf Wind, three blades have failed. We have been working with MHI to complete a root cause analysis, testing of the 354 blades at the project, and developing of a protocol for determining which blades might have sufficient deficiencies that could pose a threat to long

term reliable operation. MHI has to date replaced 25 blades under the equipment warranty. While the testing and replacement of blades has adversely affected turbine availability at Gulf Wind in 2014, we expect MHI to compensate us for all, or most of, the turbine down time under our equipment warranty. Our equipment warranty with MHI expires in late 2014, and we are in discussions with MHI on addressing a longer term arrangement to address these potential deficiencies before the equipment warranty expires, although we can give no assurance that we will be able to reach any agreement with MHI. If these potential deficiencies do in fact occur and result in blade failures, replacement costs or other effects, and MHI does not address such deficiencies under the equipment warranty or other arrangement, any such effects could have a material adverse effect on our business, financial condition and results of operation.

In addition, climate change may have the long-term effect of changing wind patterns at our projects. Changing wind patterns could cause changes in expected electricity generation. These events could also degrade equipment or components and the interconnection and transmission facilities’ lives and increases our maintenance costs. Even though our projects enter into warranty agreements with the turbine manufacturers, such agreements are typically subject to an aggregate maximum cap and there can be no assurance that the supplier will be able to fulfill its contractual obligations.

In addition, replacement and spare parts for wind turbines and key pieces of electrical equipment may be difficult or costly to acquire or may be unavailable. Sources for some significant spare parts and other equipment are often located outside of the jurisdictions in which our power projects operate. Additionally, our operating projects generally do not hold spare substation main transformers. These transformers are designed specifically for each wind power project, and order lead times can be lengthy. If one of our projects had to replace any of its substation main transformers, it would be unable to sell all of its power until a replacement is installed. To the extent we experience a prolonged interruption at one of our operating projects due to natural events or operational problems and if such events are not fully covered by insurance, our electricity generation levels could materially decrease, this could result in a material adverse effect on our business, financial condition and results of operation.

Future sales of our shares in the public market could lower our Class A share price, and any additional capital raised by us through the sale of equity or convertible debt securities may dilute shareholders’ ownership in us and may adversely affect the market price of our Class A shares.

If we sell, or if Pattern Development sells, a large number of our Class A shares, or if we issue a large number of shares of our Class A common stock in connection with future acquisitions, financings, or other circumstances, the market price of our Class A shares could decline significantly. Moreover, the perception in the public market that we or Pattern Development might sell Class A shares could depress the market price of those shares. In addition, on May 6, 2014, Pattern Development entered into a loan agreement pursuant to which it may pledge up to 18,700,000 Class A shares to secure a $100.0 million loan. If Pattern Development were to default on its obligations under the loan, the lenders, upon the expiration of certain lock-up agreements, would have the right to sell shares to satisfy Pattern Development’s obligation. Such an event could cause our stock price to decline.

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

ITEM 6. EXHIBITS


Exhibit No.		Description

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

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

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

10.1		Purchase and Sale Agreement, dated May 1, 2014, by and among Pattern Energy Group Inc., Pattern Renewables LP and Pattern Energy Group LP (PH1 PSA) (Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K dated May 5, 2014)

31.1		Certifications of the Company’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certifications of the Company’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32*		Certifications of the Company’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS**		XBRL Instance Document

101.SCH**		XBRL Taxonomy Extension Schema Document

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB**		XBRL Taxonomy Extension Label Linkbase Document

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

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

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

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.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company