Pattern Energy Group Inc. - FORM 10-Q

Attached files

file	filename
EX-99.1 - EXHIBIT 99.1 - Pattern Energy Group Inc.	pegi-20150930xex991.htm
EX-32 - EXHIBIT 32 - Pattern Energy Group Inc.	pegi2015093010qexhibit32.htm
EX-31.1 - EXHIBIT 31.1 - Pattern Energy Group Inc.	pegi2015093010qexhibit311.htm
EX-31.2 - EXHIBIT 31.2 - Pattern Energy Group Inc.	pegi2015093010qexhibit312.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 September 30, 2015.



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-36087

PATTERN ENERGY GROUP INC.

(Exact name of Registrant as specified in its charter)



Delaware		90-0893251
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Pier 1, Bay 3, San Francisco, CA 94111

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (415) 283-4000

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes ¨ No x

As of October 30, 2015, there were 74,671,950 shares of Class A common stock outstanding with par value of $0.01 per share.



Table of Contents

PATTERN ENERGY GROUP INC.

REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2015

TABLE OF CONTENTS



	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	5
	Consolidated Balance Sheets as of September 30, 2015 (unaudited) and December 31, 2014	5
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014 (unaudited)	6
	Consolidated Statements of Comprehensive Loss for the Three and Nine Months Ended September 30, 2015 and 2014 (unaudited)	7
	Consolidated Statements of Stockholders’ Equity for the Nine Months Ended September 30, 2015 and 2014 (unaudited)	8
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014 (unaudited)	10
	Notes to Consolidated Financial Statements (unaudited)	12

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	60
Item 4.	Controls and Procedures	61

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 6.	Exhibits	64
	Signatures	66



Table of Contents

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 production tax credit ("PTC"), investment tax credit ("ITC") and potential reductions in Renewable Portfolio Standards ("RPS") requirements;


•	the ability of our counterparties to satisfy their financial commitments or business obligations;


•	the availability of financing, including tax equity financing, for our power projects;


•	an increase in interest rates;


•	our substantial short-term and long-term indebtedness, including additional debt in the future;


•	competition from other power project developers;


•	development constraints, including the availability of interconnection and transmission;


•	potential environmental liabilities and the cost and conditions of compliance with applicable environmental laws and regulations;


•	our ability to operate our business efficiently, manage capital expenditures and costs effectively and generate cash flow;


•	our ability to retain and attract executive officers and key employees;


•	our ability to keep pace with and take advantage of new technologies;


•	the effects of litigation, including administrative and other proceedings or investigations, relating to our wind power projects under construction and those in operation;


•	conditions in energy markets as well as financial markets generally, which will be affected by interest rates, foreign currency exchange rate fluctuations and general economic conditions;


•	the effectiveness of our currency risk management program;


•	the effective life and cost of maintenance of our wind turbines and other equipment;


•	the increased costs of, and tariffs on, spare parts;


•	scarcity of necessary equipment;


•	negative public or community response to wind power projects;


•	the value of collateral in the event of liquidation; and


•	other factors discussed under “Risk Factors.”



Table of Contents

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 Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015 and Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.



Table of Contents

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)

	September 30, 2015			December 31, 2014
Assets
Current assets:
Cash and cash equivalents	$	103,196		$	101,656
Restricted cash	18,111			7,945
Trade receivables	37,540			35,759
Related party receivable	689			671
Reimbursable interconnection costs	663			2,532
Derivative assets, current	21,912			18,506
Current net deferred tax assets	307			318
Prepaid expenses and other current assets	23,595			27,954
Deferred financing costs, current, net of accumulated amortization of $4,699 and $3,493 as of September 30, 2015 and December 31, 2014, respectively	1,991			1,747
Total current assets	208,004			197,088
Restricted cash	34,196			39,745
Turbine advances	25,956			79,637
Construction in progress	180,115			26,195
Property, plant and equipment, net of accumulated depreciation of $370,713 and $278,291 as of September 30, 2015 and December 31, 2014, respectively	3,066,461			2,350,856
Unconsolidated investments	115,177			29,079
Derivative assets	47,033			49,369
Deferred financing costs	4,926			5,166
Net deferred tax assets	12,112			5,474
Finite-lived intangible assets, net of accumulated amortization of $2,761 and $154 as of September 30, 2015 and December 31, 2014, respectively	99,398			1,257
Other assets	27,906			11,421
Total assets	$	3,821,284		$	2,795,287

Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities	$	36,107		$	24,793
Accrued construction costs	43,610			20,132
Related party payable	1,312			5,757
Accrued interest	6,598			3,634
Dividends payable	27,384			15,734
Derivative liabilities, current	16,360			16,307
Revolving credit facility	245,000			50,000
Current portion of long-term debt, net of financing costs of $5,082 and $11,868 as of September 30, 2015 and December 31, 2014, respectively	202,580			109,693
Current net deferred tax liabilities	149			149
Current portion of contingent liabilities	8,910			4,000
Total current liabilities	588,010			250,199
Long-term debt, net of financing costs of $19,959 and $24,887 as of September 30, 2015 and December 31, 2014, respectively	1,204,848			1,304,165
Convertible senior notes, net of financing costs of $5,271 and $0 as of September 30, 2015 and December 31, 2014, respectively	196,191			—
Derivative liabilities	33,203			17,467
Asset retirement obligations	41,553			29,272
Net deferred tax liabilities	24,140			20,418
Contingent liabilities	1,070			175
Finite-lived intangible liability, net of accumulated amortization of $1,301 and $0 as of September 30, 2015 and December 31, 2014, respectively	58,999			—
Other long-term liabilities	8,757			8,857
Total liabilities	2,156,771			1,630,553
Equity:
Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 74,671,950 and 62,062,841 shares outstanding as of September 30, 2015 and December 31, 2014, respectively	747			621
Additional paid-in capital	1,009,381			723,938
Accumulated loss	(79,613		)	(44,626		)
Accumulated other comprehensive loss	(75,666		)	(45,068		)
Treasury stock, at cost; 37,492 and 25,465 shares of Class A common stock as of September 30, 2015 and December 31, 2014, respectively	(1,048		)	(717		)
Total equity before noncontrolling interest	853,801			634,148
Noncontrolling interest	810,712			530,586
Total equity	1,664,513			1,164,734
Total liabilities and equity	$	3,821,284		$	2,795,287

See accompanying notes to consolidated financial statements



Table of Contents

Pattern Energy Group Inc. Consolidated Statements of Operations (In thousands of U.S. Dollars, except share data) (Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Revenue:
Electricity sales	$	80,657		$	64,251		$	218,586		$	184,175
Energy derivative settlements	2,969			2,591			15,066			9,309
Unrealized gain (loss) on energy derivative	4,630			3,139			1,600			(11,143		)
Related party revenue	955			868			2,630			2,330
Other revenue	486			670			1,352			1,404
Total revenue	89,697			71,519			239,234			186,075
Cost of revenue:
Project expense	28,848			23,835			82,075			56,609
Depreciation and accretion	38,599			30,015			101,997			72,476
Total cost of revenue	67,447			53,850			184,072			129,085
Gross profit	22,250			17,669			55,162			56,990
Operating expenses:
General and administrative	7,218			5,772			22,309			15,963
Related party general and administrative	1,887			1,492			5,316			4,155
Total operating expenses	9,105			7,264			27,625			20,118
Operating income	13,145			10,405			27,537			36,872
Other expense:
Interest expense	(19,941		)	(17,999		)	(56,802		)	(48,427		)
Interest rate derivative settlements	(2,412		)	(1,030		)	(4,331		)	(3,082		)
Unrealized (loss) gain on derivatives, net	(5,090		)	66			(2,393		)	(6,599		)
Realized loss on derivatives, net	(9,810		)	—			(9,810		)	—
Equity in (losses) earnings in unconsolidated investments	(9,951		)	(5,002		)	768			(21,238		)
Related party income	605			664			2,029			1,736
Early extinguishment of debt	(4,113		)	—			(4,113		)	—
Net (loss) gain on transactions	(74		)	(68		)	(2,663		)	14,469
Other income (expense), net	128			145			(1,280		)	751
Total other expense	(50,658		)	(23,224		)	(78,595		)	(62,390		)
Net loss before income tax	(37,513		)	(12,819		)	(51,058		)	(25,518		)
Tax (benefit) provision	(2,181		)	(3,538		)	676			(1,505		)
Net loss	(35,332		)	(9,281		)	(51,734		)	(24,013		)
Net loss attributable to noncontrolling interest	(5,927		)	(2,073		)	(16,747		)	(13,115		)
Net loss attributable to controlling interest	$	(29,405	)	$	(7,208	)	$	(34,987	)	$	(10,898	)
Loss per share information:
Net loss attributable to controlling interest	$	(29,405	)	$	(7,208	)	$	(34,987	)	$	(10,898	)
Dividends declared on Class A common shares	(27,113		)	(15,258		)	(75,117		)	(41,395		)
Deemed dividends on Class B common shares	N/A			(7,222		)	N/A			(14,679		)
Undistributed loss attributable to common stockholders	$	(56,518	)	$	(29,688	)	$	(110,104	)	$	(66,972	)
Weighted average number of shares:
Class A common stock - Basic	72,789,583			46,317,932			69,233,698			41,022,962
Class A common stock - Diluted	72,789,583			46,317,932			69,233,698			56,577,962
Class B common stock - Basic and diluted	N/A			15,555,000			N/A			15,555,000
Loss per share
Class A common stock:
Basic loss per share	$	(0.40	)	$	(0.15	)	$	(0.51	)	$	(0.17	)
Diluted loss per share	$	(0.40	)	$	(0.15	)	$	(0.51	)	$	(0.19	)
Class B common stock:
Basic and diluted loss per share	N/A			$	(0.02	)	N/A			$	(0.24	)
Dividends declared per Class A common share	$	0.36		$	0.33		$	1.06		$	0.96
Deemed dividends per Class B common share	N/A			$	0.46		N/A			$	0.94

See accompanying notes to consolidated financial statements



Table of Contents

Pattern Energy Group Inc. Consolidated Statements of Comprehensive Loss (In thousands of U.S. Dollars) (Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Net loss	$	(35,332	)	$	(9,281	)	$	(51,734	)	$	(24,013	)
Other comprehensive loss:
Foreign currency translation, net of zero tax impact	(12,208		)	(5,706		)	(21,900		)	(6,575		)
Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax benefit of $892, $132, $948 and $198, respectively	(15,600		)	(1,960		)	(16,257		)	(19,986		)
Reclassifications to net loss due to termination of interest rate derivatives, net of zero tax impact	11,221			—			11,221			—
Reclassifications to net loss, net of tax impact of $170, $132, $511 and $169, respectively	2,590			3,658			9,546			10,215
Total change in effective portion of change in fair market value of derivatives	(1,789		)	1,698			4,510			(9,771		)
Proportionate share of equity investee’s derivative activity:
Effective portion of change in fair market value of derivatives, net of tax benefit of $1,627, $109, $2,486, and $1,914, respectively	(4,513		)	(275		)	(6,895		)	(4,558		)
Reclassifications to net loss, net of tax impact of $194, $0, $571, and $0, respectively	537			—			1,582			—
Total change in effective portion of change in fair market value of derivatives	(3,976		)	(275		)	(5,313		)	(4,558		)
Total other comprehensive loss, net of tax	(17,973		)	(4,283		)	(22,703		)	(20,904		)
Comprehensive loss	(53,305		)	(13,564		)	(74,437		)	(44,917		)
Less comprehensive loss attributable to noncontrolling interest:
Net loss attributable to noncontrolling interest	(5,927		)	(2,073		)	(16,747		)	(13,115		)
Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax benefit of $268, $40, $285 and $60, respectively	(1,023		)	330			(2,008		)	(1,565		)
Reclassifications to net loss, net of tax impact of $51, $40, $153 and $51, respectively	138			959			1,959			2,675
Total change in effective portion of change in fair market value of derivatives	(885		)	1,289			(49		)	1,110
Comprehensive loss attributable to noncontrolling interest	(6,812		)	(784		)	(16,796		)	(12,005		)
Comprehensive loss attributable to controlling interest	$	(46,493	)	$	(12,780	)	$	(57,641	)	$	(32,912	)

See accompanying notes to consolidated financial statements



Table of Contents

Pattern Energy Group Inc. Consolidated Statements of Stockholders’ Equity (In thousands of U.S. Dollars, except share data) (Unaudited)

	Controlling Interest																							Noncontrolling Interest
	Class A Common Stock			Class B Common Stock												Treasury Stock
	Shares	Amount		Shares	Amount		Additional Paid-in Capital			Accumulated Loss			Accumulated Other Comprehensive Loss			Shares		Amount			Total			Capital			Accumulated Income (Loss)			Accumulated Other Comprehensive Loss			Total			Total Equity
Balances at December 31, 2013	35,531,720	$	355	15,555,000	$	156	$	489,412		$	(13,336	)	$	(8,353	)	(934	)	$	(24	)	$	468,210		$	90,217		$	18,601		$	(9,024	)	$	99,794		$	568,004
Issuance of Class A common stock related to the public offering, net of issuance costs	10,810,810	108		—	—		286,711			—			—			—		—			286,819			—			—			—			—			286,819
Issuances of Class A common stock under equity incentive award plan	175,915	2		—	—		(2		)	—			—			—		—			—			—			—			—			—			—
Issuance of Class A common stock upon exercise of stock options	12,431	—		—	—		273			—			—			—		—			273			—			—			—			—			273
Repurchase of shares for employee tax withholding	—	—		—	—		—			—			—			(11,780	)	(380		)	(380		)	—			—			—			—			(380		)
Stock-based compensation	—	—		—	—		3,128			—			—			—		—			3,128			—			—			—			—			3,128
Refund of issuance costs related to the IPO	—	—		—	—		163			—			—			—		—			163			—			—			—			—			163
Dividends declared on Class A common stock	—	—		—	—		(41,395		)	—			—			—		—			(41,395		)	—			—			—			—			(41,395		)
Recognition of beneficial conversion feature on Class B convertible common stock	—	—		—	—		(21,901		)	—			—			—		—			(21,901		)	—			—			—			—			(21,901		)
Adjustment to paid-in capital for beneficial conversion feature recognition	—	—		—	—		21,901			—			—			—		—			21,901			—			—			—			—			21,901
Accretion of the Class B common stock beneficial conversion feature	—	—		—	—		14,679			—			—			—		—			14,679			—			—			—			—			14,679
Deemed dividends on Class B convertible common stock	—	—		—	—		(14,679		)	—			—			—		—			(14,679		)	—			—			—			—			(14,679		)
Sale of Class A membership interests in Panhandle 1	—	—		—	—		—			—			—			—		—			—			210,250			—			—			210,250			210,250
Acquisition of AEI ownership in E1 Arrayan	—	—		—	—		—			—			—			—		—			—			35,259			—			—			35,259			35,259
Contribution from noncontrolling interest	—	—		—	—		—			—			—			—		—			—			2,550			—			—			2,550			2,550
Distribution to noncontrolling interest	—	—		—	—		—			—			—			—		—			—			(1,470		)	—			—			(1,470		)	(1,470		)
Net loss	—	—		—	—		—			(10,898		)	—			—		—			(10,898		)	—			(13,115		)	—			(13,115		)	(24,013		)
Other comprehensive (loss) income, net of tax	—	—		—	—		—			—			(22,014		)	—		—			(22,014		)	—			—			1,110			1,110			(20,904		)
Balances at September 30, 2014	46,530,876	$	465	15,555,000	$	156	$	738,290		$	(24,234	)	$	(30,367	)	(12,714	)	$	(404	)	$	683,906		$	336,806		$	5,486		$	(7,914	)	$	334,378		$	1,018,284

See accompanying notes to consolidated financial statements



Table of Contents

Pattern Energy Group Inc. Consolidated Statements of Stockholders’ Equity (In thousands of U.S. Dollars, except share data) (Unaudited)

	Controlling Interest																							Noncontrolling Interest
	Class A Common Stock			Class B Common Stock												Treasury Stock
	Shares	Amount		Shares	Amount		Additional Paid-in Capital			Accumulated Loss			Accumulated Other Comprehensive Loss			Shares		Amount			Total			Capital			Accumulated Income (Loss)			Accumulated Other Comprehensive Loss			Total			Total Equity
Balances at December 31, 2014	62,088,306	$	621	—	$	—	$	723,938		$	(44,626	)	$	(45,068	)	(25,465	)	$	(717	)	$	634,148		$	529,539		$	9,892		$	(8,845	)	$	530,586		$	1,164,734
Issuance of Class A common stock related to the public offering, net of issuance costs	12,435,000	124		—	—		316,848			—			—			—		—			316,972			—			—			—			—			316,972
Issuance of Class A common stock under equity incentive award plan	186,136	2		—	—		(2		)	—			—			—		—			—			—			—			—			—			—
Repurchase of shares for employee tax withholding	—	—		—	—		—			—			—			(12,027	)	(331		)	(331		)	—			—			—			—			(331		)
Stock-based compensation	—	—		—	—		3,234			—			—			—		—			3,234			—			—			—			—			3,234
Dividends declared on Class A common stock	—	—		—	—		(75,117		)	—			—			—		—			(75,117		)	—			—			—			—			(75,117		)
Dividend equivalents declared upon vesting of deferred restricted stock units	—	—		—	—		11			—			—			—		—			11			—			—			—			—			11
Acquisition of Post Rock	—	—		—	—		—			—			—			—		—			—			205,100			—			—			205,100			205,100
Conversion option of convertible senior notes, net of issuance costs	—	—		—	—		23,754			—			—			—		—			23,754			—			—			—			—			23,754
Buyout of noncontrolling interests - Gulf Wind	—	—		—	—		17,189			—			(7,944		)	—		—			9,245			(88,747		)	(14,244		)	7,944			(95,047		)	(85,802		)
Buyout of noncontrolling interest - Lost Creek	—	—		—	—		(474		)	—			—			—		—			(474		)	—			—			—			—			(474		)
Contribution from noncontrolling interests - Logan's Gap, net of issuance costs	—	—		—	—		—			—			—			—		—			—			191,251			—			—			191,251			191,251
Distribution to noncontrolling interests	—	—		—	—		—			—			—			—		—			—			(4,382		)	—			—			(4,382		)	(4,382		)
Net loss	—	—		—	—		—			(34,987		)	—			—		—			(34,987		)	—			(16,747		)	—			(16,747		)	(51,734		)
Other comprehensive loss, net of tax	—	—		—	—		—			—			(22,654		)	—		—			(22,654		)	—			—			(49		)	(49		)	(22,703		)
Balances at September 30, 2015	74,709,442	$	747	—	$	—	$	1,009,381		$	(79,613	)	$	(75,666	)	(37,492	)	$	(1,048	)	$	853,801		$	832,761		$	(21,099	)	$	(950	)	$	810,712		$	1,664,513

See accompanying notes to consolidated financial statements



Table of Contents

Pattern Energy Group Inc. Consolidated Statements of Cash Flows (In thousands of U.S. Dollars) (Unaudited)

	Nine months ended September 30,
	2015			2014
Operating activities
Net loss	$	(51,734	)	$	(24,013	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion	102,108			72,476
Loss on disposal of equipment	398			—
Amortization of financing costs	5,581			4,246
Unrealized loss on derivatives, net	793			17,742
Stock-based compensation	3,234			3,128
Net gain on transactions	—			(16,526		)
Deferred taxes	340			(1,505		)
Equity in (earnings) losses in unconsolidated investments	(813		)	21,238
Unrealized loss on exchange rate changes	823			—
Amortization of power purchase agreements, net	1,175			—
Amortization of debt discount/premium, net	798			—
Realized loss on derivatives, net	10,192			—
Early extinguishment of debt	3,958			—
Changes in operating assets and liabilities:
Trade receivables	5,657			(5,255		)
Prepaid expenses and other current assets	(2,589		)	13,139
Other assets (non-current)	(2,022		)	(503		)
Accounts payable and other accrued liabilities	4,180			1,642
Related party receivable/payable	506			(1,017		)
Accrued interest payable	1,970			(917		)
Contingent liabilities	764			—
Long-term liabilities	83			25
Increase in restricted cash	(2,120		)	—
Net cash provided by operating activities	83,282			83,900
Investing activities
Cash paid for acquisitions, net of cash acquired	(406,284		)	(167,585		)
Decrease in restricted cash	41,820			23,861
Increase in restricted cash	(33,890		)	(10,406		)
Capital expenditures	(315,954		)	(18,615		)
Distribution from unconsolidated investments	23,494			17,104
Contribution to unconsolidated investments	—			(2,320		)
Reimbursable interconnection receivable	1,869			1,418
Other assets	2,781			2,472
Net cash used in investing activities	(686,164		)	(154,071		)

See accompanying notes to consolidated financial statements



Table of Contents

Pattern Energy Group Inc. Consolidated Statements of Cash Flows (In thousands of U.S. Dollars) (Unaudited)

	Nine months ended September 30,
	2015			2014
Financing activities
Proceeds from public offering, net of expenses	$	317,822		$	286,834
Proceeds from issuance of convertible senior notes, net of issuance costs	219,557			—
Proceeds from exercise of stock options	—			273
Repurchase of shares for employee tax withholding	(331		)	(380		)
Dividends paid	(63,455		)	(37,104		)
Payment for deferred equity issuance costs	(1,940		)	—
Buyout of noncontrolling interest	(121,224		)	—
Capital contributions - noncontrolling interest	193,064			2,550
Capital distributions - noncontrolling interest	(4,382		)	(1,470		)
Decrease in restricted cash	41,429			13,508
Increase in restricted cash	(41,184		)	(13,508		)
Refund of deposit for letters of credit	3,425			—
Payment for deferred financing costs	(8,445		)	(603		)
Proceeds from revolving credit facility	295,000			—
Repayment of revolving credit facility	(100,000		)	—
Proceeds from construction loans	294,502			1,087
Repayment of long-term debt	(405,036		)	(53,085		)
Payment for interest rate derivatives	(11,061		)	—
Net cash provided by financing activities	607,741			198,102
Effect of exchange rate changes on cash and cash equivalents	(3,319		)	(842		)
Net change in cash and cash equivalents	1,540			127,089
Cash and cash equivalents at beginning of period	101,656			103,569
Cash and cash equivalents at end of period	$	103,196		$	230,658
Supplemental disclosures
Cash payments for interest expense, net of capitalized interest	$	38,241		$	43,040
Acquired property, plant and equipment from acquisitions	579,712			674,743
Schedule of non-cash activities
Change in fair value of designated interest rate swaps	4,510			(18,541		)
Change in property, plant and equipment	20,744			(97,051		)
Non-cash deemed dividends on Class B convertible common stock	—			14,679
Non-cash increase in additional paid-in capital from buyout of noncontrolling interests	16,715			—
Equity issuance costs paid in prior period related to current period offerings	433			—

See accompanying notes to consolidated financial statements



Table of Contents

Pattern Energy Group Inc.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

Pattern Energy Group Inc. (“Pattern Energy” or the “Company”) was organized in the state of Delaware on October 2, 2012. Pattern Energy issued 100 shares on October 17, 2012 to Pattern Renewables LP, a 100% owned subsidiary of Pattern Energy Group LP (“Pattern Development”). On September 24, 2013, Pattern Energy’s charter was amended, and the number of shares that Pattern Energy is authorized to issue was increased to 620,000,000 total shares; 500,000,000 of which are designated Class A common stock, 20,000,000 of which were designated Class B common stock, and 100,000,000 of which are designated Preferred Stock. On October 2, 2013, concurrent with the initial public offering, the Company also issued to Pattern Development 19,445,000 shares of Class A common stock, representing 63% of the Company's Class A common stock outstanding at the time, and 15,555,000 shares of Class B common stock. On December 31, 2014, the Company’s outstanding Class B common stock was converted into Class A common stock on a one-for-one basis. Shares of Class B common stock converted into shares of Class A common stock were retired. The Company is not authorized to reissue shares of Class B common stock.

On May 14, 2014, the Company completed an underwritten public offering of its Class A common stock resulting in a reduction of Pattern Development’s interest in the Company from approximately 63% to 35%. Consequently, the Company is no longer subject to ASC 805-50-30-5, Transactions between Entities under Common Control. All transactions with Pattern Development after May 14, 2014 are recognized at fair value on the measurement date in accordance with the Accounting Standard Codification (“ASC”) 805 – Business Combinations. On February 9, 2015, the Company completed an underwritten public offering of its Class A common stock, resulting in a further reduction of Pattern Development’s interest in the Company from 35% to 25% causing it to no longer be entitled to certain approval rights pursuant to the Shareholder Approval Rights Agreement dated October 2, 2013.

Pattern Energy is an independent energy generation company focused on constructing, owning and operating energy projects with long-term energy sales contracts located in the United States, Canada and Chile. The Company consists of the consolidated operations of certain entities and assets contributed by, or purchased principally from, Pattern Development. The Company owns 100% of Hatchet Ridge Wind, LLC (“Hatchet Ridge”), St. Joseph Windfarm Inc. (“St. Joseph”), Spring Valley Wind LLC (“Spring Valley”), Pattern Santa Isabel LLC (“Santa Isabel”), Ocotillo Express LLC (“Ocotillo”), Fowler Ridge IV Wind Farm LLC (“Amazon Wind Farm (Fowler Ridge)”), Pattern Gulf Wind LLC ("Gulf Wind") and Lost Creek Wind, LLC ("Lost Creek"). The Company owns a controlling interest in Parque Eólico El Arrayán SpA (“El Arrayán”), Panhandle Wind Holdings LLC (“Panhandle 1”), Panhandle B Member 2 LLC (“Panhandle 2”), Post Rock Wind Power Project, LLC (“Post Rock”) and Logan's Gap Wind LLC ("Logan's Gap"), and noncontrolling interests in South Kent Wind LP (“South Kent”), Grand Renewable Wind LP (“Grand”) and K2 Wind Ontario Limited Partnership (“K2”). The principal business objective of the Company is to produce stable and sustainable cash flows through the generation and sale of energy and to selectively grow its project portfolio.

2. Summary of Significant Accounting Policies

As of September 30, 2015, the Company has added the following significant accounting policies to the significant accounting policies described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014: change in depreciable lives of property, plant and equipment, asset acquisitions, finite-lived intangible assets and change in presentation of deferred financing costs within short-term and long-term debt, as described below.

Basis of Presentation and Principles of Consolidation

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

Unaudited Interim Financial Information

The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and Article 10 of Regulation S-X issued by the U.S. Securities and Exchange Commission (“SEC”). Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, the interim financial information reflects all adjustments of a normal recurring nature, necessary for a fair presentation of the Company’s financial position at September 30, 2015, the results of operations and comprehensive



Table of Contents

loss for the three and nine months ended September 30, 2015 and 2014, respectively, and the cash flows for the nine months ended September 30, 2015 and 2014, respectively. The consolidated balance sheet at December 31, 2014 has been derived from the audited financial statements at that date, but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements. This Form 10-Q should be read in conjunction with the consolidated financial statements and accompanying notes contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Use of Estimates

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

Change in Depreciable Lives of Property, Plant and Equipment

The Company periodically reviews the estimated economic useful lives of its fixed assets. In 2015, this review indicated that the expected economic useful lives of certain wind farms were longer than the estimated economic useful lives used for depreciation purposes in the Company’s financial statements. As a result, effective January 1, 2015, the Company changed its estimate of the economic useful lives of wind farms for which construction began after 2011, from 20 to 25 years. All other wind farms continue to depreciate over an estimated economic useful life of 20 years. For the three and nine months ended September 30, 2015, the effect of this change reduced depreciation expense by $3.6 million and $11.0 million, respectively, decreased net loss by $3.4 million and $10.4 million, net of tax, respectively, and decreased Class A basic and diluted loss per share by $0.02 and $0.07, respectively.

Acquisitions

Business Combinations

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

Asset Acquisitions

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

Equity Method Investments

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

Noncontrolling Interests

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



Table of Contents

For the noncontrolling interests at the Company’s Panhandle 1, Panhandle 2, Post Rock and Logan's Gap projects, and previously the Company's Gulf Wind project prior to the acquisition of the noncontrolling interests in July 2015, the Company has determined that the operating partnership agreements do not allocate economic benefits pro rata to its two classes of investors and has determined that the appropriate methodology for calculating the noncontrolling interest balance that reflects the substantive profit sharing arrangement is a balance sheet approach using the hypothetical liquidation at book value (“HLBV”) method.

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

Concentrations of Credit Risk

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

The Company sells electricity and environmental attributes primarily to creditworthy utilities under long-term, fixed-priced Power Sale Arrangements (“PPAs”). During 2015, Standard & Poor’s Rating Services (“S&P”) further downgraded the credit rating of the Puerto Rico Electric Power Authority (“PREPA”) from CCC to CC. Through September 30, 2015, Moody’s Investor Service’s credit rating of PREPA remains unchanged at Caa3. As of September 30, 2015 and November 5, 2015, PREPA was current with respect to payments due under the PPA.

The following table presents significant customers who accounted for the following percentages of total revenues during the three and nine months ended September 30, 2015 and 2014, respectively, and the related maximum amount of credit loss based on their respective percentages of total trade receivables:



	Revenue								Trade Receivables
	Three months ended September 30,				Nine months ended September 30,				Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014		2015		2014		2015		2014
San Diego Gas & Electric	19.62	%	23.34	%	19.08	%	26.37	%	25.56	%	30.05	%	25.56	%	30.05	%
PREPA	9.17	%	10.90	%	9.54	%	11.04	%	11.80	%	13.46	%	11.80	%	13.46	%

The Independent Electricity System Operator (“IESO”) of Ontario, Canada is the customer for each of the Company’s Grand, K2 and South Kent projects. The Company accounts for these projects under the equity method of accounting and as a result, the Company’s ownership interest in these projects is recorded in equity in (losses) earnings in unconsolidated investments and not in revenue. As such, IESO is not included in the foregoing table of significant customers. However, we rely on a limited number of key power purchasers, including IESO, and face a concentration of credit risk from IESO as a customer.

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

Finite-Lived Intangible Assets

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



Table of Contents

The Company amortizes intangible assets and liabilities associated with PPAs using the straight-line method over the remaining term of the related PPA. The intangible asset associated with the PPA is amortized over approximately 15 years and the intangible liability associated with the PPA is amortized over approximately 17 years. The Company amortizes easements, land options and mining rights using the straight-line method over the term of their estimated useful lives, which represents the term of the easements and land option and mining rights agreements, ranging from approximately 5-25 years. The Company periodically evaluates whether events or changes in circumstances have occurred that indicate the carrying amount of finite-lived intangible assets may not be recoverable, or information indicates that impairment may exist.

Reclassification

Certain prior period balances have been reclassified to conform to the current period presentation in the Company’s consolidated financial statements and the accompanying notes.

The Company has also revised its consolidated statements of comprehensive loss for the three and nine months ended September 30, 2014 to correct an immaterial classification error. The consolidated statements of comprehensive loss for the three and nine months ended September 30, 2014 has been corrected to reflect the reclassification of approximately $7.3 million and $20.4 million, respectively, between the effective portion of change in fair market value of derivatives and reclassification to net loss for controlling interest. The consolidated statements of comprehensive loss for the three and nine months ended September 30, 2014 has also been corrected to reflect the reclassification of approximately $1.9 million and $5.4 million, respectively, between the effective portion of change in fair market value of derivatives and reclassification to net loss for noncontrolling interest. These revisions had no impact on comprehensive loss or comprehensive loss attributable to noncontrolling interest. The accumulated other comprehensive loss footnote has also been corrected to reflect this immaterial error correction.

The Company has also revised its supplemental cash flow disclosures for cash payments of interest expenses, net of capitalized interest, to include $3.3 million of interest payments, which represents the correction of an immaterial error, for the nine months ended September 30, 2014.

Recently Issued Accounting Standards

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-16, “Business Combinations: Simplifying the Accounting for Measurement-Period Adjustments,” which requires an acquirer to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments under ASU 2015-16 require that the acquirer record, in the same period's financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. ASU 2015-16 also requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods, if the adjustment to the provisional amounts had been recognized as of the acquisition date. ASU 2015-16 is effective for annual reporting periods beginning after December 15, 2015 and interim periods within those fiscal years. The amendments in this update should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The Company is currently assessing the future impact of this update on its consolidated financial statements and expects to adopt this update beginning January 1, 2016.

In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers: Deferral of the Effective Date” to amend ASU 2015-09 “Revenue from Contracts with Customers” to defer the effective date of ASU 2014-09 for all entities by one year. The guidance in ASU 2014-09 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. As a result of this amendment, ASU 2014-09 is now effective for annual reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted only as of annual reporting periods beginning after December 15, 2015 and interim periods within those fiscal years. The guidance permits companies to either apply the requirements retrospectively to all prior periods presented, or apply the requirements in the year of adoption, through a cumulative adjustment. In June 2015, the FASB voted to defer the effective date by one year, with early adoption permitted as of the original effective date. The Company is currently assessing the future impact of this update on its consolidated financial statements and related disclosures and expects to adopt this update beginning January 1, 2018.



Table of Contents

In August 2015, the FASB issued ASU 2015-13, “Derivatives and Hedging: Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” to allow the application of the normal purchases and normal sales scope exception to certain electricity contracts within nodal energy markets. The amendments specify that the purchase or sale of electricity on a forward basis within nodal energy markets does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. The amendments in this update are effective upon issuance and are in line with the Company’s current accounting policies. The adoption of ASU 2015-13 did not have an impact to the Company’s consolidated financial statements and related disclosures.

In July 2015, the FASB issued ASU 2015-11, “Inventory: Simplifying the Measurement of Inventory” which changes the measurement principle for inventory from the lower of cost or market to the lower of cost and net realizable value. Net realizable value is defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments do not apply to inventory that is measured using last-in, first-out or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first out or average cost. ASU 2015-11 is effective for annual reporting periods beginning after December 15, 2016 and interim periods within those fiscal years. The amendments in this update should be applied prospectively. Early adoption is permitted as of the beginning of an interim or annual reporting period. The adoption of the provisions of ASU 2015-11 is not expected to have a material impact on the Company’s consolidated financial statements and related disclosures. The Company expects to adopt this update beginning January 1, 2017.

In June 2015, the FASB issued ASU 2015-10, “Technical Corrections and Improvements” which covers a wide range of topics in the Accounting Standards Codification (the “Codification”). The amendments in this update represent changes to clarify the Codification, correct unintended application of guidance, or make minor improvements to the Codification that are not expected to have a significant effect on current accounting practice or create a significant administrative cost on most entities. The amendments in ASU 2015-10 were effective immediately upon issuance and the adoption did not have material impact on the Company's consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03, “Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. ASU 2015-03 is effective for public companies for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years and should be applied retrospectively. Early adoption is permitted for financial statements that have not been previously issued. Upon transition, an entity is required to comply with the applicable disclosures for a change in accounting principle. The Company adopted this standard in April 2015 and applied the change in accounting principle to the consolidated financial statements as of September 30, 2015. As a result, the Company reclassified $25.0 million and $36.8 million in total deferred financing costs to long-term debt, of which $5.1 million and $11.9 million have been reclassified to current portion of long-term debt, as of September 30, 2015 and December 31, 2014, respectively, on the Company’s consolidated balance sheets. Deferred financing costs related to the Company’s revolving credit facility remains classified as an asset on the Company’s consolidated balance sheets. The adoption of ASU 2015-3 had no impact on the Company’s results of operations and cash flows.

In February 2015, the FASB issued ASU 2015-02, “Consolidation: Amendments to the Consolidation Analysis” to modify the analysis that companies must perform in order to determine whether a legal entity should be consolidated. ASU 2015-02 simplifies current guidance by reducing the number of consolidation models; eliminating the risk that a reporting entity may have to consolidate based on a fee arrangement with another legal entity; placing more weight on the risk of loss in order to identify the party that has a controlling financial interest; reducing the number of instances that related party guidance needs to be applied when determining the party that has a controlling financial interest; and changing rules for companies in certain industries that ordinarily employ limited partnership or VIE structures. ASU 2015-02 is effective for public companies for fiscal years beginning after December 15, 2015 and interim periods within those fiscal periods. Early adoption on a modified retrospective or full retrospective basis is permitted. The Company is currently assessing the future impact of this update on its consolidated financial statements and related disclosures and expects to adopt this update beginning January 1, 2016.



Table of Contents

3. Acquisitions

Business Combinations

Wind Capital Group Acquisition

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

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

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



	May 15, 2015
Cash and cash equivalents	$	3,501
Restricted cash, current	11,787
Trade receivables	7,910
Prepaid expenses and other current assets	1,676
Restricted cash	4,592
Property, plant and equipment	541,300
Finite-lived intangible assets, net of accumulated amortization	97,400
Other assets	19,935
Accounts payable and other accrued liabilities	(2,588		)
Accrued interest	(951		)
Derivative liabilities, current	(4,236		)
Current portion of long-term debt, net of financing costs	(7,463		)
Finite-lived intangible liabilities, net of accumulated amortization	(60,300		)
Asset retirement obligations	(6,994		)
Long-term debt, net of financing costs	(108,838		)
Derivative & other long-term liabilities, less current portion	(14,631		)
Total consideration before temporary equity and noncontrolling interests	482,100
Less: temporary equity	(35,000		)
Less: noncontrolling interests	(205,100		)
Total consideration after temporary equity and noncontrolling interests	$	242,000

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



Table of Contents

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

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

The Company incurred transaction related credits of $0.2 million and expenses of $1.7 million which were recorded in net (loss) gain on transactions in the consolidated statements of operations for the three and nine months ended September 30, 2015, respectively.

On July 30, 2015, the Company acquired 100% of the Class A membership interests in Lost Creek Wind Holdco for a cash purchase price of approximately $35.2 million, which was previously recorded in temporary equity - noncontrolling interests, in the Company's consolidated balance sheets at June 30, 2015. As a result, Lost Creek is wholly owned as of September 30, 2015.

Panhandle 2 Acquisition

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

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

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

The accounting for the Panhandle 2 acquisition was completed as of March 31, 2015 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of November 10, 2014 as well as adjustments made through March 31, 2015, when the allocation became final. The consolidated fair value of the assets acquired and liabilities assumed in connection with the Panhandle 2 acquisition are as follows (in thousands):



	November 10, 2014
Cash and cash equivalents	$	240
Trade receivables	1,156
Prepaid expenses and other current assets	28,997
Property, plant and equipment	315,109
Accrued construction costs	(24,197		)
Related party payable	(121		)
Short-term debt	(195,351		)
Asset retirement obligation	(2,003		)
Total consideration	$	123,830

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



Table of Contents

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

Logan’s Gap Acquisition

On December 19, 2014, the Company acquired 100% of the membership interests in the Logan’s Gap wind project, through the acquisition of Logan’s Gap B Member LLC, from Pattern Development, for a purchase price of approximately $15.1 million and an assumed contingent liability to a third party in the amount of $8.0 million associated with the close of construction financing and the achievement of either commercial operation or tax equity funding. The wind project was under construction at the time of acquisition and is located in Comanche County, Texas. The construction of the project was being financed primarily by construction debt and Pattern Energy equity. Following construction, it was expected that institutional tax equity investors would invest in the project, pursuant to an executed equity commitment agreement, so that the construction loan would be paid off such that long term financing for the project will be equity based. Following the achievement of commercial operations, in September 2015, the Company and certain tax equity investors made capital contributions to fund the repayment of the Logan's Gap construction loan. As a result, the Company and the tax equity investors hold initial ownership interests of 82% and 18%, respectively, in the project’s distributable cash flows.

The Company acquired the assets and operating contracts for Logan’s Gap, including assumed liabilities. The identifiable assets acquired and liabilities assumed were recorded at their fair values which corresponded to the sum of the cash purchase price.

The accounting for the Logan’s Gap acquisition was completed as of March 31, 2015 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 19, 2014, as well as adjustments made through March 31, 2015, when the allocation became final. The consolidated fair value of the assets acquired and liabilities assumed in connection with the Logan’s Gap acquisition are as follows (in thousands):



	December 19, 2014
Cash and cash equivalents	$	2
Restricted cash, current	5,003
Prepaid expenses and other current assets	1,790
Deferred financing costs, current	2,882
Construction in progress	23,821
Property, plant and equipment	116
Other assets	80
Accrued construction costs	(5,617		)
Current portion of contingent liabilities	(7,975		)
Related party payable	(5,003		)
Total consideration	$	15,099

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

The Company recorded $8.0 million in contingent obligations, payable to a third party, at fair value upon and following the acquisition of the project. Of this amount, $4.0 million was paid in December 2014, upon the closing of construction financing. Of the remaining $4.0 million liability, $2.3 million was paid upon achievement of commercial operations in early September 2015. Pending final resolution among the parties of the appropriate amounts that would be payable either to the third party recipient or the local tax authorities, the Company has not yet made payment of the remainder and recorded $1.7 million in accrued liabilities as of September 30, 2015.



Table of Contents

Panhandle 1 Acquisition

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

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

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

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

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



	June 30, 2014
Cash and cash equivalents	$	1,038
Trade receivables	1,850
Prepaid expenses and other current assets	71
Restricted cash, non-current	14,293
Property, plant and equipment	332,953
Accounts payable and other accrued liabilities	(148		)
Accrued construction costs	(12,806		)
Related party payable	(44		)
Asset retirement obligation	(2,557		)
Total consideration before non-controlling interest	334,650
Less: tax equity noncontrolling interest contributions	(210,250		)
Total consideration after non-controlling interest	$	124,400

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

El Arrayán Acquisition

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



Table of Contents

Prior to the acquisition, the Company accounted for the investment under the equity method of accounting. Because the Company acquired an additional 38.5% indirect interest in El Arrayán, in accordance with ASC 805 Business Combinations, the acquisition was accounted for as a “business combination achieved in stages.” Accordingly, the Company remeasured the previously held equity interest in El Arrayán and adjusted it to fair value based on the Company’s existing equity interest in the fair value of the underlying assets and liabilities of El Arrayán. The fair value of the Company’s equity interest at the acquisition date was $37.0 million (31.5% of implied equity value of $117.5 million per below). The difference between the fair value of the Company’s ownership in El Arrayán and the Company’s carrying value of its investment of $19.1 million resulted in a gain of $17.9 million recorded in net gain on transactions in the consolidated statements of operations for the year ended December 31, 2014. The Company recognized additional deferred tax liability due to differences in accounting and tax bases resulting from the Company’s existing ownership interest in El Arrayán, which has been included in the consolidated statements of operations. The Company now holds a 70% controlling interest in the wind project and consolidates the accounts of El Arrayán.

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

The accounting for the AEI El Arrayán acquisition was completed as of December 31, 2014 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of June 25, 2014, as well as adjustments made through December 31, 2014, when the allocation became final. The consolidated fair value of the assets acquired and liabilities assumed in connection with the AEI El Arrayán acquisition are as follows (in thousands):



	Consolidated interest June 25, 2014
Cash and cash equivalents	$	713
Trade receivables	3,829
VAT receivable	17,031
Prepaid expenses and other current assets	174
Restricted cash, non-current	10,392
Property, plant and equipment	341,417
Intangible assets	1,121
Net deferred tax assets	5,455
Accounts payable and other accrued liabilities	(6,830		)
Accrued construction costs	(9,495		)
Accrued interest	(2,592		)
Derivative liabilities, current	(1,942		)
Current portion of long-term debt	(16,586		)
Long-term debt	(209,295		)
Derivative liabilities, non-current	(501		)
Asset retirement obligation	(2,354		)
Net deferred tax liabilities	(13,001		)
Total consideration	117,536
Less: non-controlling interest	(35,259		)
Controlling interest	$	82,277

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



Table of Contents

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

Supplemental pro forma data

The unaudited pro forma statement of operations data below gives effect to the Lost Creek, Post Rock, Panhandle 1 and El Arrayán acquisitions as if they had occurred on January 1, 2014. The pro forma net loss for the three and nine month periods ended September 30, 2015 was adjusted to exclude nonrecurring transaction related credits of $0.2 million and expenses of $1.7 million, respectively. The pro forma net loss for the three and nine months ended September 30, 2014 was adjusted to exclude nonrecurring transaction related expenses of zero and $1.1 million, respectively. In addition, the 2014 pro forma net loss for the three and nine months ended September 30, 2014 was adjusted to exclude a nonrecurring gain of zero and $17.9 million, respectively, upon acquisition of AEI El Arrayán. The unaudited pro forma data is presented for illustrative purposes only and is not intended to be indicative of actual results that would have been achieved had these acquisitions been consummated as of January 1, 2014. The unaudited pro forma data should not be considered representative of the Company’s future financial condition or results of operations.



	Three months ended September 30,						Nine months ended September 30,
Unaudited pro forma data (in thousands)	2015			2014			2015			2014
Pro forma total revenue	$	89,697		$	81,432		$	260,497		$	230,838
Pro forma total expenses	125,261			97,223			315,976			286,838
Pro forma net loss	(35,564		)	(15,791		)	(55,479		)	(56,000		)
Less: pro forma net loss attributable to noncontrolling interest	(5,927		)	(3,318		)	(23,539		)	(19,631		)
Pro forma net loss attributable to controlling interest	$	(29,637	)	$	(12,473	)	$	(31,940	)	$	(36,369	)

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

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



Unaudited data (in thousands)	Three months ended September 30, 2015			Nine months ended September 30, 2015
Total revenue	$	10,081		$	15,253
Total expenses	15,197			21,547
Net loss	(5,116		)	(6,294		)
Less: net loss attributable to noncontrolling interest	(1,965		)	(2,765		)
Net loss attributable to controlling interest	$	(3,151	)	$	(3,529	)

Asset Acquisition

Amazon Wind Farm (Fowler Ridge)

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



Table of Contents

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



	April 29, 2015
Prepaid expenses and other current assets	$	1,753
Deferred financing costs, current	2,132
Turbine advances	4,000
Construction in progress	34,412
Finite-lived intangible assets, net of accumulated amortization	2,247
Accrued construction costs	(6,549		)
Total consideration	$	37,995

In connection with the acquisition, the Company may make additional contingent payments of up to $29.1 million, consisting of a $25.1 million fixed amount and up to $4.0 million, as calculated based on final budget to actual amounts, both of which are payable to Pattern Development upon tax equity funding. As of September 30, 2015, the Company has not accrued for the additional contingent payments and will recognize the potential liabilities when the contingency is removed.

The Company also acquired a $5.0 million contingent obligation, which was paid subsequent to the close of construction financing, and assumed an estimated $7.3 million third party contingent liability payable at the time of commissioning of the first wind turbine, which has been recorded as a contingent liability as of September 30, 2015. In addition, as of September 30, 2015, the Company accrued a $2.5 million liability, which is payable to a third party upon energization of the project’s substation.

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

Equity Method Investments

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

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



Table of Contents

4. Prepaid Expenses and Other Current Assets

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



	September 30, 2015		December 31, 2014
Prepaid expenses	$	15,246	$	15,275
Prepaid construction costs	1,018		5,155
Sales tax	53		786
Other current assets:
Deposit for letters of credit	—		3,425
Deferred equity issuance costs	2,380		2,331
Spare parts inventory	3,398		72
Other	1,500		910
Prepaid expenses and other current assets	$	23,595	$	27,954

5. Property, Plant and Equipment

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



	September 30, 2015			December 31, 2014
Operating wind farms	$	3,433,528		$	2,624,640
Furniture, fixtures and equipment	3,397			4,366
Land	249			141
Subtotal	3,437,174			2,629,147
Less: accumulated depreciation	(370,713		)	(278,291		)
Property, plant and equipment, net	$	3,066,461		$	2,350,856

The Company recorded depreciation expense related to property, plant and equipment of $38.1 million and $100.6 million for the three and nine months ended September 30, 2015, respectively, and recorded $29.6 million and $71.4 million of depreciation expense for the same periods in the prior year.

The cash grants in lieu of investment tax credits received from the U.S. Department of the Treasury for Ocotillo, Santa Isabel and Spring Valley reduced depreciation expense recorded in the consolidated statements of operations by approximately $2.9 million and $8.6 million for the three and nine months ended September 30, 2015, respectively, and reduced depreciation expense by $3.2 million and $9.5 million for the same periods in the prior year.



Table of Contents

6. Finite-Lived Intangible Assets and Liability

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



	September 30, 2015
	Weighted Average Remaining Life	Gross			Accumulated Amortization			Net
Intangible assets
Power purchase agreement	15	$	97,400		$	(2,476	)	$	94,924
Other intangible assets	17	4,759			(285		)	$	4,474
Total intangible assets		$	102,159		$	(2,761	)	$	99,398
Intangible liability
Power purchase agreement	17	$	(60,300	)	$	1,301		$	(58,999	)



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

The Company amortizes the PPA asset and PPA liability in electricity sales in the consolidated statements of operations and recorded $1.6 million and $(0.9) million, respectively, for the three months ended September 30, 2015. For the nine months ended September 30, 2015, the Company recorded $2.5 million and $(1.3) million related to the amortization of the PPA asset and PPA liability, respectively.

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



Year ended December 31,	Power purchase agreements, net		Other intangible assets
2015	$	771	$	37
2016	3,049		276
2017	3,031		351
2018	3,031		276
2019	3,031		276
Thereafter	23,012		3,258

7. Unconsolidated Investments

The following presents projects that are accounted for under the equity method of accounting, presented on the Company's consolidated balance sheets for the periods below (in thousands):



					Percentage of Ownership
	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014
South Kent	$	308	$	17,360	50.0	%	50.0	%
Grand	3,623		11,719		45.0	%	45.0	%
K2	111,246		—		33.3	%	N/A
Unconsolidated investments	$	115,177	$	29,079

El Arrayán

On June 25, 2014, the Company increased its total ownership interest in El Arrayán to 70%. Refer to Note 3, Acquisitions - Business Combinations - El Arrayán Acquisition, 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.



Table of Contents

South Kent

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

Grand

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

The Company is a noncontrolling investor in a joint venture established to develop, construct and own a wind power project located in Ontario, Canada. The project has a 20-year PPA and commenced commercial operations in May 2015. Refer to Note 3, Acquisitions - Equity Method Investments, for disclosure on the acquisition of K2.

The following table summarizes the aggregated operating results of the unconsolidated investments for the three and nine months ended September 30, 2015 and 2014, respectively (in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015		2014
Revenue	$	35,697		$	16,820		$	122,483	$	45,516
Cost of revenue	20,444			13,779			48,120		24,851
Operating expenses	3,133			1,465			8,447		3,169
Other expense	31,476			11,781			59,925		61,327
Net (loss) income	$	(19,356	)	$	(10,205	)	$	5,991	$	(43,831	)

Significant Equity Method Investees

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

South Kent



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015		2014
Revenue	$	17,137		$	16,820		$	69,883	$	43,695
Cost of revenue	8,518			10,696			23,640		21,767
Operating expenses	1,056			1,349			3,763		2,812
Other expense	19,727			12,121			39,159		51,346
Net (loss) income	$	(12,164	)	$	(7,346	)	$	3,321	$	(32,230	)

Grand



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015		2014
Revenue	$	7,412		$	—		$	34,190	$	—
Cost of revenue	5,105			—			14,460		—
Operating expenses	869			117			2,902		358
Other expense	8,793			2,741			16,006		9,979
Net (loss) income	$	(7,355	)	$	(2,858	)	$	822	$	(10,337	)



Table of Contents

8. Accounts Payable and Other Accrued Liabilities

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



	September 30, 2015		December 31, 2014
Accounts payable	$	1,054	$	673
Other accrued liabilities	11,446		7,892
Warranty settlement payments	—		639
LTSA upgrades liability	574		680
Turbine operations and maintenance payable	668		1,310
Purchase agreement obligations	4,225		—
Land lease rent payable	1,259		2,115
Spare-parts inventory payables	1,025		—
Payroll liabilities	4,550		4,453
Property tax payable	10,323		4,625
Sales tax payable	983		2,406
Accounts payable and other accrued liabilities	$	36,107	$	24,793

9. Revolving Credit Facility

In September 2015, the Company entered into Amendment No. 2 to the Amended and Restated Credit and Guaranty Agreement which added two additional lenders to the facility and increased available borrowings under the existing revolving credit facility from $350.0 million to $450.0 million.

As of September 30, 2015 and December 31, 2014, outstanding loan balances under the revolving credit facility were $245.0 million and $50.0 million, respectively. In addition, as of September 30, 2015 and December 31, 2014, letters of credit of $49.2 million and $45.1 million, respectively, were issued under the revolving credit facility.



Table of Contents

10. Long-term Debt

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



							As of September 30, 2015
	September 30, 2015			December 31, 2014			Contractual Interest Rate		Effective Interest Rate			Maturity
Project-level
Fixed interest rate
El Arrayán EKF term loan	$	107,160		$	109,630		5.56	%	5.56	%		March 2029
St. Joseph term loan	160,235			189,472			5.88	%	5.95	%		May 2031
Santa Isabel term loan	110,483			112,609			4.57	%	4.57	%		September 2033
Variable interest rate
Logan's Gap construction loan	—			58,691			N/A		N/A			December 2015
Amazon Wind (Fowler Ridge) construction loan	143,350			—			1.69	%	1.69	%		December 2015
Gulf Wind term loan	—			156,122			N/A		N/A			March 2020
Ocotillo commercial term loan	208,967			222,175			2.08	%	3.92	%	⁽¹⁾	August 2020
Lost Creek term loan	114,786			—			2.19	%	5.38	%	⁽¹⁾	September 2027
El Arrayán commercial term loan	97,418			99,665			2.94	%	5.65	%	⁽¹⁾	March 2029
Spring Valley term loan ⁽²⁾	162,885			167,261			2.71	%	5.51	%	⁽¹⁾	June 2030
Ocotillo development term loan	105,600			106,700			2.43	%	4.55	%	⁽¹⁾	August 2033
Imputed interest rate
Hatchet Ridge term loan	220,152			228,288			1.43	%	1.43	%		December 2032
	1,431,036			1,450,613
Unamortized premium, net⁽³⁾	1,433			—
Unamortized financing costs	(25,041		)	(36,755		)
Current portion (including construction loans) ⁽⁴⁾	(202,580		)	(109,693		)
Long-term debt, less current portion (including construction loans)	$	1,204,848		$	1,304,165


⁽¹⁾	Includes impact of interest rate derivatives. Refer to Note 12, Derivative Instruments, for discussion of interest rate derivatives.


⁽²⁾	On October 20, 2015, the Company made a $29.7 million prepayment towards the outstanding principal balance of the Spring Valley term loan. Refer to Note 22, Subsequent Events, for additional information.


⁽³⁾	Amount is related to the Lost Creek term loan.


⁽⁴⁾	Amount is presented net of the current portion of unamortized financing costs of $5.1 million and $11.9 million as of September 30, 2015 and December 31, 2014, respectively.



Table of Contents

The following table presents a reconciliation of interest expense presented in the Company’s consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014 (in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Interest and commitment fees incurred	$	17,922		$	15,938		$	52,589		$	43,245
Capitalized interest, commitment fees, and letter of credit fees	(2,083		)	(440		)	(5,656		)	(2,320		)
Letter of credit fees incurred	1,358			1,103			3,490			3,256
Amortization of debt discount/premium, net	829			—			798			—
Amortization of financing costs	1,915			1,398			5,581			4,246
Interest expense	$	19,941		$	17,999		$	56,802		$	48,427

Amazon Wind Farm (Fowler Ridge)

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

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

Logan's Gap

On September 18, 2015, the Company and certain tax equity investors made capital contributions to fund the repayment of the Logan's Gap construction loan. As of September 30, 2015, the balance of the construction loan was zero. Refer to Note 16, Stockholders' Equity - Noncontrolling Interests, for additional information.

Gulf Wind

On July 28, 2015, the Company acquired the noncontrolling interests in the Gulf Wind project, resulting in a 100% ownership of the membership interests in the Gulf Wind project. Refer to Note 16, Stockholders' Equity - Noncontrolling Interests, for additional information. Subsequent to the acquisitions, on July 30, 2015, the Company prepaid 100% of the outstanding balance of the Gulf Wind project’s term loan of $154.1 million, resulting in a loss on extinguishment of debt of approximately $4.1 million. As a result of the early extinguishment of debt, the Company terminated the related interest rate swaps and cap. Refer to Note 12, Derivative Instruments, for additional information.

Lost Creek

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

On September 3, 2015, Lost Creek entered into a Second Amended and Restated Credit Agreement which, among other things, reduced the interest rate from LIBOR plus 2.75% (with periodic increases of 0.25%) to LIBOR plus 1.65% (increasing by 0.125% every four years) and extended the tenor of the term loan from March 2021 to September 2027.



Table of Contents

Under ASC 470-50 – Debt Modifications and Extinguishments, these amendments to the term loan are considered a modification of debt on a lender-by-lender basis. As a result, the capitalized amendment fees of $1.5 million paid to lenders are amortized over the remaining term of the modified debt using the effective interest method. In addition, the Company expensed third party legal and other fees of approximately $0.7 million, which are included in other income (expense), net on the Company's consolidated statements of operations.

The Amended Credit Agreement includes a collateral agreement that requires proceeds from the sale of energy from the Lost Creek wind project be remitted directly to the depositary agent of the Amended Credit Agreement to provide for debt service payments and operating costs required under the Amended Credit Agreement. The Second Amended and Restated Credit Agreement also replaced the existing debt service and operating and maintenance reserves with a $10.7 million revolving credit facility provided by certain lenders in the event Lost Creek is unable to make payments towards debt service reserve requirements and operating and maintenance reserve requirements.

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

Convertible Senior Notes due 2020

In July 2015, the Company issued $225.0 million aggregate principal amount of 4.00% convertible senior notes due 2020 (“2020 Notes”). The 2020 Notes bear interest at a rate of 4.00% per year, payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2016. The 2020 Notes will mature on July 15, 2020.

The 2020 Notes were sold in a private placement under a purchase agreement entered into by and among the Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated, BMO Capital Markets Corp. and Citigroup Global Markets Inc., acting as representatives of several initial purchasers named therein, for resale to qualified institutional buyers as defined in, and in reliance on Rule 144A under the Securities Act of 1933, as amended.

At any time prior to the close of business on the business day immediately preceding January 15, 2020, holders may convert the 2020 Notes under the following circumstances:

•

during any calendar quarter commencing after the calendar quarter ending on September 30, 2015, if the last reported sale price of the Company’s Class A common stock for at least 20 trading days during a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;


•	during the five business day period after any 10 consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of notes for each trading day of the measurement period was less than 98% of the product of the last reported sale price of the Class A common stock and the conversion rate on each such trading day;


•	upon occurrence of specified corporate events; or


•	at any time on or after January 15, 2020 until close of business on the second scheduled trading day immediately preceding the maturity date.

Upon conversion, the Company may, at its discretion, pay cash, shares of the Company’s Class A common stock, or a combination of cash and stock.

The 2020 Notes will be converted at an initial conversation rate of 35.4925 shares of Class A common stock per $1,000 principal amount of notes, which is equivalent to an initial conversion price of approximately $28.175 per share of Class A common stock. The conversion rate is subject to adjustment in some events (including, but not limited to, certain cash dividends made to holders of the Company's Class A common stock which exceed the initial dividend threshold of $0.363 per quarter per share). The conversion rate would be adjusted to offset the effect of the portion of the dividend in excess of $0.363. The conversion rate will not be adjusted for any accrued and unpaid interest. The 2020 Notes are not redeemable prior to maturity.



Table of Contents

Upon the occurrence of certain fundamental changes involving the Company, holders of the 2020 Notes may require the Company to repurchase all or a portion of their 2020 Notes for cash at a price of 100% of the principal amount of the 2020 Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.

The 2020 Notes are guaranteed on a senior unsecured basis by a subsidiary of the Company and are general unsecured obligations of the Company. The obligations rank senior in rights of payment to the Company’s subordinated debt, equal in right of payment to the Company’s unsubordinated debt and effectively junior in right of payment to any of the Company’s secured indebtedness to the extent of the value of the assets securing such indebtedness.

The 2020 Notes are accounted for in accordance with ASC 470-20, Debt with Conversion and Other Options, and ASC 815, Derivatives and Hedging. Under ASC 815, issuers of certain convertible debt instruments are generally required to separately account for the conversion option of the convertible debt instrument as a derivative, unless it meets a scope exception which allows the issuer to classify the conversion option as equity. As the 2020 Notes have met the scope exception, the Company is required to separately account for the liability and equity components of the convertible debt instrument in accordance with ASC 470-20, Debt with Conversion and Other Options. The carrying amount of the liability component is determined based on the fair value of a similar liability without the conversion option. The market interest rate used in determining the liability component of the 2020 Notes was 6.6%. The amount of the equity component is then calculated by deducting the fair value of the liability component from the principal amount of the 2020 Notes.

The following table presents a summary of the equity and liability components of the 2020 Notes (in thousands):



	September 30, 2015
Principal	$	225,000
Less:
Unamortized debt discount	(23,538		)
Unamortized financing costs	(5,271		)
Carrying value of convertible senior notes	$	196,191
Carrying value of the equity component ⁽¹⁾	$	23,754


⁽¹⁾	Included in the consolidated balance sheets within additional paid-in capital, net of $0.7 million in equity issuance costs.

During both the three and nine months ended September 30, 2015, the Company recorded $1.6 million, $0.2 million and $0.9 million related to the contractual coupon interest, amortization of financing costs and amortization of debt discount, respectively, in interest expense in its consolidated statements of operations.

11. Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated cost of decommissioning the turbines, removing above-ground installations and restoring the sites at the end of its estimated economic useful life. Effective January 1, 2015, the Company changed its estimate of the useful lives of wind farms for which construction began after 2011, from 20 years to 25 years. As a result, during the nine months ended September 30, 2015, the Company recorded a one-time adjustment of $1.9 million to reduce the carrying balance of the asset retirement obligations to reflect the change in estimate associated with the timing of the original undiscounted cash flows.

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligations as of September 30, 2015 and 2014 (in thousands):



	Nine months ended September 30,
	2015			2014
Beginning asset retirement obligations	$	29,272		$	20,834
Net additions during the year	13,034			4,912
Foreign currency translation adjustment	(323		)	(135		)
Adjustment related to change in useful life	(1,907		)	—
Accretion expense	1,477			1,057
Ending asset retirement obligations	$	41,553		$	26,668



Table of Contents

12. Derivative Instruments

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

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

Undesignated Derivative Instruments Classified as Assets (Liabilities):



									For the period ended
			Fair Market Value						QTD Gain (Loss) Recognized into Income			YTD Gain (Loss) Recognized into Income
Derivative Type	Quantity	Maturity Dates	Current Portion			Long-Term Portion			QTD Gain (Loss) Recognized into Income			YTD Gain (Loss) Recognized into Income
September 30, 2015
Interest rate swaps	6	6/30/2030	$	(3,106	)	$	(1,188	)	$	(5,549	)	$	(3,414	)
Interest rate cap	1	Terminated	—			—			22			—
Energy derivative	1	4/30/2019	19,582			46,493			4,630			1,600
Foreign currency forward contracts	20	Various through 3/31/2017	2,330			540			2,479			2,870
Interest rate swaps	5	Matured	—			—			7			—
Interest rate swaps	6	3/31/2021	(986		)	(1,023		)	(680		)	(598		)
			$	17,820		$	44,822		$	909		$	458
December 31, 2014
Interest rate swaps	6	6/30/2030	$	(3,403	)	$	2,523		$	(5,040	)	$	(11,339	)
Interest rate cap	1	12/31/2024	—			352			(29		)	(329		)
Energy derivative	1	4/30/2019	18,506			45,969			7,265			(3,878		)
			$	15,103		$	48,844		$	2,196		$	(15,546	)
September 30, 2014
Interest rate swaps	6	6/30/2030	$	(3,632	)	$	7,791		$	105		$	(6,299	)
Interest rate cap	1	12/31/2024	—			381			(39		)	(300		)
Energy derivative	1	4/30/2019	13,918			43,291			3,139			(11,143		)
			$	10,286		$	51,463		$	3,205		$	(17,742	)



Table of Contents

Designated Derivative Instruments Classified as Assets (Liabilities):



									For the period ended
			Fair Market Value						QTD Gain (Loss) Recognized into OCI			YTD Gain (Loss) Recognized into OCI
Derivative Type	Quantity	Maturity Dates	Current Portion			Long-Term Portion			QTD Gain (Loss) Recognized into OCI			YTD Gain (Loss) Recognized into OCI
September 30, 2015
Interest rate swaps	6	6/30/2033	$	(1,823	)	$	(1,718	)	$	(3,814	)	$	(2,149	)
Interest rate swaps	3	3/31/2032	(2,171		)	(4,610		)	(1,954		)	(1,183		)
Interest rate swaps	7	Terminated	—			—			10,798			11,634
Interest rate swaps	2	6/28/2030	(4,181		)	(9,625		)	(4,237		)	(2,146		)
Interest rate swaps	6	9/30/2027	(4,093		)	(14,316		)	(2,460		)	(1,593		)
Interest rate swaps	6	9/30/2027	—			(723		)	(122		)	(53		)
			$	(12,268	)	$	(30,992	)	$	(1,789	)	$	4,510
December 31, 2014
Interest rate swaps	6	6/30/2033	$	(1,917	)	$	525		$	(3,722	)	$	(8,912	)
Interest rate swaps	3	3/31/2032	(1,822		)	(3,338		)	(1,863		)	(1,983		)
Interest rate swaps	7	3/15/2020	(4,719		)	(6,915		)	(425		)	1,094
Interest rate swaps	2	6/28/2030	(4,446		)	(7,214		)	(3,889		)	(9,869		)
			$	(12,904	)	$	(16,942	)	$	(9,899	)	$	(19,670	)
September 30, 2014
Interest rate swaps	6	6/30/2033	$	(2,020	)	$	4,351		$	(434	)	$	(5,190	)
Interest rate swaps	3	3/31/2032	(2,423		)	(169		)	(4		)	(120		)
Interest rate swaps	7	3/15/2020	(4,916		)	(6,293		)	1,870			1,519
Interest rate swaps	2	6/28/2030	(4,621		)	(3,149		)	266			(5,980		)
			$	(13,980	)	$	(5,260	)	$	1,698		$	(9,771	)

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 was 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 qualified for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three and nine months ended September 30, 2015 and 2014, respectively. The Company reclassified unrealized losses of $0.4 million related to cash settlements between July 1, 2015 and July 28, 2015 and unrealized losses of $3.0 million related to cash settlements during the nine months ended September 30, 2015, from accumulated other comprehensive loss into net loss. For the three and nine months ended September 30, 2014, the Company reclassified unrealized losses of $1.4 million and $4.1 million, respectively. In connection with the early extinguishment of debt, the Company terminated the related interest rate swaps and interest rate cap which resulted in a total net loss of $11.4 million, recognized in realized loss on derivatives, net in the consolidated statements of operations and primarily represents a realization of losses previously recorded within accumulated other comprehensive loss.

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 had an effective date of March 31, 2020, a termination date of December 31, 2024, and a notional amount of $42.1 million, which reduced quarterly during its term. The cap was a derivative, but did not qualify for hedge accounting and was not designated. As discussed above, the interest rate cap was terminated as a result of the early extinguishment of debt.

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 September 30, 2015 and December 31, 2014 was $66.1 million and $64.5 million, respectively. Gulf Wind recognized unrealized gains of $4.6 million and $1.6 million for the three and nine months ended September 30, 2015, respectively, and an unrealized gain of $3.1 million and unrealized loss of $11.1 million for the same periods in the prior year, in unrealized gain (loss) on energy derivative in the consolidated statements of operations.



Table of Contents

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 nine months ended September 30, 2015 and 2014, respectively. The Company reclassified unrealized losses of $1.2 million and $3.6 million related to cash settlements from accumulated other comprehensive loss into net loss during the three and nine months ended September 30, 2015, respectively, and unrealized losses of $1.3 million and $3.8 million for the same periods in the prior year. The Company estimates that $4.2 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months.

Ocotillo

In October 2012, Ocotillo entered into interest rate swaps with its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 2.5% and 2.2% for the development bank term loans and the commercial bank term loans, respectively. The fixed interest rate payments of the commercial bank term loan will increase by 0.25% on the fourth anniversary of the closing date. The interest rate swaps for the development bank loans qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three and nine months ended September 30, 2015 and 2014, respectively. The Company reclassified unrealized losses of $0.5 million and $1.6 million related to cash settlements from accumulated other comprehensive loss into net loss during each of the three and nine months ended September 30, 2015, respectively, and unrealized losses of $0.6 million and $1.6 million for the same periods in the prior year. The Company estimates that $1.8 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months. The interest rate swaps for the commercial bank loans are undesignated derivatives that are used to mitigate exposure to variable interest rate debt.

El Arrayán

In May 2012, El Arrayán entered into three interest rate swaps with its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 3.4% for the first two years of its term debt and subsequently increased to 5.8%, and increases by 0.25% on every fourth anniversary of the closing date, thereafter. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three and nine months ended September 30, 2015 and 2014, respectively. The Company reclassified unrealized losses of $0.5 million and $1.4 million related to cash settlements from accumulated other comprehensive loss, net of tax, into net loss during the three and nine months ended September 30, 2015, respectively. The Company reclassified unrealized losses of $0.5 million and $0.7 million, net of tax, related to cash settlements into net loss from accumulated other comprehensive loss for the three and nine months ended September 30, 2014. The Company estimates that $2.2 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months.

Lost Creek

In October 2009, Lost Creek entered into interest rate swaps with its lenders to manage exposure to its interest rate risk on its long-term debt and anticipated refinancing. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 3.77% for the initial five-year period of the term loan. Lost Creek also entered into interest rate swaps to exchange variable interest rate payments for fixed interest rate payments of approximately 5.10%, for the anticipated refinancing of the balloon payment in 2015, over a 12-year period. In April 2011, Lost Creek entered into an amended and restated credit facility to increase the term loan by $23.0 million to an aggregate term loan of $144.0 million. As a result, Lost Creek entered into additional interest rate swaps on the additional loan amount of $23.0 million, exchanging variable interest rate payments for fixed interest payments of 3.51% over a 10-year period and exchanging variable interest rate payments for fixed interest rate payments of 5.58% for the anticipated refinancing of the balloon payment of the additional loan amount in March 2021 through September 2027.

Through the Wind Capital Group Acquisition, as described in Note 3 - Acquisitions - Business Combinations, the Company became party to these interest rate swaps. To achieve hedge accounting for these pre-business combination hedging relationships, the Company is required to re-designate the hedging relationships. The Company performed an evaluation of the hedge effectiveness of the interest rate swap instruments as of May 15, 2015, which indicated that the interest rate swap instruments designated within two of the tranches failed the hedge effectiveness criteria and do not quality for cash flow hedge accounting. As a result, the interest



Table of Contents

rate swaps related to the initial long-term debt maturing in September 2015 and additional term loan maturing in March 2021 have been de-designated.

During the three and nine months ended September 30, 2015, the Company recorded ineffectiveness of $1.8 million and $1.7 million, respectively, related to the designated cash flow hedges in unrealized (loss) gain on derivatives, net in the consolidated statements of operations. During the three and nine months ended September 30, 2015, there were no cash settlements related to the designated derivatives at Lost Creek. The Company estimates that $4.1 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months.

Foreign Currency Forward Contracts

In January 2015, the Company established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in the Company’s cash flow, which may have an adverse impact to our short-term liquidity or financial condition. A majority of the Company’s power sale agreements and operating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. In 2015, the Company entered into foreign currency forward contracts at various times to mitigate the currency exchange rate risk on Canadian dollar denominated cash flows. These instruments have remaining maturities ranging from one to eighteen months. The foreign currency forward contracts are considered non-designated derivative instruments and are not used for trading or speculative purposes.

As of September 30, 2015, the total notional amount of foreign currency forward contracts outstanding was C$59.6 million and the total fair value of these contracts was $2.9 million. For the three and nine months ended September 30, 2015, the Company recognized an unrealized gain on foreign currency forward contracts of $2.5 million and $2.9 million, respectively, in unrealized (loss) gain on derivatives, net in the consolidated statements of operations. The Company also recognized a realized gain of $0.4 million during both the three and nine months ended September 30, 2015 in realized loss on derivatives, net in the consolidated statements of operations related to foreign currency forward contracts that matured during the period.

13. Accumulated Other Comprehensive Loss

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



	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI			Total
Balances at December 31, 2014	$	(19,338	)	$	(26,672	)	$	(7,903	)	$	(53,913	)
Other comprehensive loss before reclassifications	(21,900		)	(16,257		)	(6,895		)	(45,052		)
Amounts reclassified from accumulated other comprehensive loss due to termination of interest rate derivatives	—			11,221			—			11,221
Amounts reclassified from accumulated other comprehensive loss	—			9,546			1,582			11,128
Net current period other comprehensive loss	(21,900		)	4,510			(5,313		)	(22,703		)
Balances at September 30, 2015	$	(41,238	)	$	(22,162	)	$	(13,216	)	$	(76,616	)



	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	(6,575		)	(19,986		)	(4,558		)	(31,119		)
Amounts reclassified from accumulated other comprehensive loss	—			10,215			—			10,215
Net current period other comprehensive loss	(6,575		)	(9,771		)	(4,558		)	(20,904		)
Balances at September 30, 2014	$	(15,038	)	$	(16,773	)	$	(6,470	)	$	(38,281	)



Table of Contents

Amounts reclassified from accumulated other comprehensive loss into net loss for the effective portion of change in fair value of derivatives is recorded to interest expense in the consolidated statements of operations. Amounts reclassified from accumulated other comprehensive loss into net loss for the Company’s proportionate share of equity investee’s other comprehensive loss is recorded to equity in (losses) earnings in unconsolidated investments in the consolidated statements of operations. The reclassification of accumulated other comprehensive loss related to the termination of the Gulf Wind interest rate swaps is recorded in realized loss on derivatives, net in the consolidated statements of operations.

14. Fair Value Measurements

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

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



	Fair Value
	Level 1		Level 2			Level 3			Total
September 30, 2015
Interest rate swaps	$	—	$	(49,563	)	$	—		$	(49,563	)
Energy derivative	—		—			66,075			66,075
Foreign currency forward contracts	—		2,870			—			2,870
Contingent liabilities	—		—			(1,867		)	(1,867		)
	$	—	$	(46,693	)	$	64,208		$	17,515
December 31, 2014
Interest rate swaps	$	—	$	(30,726	)	$	—		$	(30,726	)
Interest rate cap	—		352			—			352
Energy derivative	—		—			64,475			64,475
Contingent liabilities	—		—			(175		)	(175		)
	$	—	$	(30,374	)	$	64,300		$	33,926

Level 2 Inputs

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

Level 3 Inputs

Energy Derivative

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



Table of Contents

The following table presents a reconciliation of the energy derivative contract measured at fair value, in thousands, on a recurring basis using significant unobservable inputs (Level 3) for the three and nine months ended September 30, 2015 and 2014, respectively. There were no transfers between Level 2 and Level 3 during the periods presented.



	Energy Derivative						Energy Derivative
	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Balances, beginning of period	$	61,445		$	54,071		$	64,475		$	68,353
Settlements	(2,969		)	(2,591		)	(15,066		)	(9,309		)
Change in fair value	7,599			5,729			16,666			(1,835		)
Balances, end of period	$	66,075		$	57,209		$	66,075		$	57,209

Contingent Liabilities

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

The following table presents a reconciliation of contingent liabilities measured at fair value, in thousands, on a recurring basis using significant unobservable inputs (Level 3) for the three and nine months ended September 30, 2015 and 2014, respectively. There were no transfers between Level 2 and Level 3 during the periods presented.



	Contingent Liabilities					Contingent Liabilities
	Three months ended September 30,					Nine months ended September 30,
	2015			2014		2015			2014
Balances, beginning of period	$	(1,320	)	$	—	$	(175	)	$	—
Change in estimate	(547		)	—		(1,692		)	—
Balances, end of period	$	(1,867	)	$	—	$	(1,867	)	$	—

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



			Fair Value
	As reflected on the balance sheet		Level 1		Level 2		Level 3		Total
September 30, 2015
Long-term debt, including current portion	$	1,407,428	$	—	$	1,380,919	$	—	$	1,380,919
Convertible senior notes	$	196,191	$	—	$	197,820	$	—	$	197,820
December 31, 2014
Long-term debt, including current portion	$	1,413,858	$	—	$	1,416,744	$	—	$	1,416,744

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



Table of Contents

15. Income Taxes

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

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

16. Stockholders' Equity

Common Stock

On July 28, 2015, the Company completed an underwritten public offering of its Class A common stock. In total, 5,435,000 shares of the Company's Class A common stock were sold. Net proceeds generated for the Company were approximately $120.8 million after deduction of underwriting discounts, commissions and transaction expenses.

On February 9, 2015, the Company completed an underwritten public offering of its Class A common stock. In total, 12,000,000 shares of the Company’s Class A common stock were sold. Of this amount, the Company issued and sold 7,000,000 shares of its Class A common stock and Pattern Development, the selling stockholder, sold 5,000,000 shares of Class A common stock. The Company received net proceeds of approximately $196.2 million after deducting underwriting discounts and commissions and estimated offering expenses payable by the Company. The Company did not receive any proceeds from the sale of shares sold by Pattern Development.

Dividends

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



	Dividends Per Share		Declaration Date	Record Date	Payment Date
2015:
Third Quarter	$	0.3630	July 21, 2015	September 30, 2015	October 30, 2015
Second Quarter	$	0.3520	April 20, 2015	June 30, 2015	July 30, 2015
First Quarter	$	0.3420	February 24, 2015	March 31, 2015	April 30, 2015



Table of Contents

Noncontrolling Interests

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



					Noncontrolling Ownership Percentage
	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014
Gulf Wind	$	—	$	97,061	—	%	60	%
El Arrayán	33,239		35,624		30	%	30	%
Logan's Gap	191,054		—		18	%	N/A
Panhandle 1	198,193		205,333		21	%	21	%
Panhandle 2	187,092		192,568		19	%	19	%
Post Rock	201,134		—		40	%	N/A
Noncontrolling interest	$	810,712	$	530,586

Gulf Wind

On July 28, 2015, the Company acquired Pattern Development’s 27% interest in the Gulf Wind project for a cash purchase price of approximately $13.0 million. Concurrently, the Company acquired 100% of MetLife Capital, Limited Partnership’s Class A membership interest in the Gulf Wind project for a cash purchase price of approximately $72.8 million. As a result of the acquisitions, the Company owns 100% of the membership interests in the Gulf Wind project. The Company's additional paid-in capital was increased by $17.2 million, representing the difference between the aggregate purchase price and carrying values of the noncontrolling interests as of July 28, 2015.

Logan's Gap

On September 18, 2015, certain tax equity investors made capital contributions to acquire 100% of the Class A membership interests in Logan's Gap and have been admitted as noncontrolling members in the entity, with an 18% initial ownership interest in the project's distributable cash flow. The Company has determined that the operating partnership agreement does not allocate economic benefits pro rata to its two classes of investors and will use the HLBV method to calculate the noncontrolling interest balance that reflects the substantive profit sharing arrangement.

17. Stock-based Compensation

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

The Company measures the fair value of the TSR-RSA’s at the grant date using a Monte Carlo simulation model and recognizes stock-based compensation over the longer of the requisite service period or performance period. For the three and nine months ended September 30, 2015, the total stock-based compensation expense for market-based restricted stock awards was approximately $0.2 million and $0.4 million, respectively.

Total stock-based compensation expense related to restricted stock awards, restricted stock units and stock options for the three and nine months ended September 30, 2015 was $1.2 million and $3.2 million, respectively, and $1.0 million and $3.1 million for the same periods in the prior year, respectively.



Table of Contents

18. Loss Per Share

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

Potentially dilutive securities are determined by applying the treasury stock method to the assumed exercise of in-the-money stock options and the assumed vesting of outstanding restricted stock awards and release of restricted stock units. Potentially dilutive securities related to the 2020 Notes are determined using the if-converted method.

On December 31, 2014, the Company’s Class B common stock was converted to Class A common stock on a one-to-one basis. For the three and nine months ended September 30, 2014, the Company computed Class A and Class B basic loss per share using the two-class method and computed diluted loss per share for Class A and Class B common stock using either the two-class method or the if-converted method, whichever was more dilutive.



Table of Contents

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



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Numerator for basic and diluted loss per share:
Net loss attributable to controlling interest	$	(29,405	)	$	(7,208	)	$	(34,987	)	$	(10,898	)
Less: dividends declared on Class A common shares	(27,113		)	(15,258		)	(75,117		)	(41,395		)
Less: deemed dividends on Class B common shares	N/A			(7,222		)	N/A			(14,679		)
Undistributed loss attributable to common stockholders	$	(56,518	)	$	(29,688	)	$	(110,104	)	$	(66,972	)
Denominator for loss per share:
Weighted average number of shares:
Class A common stock - basic	72,789,583			46,317,932			69,233,698			41,022,962
Add dilutive effect of:
Stock options	—			133,197			47,480			112,252
Restricted stock awards	10,011			191,451			87,946			191,451
Restricted stock units	13,405			—			19,789			—
Convertible senior notes	5,555,348			—			1,872,132			—
Class B common stock	N/A			15,555,000			N/A			15,555,000
Class A common stock - fully diluted	78,368,347			62,197,580			71,261,045			56,881,665
Less: antidilutive securities
Stock options	—			(133,197		)	(47,480		)	(112,252		)
Restricted stock awards	(10,011		)	(191,451		)	(87,946		)	(191,451		)
Restricted stock units	(13,405		)	—			(19,789		)	—
Convertible senior notes	(5,555,348		)	—			(1,872,132		)	—
Class B common stock	N/A			(15,555,000		)	N/A			—
Class A common stock - diluted (excluding antidilutive securities)	72,789,583			46,317,932			69,233,698			56,577,962
Class B common stock - basic and diluted	N/A			15,555,000			N/A			15,555,000
Calculation of basic and diluted earnings (loss) per share:
Class A common stock:
Dividends	$	0.37		$	0.33		$	1.08		$	1.01
Undistributed loss	(0.78		)	(0.48		)	(1.59		)	(1.18		)
Basic loss per share	$	(0.40	)	$	(0.15	)	$	(0.51	)	$	(0.17	)
Class A common stock:
Diluted loss per share	$	(0.40	)	$	(0.15	)	$	(0.51	)	$	(0.19	)
Class B common stock:
Deemed dividends	N/A			$	0.46		N/A			$	0.94
Undistributed loss	N/A			(0.48		)	N/A			(1.18		)
Basic and diluted loss per share	N/A			$	(0.02	)	N/A			$	(0.24	)
Dividends declared per Class A common share	$	0.36		$	0.33		$	1.06		$	0.96
Deemed dividends per Class B common share	N/A			$	0.46		N/A			$	0.94



Table of Contents

19. Geographic Information

The table below provides information, by country, about the Company’s consolidated 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 September 30,				Nine months ended September 30,				September 30, 2015		December 31, 2014
	2015		2014		2015		2014		September 30, 2015		December 31, 2014
United States	$	74,250	$	53,720	$	188,980	$	144,107	$	2,549,271	$	1,784,219
Canada	8,248		9,146		29,345		33,454		194,528		233,690
Chile	7,199		8,653		20,909		8,514		322,662		332,947
Total	$	89,697	$	71,519	$	239,234	$	186,075	$	3,066,461	$	2,350,856

20. Commitments and Contingencies

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

Power Sale Agreements

The Company has various PPAs that terminate from 2019 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 September 30, 2015, under the terms of the PPAs, the Company issued irrevocable letters of credit totaling $103.6 million to ensure its performance for the duration of the PPAs.

Project Finance Agreements

The Company has various project finance agreements that obligate the Company to provide certain reserves to enhance its credit worthiness and facilitate the availability of credit. As of September 30, 2015, the Company issued irrevocable letters of credit totaling $125.7 million, of which $49.2 million was from the Company’s revolving credit facility, to ensure performance under these various project finance agreements.

Land Leases

The Company has entered into various long-term land lease agreements. As of September 30, 2015, total outstanding lease commitments were $302.6 million. During the three and nine months ended September 30, 2015, the Company recorded rent expense of $3.0 million and $8.1 million, respectively, in project expense in the consolidated statements of operations. During the three and nine months ended September 30, 2014, the Company recorded rent expense of $2.6 million and $6.3 million, respectively, in project expense in the consolidated statements of operations.

Service and Maintenance Agreements

The Company has entered into service and maintenance agreements with third party contractors to provide turbine operations and maintenance services, modifications and upgrades for varying periods over the next eleven years. Based on the terms of these agreements, the third party contractors will receive a daily base fee per turbine that may, or may not, be subject to periodic price adjustments for inflation, over the terms of the agreements. As of September 30, 2015, outstanding commitments with these third party contractors were $360.9 million, including an estimated annual price adjustment for inflation of 2%, where applicable, payable over the full term of these agreements.

Purchase, Construction and Other Commitments

The Company has entered into various commitments with service providers related to the Company’s projects and operations of its business. Outstanding commitments with these vendors, excluding turbine operations and maintenance commitments were $17.3 million as of September 30, 2015. The Company also has construction-related open commitments of $24.3 million as of September 30, 2015. In addition, the Company has a commitment to purchase $3.8 million of wind turbine spare parts from a third party contractor under a parts and service agreement.



Table of Contents

The Company has total commitments of $7.7 million over approximately the next 19 years to local community and government organizations surrounding certain wind farms.

Purchase and Sales Agreements

On April 29, 2015, the Company acquired 100% of the membership interests in Fowler Ridge IV Wind Farm LLC through the acquisition of Fowler Ridge IV B Member LLC from Pattern Development. Subject to the terms of this agreement, the Company may make additional contingent payments of up to $29.1 million, consisting of a $25.1 million fixed amount and up to $4.0 million as calculated based on final budget to actual amounts, both of which are payable to Pattern Development upon tax equity funding. In June 2015, the Company recorded a $7.3 million third party contingent payment, payable at the time of commissioning of the first wind turbine, which has been recorded as a contingent liability as of September 30, 2015. In addition, as of September 30, 2015, the Company accrued a $2.5 million liability, which is payable to a third party upon energization of the project’s substation. Refer to Note 3, Acquisitions - Asset Acquisition - Amazon Wind Farm (Fowler Ridge), for additional information.

In December 2014, the Company acquired 100% of the membership interests in Logan's Gap from Pattern Development. Pursuant to the terms of the agreement, the Company recorded a contingent obligation of $4.0 million, payable to a third party. Of the $4.0 million liability, $2.3 million was paid upon achievement of commercial operations in early September 2015. Pending final resolution among the parties of the appropriate amounts that would be payable either to the third party recipient or the local tax authorities, the Company has not yet made payment of the remainder and recorded $1.7 million in accrued liabilities as of September 30, 2015.

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 C$5.0 million. In September 2015, the Company settled the contingent obligation and made a payment of C$2.4 million, or $1.8 million calculated based on the September 2015 average exchange rate, as calculated based on final budget to actual amounts and distributions payable to Pattern Development upon term conversion, which was recognized in unconsolidated investments in the Company's consolidated balance sheets.

Turbine Availability Warranties

The Company has various turbine availability warranties from its turbine manufacturers. Pursuant to these warranties, if a turbine operates at less than minimum availability during the warranty period, the turbine manufacturer is obligated to pay, as liquidated damages, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, pursuant to certain of these warranties, if a turbine operates at more than a specified availability during the warranty period, the Company has an obligation to pay a bonus to the turbine manufacturer. As of September 30, 2015, the Company recorded liabilities of $1.0 million associated with bonuses payable to the turbine manufacturers. 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. The original settlement amount of $21.9 million was recorded as other revenue in the consolidated statements of operations and the excess of $2.2 million was accrued as a liability as of December 31, 2013. During 2014 and 2015, this liability was reduced to $1.7 million as a result of adjustments to the turbine availability. As of September 30, 2015, the excess amount was repaid to the turbine manufacturer.

Long-Term Service Guarantees

The Company has service guarantees from its turbine service and maintenance providers. These service guarantees, primarily from one provider, are associated with long-term turbine service arrangements which commenced on various dates in 2014 and will commence on various dates in 2015 for certain wind projects. Pursuant to these guarantees, if a turbine operates at less than minimum availability during the guarantee period, the service provider is obligated to pay, as liquidated damages, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, pursuant to certain of these guarantees, if a turbine operates at more than a specified availability during the guarantee period, the Company has an obligation to pay a bonus to the service provider. As of September 30, 2015, the Company recorded liabilities of $0.9 million associated with bonuses payable to service providers.



Table of Contents

Indemnity

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

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

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

21. Related Party Transactions

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

Management Services Agreement and Shared Management

Effective October 2, 2013, the Company entered into a bilateral Management Services Agreement with Pattern Development which provides for the Company and Pattern Development to benefit, primarily on a cost-reimbursement basis plus a 5% fee on certain direct costs, from the parties’ respective management and other professional, technical and administrative personnel, all of whom will report to and be managed by the Company’s executive officers. Pursuant to the Management Services Agreement, certain of the Company’s executive officers, including its Chief Executive Officer, will also serve as executive officers of Pattern Development and devote their time to both the Company and Pattern Development as is prudent in carrying out their executive responsibilities and fiduciary duties. The Company’s Chief Executive Officer also serves as the Chief Executive Officer of Pattern Development. The Company refers to the employees who will serve as executive officers of both the Company and Pattern Development as the “shared PEG executives.” The shared PEG executives will have responsibilities for both the Company and Pattern Development and, as a result, these individuals will not devote all of their time to the Company’s business. Under the terms of the Management Services Agreement, Pattern Development is required to reimburse the Company for an allocation of the compensation paid to such executives reflecting the percentage of time spent providing services to Pattern Development.

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



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Related party general and administrative	$	1,887		$	1,492		$	5,316		$	4,155
Related party income	(605		)	(664		)	$	(2,029	)	(1,736		)
Total	$	1,282		$	828		$	3,287		$	2,419

As of September 30, 2015 and December 31, 2014, the amounts payable to Pattern Development for bilateral management service cost reimbursements were $1.3 million and $0.8 million, respectively. In addition, the Company had a related party receivable of zero and $0.1 million as of September 30, 2015 and December 31, 2014, respectively, for IPO cost reimbursements due from Pattern Development.



Table of Contents

Letters of Credit, Indemnities and Guarantees

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

Purchase and Sales Agreements

In September 2015, pursuant to the terms of the Purchase and Sale agreement between the Company and Pattern Development dated December 20, 2013, the Company settled the contingent obligation and made a payment of C$2.4 million, or $1.8 million calculated based on the September 2015 average exchange rate, as calculated based on final budget to actual amounts and distributions payable to Pattern Development upon term conversion.

On July 28, 2015, the Company acquired a 27% interest in the Gulf Wind project from Pattern Development for a cash purchase price of approximately $13.0 million. Refer to Note 16, Stockholders' Equity - Noncontrolling Interests for additional information.

On June 17, 2015, the Company acquired a one-third equity interest in K2 from Pattern Development for a purchase price of approximately $128.0 million, plus assumed estimated proportionate debt at term conversion of approximately $221.8 million, U.S. dollar equivalent. This represents a 90MW interest in the 270MW wind project, located in the Township of Ashfield-Colborne-Wawanosh, Ontario.

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

On December 19, 2014, the Company acquired 100% of the membership interests in Logan’s Gap from Pattern Development, for a purchase price of approximately $15.1 million. Logan’s Gap is a 164MW wind project located in Comanche County, Texas.

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

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

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

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

Management Fees

The Company provides management services and receives a fee for such services under agreements with its joint venture investees, South Kent, Grand, K2 and El Arrayán, prior to the Company’s acquisition of the controlling interest of El Arrayán on June 25, 2014, in addition to various Pattern Development subsidiaries. Management fees of $1.0 million and $2.6 million were recorded as related party revenue in the consolidated statements of operations for the three and nine months ended September 30, 2015, respectively, and $0.9 million and $2.3 million for the same periods in the prior year. A related party



Table of Contents

receivable of $0.7 million and $0.7 million was recorded in the consolidated balance sheets as of September 30, 2015 and December 31, 2014, respectively.

22. Subsequent Events

On October 29, 2015, the Company declared an increased dividend for the fourth quarter, payable on January 29, 2016, to holders of record on December 31, 2015, in the amount of $0.372 per Class A share, or $1.49 on an annualized basis. This is a 2.5% increase from the third quarter 2015 dividend of $0.363.

On October 20, 2015, the Company consummated a repricing of the financing agreements related to the Spring Valley facility. Pursuant to the terms of the repricing, the interest rate on the term loan for the facility was reduced from LIBOR plus 2.38% to LIBOR plus 1.75% (increasing by 0.125% every four years). The Company also made a prepayment of $29.7 million towards the outstanding principal balance on Spring Valley's term loan facility. In addition, as part of the repricing, $22.5 million of the project reserve requirements were eliminated.



Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes thereto included as part of our Annual Report on Form 10-K for the year ended December 31, 2014 and our unaudited consolidated financial statements for the three and nine months ended September 30, 2015 and other disclosures (including the disclosures under “Part II. Item 1A. Risk Factors”) included in this Quarterly Report on Form 10-Q. Our consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles and are presented in U.S. dollars. Unless the context provides otherwise, references herein to “we,” “our,” “us,” “our company” and “Pattern Energy” refer to Pattern Energy Group Inc., a Delaware corporation, together with its consolidated subsidiaries.

Overview

We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued growth of our business. We hold interests in 16 wind power projects located in the United States, Canada and Chile that use proven, best-in-class technology and have a total owned capacity of 2,282 MW. These projects consist of 15 operating projects with one project under construction. The Amazon Wind Farm (Fowler Ridge) project, which we acquired from Pattern Development in April 2015, is scheduled to commence commercial operation prior to the end of 2015 and has contracted to sell a majority of its output pursuant to a long-term, fixed-price power sale agreement with a creditworthy counterparty. The credit rating of one of our counterparties, PREPA, was downgraded in 2014 and further downgraded in 2015. Refer to Item 1A “Risk Factors – Our projects rely on a limited number of key power purchasers. The power purchaser for our Santa Isabel project has been downgraded” of our Form 10-K for the year ended December 31, 2014. Eighty-nine percent of the electricity to be generated by our projects will be sold under our power sale agreements, which have a weighted average remaining contract life of approximately 15 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 Class A share over time. We expect our continuing relationship with Pattern Development, a leading developer of renewable energy and transmission projects, will be an important source of growth for our business. In addition, we expect opportunities in Japan and Mexico will form part of our growth strategy. Currently, Pattern Development has a 5,900 MW pipeline of development projects, all of which are subject to our right of first offer. We target achieving a total owned capacity of 5,000 MW by year end 2019 through a combination of acquisitions from Pattern Development and other third parties capitalizing on the large and fragmented global wind power market.

Recent Developments

On October 29, 2015, we declared an increased dividend for the fourth quarter, payable on January 29, 2016, to holders of record on December 31, 2015, in the amount of $0.372 per Class A share, or $1.49 on an annualized basis. This is a 2.5% increase from the third quarter 2015 dividend of $0.363.

On October 20, 2015, we consummated a repricing of the financing agreements related to the Spring Valley facility. Pursuant to the terms of the repricing, the interest rate on the term loan for the facility was reduced from LIBOR plus 2.38% to LIBOR plus 1.75% (increasing by 0.125% every four years). We also made a prepayment of $29.7 million towards the outstanding principal balance on Spring Valley's term loan facility. In addition, as part of the repricing, $22.5 million of the project reserve requirements were eliminated.

On September 28, 2015, we entered into Amendment No. 2 to the Amended and Restated Credit and Guaranty Agreement which added two additional lenders to the facility and increased available borrowings under the existing revolving credit facility from $350.0 million to $450.0 million.



Table of Contents

On September 3, 2015, we consummated a Second Amended and Restated Credit Agreement related to the Lost Creek facility, which, among other things, reduced the interest rate from LIBOR plus 2.75% (with periodic increases of 0.25%) to LIBOR plus 1.65% (increasing by 0.125% every four years) and extended the tenor of the term loan from March 2021 to September 2027.

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

On July 30, 2015, subsequent to the acquisitions of the noncontrolling interests in the Gulf Wind project, we prepaid 100% of the outstanding balance of the Gulf Wind project’s term loan of $154.1 million, resulting in a loss on debt settlement of approximately $4.1 million and also terminated the related interest rate swaps resulting in a total net loss of $11.4 million.

On July 28, 2015, we acquired Pattern Development’s 27% interest in the Gulf Wind project for a cash purchase price of approximately $13.0 million. Concurrently, we acquired 100% MetLife Capital, Limited Partnership’s (“MetLife Capital”) Class A membership interest in the Gulf Wind project for a cash purchase price of approximately $72.8 million. As a result of the acquisitions, we own 100% of the membership interests in the Gulf Wind project.

On July 28, 2015, we completed an underwritten public offering of our Class A common stock. In total, 5,435,000 shares of our Class A common stock were sold. Net proceeds generated to us were approximately $120.8 million after deduction of underwriting discounts, commissions and transaction expenses. As a result, Pattern Development's interest in us was diluted from approximately 25% to 23%. Concurrently, we issued $225.0 million aggregate principal amount of 4.00% Convertible Senior Notes due 2020 (“2020 Notes”). Net proceeds generated for us were approximately $218.8 million, after deducting the initial purchasers’ discount, commissions and transaction expenses. The 2020 Notes bear interest at a rate of 4.00% per year, payable semiannually in arrears on January 15 and July 15, beginning on January 15, 2016. The 2020 Notes will mature on July 15, 2020, unless earlier repurchased or converted. The 2020 Notes are guaranteed on a senior unsecured basis by one of our subsidiaries.

On July 21, 2015, we declared an increased dividend for the third quarter, payable on October 30, 2015, to holders of record on September 30, 2015, in the amount of $0.363 per Class A share, or $1.452 on an annualized basis. This is a three percent increase from the second quarter 2015 dividend of $0.352.

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

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

The following table sets forth our construction project as well as its power capacity and our anticipated date of its commencement of commercial operations:



Projects	Location	Construction Start	Commercial Operations	MW
Projects	Location	Construction Start	Commercial Operations	Rated	Owned
Amazon Wind Farm (Fowler Ridge)	Indiana	Q2 2015	Q4 2015	150	116
				150	116

On August 7, 2015, Pattern Development, through two of its subsidiaries, Broadview Energy KW, LLC and Broadview Energy JN, LLC entered into two 20-year PPAs with the Southern California Edison Company in connection with 297 MW of a 497 MW gross capacity wind power project, referred to as "Broadview", based in Curry County, New Mexico, that was previously added to our identified Right of First Offer Projects (“Identified ROFO Projects”) list on June 24, 2015 as the New Mexico/California wind power project. Subsequently on October 20, 2015, Pattern Development entered into an additional 25-year PPA with the Sacramento Municipal Utility District in connection with the remaining 200 MW of such wind project, referred to as "Grady." The project, which is being built in multiple phases, will deliver wind power directly into California.



Table of Contents

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



						Capacity (MW)
Identified ROFO Projects	Status	Location	Construction Start (1)	Commercial Operations (2)	Contract Type	Rated(3)	Pattern Development- Owned (4)
Armow	In construction	Ontario	2014	2015	PPA	180	90
Meikle	In construction	British Columbia	2015	2016	PPA	185	180
Conejo Solar	In construction	Chile	2015	2016	PPA	104	84
Belle River	Securing final permits	Ontario	2016	2017	PPA	100	50
Henvey Inlet	Late stage development	Ontario	2016	2017	PPA	300	150
Mont Sainte-Marguerite	Late stage development	Québec	2016	2017	PPA	147	147
North Kent	Late stage development	Ontario	2016	2017	PPA	100	43
Broadview/Grady	Late stage development	New Mexico	2016	2016/2017	PPA	497	398
Tsugaru	Late stage development	Japan	2015	2018	PPA	125	63
Ohorayama	Late stage development	Japan	2015	2017	PPA	33	31
Kanagi Solar	In construction	Japan	2014	2016	PPA	14	5
Futtsu Solar	In construction	Japan	2014	2016	PPA	42	17
Otsuki	Operational	Japan	2009	2016	PPA	12	12
						1,839	1,270


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


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


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


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

Key Metrics

We regularly review a number of financial measurements and operating metrics to evaluate our performance, measure our growth and make strategic decisions. In addition to traditional U.S. GAAP performance and liquidity measures, such as revenue, cost of revenue, net income (loss) and cash provided by (used in) operating activities, we also consider proportional MWh sold, average realized electricity price and Adjusted EBITDA in evaluating our operating performance and cash available for distribution as supplemental liquidity measures. Adjusted EBITDA and cash available for distribution are non-GAAP financial measures which management believes may assist investors in evaluating the Company’s financial performance and its ability to pay dividends. Each of these key metrics is discussed below.

Proportional MWh Sold and Average Realized Electricity Price

The number of MWh sold and the average realized price per MWh sold are the operating metrics that determine our revenue, as well as the revenue of our unconsolidated investments. Proportional MWh sold for any period presented, represents the sum of the product of (i) the number of MWh sold by each of our projects multiplied by (ii) our percentage interest in each projects’ distributable cash flow. For any period presented, average realized electricity price represents (i) the sum of the products of: (a) total revenue from electricity sales and energy derivative settlements at each of our projects, excluding the amortization of finite-lived intangible assets related to the Lost Creek and Post Rock PPAs, which were acquired in the second quarter of 2015, and (b) our percentage interest in each project’s distributable cash flow divided by (ii) our proportional MWh sold.



Table of Contents

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



	Three months ended September 30,
	2015		2014		Change			% Change
Proportional MWh sold	1,256,403		710,326		546,077			76.9	%
Average realized electricity price per MWh	$	74	$	94	$	(20	)	(21.3	)%

Our proportional MWh sold for the three months ended September 30, 2015 was 1,256,403 MWh, as compared to 710,326 MWh for the three months ended September 30, 2014, an increase of 546,077 MWh, or 76.9%. This increase in proportional MWh sold was primarily attributable to the commencement of commercial operations at Panhandle 2 in November 2014, Grand in December 2014, and Logan's Gap in September 2015. Acquisitions of Lost Creek and Post Rock in May 2015, K2 in June 2015, and Gulf Wind in July 2015 also contributed to the proportional MWh increase for the same comparative period.

Our average realized electricity price was approximately $74 per MWh for the three months ended September 30, 2015 as compared to approximately $94 per MWh for the three months ended September 30, 2014. The $20 per MWh decrease in the average realized electricity price was primarily due to lower average PPA pricing associated with new wind projects, and the impact of foreign exchange on revenue denominated in the Canadian dollar at St. Joseph and South Kent.

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



	Nine months ended September 30,
	2015		2014		Change			% Change
Proportional MWh sold	3,390,081		2,026,235		1,363,846			67.3	%
Average realized electricity price per MWh	$	77	$	95	$	(18	)	(18.9	)%

Our proportional MWh sold for the nine months ended September 30, 2015 was 3,390,081 MWh, as compared to 2,026,235 MWh for the nine months ended September 30, 2014, an increase of 1,363,846 MWh, or 67.3%. This increase in proportional MWh sold was primarily attributable to the acquisition and commencement of commercial operations at both Panhandle 1 and El Arrayán in June 2014, and Panhandle 2 in November 2014, the commencement of commercial operations at Grand in December 2014 and Logan's Gap in September 2015, and the acquisitions of Lost Creek, Post Rock and K2 also during the nine months ended September 30, 2015 compared to the same period in 2014.

Our average realized electricity price was approximately $77 per MWh for the first nine months of 2015 as compared to approximately $95 per MWh for the first nine months of 2014. The $18 per MWh decrease in the average realized electricity price was primarily due to lower average PPA pricing associated with new wind projects and the impact on foreign exchange on revenue denominated in the Canadian dollar at St. Joseph and South Kent.

Adjusted EBITDA

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



Table of Contents

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



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Net loss	$	(35,332	)	$	(9,281	)	$	(51,734	)	$	(24,013	)
Plus:
Interest expense, net of interest income	18,278			17,742			54,692			47,685
Tax (benefit) provision	(2,181		)	(3,538		)	676			(1,505		)
Depreciation, amortization and accretion	40,241			30,015			104,082			72,476
EBITDA	21,006			34,938			107,716			94,643
Unrealized (gain) loss on energy derivative	(4,630		)	(3,139		)	(1,600		)	11,143
Interest rate derivative settlements	2,412			1,030			4,331			3,082
Unrealized loss (gain) on derivatives, net	5,090			(66		)	2,393			6,599
Realized loss on derivatives	9,810			—			9,810			—
Early extinguishment of debt	4,113			—			4,113			—
Net loss (gain) on transactions	74			68			2,663			(14,469		)
Plus, proportionate share from equity accounted investments:
Interest expense, net of interest income	6,466			4,000			17,085			9,197
Tax provision	—			—			—			102
Depreciation, amortization and accretion	6,746			4,299			16,246			9,023
Unrealized loss on interest rate and currency derivatives, net	7,637			3,215			9,531			21,046
Realized loss on interest rate and currency derivatives	—			—			—			22
Adjusted EBITDA	$	58,724		$	44,345		$	172,288		$	140,388

Adjusted EBITDA for the three months ended September 30, 2015 was $58.7 million compared to $44.3 million for the same period in the prior year, an increase of $14.4 million, or 32.4%. The increase in Adjusted EBITDA was primarily attributable to the commencement of commercial operations at Panhandle 2 in November 2014, Grand in December 2014 and Logan's Gap in September 2015, and the acquisitions of Lost Creek, Post Rock, and K2 in the second quarter of 2015 as well as the acquisitions of the noncontrolling interests in Gulf Wind in July 2015.

Adjusted EBITDA for the nine months ended September 30, 2015 was $172.3 million compared to $140.4 million for the same period in the prior year, an increase of $31.9 million, or 22.7%. The increase in Adjusted EBITDA was primarily attributable to the commencement of commercial operations at Panhandle 1, Panhandle 2, El Arrayán, and Grand at various times in 2014 and Logan's Gap in September 2015, and the acquisitions of Lost Creek, Post Rock and K2 in the second quarter of 2015 as well as the acquisitions of the noncontrolling interests in Gulf Wind in July 2015. In addition to commencement of commercial operations, Adjusted EBITDA for the nine month period was favorably impacted by a $5.8 million increase in energy derivative settlements at Gulf Wind.



Table of Contents

Cash Available for Distribution

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

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



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Net cash provided by operating activities	$	34,682		$	23,078		$	83,282		$	83,900
Changes in operating assets and liabilities	(4,293		)	(2,035		)	(6,429		)	(7,720		)
Network upgrade reimbursement	618			1,236			1,854			2,472
Release of restricted cash to fund project and general and administrative costs	—			149			1,501			210
Operations and maintenance capital expenditures	27			(40		)	(294		)	(134		)
Transaction costs for acquisitions	49			—			1,826			1,128
Distributions from unconsolidated investment	9,647			4,704			23,494			4,704
Reduction of other asset - Gulf Wind energy derivative deposit	5,355			—			5,355			—
Other	(1,261		)	—			(1,553		)	—
Less:
Distributions to noncontrolling interests	(2,871		)	—			(4,382		)	(1,470		)
Principal payments paid from operating cash flows ⁽¹⁾	(19,674		)	(16,149		)	(45,057		)	(38,245		)
Cash available for distribution	$	22,279		$	10,943		$	59,597		$	44,845

⁽¹⁾ Principal payments paid from operating cash flows includes a principal payment on the Lost Creek debt that was due September 30, 2015 and paid subsequently on October 1, 2015 due to an administrative delay.

Cash available for distribution was $22.3 million for the three months ended September 30, 2015 as compared to $10.9 million for the three months ended September 30, 2014, an increase of $11.3 million, or 103.6%. This increase was primarily due to additional electricity sales from the commencement of commercial operations at Panhandle 2 in November 2014 and Logan's Gap in September 2015, and the acquisitions of Lost Creek and Post Rock in the second quarter of 2015. In addition, we received an increase of $4.9 million in cash distributions from unconsolidated investments during the three months ended September 30, 2015 compared to the same period in the prior year. Cash available for distribution was also impacted by a $5.4 million cash distribution from the partial refund of a deposit associated with the Gulf Wind energy derivative. These increases to cash available for distribution are partially offset by increases in project expenses of approximately $5.0 million, operating expenses of $1.8 million and interest expense of $1.9 million, primarily from the commencement of operations at Panhandle 2 and Logan's Gap, and the acquisitions of Lost Creek and Post Rock.

Cash available for distribution was $59.6 million for the nine months ended September 30, 2015 as compared to $44.8 million for the same period in the prior year, an increase of $14.8 million, or 32.9%. This increase was primarily due to additional electricity sales from the commencement of commercial operations at Panhandle 1, El Arrayán, and Panhandle 2 at various times in 2014 as well as Logan's Gap in September of 2015 and the acquisitions of Lost Creek and Post Rock in the second quarter of 2015. In addition, we received an increase of $18.8 million in cash distributions from unconsolidated investments



Table of Contents

and a $5.8 million increase from energy derivative settlements in the nine months of 2015 compared to the same period in the prior year. Cash available for distribution was also impacted by a $5.4 million cash distribution from the partial refund of a deposit associated with the Gulf Wind energy derivative. These increases were partially offset by increases in project expenses of $25.5 million, operating expenses of $7.5 million, interest expense of $8.4 million, primarily from the commencement of operations at Panhandle 1, El Arrayán, Panhandle 2, and Logan's Gap and the acquisitions of Lost Creek and Post Rock.

Results of Operations

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

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



	Three months ended September 30,
	2015			2014			$ Change			% Change
Revenue	$	89,697		$	71,519		$	18,178		25.4	%
Project expense	28,848			23,835			5,013			21.0	%
Depreciation and accretion	38,599			30,015			8,584			28.6	%
Total cost of revenue	67,447			53,850			13,597			25.2	%
Gross profit	22,250			17,669			4,581			25.9	%
General and administrative	7,218			5,772			1,446			25.1	%
Related party general and administrative	1,887			1,492			395			26.5	%
Total operating expenses	9,105			7,264			1,841			25.3	%
Operating income	13,145			10,405			2,740			26.3	%
Total other expense	(50,658		)	(23,224		)	(27,434		)	118.1	%
Net loss before income tax	(37,513		)	(12,819		)	(24,694		)	192.6	%
Tax benefit	(2,181		)	(3,538		)	1,357			(38.4	)%
Net loss	(35,332		)	(9,281		)	(26,051		)	280.7	%
Net loss attributable to noncontrolling interest	(5,927		)	(2,073		)	(3,854		)	185.9	%
Net loss attributable to controlling interest	$	(29,405	)	$	(7,208	)	$	(22,197	)	307.9	%

Revenue. Revenue for the three months ended September 30, 2015 was $89.7 million as compared to $71.5 million for the three months ended September 30, 2014, an increase of $18.2 million, or 25.4%. This increase in revenue was primarily attributable to increased electricity sales due to the acquisitions of Lost Creek and Post Rock, in the second quarter of 2015 and the commencement of commercial operations at Panhandle 2 in November 2014 and Logan's Gap in September 2015.

Cost of revenue. Cost of revenue for the three months ended September 30, 2015 was $67.4 million as compared to $53.9 million for the three months ended September 30, 2014, an increase of $13.6 million, or 25.2%. The increase in cost of revenue was primarily attributable to the commencement of commercial operations at Panhandle 2 in November 2014 and Logan's Gap in September 2015 and the acquisitions of Lost Creek and Post Rock, in the second quarter of 2015. As each new project commences commercial operations, we incur new incremental and ongoing costs for maintenance and services agreements, property taxes, insurance, land lease, depreciation and other costs associated with managing, operating and maintaining the facility, including adding site employees and other operations staff.

Operating expenses. Operating expenses for the three months ended September 30, 2015 were $9.1 million as compared to $7.3 million for the three months ended September 30, 2014, an increase of $1.8 million, or 25.3%. The increase in operating expenses was primarily attributable to increases in general and administrative expense to support new projects which were acquired or became commercially operable in 2014 and 2015.



Table of Contents

Other expense. Other expense for the three months ended September 30, 2015 was $50.7 million compared to $23.2 million for the three months ended September 30, 2014, an increase of $27.4 million, or 118.1%. The increase in other expense was primarily attributable to the following:


•	a $9.8 million increase in realized losses on derivatives due primarily to the termination of the interest rate swap and cap associated with the repayment of debt at Gulf Wind previously recorded in other comprehensive income;


•	a $5.2 million increase in unrealized losses on interest rate derivatives due primarily to decreases in forward interest rate curves compared to the previous period;


•	a $4.9 million increase in equity in losses in unconsolidated investments due primarily to losses on interest rate derivatives as a result of decreasing forward interest rate curves compared to the prior period;


•	a $4.1 million loss from early extinguishment of debt at Gulf Wind;


•	a $1.9 million increase in interest expense due primarily to the issuance of convertible debt in July 2015 and increased loan balances on the revolving credit facility; and


•	a $1.4 million increase in interest rate derivative settlements due primarily to the settlement of an undesignated interest rate swap at Lost Creek.

Tax (benefit) provision. The tax benefit was $2.2 million for the three months ended September 30, 2015 compared to a $3.5 million benefit for the three months ended September 30, 2014, a decrease of $1.4 million, or 38.4%. The benefit for the three months ended September 30, 2015 was primarily the result of reducing the deferred tax liability on the recognized equity in income in unconsolidated investments at South Kent, Grand, and K2, related to unrealized losses on undesignated derivatives, recognizing a deferred tax asset on the recognized losses in El Arrayán offset by the tax expense in our Canadian and Puerto Rican operations and the foreign withholding taxes on intercompany transactions in certain foreign jurisdictions. The benefit for the three months ended September 30, 2014 was primarily the result of recording a deferred tax asset on the recognized equity in losses in unconsolidated investments at South Kent and Grand, related to unrealized losses on undesignated derivatives.

Net loss attributable to noncontrolling interest. The net loss attributable to noncontrolling interest was $5.9 million for the three months ended September 30, 2015 compared to $2.1 million for the three months ended September 30, 2014, an increase of $3.9 million, or 185.9%, primarily due to net loss attributable to noncontrolling interests from Panhandle 2, which was acquired and commenced commercial operations in November 2014 and to net loss attributable to noncontrolling interests from Post Rock, which was acquired in the second quarter of 2015.



Table of Contents

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

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



	Nine months ended September 30,
	2015			2014			$ Change			% Change
Revenue	$	239,234		$	186,075		$	53,159		28.6	%
Project expense	82,075			56,609			25,466			45.0	%
Depreciation and accretion	101,997			72,476			29,521			40.7	%
Total cost of revenue	184,072			129,085			54,987			42.6	%
Gross profit	55,162			56,990			(1,828		)	(3.2	)%
General and administrative	22,309			15,963			6,346			39.8	%
Related party general and administrative	5,316			4,155			1,161			27.9	%
Total operating expenses	27,625			20,118			7,507			37.3	%
Operating income	27,537			36,872			(9,335		)	(25.3	)%
Total other expense	(78,595		)	(62,390		)	(16,205		)	26.0	%
Net loss before income tax	(51,058		)	(25,518		)	(25,540		)	100.1	%
Tax provision (benefit)	676			(1,505		)	2,181			(144.9	)%
Net loss	(51,734		)	(24,013		)	(27,721		)	115.4	%
Net loss attributable to noncontrolling interest	(16,747		)	(13,115		)	(3,632		)	27.7	%
Net loss attributable to controlling interest	$	(34,987	)	$	(10,898	)	$	(24,089	)	221.0	%

Revenue. Revenue for the nine months ended September 30, 2015 was $239.2 million as compared to $186.1 million for the nine months ended September 30, 2014, an increase of $53.2 million, or 28.6%. This increase in revenue was primarily due to increased electricity sales related to the acquisition and commencement of commercial operations at El Arrayán, Panhandle 1 and Panhandle 2 at various times in 2014 and Logan's Gap in September 2015, and the acquisitions of Lost Creek, and Post Rock in the second quarter of 2015.

Unrealized gain on energy derivative increased $12.7 million in the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014 due to lower forward electricity price curves. In addition, energy derivative settlements increased $5.8 million in the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014 due to decreased spot market electricity prices. 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 nine months ended September 30, 2015 was $184.1 million as compared to $129.1 million for the nine months ended September 30, 2014, an increase of $55.0 million, or 42.6%. The increase in cost of revenue was primarily attributable to the commencement of commercial operations at Panhandle 1, Panhandle 2, and El Arrayán at various times in 2014 and Lost Creek and Post Rock in the second quarter of 2015 and Logan's Gap in September 2015. As each new project commences commercial operations, we incur new incremental and ongoing costs for maintenance and services agreements, property taxes, insurance, land lease, depreciation and other costs associated with managing, operating and maintaining the facility, including adding site employees and other operations staff.

Operating expenses. Operating expenses for the nine months ended September 30, 2015 were $27.6 million as compared to $20.1 million for the nine months ended September 30, 2014, an increase of $7.5 million, or 37.3%. The increase in operating expenses was primarily attributable to increases in general and administrative expense to support new projects which were acquired or became commercially operable in 2014 and 2015.



Table of Contents

Other expense. Other expense for the nine months ended September 30, 2015 was $78.6 million compared to $62.4 million for the nine months ended September 30, 2014, an increase of $16.2 million, or 26.0%. The increase in other expense was primarily attributable to the following:


•	a $17.1 million increase in net losses on transactions due primarily to the absence of a $18.0 million gain related to the additional 38.5% interest in the El Arrayán project recorded in the comparable prior period;


•	a $9.8 million increase in realized losses on derivatives due primarily to the termination of the interest rate swap and cap associated with the repayment of debt at Gulf Wind previously recorded in other comprehensive income;


•	a $8.4 million increase in interest expense due primarily to the issuance of convertible debt in July 2015 and increased loan balances on the revolving credit facility; and


•	a $4.1 million loss from early extinguishment of debt at Gulf Wind.

Other expense increases listed above were offset primarily by a $22.0 million decrease in equity in losses in unconsolidated investments due to gains from interest rate derivatives when compared to losses in the comparable prior year period.

Tax (benefit) provision. The tax provision was $0.7 million for the nine months ended September 30, 2015 compared to a $1.5 million benefit for the nine months ended September 30, 2014, a decrease of $2.2 million, or 144.9%. The tax provision for the nine months ended September 30, 2015 was attributable to the recognition of deferred tax liabilities on equity earnings in unconsolidated investments at South Kent, Grand, and K2, tax expense at our Canadian and Puerto Rican operations, and foreign withholding taxes on intercompany transactions in certain foreign jurisdictions, offset by the recognition of a deferred tax asset on losses at El Arrayán. The benefit for the nine months ended September 30, 2014 was primarily related to the recording of a deferred tax asset on the unrealized derivative losses at South Kent and Grand offset by the recording of a discrete tax expense on the gain related to the fair value remeasurement of our original 31.5% interest in El Arrayán.

Net loss attributable to noncontrolling interest. The net loss attributable to noncontrolling interest was $16.7 million for the nine months ended September 30, 2015 compared to $13.1 million for the nine months end September 30, 2014, an increase of $3.6 million, or 27.7%. This increase was primarily related to net loss from noncontrolling interests from Panhandle 1, Panhandle 2, and El Arrayán, all of which commenced commercial operations at various times in 2014, and to net loss from noncontrolling interests from Post Rock which was acquired in the second quarter of 2015.

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 September 30, 2015 and December 31, 2014, our available liquidity was as follows (in millions):



	September 30, 2015		December 31, 2014
Unrestricted cash	$	103.2	$	101.7
Restricted cash	52.3		47.7
Revolver availability	155.8		254.9
Project facilities:
Post construction use	92.9		90.5
Construction use	68.6		188.4
	$	472.8	$	683.2

We believe that throughout 2015 and 2016, we will have sufficient liquid assets, cash flows from operations, borrowings available under our revolving credit facility as well as funds provided by tax equity investors, to meet our financial commitments, debt service obligations, contingencies and anticipated required capital expenditures, without taking into account



Table of Contents

capital required for additional project acquisitions. Additionally, we believe that our construction project has been sufficiently capitalized, or that we have sufficient liquidity, such that we will not need to seek additional financing arrangements in order to complete construction and achieve commercial operations at the project. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corresponding adverse effect on our borrowing capacity. In connection with our future capital expenditures and other investments, including any project acquisitions that we may make, we may, from time to time, issue debt or equity securities.

Financing Developments

Since May 2015, we have consummated repricings and refinancings of borrowings under several of our project level finance facilities, including at South Kent, Lost Creek, and Spring Valley. As a result of such repricings and refinancings, we have (among other things) reduced the interest rates charges paid under the project finance facilities (South Kent, Lost Creek, and Spring Valley), reduced the size of future scheduled step-ups in interest rates and extended the time periods prior to such scheduled step-ups becoming effective (Lost Creek and Spring Valley), and made prepayments of amounts due under the facilities and thereby reducing the aggregate principal amount subject to financing (Spring Valley), while also negotiating elimination of certain reserve accounts under such facilities. In addition, during the third quarter of 2015, we also prepaid 100% of the outstanding balance of the Gulf Wind project’s term loan of $154.1 million. Such repricings, refinancings, and repayments result in both current and long-term future financial benefits to the Company, including reduced interest expense, reduced project-level debt scheduled principal repayments, increased likelihood the projects will be able to satisfy conditions precedent to distribute excess cash flows upstream to owners, and reduced capital allocated to project-level standby reserves which have beneficial effects to our consolidated statements of operations, as well as net cash provided by operating activities which is the most directly comparable U.S. GAAP measure to our cash available for distribution. We believe the effects of these repricings, refinancings, and repayments have helped, and will continue to help, contribute to offsetting effects of other events which have occurred in 2015 and may continue after 2015, such as low wind levels which have occurred across the western United States and Texas, which negatively impacts net cash provided by operating activities, as well as, indirectly, cash available for distribution. Subject to market conditions, we will continue to consider various forms of repricings, refinancings, and/or repayments of our project level finance facilities. No assurances, however, can be given that we will be able to consummate any such transactions, the transactions can be consummated on terms that are financially favorable to us, or that such transactions will have the intended financial effects of improving the consolidated statements of operations, net cash provided by operating activities, or cash available for distribution.

Cash Flows

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



	September 30, 2015			September 30, 2014
Net cash provided by operating activities	$	83.3		$	83.9
Net cash used in investing activities	(686.2		)	(154.1		)
Net cash provided by financing activities	607.7			198.1
Effect of exchange rate changes	(3.3		)	(0.8		)
Net change in cash and cash equivalents	$	1.5		$	127.1

Net Cash Provided by Operating Activities

Net cash provided by operating activities was $83.3 million for the nine months ended September 30, 2015 as compared to $83.9 million for the nine months ended September 30, 2014, a decrease of $0.6 million, or 0.7%. The decrease in net cash provided by operating activities is primarily related to additional electricity revenue from commercial operations at Panhandle 1, El Arrayán, Panhandle 2, which commenced operations at various times in 2014, and Logan's Gap in September 2015, and the acquisitions of Lost Creek and Post Rock, which were acquired in the second quarter of 2015 offset by increases in operating expenses associated with new project additions.



Table of Contents

Net Cash Used in Investing Activities

Net cash used in investing activities was $686.2 million for the nine months ended September 30, 2015, which consisted primarily of $406.3 million of acquisitions, net of cash acquired, which includes $238.5 million for both Lost Creek and Post Rock, $37.5 million for Amazon Wind Farm (Fowler Ridge) and $128.4 million for an unconsolidated investment in K2, in addition to $316.0 million for capital expenditures related to the construction at Logan’s Gap and Amazon Wind Farm (Fowler Ridge). These increases were partially offset by $23.5 million of distributions from unconsolidated investments.

Net Cash Provided by Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2015 was $607.7 million, which consisted of proceeds of $317.8 million from the February and July 2015 equity offerings, $219.6 million from the July 2015 issuance of convertible debt, net of issuance costs, $295.0 million from the revolving credit facility, $294.5 million in construction loans, and tax equity funding for Logan's Gap of $191.3 million. Offsetting these increases were dividend payments of $63.5 million, payments of $121.2 million for the purchase of the noncontrolling interests at Gulf Wind and Lost Creek in July 2015, and repayments of $405.0 million in long-term debt related to Gulf Wind and Logan's Gap.

Cash Dividends to Investors

We intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A common stock. On November 26, 2013, we announced the initiation of a quarterly dividend on our Class A common stock. On October 29, 2015, we increased our dividend to $0.372 per share, or $1.49 per share on an annualized basis, commencing with respect to dividends paid on January 29, 2016 to holders of record on December 31, 2015. The following table sets forth the dividends declared on shares of Class A common stock for the periods indicated.



	Dividends Per Share		Declaration Date	Record Date	Payment Date
2015:
Fourth Quarter	$	0.3720	October 29, 2015	December 31, 2015	January 29, 2016
Third Quarter	0.3630		July 21, 2015	September 30, 2015	October 30, 2015
Second Quarter	0.3520		April 20, 2015	June 30, 2015	July 30, 2015
First Quarter	0.3420		February 24, 2015	March 31, 2015	April 30, 2015
2014:
Fourth Quarter	$	0.3350	October 29, 2014	December 31, 2014	January 30, 2015
Third Quarter	0.3280		August 1, 2014	September 30, 2014	October 30, 2014
Second Quarter	0.3220		April 30, 2014	June 30, 2014	July 30, 2014
First Quarter	0.3125		February 26, 2014	March 31, 2014	April 30, 2014

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



Table of Contents

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

Capital Expenditures and Investments

Construction

All capital expenditures and investments to date were either funded by us, Pattern Development or by project finance lenders under project-level credit facilities. For the remainder of 2015, we expect to make capital expenditures of $94.7 million at our owned construction project – Amazon Wind Farm (Fowler Ridge).

Acquisitions

We expect to make investments in additional projects. We have made payments to Pattern Development in the amount of $37.5 million in connection with the Amazon Wind Farm (Fowler Ridge) acquisition, $128.0 million in connection with the K2 acquisition and $242.0 million to unrelated third parties to acquire Lost Creek and Post Rock. Refer to Note 3, Acquisitions, for additional information. In addition, in July 2015, we acquired the noncontrolling interests in the Gulf Wind project for $85.8 million and acquired 100% of the Class A membership interests in Lost Creek Wind Holdco for approximately $35.2 million. Refer to Note 16, Stockholders' Equity - Noncontrolling Interests, for additional information.

Although we have no commitments to make any acquisitions, we consider it reasonably likely that we may have the opportunity to acquire certain other Pattern Development projects under our purchase rights within the next 24 month period.

Operations

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 remainder of 2015, our operational and expansionary capital expenditures are projected to be approximately $0.4 million and $6.4 million, respectively.

Critical Accounting Policies and Estimates

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

Change in Depreciable Lives of Property, Plant and Equipment

We periodically review the estimated economic useful lives of our fixed assets. In 2015, our review indicated that the expected economic useful lives of certain wind farms were longer than the estimated economic useful lives used for depreciation purposes in our financial statements. As a result, effective January 1, 2015, we changed our estimate of the economic useful lives of wind farms for which construction began after 2011, from 20 to 25 years. All other wind farms continue to depreciate over an estimated economic useful life of 20 years. For the three and nine months ended September 30, 2015, the effect of this change reduced depreciation expense by $3.6 million and $11.0 million, respectively, decreased net loss by $3.4 million and $10.4 million, net of tax, respectively, and decreased Class A basic and diluted loss per share by $0.02 and $0.07, respectively.

Contractual Obligations

We have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to our capital expenditure programs, as disclosed in the Annual Report on Form 10-K for the year ended December 31, 2014. See also Note 10, Long-term Debt, and Note 20, Commitments and Contingencies, in the consolidated financial statements for additional discussion of contractual obligations.



Table of Contents

Below is a summary of our proportion of debt in unconsolidated investments, as of September 30, 2015 (in thousands):



	Total Project Debt		Percentage of Ownership		Our Portion of Unconsolidated Project Debt
South Kent	$	485,570	50.0	%	$	242,785
Grand	282,417		45.0	%	127,088
K2	556,415		33.3	%	185,467
Unconsolidated investments - debt	$	1,324,402			$	555,340

Off-Balance Sheet Arrangements

As of September 30, 2015, we had no off-balance sheet arrangements and have not entered into any transactions involving uncombined, limited purpose entities or commodity contracts.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have significant exposure to commodity prices, interest rates and foreign currency exchange rates, as described below. To mitigate these market risks, we have entered into multiple derivatives. We have not applied hedge accounting treatment to all of our derivatives, therefore we are required to mark some of our derivatives to market through earnings on a periodic basis, which will result in non-cash adjustments to our consolidated net loss and may result in volatility in our earnings, in addition to potential cash settlements for any losses.

Commodity Price Risk

We manage our commodity price risk for electricity sales through the use of long-term power sale agreements with creditworthy counterparties. Our financial results reflect approximately 1,836,348 MWh of electricity sales during the nine months ended September 30, 2015 that were not subject to power sale agreements and were subject to spot market pricing. A hypothetical increase or decrease of $3.86 per MWh (or an approximately 10% change) in these spot market prices would have increased or decreased consolidated net loss by $1.4 million for the nine months ended September 30, 2015.

Interest Rate Risk

We use a variety of derivative instruments to manage our exposure to fluctuations in interest rates, including interest rate swaps, primarily in the context of our project-level indebtedness. We generally match the tenor and amount of these instruments to the tenor and amount, respectively, of the related debt financing. We also will have exposure to changes in interest rates with respect to our revolving credit agreement to the extent that we make draws under that facility. A hypothetical increase or decrease in short-term interest rates by 100 basis points would have increased or decreased consolidated net loss by $0.9 million for the nine months ended September 30, 2015.

Foreign Currency Risk

We use foreign currency forward contracts to manage our exposure to fluctuations in foreign currency exchange rates. Our wind power projects are located in the United States, Canada and Chile. As a result, our financial results could be significantly affected by factors such as changes in foreign currency exchange rates or weak economic conditions in the foreign markets in which we operate. When the U.S. dollar strengthens against foreign currencies, the relative value in revenue earned in the respective foreign currency decreases. When the U.S. dollar weakens against foreign currencies, the relative value in revenue earned in the respective foreign currency increases. A majority of our power sale agreements and operating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. For the nine months ended September 30, 2015, our financial results included C$5.7 million, or $4.8 million calculated based on the monthly average exchange rate, in net loss from our St. Joseph project and our equity in losses at our South Kent, Grand and K2 projects. A hypothetical increase or decrease of 10% in exchange rates between the Canadian and U.S. dollar would have increased or decreased consolidated net loss by $0.5 million for the nine months ended September 30, 2015.



Table of Contents

ITEM 4. CONTROLS AND PROCEDURES

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

Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2015.

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



Table of Contents

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject, from time to time, to routine legal proceedings and claims arising out of the normal course of business. There has been no material change in the nature of our legal proceedings from the description provided in our Annual Report on Form 10-K for the year ended December 31, 2014, except that with respect to the legal proceedings at Ocotillo, the U.S. Court of Appeals for the Ninth Circuit has scheduled oral arguments on the appeals in early November 2015. Additional information with respect to such litigation can be found in the Annual Report on Form 10-K for the year ended December 31, 2014 under “Item 3. Legal Proceedings - Ocotillo.”

In addition, during the third quarter of 2015, rights to appeal prior decisions granting the Renewable Energy Approval (“REA”) under Ontario's Environmental Protection Act for our K2 Wind facility were exhausted without further appeal. As a result, a stay of a previously filed civil suit against the K2 Wind facility pending final determination of the REA is lifted, allowing such suit to move forward if the claimants so choose to continue such suit. Such civil suit had claimed, among other things, nuisance based on both the construction and operation of the facility.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should consider the risks described under the caption “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2014 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015. There have been no material changes in our risk factors as described in such documents, except as set forth below.

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

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

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

Risks Related to Our Acquisition Strategy and Future Growth

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

Our business strategy includes acquiring power and transmission projects that are either operational, construction-ready, or in limited circumstances, under development. We intend to pursue opportunities to acquire projects from third-party IPPs where we may submit bids from time to time and from Pattern Development pursuant to our purchase rights. Various factors could affect the availability of attractive projects to grow our business, including:


•	competing bids for a project, including a project subject to our purchase rights, from other IPPs, including companies that may have substantially greater capital and other resources than we do;


•	fewer third-party acquisition opportunities than we expect, which could result from, among other things, available projects having less desirable economic returns or higher risk profiles than we believe suitable for our business plan and investment strategy;

•

Pattern Development's failure to complete the development of (i) the identified ROFO projects, which could result from, among other things, permitting challenges, failure to procure the requisite financing, equipment or interconnection, or an inability to satisfy the conditions to effectiveness of project agreements such as PPAs and (ii) any of the other projects in its development pipeline, in a timely manner, or at all, in either case, which could limit our acquisition opportunities under our purchase rights;



Table of Contents


•	our failure to exercise our purchase rights or acquire assets from Pattern Development;


•	our failure to successfully develop and finance projects, to the extent that we decide to pursue development activities with respect to new power projects;

•

local opposition to wind turbine installations is growing in certain markets due to concerns about noise, health and other alleged impacts of wind power projects. In addition, indigenous communities in the United States and Canada, including Native Americans and First Nations, are becoming more involved in the development of wind power projects and have certain treaty rights that can negatively affect the viability of power projects. As a result, for these and other reasons, litigation and challenges to wind power projects has increased; and

•

volatility in the market price of our Class A shares may prevent or limit our ability to utilize our equity securities as a source of capital to help fund acquisition opportunities. We utilized in part proceeds from underwritten public offerings of our Class A shares in both July 2015 and February 2015 for investment in acquisition opportunities and to repay other debt previously incurred to finance acquisition opportunities. In the event we determine it is not economical to utilize, or we are unable to utilize our equity securities as a source of capital to fund acquisition opportunities, we may need to consider utilizing other sources of capital, such as cash on hand, borrowings under our existing credit facilities, arranging additional credit facilities, or the issuance of debt securities, none of which may be available or may not be available at attractive terms.

Any of these factors could prevent us from executing our growth strategy, including acquiring ROFO assets from Pattern Development, or otherwise have a material adverse effect on our business, financial condition and results of operations.

Additionally, even if we consummate acquisitions that we believe will be accretive to cash available for distribution per share, those acquisitions may in fact result in a decrease in cash available for distribution per Class A share as a result of incorrect assumptions in our evaluation of such acquisitions, unforeseen consequences or other external events beyond our control. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations may change significantly, and stockholders will not generally have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.



Table of Contents

ITEM 6. EXHIBITS



Exhibit No.		Description

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

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

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

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

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

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

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

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

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

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

10.4		Amendment No. 2 dated as of September 28, 2015 to the Amended and Restated Credit and Guaranty Agreement, dated as of December 17, 2014, among Pattern US Finance Company LLC, Pattern Canada Finance Company ULC , Royal Bank of Canada (acting through its New York Branch), as Administrative Agent and the other parties party thereto (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed October 1, 2015).

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

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

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

99.1		Amendment No. 1 dated as of June 12, 2015 to the Amended and Restated Credit and Guaranty Agreement, dated as of December 17, 2014, among Pattern US Finance Company LLC, Pattern Canada Finance Company ULC , Royal Bank of Canada (acting through its New York Branch), as Administrative Agent and the other parties party thereto.

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



Table of Contents



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.



Table of Contents

SIGNATURE

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



			Pattern Energy Group Inc.

Dated:	November 5, 2015	By:	/s/ Michael J. Lyon
			Michael J. Lyon
			Chief Financial Officer

			(On behalf of the Registrant and as Principal Financial Officer)

Pattern Energy Group Inc. - FORM 10-Q - November 4, 2015

Attached files

Pattern Energy Group Inc. Reports