Pattern Energy Group Inc. - FORM 10-Q

Attached files

file	filename
EX-32 - EXHIBIT 32 - Pattern Energy Group Inc.	pegi2018093010qexhibit32.htm
EX-31.2 - EXHIBIT 31.2 - Pattern Energy Group Inc.	pegi2018093010qexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - Pattern Energy Group Inc.	pegi2018093010qexhibit311.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, 2018.



☐	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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐

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



Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐



If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.	☐

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

As of November 1, 2018, there were 98,095,884 shares of Class A common stock outstanding with par value of $0.01 per share.

PATTERN ENERGY GROUP INC.

REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2018

TABLE OF CONTENTS



	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	5

	Consolidated Balance Sheets as of September 30, 2018 (unaudited) and December 31, 2017	5
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2018 and 2017 (unaudited)	6
	Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2018 and 2017 (unaudited)	7
	Consolidated Statements of Stockholders’ Equity for the Nine Months Ended September 30, 2018 and 2017 (unaudited)	8
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2018 and 2017 (unaudited)	9
	Notes to Consolidated Financial Statements (unaudited)	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	45
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	59
Item 4.	Controls and Procedures	60

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 6.	Exhibits	63
	Signatures	65

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q (Form 10-Q) may constitute “forward-looking statements.” You can identify these statements by forward-looking words such as "anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan," "potential," "should," "will," "would," or similar words. You should read statements that contain these words carefully because they discuss our current plans, strategies, prospects, and expectations concerning our business, operating results, financial condition, and other similar matters. While we believe that these forward-looking statements are reasonable as and when made, there may be events in the future that we are not able to predict accurately or control, and there can be no assurance that future developments affecting our business will be those that we anticipate. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause 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 acquisitions of power projects;


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


•	fluctuations in supply, demand, prices and other conditions for electricity, other commodities and renewable energy credits (RECs);


•	our electricity generation, our projections thereof and factors affecting production, including wind, solar and other conditions, other weather conditions, turbine and transmission 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 those related to taxation, 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 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, solar panels and other equipment;


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


•	scarcity of necessary equipment;


•	negative public or community response to wind and solar power projects;


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


•	other factors discussed under “Risk Factors.”

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see Part II, "Item 1A. Risk Factors" in this Form 10-Q and Part I, "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2017.

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

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

	September 30,			December 31,
	2018			2017
Assets
Current assets:
Cash and cash equivalents (Note 8)	$	125,689		$	116,753
Restricted cash (Note 8)	6,324			9,065
Counterparty collateral	5,855			29,780
Trade receivables (Note 8)	50,303			54,900
Derivative assets, current	15,842			19,445
Prepaid expenses (Note 8)	21,080			17,847
Deferred financing costs, current, net of accumulated amortization of $2,670 and $2,580 as of September 30, 2018 and December 31, 2017, respectively	1,482			1,415
Other current assets (Note 8)	13,584			21,105
Total current assets	240,159			270,310
Restricted cash (Note 8)	13,899			12,162
Major construction advances	71,406			—
Construction in progress	221,185			—
Property, plant and equipment, net (Note 8)	4,109,864			3,965,121
Unconsolidated investments	372,380			311,223
Derivative assets	24,757			9,628
Deferred financing costs	8,797			7,784
Net deferred tax assets	1,616			6,349
Finite-lived intangible assets, net (Note 8)	221,183			136,048
Goodwill	56,453			—
Other assets (Note 8)	30,372			22,906
Total assets	$	5,372,071		$	4,741,531

Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities (Note 8)	$	57,360		$	53,615
Accrued construction costs (Note 8)	38,442			1,369
Counterparty collateral liability	5,855			29,780
Accrued interest (Note 8)	7,621			16,460
Dividends payable	42,185			41,387
Derivative liabilities, current	2,190			8,409
Revolving credit facility, current	186,372			—
Current portion of long-term debt, net	63,671			51,996
Contingent liabilities, current	24,771			2,592
Other current liabilities (Note 8)	12,955			11,426
Total current liabilities	441,422			217,034
Revolving credit facility	23,760			—
Long-term debt, net	2,105,834			1,878,735
Derivative liabilities	14,985			20,972
Net deferred tax liabilities	120,104			56,491
Finite-lived intangible liabilities, net (Note 8)	57,039			51,194
Contingent liabilities (Note 8)	140,048			62,398
Asset retirement obligations (Note 8)	192,006			56,619
Other long-term liabilities (Note 8)	64,033			49,946
Advanced lease revenue	28,268			—
Total liabilities	3,187,499			2,393,389
Commitments and contingencies (Note 17)
Equity:
Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 98,095,886 and 97,860,048 shares outstanding as of September 30, 2018 and December 31, 2017, respectively	983			980
Additional paid-in capital	1,170,450			1,234,846
Accumulated loss	(12,595		)	(112,175		)
Accumulated other comprehensive loss	(15,716		)	(25,691		)
Treasury stock, at cost; 178,783 and 157,812 shares of Class A common stock as of September 30, 2018 and December 31, 2017, respectively	(3,901		)	(3,511		)
Total equity before noncontrolling interest	1,139,221			1,094,449
Noncontrolling interest	1,045,351			1,253,693
Total equity	2,184,572			2,348,142
Total liabilities and equity	$	5,372,071		$	4,741,531

See accompanying notes to consolidated financial statements.

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

	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Revenue:
Electricity sales	$	115,417		$	89,807		$	353,515		$	293,977
Other revenue	2,976			2,223			16,477			6,646
Total revenue	118,393			92,030			369,992			300,623
Cost of revenue:
Project expense	37,229			33,932			105,456			96,437
Transmission costs	5,700			7,421			20,533			12,213
Depreciation, amortization and accretion	55,267			52,379			165,698			144,637
Total cost of revenue	98,196			93,732			291,687			253,287
Gross profit (loss)	20,197			(1,702		)	78,305			47,336
Operating expenses:
General and administrative	9,305			9,068			29,100			31,969
Related party general and administrative	4,285			3,587			12,016			10,589
Impairment expense	2,325			—			6,563			—
Total operating expenses	15,915			12,655			47,679			42,558
Operating income (loss)	4,282			(14,357		)	30,626			4,778
Other expense:
Interest expense	(27,460		)	(27,147		)	(80,613		)	(74,541		)
Gain (loss) on derivatives	1,536			(6,288		)	15,997			(11,687		)
Earnings (loss) in unconsolidated investments, net	(4,304		)	(3,964		)	13,166			27,431
Net earnings (loss) on transactions	1,130			(466		)	(1,970		)	(1,585		)
Other income (expense), net	(3,688		)	7			(8,910		)	560
Total other expense	(32,786		)	(37,858		)	(62,330		)	(59,822		)
Net loss before income tax	(28,504		)	(52,215		)	(31,704		)	(55,044		)
Tax provision (benefit)	3,043			(3,839		)	14,237			5,477
Net loss	(31,547		)	(48,376		)	(45,941		)	(60,521		)
Net loss attributable to noncontrolling interest	(18,952		)	(18,548		)	(201,986		)	(50,566		)
Net income (loss) attributable to Pattern Energy	$	(12,595	)	$	(29,828	)	$	156,045		$	(9,955	)

Weighted-average number of common shares outstanding
Basic	97,460,492			87,370,979			97,464,012			87,146,465
Diluted	97,460,492			87,370,979			105,788,848			87,146,465
Earnings (loss) per share attributable to Pattern Energy
Basic	$	(0.13	)	$	(0.34	)	$	1.60		$	(0.12	)
Diluted	$	(0.13	)	$	(0.34	)	$	1.58		$	(0.12	)

See accompanying notes to consolidated financial statements.

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

	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Net loss	$	(31,547	)	$	(48,376	)	$	(45,941	)	$	(60,521	)
Other comprehensive income (loss):
Foreign currency translation, net of tax of zero, $3,656, zero and $3,656	2,901			8,230			(19,547		)	17,979
Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax of ($2,273), ($1,285), ($1,227) and ($1,344), respectively	12,152			1,920			20,888			(2,498		)
Reclassifications to net loss due to de-designation of interest rate derivatives, net of zero tax impact	—			2,207			(1,529		)	2,207
Reclassifications to net loss, net of tax impact of $279, $351, $618 and $838 respectively	819			2,540			3,437			7,023
Total change in derivative activity	12,971			6,667			22,796			6,732
Proportionate share of equity investee’s derivative activity:
Effective portion of change in fair market value of derivatives, net of tax of ($1,505), ($2,075), ($1,980) and ($2,360), respectively	4,175			5,756			5,492			6,546
Reclassifications to net loss, net of tax of $375, $672, $1,273 and $2,333, respectively	1,041			1,863			3,530			6,471
Total change in proportionate share of equity investee's derivative activity	5,216			7,619			9,022			13,017
Total other comprehensive income, net of tax	21,088			22,516			12,271			37,728
Comprehensive loss	(10,459		)	(25,860		)	(33,670		)	(22,793		)
Less comprehensive income (loss) attributable to noncontrolling interest:
Net loss attributable to noncontrolling interest	(18,952		)	(18,548		)	(201,986		)	(50,566		)
Foreign currency translation, net of zero tax impact	1,636			(718		)	(1,277		)	(718		)
Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax of $12, ($267), ($96) and ($166), respectively	2,245			763			3,226			489
Reclassifications to net gain due to de-designation of interest rate derivatives, net of zero tax impact	—			—			(447		)	—
Reclassifications to net loss, net of tax of $38, $86, $41 and $148, respectively	167			244			794			411
Total change in derivative activity	2,412			1,007			3,573			900
Comprehensive loss attributable to noncontrolling interest	(14,904		)	(18,259		)	(199,690		)	(50,384		)
Comprehensive income (loss) attributable to Pattern Energy	$	4,445		$	(7,601	)	$	166,020		$	27,591

See accompanying notes to consolidated financial statements.



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

	Class A Common Stock			Treasury Stock					Additional Paid-in Capital			Accumulated Income (Loss)			Accumulated Other Comprehensive Income (Loss)			Total			Noncontrolling Interest				Total Equity
	Shares	Amount		Shares		Amount			Additional Paid-in Capital			Accumulated Income (Loss)			Accumulated Other Comprehensive Income (Loss)			Total			Noncontrolling Interest				Total Equity
Balances at December 31, 2016	87,521,651	$	875	(110,964	)	$	(2,500	)	$	1,145,760		$	(94,270	)	$	(62,367	)	$	987,498		$	891,246			$	1,878,744
Issuance of Class A common stock, net of issuance costs	931,561	9		—		—			22,500			—			—			22,509			—				22,509
Issuance of Class A common stock under equity incentive award plan	231,311	2		—		—			(2		)	—			—			—			—				—
Repurchase of shares for employee tax withholding	—	—		(4,182	)	(97		)	—			—			—			(97		)	—				(97		)
Stock-based compensation	—	—		—		—			4,085			—			—			4,085			—				4,085
Dividends declared ($1.25 per Class A common share)	—	—		—		—			(110,168		)	—			—			(110,168		)	—				(110,168		)
Acquisition of Broadview Project and Meikle	—	—		—		—			—			—			—			—			390,389				390,389
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(13,701		)		(13,701		)
Other	—	—		—		—			77			—			—			77			(201		)		(124		)
Net loss	—	—		—		—			—			(9,955		)	—			(9,955		)	(50,566		)		(60,521		)
Other comprehensive income, net of tax	—	—		—		—			—			—			37,546			37,546			182				37,728
Balances at September 30, 2017	88,684,523	$	886	(115,146	)	$	(2,597	)	$	1,062,252		$	(104,225	)	$	(24,821	)	$	931,495		$	1,217,349			$	2,148,844

Balances at December 31, 2017	98,017,860	$	980	(157,812	)	$	(3,511	)	$	1,234,846		$	(112,175	)	$	(25,691	)	$	1,094,449		$	1,253,693			$	2,348,142
Issuance of Class A common stock under equity incentive award plan	256,809	3		—		—			(3		)	—			—			—			—				—
Repurchase of shares for employee tax withholding	—	—		(20,971	)	(390		)	—			—			—			(390		)	—				(390		)
Stock-based compensation	—	—		—		—			3,517			—			—			3,517			—				3,517
Dividends declared ($1.27 per Class A common share)	—	—		—		—			(67,747		)	(56,465		)	—			(124,212		)	—				(124,212		)
Acquisitions	—	—		—		—			—			—			—			—			52,493			—	52,493
Sale of subsidiaries	—	—		—		—			—			—			—			—			(32,278		)		(32,278		)
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(28,867		)		(28,867		)
Other	—	—		—		—			(163		)	—			—			(163		)	—				(163		)
Net income (loss)	—	—		—		—			—			156,045			—			156,045			(201,986		)		(45,941		)
Other comprehensive income, net of tax	—	—		—		—			—			—			9,975			9,975			2,296				12,271
Balances at September 30, 2018	98,274,669	$	983	(178,783	)	$	(3,901	)	$	1,170,450		$	(12,595	)	$	(15,716	)	$	1,139,221		$	1,045,351			$	2,184,572

See accompanying notes to consolidated financial statements.

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

	Nine months ended September 30,
	2018			2017
Operating activities
Net loss	$	(45,941	)	$	(60,521	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion	187,741			156,330
Impairment expense	6,563			—
Loss (gain) on derivatives	(3,236		)	17,869
Stock-based compensation	3,517			4,085
Deferred taxes	13,910			9,133
Intraperiod tax allocation	—			(3,656		)
Earnings in unconsolidated investments, net	(13,166		)	(27,431		)
Distributions from unconsolidated investments	42,838			43,093
Other reconciling items	1,802			(2,047		)
Changes in operating assets and liabilities:
Counterparty collateral asset	23,925			10,105
Trade receivables	(47		)	(2,861		)
Prepaid expenses	(1,241		)	(3,187		)
Other current assets	13,749			(9,790		)
Other assets (non-current)	(4,173		)	2,457
Advanced lease revenue	33,792			—
Accounts payable and other accrued liabilities	(1,801		)	16,389
Counterparty collateral liability	(23,925		)	(10,105		)
Accrued interest	(5,841		)	(3,884		)
Other current liabilities	(2,651		)	6,650
Contingent liabilities, current	24,070			1,390
Long-term liabilities	7,366			14,569
Contingent liabilities	(27,013		)	742
Derivatives	228			—
Net cash provided by operating activities	230,466			159,330
Investing activities
Cash paid for acquisitions, net of cash and restricted cash acquired	(188,527		)	(229,329		)
Proceeds from sale of subsidiaries, net of cash and restricted cash distributed	55,820			—
Payment for construction advances/deposits	(68,937		)	—
Payment for construction in progress	(49,450		)	—
Payment for property, plant and equipment	(10,212		)	(44,295		)
Distributions from unconsolidated investments	4,752			11,211
Other assets	(781		)	7,607
Investment in Pattern Development 2.0	(86,254		)	(60,000		)
Net cash used in investing activities	(343,589		)	(314,806		)

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

	Nine months ended September 30,
	2018			2017
Financing activities
Proceeds from public offerings, net of issuance costs	—			22,431
Dividends paid	(123,616		)	(107,943		)
Capital contributions - noncontrolling interest	3,383			—
Capital distributions - noncontrolling interest	(28,867		)	(13,701		)
Payment for financing fees	(7,478		)	(7,763		)
Proceeds from revolving credit facility	488,907			323,000
Repayment of revolving credit facility	(279,000		)	(250,000		)
Proceeds from long-term debt	164,673			404,395
Repayment of long-term debt	(53,274		)	(192,109		)
Repayment of note payable - related party	(909		)	—
Repayment of short-term debt	(36,973		)	—
Payment for termination of designated derivatives	—			(14,372		)
Other financing activities	(2,771		)	(3,712		)
Net cash provided by financing activities	124,075			160,226
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(3,020		)	3,952
Net change in cash, cash equivalents and restricted cash	7,932			8,702
Cash, cash equivalents and restricted cash at beginning of period	137,980			109,371
Cash, cash equivalents and restricted cash at end of period	$	145,912		$	118,073
Supplemental disclosures
Cash payments for income taxes	$	490		$	335
Cash payments for interest expense	$	79,302		$	70,100
Schedule of non-cash activities
Change in major construction advances, construction in progress and property, plant and equipment	$	225,898		$	619

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

Pattern Energy Group Inc. (Pattern Energy or the Company) was organized in the state of Delaware on October 2, 2012. Pattern Energy is an independent energy generation company focused on constructing, owning and operating energy projects with long-term energy sales contracts. Pattern Energy Group LP (Pattern Development 1.0) owns a 0.4% interest in the Company at September 30, 2018. The Pattern Development Companies (Pattern Development 1.0, Pattern Energy Group 2 LP (Pattern Development 2.0) and their respective subsidiaries) are leading developers of renewable energy and transmission projects.

The Company consists of the consolidated operations of certain entities purchased principally from Pattern Development 1.0, except for purchases of Lost Creek, Post Rock and certain additional interests in El Arrayán (each as defined below) which were purchased from third-parties. Each of the Company's wind and solar projects and certain assets are consolidated into the Company's subsidiaries as follows:


•	Pattern US Operations Holdings LLC, which consists primarily of:


▪	100% ownership of Hatchet Ridge Wind, LLC (Hatchet Ridge), Spring Valley Wind LLC (Spring Valley), Pattern Santa Isabel LLC (Santa Isabel), Ocotillo Express LLC (Ocotillo), Pattern Gulf Wind LLC (Gulf Wind) and Lost Creek Wind, LLC (Lost Creek), and

▪

consolidated controlling interests in Panhandle Wind LLC (Panhandle 1), Panhandle Wind 2 LLC (Panhandle 2), Post Rock Wind Power Project, LLC (Post Rock), Logan's Gap Wind LLC (Logan's Gap), Fowler Ridge IV Wind Farm LLC (Amazon Wind), and Broadview Finco Pledgor LLC (Broadview Project), which consists primarily of Broadview Energy KW, LLC and Broadview Energy JN, LLC (together, Broadview) and Western Interconnect LLC, a transmission line (Western Interconnect);


•	Pattern Canada Operations Holdings ULC, which consists primarily of:


▪	100% ownership of St. Joseph Windfarm Inc. (St. Joseph),


▪	a consolidated controlling interest in Meikle Wind Energy Limited Partnership (Meikle) and Mont Sainte-Marguerite Wind Farm Limited Partnership (MSM), and


▪	noncontrolling interests in South Kent Wind LP (South Kent), Grand Renewable Wind LP (Grand), K2 Wind Ontario Limited Partnership (K2), and SP Armow Wind Ontario LP (Armow), each of which are accounted for as unconsolidated investments;


•	Pattern Chile Holdings LLC, which included controlling interests in Parque Eólico El Arrayán SpA (El Arrayán) and Don Goyo Transmisión S.A. (Don Goyo), a transmission asset of El Arrayán through August 20, 2018 (see Note 4, Divested Operations);


•	Green Power Tsugaru Holdings G.K. (Tsugaru Holdings), which consists primarily of 100% ownership of Green Power Tsugaru G.K. (Tsugaru); and


•	Green Power Generation G.K. (GPG), which consists primarily of:


▪	100% ownership in GK Green Power Otsuki (Ohorayama), Otsuki Wind Power Corporation (Otsuki), and GK Green Power Kanagi (Kanagi), and


▪	a consolidated controlling interest in GK Green Power Futtsu (Futtsu)). (See Note 5, Acquisitions).

During the nine months ended September 30, 2018, the Company has funded $86.3 million into Pattern Development 2.0 of which approximately $27 million was used by Pattern Development 2.0 to fund the purchase of Green Power Investments (GPI), located in Japan. As of September 30, 2018, the Company has funded $153.6 million in aggregate and holds an approximately 29% ownership interest in Pattern Development 2.0.

2. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The consolidated financial statements 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 in consolidation.

Unaudited Interim Financial Information

The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (U.S. GAAP) for interim financial information and Article 10 of Regulation S-X issued by the U.S. Securities and Exchange Commission (SEC). Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, the interim financial information reflects all adjustments of a normal recurring nature, necessary for a fair statement of the Company’s financial position at September 30, 2018, the results of operations and comprehensive income (loss) for the three and nine months ended September 30, 2018 and 2017, respectively, and the cash flows for the nine months ended September 30, 2018 and 2017, respectively. The consolidated balance sheet at December 31, 2017 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, 2017.

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 assets and 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.

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.

During the nine months ended September 30, 2018, the Company identified a $1.3 million error in tax expense related to the recognition of net operating loss carryforwards in its Chilean entity. The Company concluded the error was not material to any previously reported period and is not material to the nine months ended September 30, 2018. The Company recorded the error as an out-of-period adjustment in the second quarter of 2018.

Reconciliation of Cash and Cash Equivalents and Restricted Cash as Presented on the Statements of Cash Flows

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets that sum to the total of the same such amounts shown in the consolidated statements of cash flows (in thousands):



	September 30, 2018		December 31, 2017
Cash and cash equivalents	$	125,689	$	116,753
Restricted cash - current	6,324		9,065
Restricted cash	13,899		12,162
Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	145,912	$	137,980

Assets Held for Sale

The Company records assets held for sale at the lower of the carrying value or fair value less costs to sell. The following criteria are used to determine if property is held for sale: (i) management has the authority and commits to a plan to sell the property; (ii) the property is available for immediate sale in its present condition; (iii) there is an active program to locate a buyer and the plan to sell the property has been initiated; (iv) the sale of the property is probable within one year; (v) the property is being actively marketed at a reasonable price relative to its current fair value; and (vi) it is unlikely that the plan to sell will be withdrawn or that significant changes to the plan will be made.

In determining the fair value of the assets less costs to sell, the Company considers factors including current sales prices and any recent legitimate offers. If the estimated fair value less costs to sell of an asset is less than its current carrying value, the asset is written down to its estimated fair value less costs to sell. Due to uncertainties in the estimation process, it is possible that actual results could differ from the estimates used in the Company's historical analysis. The Company's assumptions about project sale prices require significant judgment because the current market is highly sensitive to changes in economic conditions. The Company estimates the fair values of assets held for sale based on current market conditions and assumptions made by management, which may differ from actual results and may result in additional impairments if market conditions deteriorate. When assets are classified as held for sale, the Company does not continue to record depreciation or amortization for the respective assets.

Accounting for Re-powering

The Company's commitment to a plan to re-power a project represents the decision to abandon the existing long-lived asset. Because a decision to abandon a long-lived asset is akin to a decision to dispose of a long-lived asset before the initially intended date, it is viewed as an indicator of impairment, and as such a recoverability test is required. If the recoverability test indicates that the carrying value is not recoverable, the fair value of the existing asset is compared to its net carrying value. If the fair value of the asset is less than its net carrying value, an impairment expense for the difference is recorded. The remaining useful life of the existing asset represents the period between the date the Company is committed to a plan to abandon the asset and the removal date. Due to the change in useful life, the Company will revise the estimated future cash flows of the asset retirement obligation. As a result, the Company will accelerate depreciation expense and accretion expense.

Major Construction Advances

Major construction advances represent amounts advanced to suppliers for the manufacture of wind turbines, transmission lines, and solar panels in accordance with component equipment supply agreements for the Company's projects and for which the Company has not taken title or advances to builders in accordance with balance of plant contracts. These advances are reclassified to construction in progress when the Company takes legal title to the equipment.

Goodwill

The Company records goodwill when the cost of an acquisition exceeds the fair value of the tangible and identified intangibles of the acquired business. Goodwill is not amortized, but is subject to an assessment for impairment at least annually in the fourth quarter or more frequently if events occur or circumstances change that will more likely than not reduce the fair value of the reporting unit below its carrying amount.

Advanced lease revenue

Advanced lease revenue presented on the consolidated balance sheets represents advance payments the Company has received under a power purchase agreement. As the power purchase agreement is an operating lease, the advance lease payments will be recorded as lease income on a straight-line basis over the 25-year term of the agreement.

The 2017 Tax Act

On December 22, 2017, the 2017 Tax Act (Tax Act) was enacted, which significantly revises the U.S. corporate income tax law by lowering the U.S. federal corporate income tax rate from 35% to 21%, implementing a territorial tax system and imposing a one-time tax on foreign unremitted earnings. The Tax Act also establishes several new tax provisions effective in 2018.

On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118) to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed in reasonable detail to complete the accounting for certain income tax effects of the Tax Act. SAB 118 allows registrants to record provisional amounts during a one year “measurement period” similar to that used when accounting for business combinations. The measurement period ends when the company has obtained, prepared and analyzed the information necessary to finalize its accounting, but cannot extend beyond one year.

As of December 31, 2017, the Company was able to make a reasonable estimate of the impact of several provisions of the Tax Act, including the repatriation provisions and the Tax Act’s reduction of the U.S. federal tax rate from 35% to 21% which impacts the Company's U.S. deferred tax assets and deferred liabilities. The U.S operations as of December 31, 2017 were in a net deferred tax asset position offset by a full valuation allowance and thus, any adjustments to the deferred accounts did not impact the tax provision. Although the Company made a reasonable estimate of the amounts related to the repatriation provisions and deferred tax assets and deferred tax liabilities disclosed, a final determination of the Tax Act’s impact on the Company’s tax provision and deferred tax assets and deferred tax liabilities and related valuation allowance requirements remained incomplete as of December 31, 2017 pending a full analysis of the provisions and their interpretations. As of September 30, 2018, the Company has not changed the provisional estimates recognized in 2017, and therefore no impact was reflected in the effective tax rate for the period ended September 30, 2018. Given the complexity of the Tax Act, the Company is still evaluating the tax impact and obtaining the information, including data from third parties and other items, required to complete the accounting. The date the Company expects to complete the accounting is not currently determinable while it continues to obtain the information required to complete the accounting.

The Tax Act also includes a provision to tax global intangible low-taxed income (GILTI) of foreign subsidiaries. Entities can make an accounting policy election to either recognize deferred taxes for temporary basis differences expected to reverse as GILTI in future years or provide for the tax expense related to GILTI in the year the tax is incurred. Given the complexity of the GILTI provisions, the Company is still evaluating the tax impact and has not yet made the accounting policy election.

Recently Issued Accounting Standards

Except for the evaluation of recently issued accounting standards set forth below, there have been no changes to the Company's evaluation of other recently issued accounting standards disclosed in Note 2, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements, contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

In October 2018, the Financial Accounting Standards Board (FASB) issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities (ASU 2018-17). ASU 2018-17 requires reporting entities to consider indirect interests held through related parties under common control on a proportional basis rather than as the equivalent of a direct interest in its entirety for determining whether a decision-making fee is a variable interest. The standard is effective for all entities for financial statements issued for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. Entities are required to apply the amendments in ASU 2018-17 retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. The Company is currently evaluating this guidance to determine the impact it may have on its consolidated financial statements.

In October 2018, the FASB issued ASU 2018-16, Derivatives and Hedging (Topic ASC 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes (ASU 2018-16), which expands the list of U.S. benchmark interest rates permitted in the application of hedge accounting. The provisions of ASU 2017-12 (discussed below) and ASU 2018-16 are effective for fiscal years beginning after December 15, 2018, including interim periods, with early adoption permitted. Initial adoption of ASU 2017-12 is required to be reported using a modified retrospective approach, with the exception of the presentation and disclosure requirements which are required to be applied prospectively. The Company is currently in the process of determining the impact of adoption of the provisions of ASU 2017-12 and ASU 2018-16.

In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (ASU 2018-15), which amends alignment of the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal use software license). The accounting for the service element of a hosting arrangement that is a service contract is not affected by these amendments. ASU 2018-15 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company is currently assessing the future impact of this update on its consolidated financial statements and related disclosures.

In August 2018, the FASB issued ASU 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement (ASU 2018-13), which amends changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty which should be applied prospectively for only the most recent interim or annual period presented in the initial fiscal year of adoption. ASU 2018-13 is effective for annual periods beginning after December 15, 2019, including interim periods within those periods. Early application is permitted. The Company is currently assessing the impact of changes to the disclosure requirements for fair value measurement.

In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), which amends the presentation and disclosure requirements and changes how companies assess effectiveness. The amendments are intended to more closely align hedge accounting with companies’ risk management strategies, simplify the application of hedge accounting, and increase transparency as to the scope and results of hedging programs. ASU 2017-12 is effective for annual periods beginning after December 15, 2018, including interim periods within those periods. Early application is permitted. The Company is currently assessing the future impact of this update on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), which supersedes the revenue recognition requirements in Topic 605 “Revenue Recognition” (Topic 605) and requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. The Company adopted ASU 2014-09 as of January 1, 2018 using the modified retrospective transition method. The adoption did not have material impact on the Company's consolidated financial statements, other than additional disclosures. See Note 3, Revenue for further details.

In February 2016, the FASB issued ASU 2016-02, Leases (ASU 2016-02), which requires lessees to recognize assets and liabilities on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the consolidated statements of operations. Under the new guidance, lessor accounting is largely unchanged. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods.

The Company will adopt ASU 2016-02, as updated through various amendments, beginning January 1, 2019, using the modified retrospective approach. The modified retrospective approach provides a method applying the guidance to existing leases as of the adoption date with a cumulative-effect adjustment to the opening balance of retained earnings as of that date, which is not expected to be material. Prior comparative periods will not be adjusted under this method.

The Company expects to elect the package of practical expedients permitted under the transition guidance within the new standard, which among other things, will allow the Company to carry forward prior conclusions related to contracts accounted for as leases, historical lease classification and initial direct costs. The Company will also elect the practical expedient related to land easements, allowing the Company to carry forward its accounting treatment for land easements on existing agreements as intangible assets. The Company has lease agreements with lease and non-lease components and is electing not to separate these and will treat as a single lease component. The Company will make an accounting policy election whereby short-term leases with an initial term of 12 months or less will not be recorded on the consolidated balance sheets. The Company will recognize those lease payments in the consolidated statements of operations on a straight-line basis over the lease term.

The Company is implementing a number of system enhancements to facilitate the identification, tracking and reporting of leases based upon the requirements of the new lease standard. The Company is also assessing the accounting impact of ASU 2016-02 as it applies to its power purchase agreements (PPAs), land leases, office leases and equipment leases. The Company is not yet able to quantify the impact on the financial statements of adopting this standard. The Company anticipates that certain PPAs entered into or acquired after January 1, 2019, will no longer be accounted for as leases.

3. Revenue

The Company sells electricity and related renewable energy credits (RECs) under the terms of power sale agreements (PSA) or at market prices. Depending on the terms of the PSAs, the Company may account for the contracts as operating leases pursuant to Accounting Standards Codification (ASC) 840, Leases (ASC 840), derivative instruments pursuant to ASC 815, Derivatives and Hedging (ASC 815) or contracts with customers pursuant to Topic 606. A majority of the Company's revenues are accounted for under ASC 840 or ASC 815.

On January 1, 2018, the Company adopted the new accounting standard ASC 606, Revenue from Contracts with Customers, and all the related amendments (Topic 606) and applied Topic 606 to its PSA contracts previously accounted for under Topic 605, using the modified retrospective method. Results of the reporting period beginning January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with the Company's historic accounting under Topic 605.

The Company did not record any adjustment to the opening retained earnings as of January 1, 2018 as a result of adopting Topic 606. Additionally, the adoption of Topic 606 does not materially change the presentation of revenue.

Revenue Recognition

Revenues from contracts with customers are recognized when control of promised goods and services is transferred to customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services.

The following table presents the Company's total revenue recognized and, for contracts with customers, disaggregated by revenue sources (in thousands).



	Three months ended September 30,				Nine months ended September 30,
	2018		2017⁽¹⁾		2018		2017⁽¹⁾
Revenue from contracts with customers
Electricity sales
Electricity sales under PSA	$	16,633	$	13,604	$	54,733	$	49,005
Electricity sales to market	5,562		3,915		12,291		10,430
REC sales	1,036		1,876		6,381		6,202
Electricity sales from contracts with customers	23,231		19,395		73,405		65,637
Other revenue
Related party management service fees	2,040		1,883		6,820		5,888
Other revenue from contracts with customers	2,040		1,883		6,820		5,888
Total revenue from contracts with customers	25,271		21,278		80,225		71,525
Other electricity sales ⁽²⁾	92,186		70,412		280,110		228,340
Other revenue	936		340		9,657		758
Total revenue	$	118,393	$	92,030	$	369,992	$	300,623


⁽¹⁾	As noted above, prior period amounts have not been adjusted under the modified retrospective method.


⁽²⁾	Includes revenue from PSAs accounted for as leases and energy hedge contracts.

Electricity Sales

The Company generates revenues primarily by delivering electricity to customers under PSAs and market participants. The revenues are primarily determined by the price of the electricity under the PSAs or market price multiplied by the amount of electricity that the Company delivers.

The Company transfers control of the electricity over time and the customer simultaneously receives and consumes the benefits provided by the Company's performance as it performs. Accordingly, the Company has concluded that the sale of electricity over the term of the agreement represents a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer. Each distinct transfer of electricity in megawatt hours (MWh) that the Company promises to transfer to the customer meets the criteria to be a performance obligation satisfied over time. The electricity sales are recognized based on an output measure, as each MWh is delivered to the customers. The Company recognizes revenue based on the amount invoiced on the basis of the prices multiplied by MWh delivered. The Company does not determine the total transaction price at contract inception, allocate the transaction price to performance obligations, or disclose the value of the variable portion of the remaining performance obligations for contracts for which it recognizes revenue as invoiced.

Renewable Energy Credits Sales

Each promise to deliver RECs is a distinct performance obligation that is satisfied at a point in time as none of the criteria are met to account for such promise as performance obligation satisfied over time. The Company either delivers RECs with electricity under PSAs or on a standalone basis (in a contract that does not include electricity). When RECs are sold on a standalone basis, the revenue related to the RECs is recognized at the point in time at which control of the energy credits is transferred to customers. RECs delivered under PSAs with electricity are immaterial in the context of the contracts with customers and therefore not separately accounted for.

Remaining performance obligations represent the transaction price of standalone RECs for which RECs have not been delivered to the customer's account. The transaction price is determined on the basis of the stated contract price multiplied by RECs to be delivered. As of September 30, 2018, approximately $20.4 million of revenue is expected to be recognized from remaining performance obligations associated with existing contracts for the standalone sale of RECs. The Company expects to recognize revenue on approximately half of these remaining performance obligations over the next 24 months, with the balance recognized thereafter.

Related party management service fees

Related party revenue management service fees represent revenue recognized from the services provided by the Company, under Management, Operations and Maintenance Agreements (MOMAs) and Project Administration Agreements (PAAs) with certain wind farms that are consolidated subsidiaries of Pattern Development Companies or entities the Company accounts for as equity investments. Under these agreements, the Company provides services to the various wind farms, typically for a fixed annual fee payable in monthly installments, which escalates with the consumer price index (CPI) on an annual basis. The services by the Company to the wind farm under the agreement each month represent a single performance obligation, which is delivered to the project over time and is invoiced at a fixed price per month and will be recognized over time as invoiced to the respective wind farm.

Remaining performance obligations represent the fixed monthly installments for which services have not been performed. The transaction price is determined on the basis of the stated contract price.

Transaction Price Allocated to the Remaining Performance Obligations

The Company expects to recognize revenue under PSAs and related party management service fees for the following amounts related to fixed consideration associated with remaining performance obligations in each of the future periods noted as of September 30, 2018 (in thousands):



	Amount
2018 (remainder)	$	25,558
2019	80,147
2020	67,705
2021	67,837
2022	67,971
Thereafter	355,702
Total	$	664,920

Contract Balances

The Company did not record any contract assets as none of its right to payment was subject to something other than passage of time. The Company also did not record any contract liabilities as it recognizes revenue only at the amount to which it has the right to invoice for the electricity and RECs delivered; therefore, there are no advanced payments or billings in excess of electricity or RECs delivered.

4. Divested Operations

Chilean Sale

On May 21, 2018, the Company, through its indirect wholly-owned subsidiaries, entered into a stock purchase agreement with a third party pursuant to which the Company agreed to sell, and the buyer agreed to purchase, certain subsidiaries which hold approximately a 71% interest in El Arrayán Wind and assets and rights relating to ownership and operation of an extension of the trunk transmission system in Chile (Chilean Sale). El Arrayán Wind is a wind electric generation facility located approximately 400 kilometers north of Santiago on the coast of Chile in which the Company had an owned interest of approximately 81 megawatts (MW).

On August 20, 2018, the Company completed the Chilean Sale for cash proceeds of $70.4 million. The Company measured impairment expense as the difference between the carrying amount of the net assets and fair value less estimated costs to sell. As a result, the Company recorded a total impairment expense of $2.3 million and $6.6 million for the three and nine months September 30, 2018, respectively, in the consolidated statements of operations due to current period earnings, additional contributions in the current quarter and changes in the fair value.

The operating results of El Arrayán Wind were included on the consolidated statements of operations through the date of sale.

5. Acquisitions

Business Combinations

Japan Acquisition

On March 7, 2018, pursuant to a series of purchase and sale agreements with Pattern Development 1.0 and GPI, the Company acquired Tsugaru Holdings which owns Tsugaru, a project company currently constructing a 122 MW name plate capacity wind facility in Aomori Prefecture, Japan expected to commence commercial operations in early to mid-2020; Ohorayama, a wind project located in Kochi Prefecture, Japan, with a name plate capacity of 33 MW that commenced commercial operations in March 2018; Kanagi, a solar project located in Shimane Prefecture, Japan, with a name plate capacity of 10 MW that commenced commercial operations in 2016; Otsuki, a wind project located in Kochi Prefecture, Japan, with a name plate capacity of 12 MW that commenced commercial operations in 2006; and Futtsu, a solar project located in Chiba Prefecture, Japan, with a name plate capacity of 29 MW that commenced commercial operations in 2016 (collectively referred to as the Japan Acquisition). The acquisition is in alignment with the Company's strategy to expand its portfolio of power generating projects.

Total consideration for the Japan Acquisition was $282.5 million, which consisted of approximately $176.6 million of cash and post-closing contingent payments with an acquisition date fair value of approximately $105.9 million. As part of the acquisition, the Company also assumed $181.3 million of debt. The Company incurred transaction-related expenses of $1.3 million which were recorded in net earnings (loss) on transactions in the consolidated statements of operations for the nine months ended September 30, 2018.

The identifiable assets, operating contracts and liabilities assumed for the Japan Acquisition were recorded at their fair values, which corresponded to the sum of the cash purchase price, contingent consideration payment, and the fair value of the other investor's noncontrolling interests.

The following table details the total consideration paid by the Company and the fair value of the assets acquired and liabilities assumed (in thousands):



	March 7, 2018
Consideration	$	282,548

Cash and cash equivalents ⁽¹⁾	$	10,100
Restricted cash ⁽¹⁾	8,890
Property, plant and equipment, net	263,281
Construction in progress	180,949
Goodwill	60,302
Finite-lived intangible assets	103,170
Other assets acquired	19,540
Long-term debt ⁽¹⁾	(173,828		)
Deferred tax liabilities	(67,179		)
Asset retirement obligations	(39,872		)
Other liabilities assumed	(71,692		)
Assets and liabilities assumed before noncontrolling interests	293,661
Less: noncontrolling interests	(11,113		)
Consideration	$	282,548

⁽¹⁾Amounts recorded at carrying value which was representative of the fair value on the date of acquisition.

Property, plant and equipment, construction in progress, and finite-lived intangible assets were recorded at fair value estimated using the cost and income approach. The fair value of the asset retirement obligations was recorded at fair value using market data. The noncontrolling interest in Futtsu was recorded at fair value estimated using a projected cash flow stream of distributable cash, discounted to present value with a discount rate reflecting the cost of equity adjusted for control premium.

The predecessor’s tax bases were carried forward for tax purposes. Accordingly, the Company recorded deferred tax liabilities on the bases differences arising from the step up to fair value for financial reporting purposes but not for tax purposes.

The Company assumed an existing $16.2 million contingent liability as part of the acquisition. The payment of this liability was subject to the completion of a construction milestone at Tsugaru and was calculated based on the nameplate capacity of Tsugaru. In September 2018, the Company paid $15.2 million which was the amount due for such contingent liability because of changes in foreign exchange rates, and the liability balance was reduced to zero.

Contingent purchase consideration with a fair value of $102.9 million, subject to foreign currency exchange rate changes, is contingent upon term conversion of the Tsugaru construction loan and to the extent such term conversion does not occur such consideration will be made upon the commencement of commercial operations of Tsugaru, both of which are expected to occur in 2020. Additionally, the Company was obligated to make a $3.0 million, subject to foreign currency exchange rate changes, cash distribution payment to Pattern Development 1.0 upon term conversion of the Ohorayama construction loan which occurred in June 2018. The Company paid this consideration in July 2018. See Note 14, Fair Value Measurements for further discussion on the fair value of the contingent consideration.

The accounting for this acquisition is preliminary. The fair value estimates for the assets acquired and liabilities assumed are 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). During the nine months ended September 30, 2018, the Company adjusted the initial valuation by increasing property, plant and equipment by $0.6 million and decreasing construction in progress by $0.6 million which are a result of the updated inputs used in determining the fair value of these assets and liabilities.

Broadview Project Acquisition

On April 21, 2017, pursuant to a Purchase and Sale Agreement with Pattern Development 1.0, the Company acquired a 100% ownership interest in Broadview Project which indirectly owns both 100% of the Class B membership interest in Broadview Energy Holdings LLC (Broadview Holdings) and a 99% ownership interest in Western Interconnect, a 35-mile 345 kV transmission line. Broadview Holdings owns 100% ownership interests that comprise the 324 MW Broadview wind power projects, which achieved commercial operations in the first quarter of 2017. The acquisition is in alignment with the Company's strategy to expand its portfolio of power generating projects. The Company's indirect Class B membership interest in Broadview Holdings represents an 84% initial interest in distributable cash flow from Broadview. Consideration consisted of $214.7 million of cash, a $2.4 million assumed liability and a post-closing payment of approximately $21.3 million contingent upon the commercial operation of the Grady Project (as defined below). As part of the acquisition, the Company also assumed $51.2 million of construction debt and related accrued interest outstanding at Western Interconnect which was immediately extinguished, and concurrently the Company entered into a variable rate term loan for $54.4 million. The Grady Wind Energy Center LLC (the Grady Project) is a wind power project being developed by Pattern Development 2.0 separately from Broadview, which is under construction, and which will be interconnected through Western Interconnect.

The identifiable assets, operating contracts and liabilities assumed for the Broadview Project were recorded at their fair values, which corresponded to the sum of the cash purchase price, contingent consideration payment, and the fair value of the other investors' noncontrolling interests. As described in the Company's Form 10-K for the year ended December 31, 2017, the accounting for the Broadview Project acquisition is final.

Asset Acquisitions

Mont Sainte-Marguerite

On August 10, 2018, pursuant to a Purchase and Sale Agreement by and among the Company, Pattern Development 1.0, and an affiliate of Public Sector Pension Investment Board (PSP), the Company subscribed for 50.99% of the limited partner interests in MSM LP Holdings LP (which holds 99.98% of the economic interests in MSM) and purchased, from an affiliate of Pattern Development 1.0, 70% of the issued and outstanding shares in the capital of Pattern MSM GP Holdings Inc. (Pattern MSM Corp) and 70% of the issued and outstanding shares in the capital of Pattern Development MSM Management ULC (MSM ULC), in exchange for aggregate consideration of $39.3 million. Concurrently, an affiliate of PSP subscribed for a 48.99% limited partner interest in MSM LP Holdings LP, and purchased, from an affiliate of Pattern Development 1.0, 30% of the issued and outstanding shares of Pattern MSM Corp, and 30% of the issued and outstanding shares in the capital of MSM ULC for a purchase price of $37.7 million. MSM operates the approximately 143 megawatt wind farm located in the Chaudière-Appalaches region south of Québec City, Canada, which achieved commercial operation in the first quarter of 2018. The acquisition is in alignment with the Company's strategy to expand its portfolio of power generating projects.

MSM was determined to be a variable interest entity (VIE), for which the Company is the primary beneficiary. The Company recorded the fair value of the individual assets, operating contracts and liabilities of the VIE, which did not meet the definition of a business. The noncontrolling interest was recorded at fair value estimated using the purchase price paid by PSP pursuant to the Purchase and Sale Agreement. No gain or loss was recognized upon acquisition. The Company incurred transaction-related expenses of $0.6 million which were recorded in net earnings (loss) on transactions in the consolidated statements of operations for the nine months ended September 30, 2018.

The following table details the total consideration paid by the Company and the fair value of the assets acquired and liabilities assumed (in thousands):



	August 10, 2018
Consideration	$	39,252

Cash and cash equivalents ⁽¹⁾	$	2,934
Restricted cash ⁽¹⁾	5,329
Property, plant and equipment, net	270,122
Other assets acquired	37,491
Long-term debt	(196,001		)
Advanced lease revenue ⁽¹⁾	(29,157		)
Other liabilities assumed	(13,759		)
Assets and liabilities assumed before noncontrolling interests	76,959
Less: noncontrolling interests ⁽¹⁾	(37,707		)
Consideration	$	39,252

⁽¹⁾Amounts recorded at carrying value which was representative of the fair value on the date of acquisition.

Meikle

On August 10, 2017, pursuant to a Purchase and Sale Agreement by and among the Company, Pattern Development 1.0, and an affiliate of PSP, the Company acquired 50.99% of the limited partner interests in Meikle and 70% of the issued and outstanding shares of Meikle Wind Energy Corp. (Meikle Corp) for a purchase price of $67.4 million, paid at closing, in addition to $1.1 million of capitalized transaction-related expenses. An affiliate of PSP acquired 48.99% of the limited partner interest in Meikle and 30% of the issued and outstanding shares of Meikle Corp for a purchase price of $64.8 million. Meikle operates the approximately 179 MW wind farm located in the Peace River Regional District of British Columbia, Canada, which achieved commercial operations in the first quarter of 2017. The acquisition is in alignment with the Company's strategy to expand its portfolio of power generating projects.

The fair value of the purchase consideration, including transaction-related expenses of the asset acquisition, and fair value of the noncontrolling interest is allocated to the relative fair value of the individual assets, operating contracts and liabilities assumed. The noncontrolling interest was recorded at fair value estimated using the purchase price paid by the affiliate of PSP pursuant to the Purchase and Sale Agreement.

Supplemental Pro Forma Data (unaudited)

Ohorayama commenced operations in March 2018 and until approximately one week before acquisition, Ohorayama was still under construction. In addition, Tsugaru is expected to commence commercial operations in early to mid-2020. Therefore, pro forma data for Ohorayama and Tsugaru have not been provided as there is no material difference between pro forma data that give effects to the Japan Acquisition as if it had occurred on January 1, 2017 and the actual data reported for the three and nine months ended September 30, 2018 and 2017.

Broadview reached commercial operations in March 2017 and until approximately three weeks before acquisition, Broadview was still under construction. Therefore, pro forma data for Broadview has not been provided as there is no material difference between pro forma data that give effect to the Broadview Project acquisition as if it had occurred on January 1, 2017 and actual data reported for the three and nine months ended September 30, 2018 and 2017.

The unaudited pro forma statement of operations data below gives effect to the Japan Acquisition, as if it had occurred on January 1, 2017. The 2018 pro forma net loss was adjusted to exclude nonrecurring transaction related expenses of $1.3 million. 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 the acquisition been consummated as of January 1, 2017. 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)	2018			2017			2018			2017
Pro forma total revenue	$	118,393		$	98,149		$	373,727		$	320,377
Pro forma total expenses	(149,940		)	(147,963		)	(419,008		)	(383,760		)
Pro forma net loss	(31,547		)	(49,814		)	(45,281		)	(63,383		)
Less: pro forma net loss attributable to noncontrolling interest	(18,952		)	(18,457		)	(201,780		)	(50,258		)
Pro forma net income attributable to Pattern Energy	$	(12,595	)	$	(31,357	)	$	156,499		$	(13,125	)

The following table presents the amounts included in the consolidated statements of operations for the business combinations discussed above since their respective dates of acquisition:



Unaudited data (in thousands)	Three months ended September 30, 2018			Nine months ended September 30, 2018
Total revenue	$	23,123		$	73,060
Total expenses	(26,253		)	(73,082		)
Net income	(3,130		)	(22		)
Less: net loss attributable to noncontrolling interest	(3,650		)	(42,227		)
Net income attributable to Pattern Energy	$	520		$	42,205

Unconsolidated Investments

Pattern Development 2.0

Under the Second Amended and Restated Agreement of Limited Partnership of Pattern Development 2.0 (A&R LPA), the Company has the right to contribute up to $300.0 million to Pattern Development 2.0 in one or more subsequent rounds of financing. On July 27, 2017, the Company funded an initial $60.0 million capital call. As of September 30, 2018, the Company has funded $153.6 million in aggregate and holds an approximately 29% ownership interest in Pattern Development 2.0. The Company is a noncontrolling investor in Pattern Development 2.0, but has significant influence over Pattern Development 2.0. Accordingly, the investment is accounted for under the equity method of accounting.

The Company capitalized $1.5 million of transaction costs associated with the initial investment. The Company's initial investment in Pattern Development 2.0 of $60.0 million was $40.6 million higher than the Company's underlying equity in the net assets of Pattern Development 2.0 at the time of the initial funding. This equity method basis difference was primarily attributable to equity method goodwill.

6. Property, Plant and Equipment

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



	September 30,			December 31,
	2018			2017
Operating wind farms	$	4,889,281		$	4,640,718
Transmission line	93,849			93,849
Furniture, fixtures and equipment	13,158			12,643
Land	245			141
Subtotal	4,996,533			4,747,351
Less: accumulated depreciation	(886,669		)	(782,230		)
Property, plant and equipment, net	$	4,109,864		$	3,965,121

The Company recorded depreciation expense related to property, plant and equipment of $54.2 million and $162.3 million for the three and nine months ended September 30, 2018, respectively, and recorded $51.4 million and $141.9 million for the same periods in the prior year.

7. Finite-Lived Intangible Assets and Liabilities and Goodwill

Finite-Lived Intangible Assets and Liabilities

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



	September 30, 2018
	Weighted Average Remaining Life	Gross		Accumulated Amortization			Net
Intangible assets
Power purchase agreements	16	$	222,827	$	(26,429	)	$	196,398
Industrial revenue bond tax savings	24	12,778		(741		)	12,037
Other intangible assets	33	13,897		(1,210		)	12,687
Leasehold interest	8	$	66	$	(5	)	$	61
Total intangible assets		$	249,568	$	(28,385	)	$	221,183
Intangible liabilities
Power purchase agreement	14	$	60,300	$	(11,707	)	$	48,593
Leasehold interest	22	8,661		(215		)	8,446
Total intangible liabilities		$	68,961	$	(11,922	)	$	57,039



	December 31, 2017
	Weighted Average Remaining Life	Gross		Accumulated Amortization			Net
Intangible assets
Power purchase agreement	15	$	127,084	$	(17,611	)	$	109,473
Industrial revenue bond tax savings	24	12,778		(351		)	12,427
Other intangible assets	34	15,234		(1,086		)	14,148
Total intangible assets		$	155,096	$	(19,048	)	$	136,048
Intangible liability
Power purchase agreement	15	$	60,300	$	(9,106	)	$	51,194

The Company presents amortization of the PPA assets and PPA liabilities as an offset to electricity sales in the consolidated statements of operations, which resulted in net expense of $2.4 million and $6.3 million for the three and nine months ended September 30, 2018, respectively, and net expense of $0.9 million and $2.4 million for the same periods in 2017, respectively. For other intangible assets, the Company includes the amortization in depreciation, amortization and accretion in the consolidated statements of operations and recorded amortization expense of less than $0.1 million and $0.2 million for the three and nine months ended September 30, 2018, respectively, and amortization expense of $0.1 million and $0.4 million for the same periods in 2017, respectively.

As part of the 2017 Broadview acquisition, the Company acquired an intangible asset related to future property tax savings resulting from the issuance of industrial revenue bonds during construction of the project. The intangible asset is being amortized to depreciation, amortization and accretion in the consolidated statements of operations. The Company recorded amortization expense of $0.1 million and $0.4 million for the three and nine months ended September 30, 2018, respectively, and $0.1 million and $0.2 million for the same periods in 2017, respectively, related to the industrial revenue bond tax savings intangible asset.

As a result of the Japan Acquisition, the Company recorded $103.2 million of intangible PPA assets resulting from market prices that are lower than the contractual prices. In addition, the Company recorded a $9.3 million intangible leasehold interest liability, as a result of higher market prices compared to the contractual prices, which is being amortized to depreciation, amortization and accretion in the consolidated statements of operations.

The following table presents estimated future amortization for the next five years related to the Company's finite-lived intangible assets and liabilities (in thousands):



Year ended December 31,	Power purchase agreements, net		Industrial revenue bond tax savings		Other intangible assets		Leasehold interests
2018 (remainder)	$	2,411	$	128	$	139	$	(93	)
2019	9,645		512		556		(370		)
2020	9,645		512		556		(370		)
2021	9,645		512		556		(370		)
2022	9,645		512		556		(370		)
Thereafter	106,876		9,862		10,278		(6,813		)

Goodwill

In connection with the Japan Acquisition, the Company recognized goodwill of $60.3 million, which was allocated to the power projects reporting unit. The Company will perform an impairment test of its goodwill on at least an annual basis, starting in the fourth quarter 2018.

The following table presents a reconciliation of the beginning and ending carrying amounts of goodwill (in millions):



	Total
Balances at December 31, 2017	$	—
Net additions during the period⁽¹⁾	60.3
Foreign currency translation adjustment	(3.8		)
Balances at September 30, 2018	$	56.5


⁽¹⁾	The Company recorded goodwill on March 7, 2018 as a result of the Japan Acquisition.

8. Variable Interest Entities

The Company consolidates VIEs in which it holds a variable interest and is the primary beneficiary. The Company has determined that Logan's Gap, Panhandle 1, Panhandle 2, Post Rock, Amazon Wind, Broadview Energy Holdings LLC (a subsidiary of Broadview Project), and MSM are VIEs. The Company determined that as the managing member of the VIEs, it is the primary beneficiary by reference to the power and benefits criterion under ASC 810, Consolidation, and therefore, consolidates VIEs. The Company considered responsibilities within the contractual agreements, which grant it the power to direct the activities of the VIE that most significantly impact the VIE's economic performance. Such activities include management of the wind farms' operations and maintenance, budgeting, policies and procedures. In addition, the Company has the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIEs on the basis of the income allocations and cash distributions.

The Company’s equity method investment in Pattern Development 2.0 is considered to be a VIE primarily because the total equity at risk is not sufficient to permit Pattern Development 2.0 to finance its activities without additional subordinated financial support by the equity holders. The Company does not hold the power or benefits to be the primary beneficiary and does not consolidate the VIE. The carrying value of its unconsolidated investment in Pattern Development 2.0 was $134.7 million as of September 30, 2018. The Company's maximum exposure to loss is equal to the carrying value of the investment.

The following table summarizes the carrying amounts of major consolidated balance sheet items for consolidated VIEs as of September 30, 2018 and December 31, 2017. All assets (excluding deferred financing costs, net and finite-lived intangible assets, net) and liabilities of a consolidated VIE presented below are (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary.



	September 30, 2018		December 31, 2017
Assets
Current assets:
Cash and cash equivalents	$	39,455	$	33,273
Restricted cash	4,351		4,314
Trade receivables	11,967		12,769
Prepaid expenses	6,243		4,965
Other current assets	1,828		2,597
Deferred financing costs, net	141		150
Total current assets	63,985		58,068

Restricted cash	5,673		3,330
Property, plant and equipment, net	2,185,859		1,984,606
Deferred financing costs, net	1,686		1,549
Finite-lived intangible assets, net	11,750		12,210
Other assets	12,661		12,984
Total assets	$	2,281,614	$	2,072,747

Liabilities
Current liabilities:
Accounts payable and other accrued liabilities	$	31,993	26,826
Accrued construction costs	3,114		759
Accrued interest	175		78
Current portion of long-term debt, net	4,803		—
Other current liabilities	5,124		4,789
Total current liabilities	45,209		32,452

Long-term debt, net	158,092		—
Finite-lived intangible liability, net	48,593		51,194
Contingent liabilities	—		87
Asset retirement obligations	56,412		22,394
Other long-term liabilities	33,292		24,951
Advanced lease revenue	28,259		—
Total liabilities	$	369,857	$	131,078

9. Unconsolidated Investments

The Company's unconsolidated investments consist of the following for the periods presented below (in thousands):



					Percentage of Ownership
	September 30,		December 31,		September 30,		December 31,
	2018		2017		2018		2017
South Kent	$	7,983	$	6,151	50.0	%	50.0	%
Grand	7,813		6,611		45.0	%	45.0	%
K2	96,118		103,328		33.3	%	33.3	%
Armow	125,802		132,890		50.0	%	50.0	%
Pattern Development 2.0	134,664		62,243		29.3	%	20.9	%
Unconsolidated investments	$	372,380	$	311,223

Pattern Development 2.0

During the nine months ended September 30, 2018, the Company has funded $86.3 million into Pattern Development 2.0 of which approximately $27.0 million was used by Pattern Development 2.0 to fund the purchase of GPI. As of September 30, 2018, the Company has funded $153.6 million in aggregate and holds an approximately 29% ownership interest in Pattern Development 2.0.

Basis Amortization of Unconsolidated Investments

The cost of the Company’s investment in the net assets of unconsolidated investments was higher than the fair value of the Company’s equity interest in the underlying net assets of its unconsolidated investments. The basis differences were primarily attributable to property, plant and equipment, PPAs, and equity method goodwill. The Company amortizes the basis difference attributable to property, plant and equipment, and PPAs over their useful life and contractual life, respectively. The Company does not amortize equity method goodwill. For the three and nine months ended September 30, 2018, the Company recorded basis difference amortization for its unconsolidated investments of $2.9 million and $8.3 million, respectively, and for the same periods in 2017, the Company recorded basis difference amortization of $2.9 million and $8.5 million, respectively, in earnings in unconsolidated investments, net on the consolidated statements of operations.

Significant Equity Method Investees

The following table presents summarized statements of operations information for the three and nine months ended September 30, 2018 and 2017 as required for the Company's significant equity method investees, South Kent, Grand, K2, Armow and Pattern Development 2.0 pursuant to Regulation S-X Rule 10-01(b)(1) (in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018		2017
Revenue	$	65,026		$	45,008		$	244,715	$	228,111
Cost of revenue	29,017			31,550			89,183		89,288
Operating expenses	20,490			11,030			74,233		12,663
Other expense	17,434			12,062			57,118		50,038
Net income (loss)	$	(1,915	)	$	(9,634	)	$	24,181	$	76,122

10. Debt

The Company’s debt consists of the following for periods presented below (in thousands):



							As of September 30, 2018
	September 30, 2018			December 31, 2017			Contractual Interest Rate			Effective Interest Rate
	September 30, 2018			December 31, 2017			Contractual Interest Rate			Effective Interest Rate			Maturity
Corporate-level
Corporate Revolving Credit Facility	$	186,372		$	—		varies		⁽¹⁾	3.68	%		November 2022
2020 Notes	225,000			225,000			4.00	%		6.60	%		July 2020
2024 Notes	350,000			350,000			5.88	%		5.88	%		February 2024
Project-level
Fixed interest rate
El Arrayán EKF term loan	—			99,112
Santa Isabel term loan	100,969			103,878			4.57	%		4.57	%		September 2033
MSM medium term loan	66,940			—			3.97	%		3.97	%		December 2029
MSM long term loan	97,959			—			5.04	%		5.04	%		June 2042
Variable interest rate
Japan Credit Facility	23,760			—			varies		⁽⁵⁾	1.82	%		August 2022
Ocotillo commercial term loan	281,295			289,339			3.83	%		4.05	%	⁽³⁾	June 2033
El Arrayán commercial term loan	—			90,102
Spring Valley term loan	121,862			125,678			4.14	%		5.00	%	⁽³⁾	June 2030
St. Joseph term loan ⁽²⁾	162,645			171,487			3.64	%		3.95	%	⁽³⁾	November 2033
Western Interconnect term loan ⁽²⁾	52,160			54,395			2.39	%		2.56	%	⁽³⁾	April 2027
Meikle term loan ⁽²⁾	254,816			266,557			3.52	%		3.95	%	⁽³⁾	May 2024
Futtsu term loan	73,185			—			1.07	%		1.85	%	⁽³⁾	December 2033
Ohorayama term loan	89,550			—			0.87	%		0.88	%	⁽³⁾	February 2036
Tsugaru Construction Loan	90,030			—			0.72	%		0.72	%	⁽³⁾	March 2038
Tsugaru Holdings Loan Agreement	57,024			—			3.13	%		3.13	%		July 2022
Imputed interest rate
Hatchet Ridge financing lease obligation	184,704			192,079			1.43	%		1.43	%		December 2032
	2,418,271			1,967,627
Unamortized discount, net⁽⁴⁾	(12,375		)	(13,470		)
Unamortized financing costs	(26,259		)	(23,426		)
Total debt, net	2,379,637			1,930,731

As reflected on the consolidated balance sheets
Revolving credit facility, current	$	186,372		$	—
Revolving credit facility	23,760			—
Current portion of long-term debt, net	63,671			51,996
Long term debt, net	2,105,834			1,878,735
Total debt, net	$	2,379,637		$	1,930,731


⁽¹⁾	Refer to Corporate Revolving Credit Facility for interest rate details.


⁽²⁾	The amortization for the St. Joseph term loan, the Western Interconnect term loan and the Meikle term loan are through September 2036, March 2036 and December 2038, respectively, which differs from the stated maturity date of such loans due to prepayment requirements.


⁽³⁾	Includes impact of interest rate swaps. See Note 12, Derivative Instruments, for discussion of interest rate swaps.


⁽⁴⁾	The discount relates to the 2020 Notes.


⁽⁵⁾	Refer to Japan Credit Facility for interest rate details.

Interest and commitment fees incurred and interest expense for debt consisted of the following (in thousands):



	Three months ended September 30,					Nine months ended September 30,
	2018			2017		2018			2017
Corporate-level interest and commitment fees incurred	$	10,014		$	9,215	$	28,234		$	24,827
Project-level interest and commitment fees incurred	15,897			14,635		46,982			40,103
Capitalized interest, commitment fees, and letter of credit fees	(1,227		)	—		(2,708		)	—
Amortization of debt discount/premium, net	1,281			1,153		3,758			3,379
Amortization of financing costs	1,395			2,028		4,033			5,879
Other interest	100			116		314			353
Interest expense	$	27,460		$	27,147	$	80,613		$	74,541

Corporate Level Debt

Corporate Revolving Credit Facility

Certain of the Company's subsidiaries have entered into a Second Amended and Restated Credit and Guaranty Agreement to the Revolving Credit Facility (the Corporate Revolving Credit Facility). The Corporate Revolving Credit Facility provides for a revolving credit facility of $440.0 million. The facility has a five-year term and is comprised of a revolving loan facility, a letter of credit facility and a swingline facility. The facility is secured by pledges of the capital stock and ownership interests in certain of the Company's holding company subsidiaries, in addition to other customary collateral.

As of September 30, 2018, $213.2 million was available for borrowing under the $440.0 million Corporate Revolving Credit Facility. The Corporate Revolving Credit Facility contains a broad range of covenants that, subject to certain exceptions, restrict the Company’s holding company subsidiaries' ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business. As of September 30, 2018, the Company's holding company subsidiaries were in compliance with covenants contained in the Corporate Revolving Credit Facility.

As of September 30, 2018 and December 31, 2017, letters of credit of $40.4 million and $47.5 million, respectively, were issued under the Corporate Revolving Credit Facility.

2020 Notes

In July 2015, the Company issued $225.0 million aggregate principal amount of 4.00% convertible senior notes due 2020 (Convertible Senior Notes or 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. The following table presents a summary of the equity and liability components of the 2020 Notes (in thousands):



	September 30, 2018			December 31, 2017
Principal	$	225,000		$	225,000
Less:
Unamortized debt discount	(9,711		)	(13,470		)
Unamortized financing costs	(1,971		)	(2,794		)
Carrying value of convertible senior notes	$	213,318		$	208,736
Carrying value of the equity component ⁽¹⁾	$	23,743		$	23,743


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

Project Debt

Japan Credit Facility

In August 2018, GPG entered into a credit agreement for a revolving credit facility (the Japan Credit Facility). Under the Japan Credit Facility, GPG may borrow up to $30.8 million and the Japan Credit Facility matures in August 2022. The base rate is based on the Japan Credit Facility Tokyo Interbank Offered Rate (TIBOR) plus an applicable margin between 1.75% and 2.25% plus an annual commitment fee of 0.30%. As of September 30, 2018, $7.0 million was available for borrowing.

Tsugaru Facility

In March 2018, Tsugaru entered into a credit agreement for a construction facility (Tsugaru Construction Loan), a term facility, a letter of credit facility (the LC Facility) and a Japanese consumption tax facility (the JCT Facility) (collectively, the Tsugaru Facility). Under the Tsugaru Facility, up to $371.4 million may be borrowed to fund the construction of Tsugaru which automatically converts to a term facility upon the earlier of completion of construction of the project (expected to be March 2020) or September 2020 (the Term Conversion Date). The Tsugaru Construction Loan, including the term facility and LC Facility, mature 18 years following the Term Conversion Date, not later than March 2039. The interest rate on the Tsugaru Construction Loan and term facility is TIBOR plus 0.65%. The LC Facility establishes a $19.7 million debt service reserve account letter of credit and an $8.0 million operations and maintenance reserve account letter of credit with amounts outstanding under the letters of credit owing interest at a rate of 1.10% and fees on the undrawn amounts of 0.30%. The JCT Facility provides for up to $33.8 million to pay Japanese consumption taxes arising from payment of project costs, with an interest rate of TIBOR plus 0.30% and a maturity date corresponding to the Term Conversion Date. A commitment fee of 0.3% is owed on any available amounts under the Construction Facility and the JCT Facility and on any undrawn amounts on the letters of credit up to the Term Conversion Date. Collateral for the credit facility includes Tsugaru's tangible assets and contractual rights and cash on deposit with the depository agent. The credit agreement contains a broad range of covenants that, subject to certain exceptions, restrict Tsugaru's ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests, dissolve, make distributions or change its business. As of September 30, 2018, outstanding borrowings under the Tsugaru Construction Loan totaled $90.0 million.

Tsugaru Holdings Loan Agreement

In March 2018, Tsugaru Holdings entered into a loan agreement (Tsugaru Holdings Loan Agreement) that provides for borrowings of up to $70.1 million during the Tsugaru construction period, until no later than September 2020. The interest rate on outstanding borrowings under the Tsugaru Holdings Loan Agreement is TIBOR plus 3.0% with principal due July 2022 and a commitment fee of 0.50% on the unused portion of the Tsugaru Holdings Loan Agreement. The Tsugaru Holdings Loan Agreement is subject to certain covenants and is secured by the membership interests and other rights. As of September 30, 2018, outstanding borrowings under the Tsugaru Holdings Loan Agreement totaled $57.0 million.

11. Asset Retirement Obligation

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.

In the third quarter of 2018, the Company committed to a plan to re-power its Gulf Wind project by the end of 2020, and as such, received new cost analyses for decommissioning of the Gulf Wind project. This initiated a new decommissioning cost study by the Company. As a result, the Company revised its estimated future cash flows to reflect the updated costs for its existing asset retirement obligations. The change in estimate did not result in any charge to net income (loss) for the three and nine months ended September 30, 2018.

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligation (in thousands):



	Nine months ended September 30,
	2018			2017
Beginning asset retirement obligations	$	56,619		$	44,783
Net additions during the period ⁽¹⁾	51,541			8,112
Foreign currency translation adjustment	(2,672		)	233
Divested operations	(2,550		)	—
Revision in estimated cash flows	86,314			—
Accretion expense	2,754			2,130
Ending asset retirement obligations	$	192,006		$	55,258


⁽¹⁾	Reflects additions due to acquisitions during the nine months ended September 30, 2018. See Note 5, Acquisitions, for discussion of acquisitions.

12. Derivative Instruments

The Company employs a variety of derivative instruments to manage its exposure to fluctuations in electricity prices, interest rates and foreign currency exchange rates. Energy prices are subject to wide swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists primarily on variable-rate debt for which the cash flows vary based upon movement in interest rates. Additionally, the Company is exposed to foreign currency exchange rate risk primarily from its business operations in Canada and Japan. 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 Company does not hedge all of its electricity price risk, interest rate risks, and foreign currency exchange rate risks, thereby exposing the unhedged portions to changes in market prices.

As of September 30, 2018, the Company also had other energy-related contracts that did not meet the definition of a derivative instrument or qualified for the normal purchase normal sale scope exception and were therefore exempt from fair value accounting treatment.

The following tables present the fair values of the Company's derivative instruments on a gross basis as reflected on the Company’s consolidated balance sheets (in thousands):



	September 30, 2018
	Derivative Assets				Derivative Liabilities
	Current		Long-Term		Current		Long-Term
Fair Value of Designated Derivatives
Interest rate swaps	$	616	$	18,057	$	1,706	$	13,020

Fair Value of Undesignated Derivatives
Interest rate swaps	$	—	$	—	$	241	$	124
Energy derivative	11,880		—		—		—
Foreign currency forward contracts	3,346		6,700		243		1,841
Total Fair Value	$	15,842	$	24,757	$	2,190	$	14,985

	December 31, 2017
	Derivative Assets				Derivative Liabilities
	Current		Long-Term		Current		Long-Term
Fair Value of Designated Derivatives
Interest rate swaps	$	—	$	1,968	$	4,397	$	17,961

Fair Value of Undesignated Derivatives
Interest rate swaps	$	—	$	228	$	858	$	2,542
Energy derivative	19,440		7,432		—		—
Foreign currency forward contracts	5		—		3,154		469
Total Fair Value	$	19,445	$	9,628	$	8,409	$	20,972

The following table summarizes the notional amounts of the Company's outstanding derivative instruments (in thousands except for MWh):



	Unit of Measure	September 30,		December 31,
	Unit of Measure	2018		2017
Designated Derivative Instruments
Interest rate swaps	USD	$	419,633	$	253,271
Interest rate swaps	CAD	$	725,531	$	736,136
Interest rate swaps	JPY	¥	55,806,344	¥	—

Undesignated Derivative Instruments
Interest rate swaps	USD	$	61,032	$	85,474
Energy derivative	MWh	313,948		697,471
Foreign currency forward contracts	CAD	$	105,750	$	127,500
Foreign currency forward contracts	JPY	¥	11,786,050	¥	—

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

The Company has interest rate swap agreements to hedge variable rate project-level debt. Under these interest rate swaps, the projects make fixed-rate interest payments and the counterparties to the agreements make variable-rate interest payments. For interest swaps that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive loss and reclassified into earnings in the period or periods during which cash settlement occurs. The designated interest rate swaps have remaining maturities ranging from approximately 5.3 years to 20.3 years as of September 30, 2018.

The following table presents the pre-tax effect of the derivative instruments designated as cash flow recognized in accumulated other comprehensive loss, amounts reclassified to earnings for the following periods, as well as, amounts recognized in interest expense (in thousands):



		Three months ended September 30,						Nine months ended September 30,
	Description	2018			2017			2018			2017
Gains (losses) recognized in accumulated OCI	Effective portion of change in fair value	$	14,425		$	3,205		$	22,115		$	(1,154	)
Gains (losses) reclassified from accumulated OCI into:
Interest expense	Derivative settlements	$	(1,098	)	$	(2,891	)	$	(4,055	)	$	(7,861	)
Realized loss on designated derivatives	Termination	$	—		$	(2,207	)	$	—		$	(2,207	)
Gain (loss) on derivatives	De-designation of derivatives	$	—		$	—		$	1,529		$	—
Interest expense	Ineffective portion	$	471		$	329		$	1,029		$	252

The Company estimates that $1.0 million in accumulated other comprehensive loss will be reclassified into earnings over the next twelve months.

Derivatives Not Designated as Hedging Instruments

The following table presents gains and losses on derivatives not designated as hedges (in thousands):



	Financial Statement Line Item	Three months ended September 30,					Nine months ended September 30,
Derivative Type	Financial Statement Line Item	2018		2017			2018			2017
Interest rate swaps	Gain (loss) on derivatives	$	232	$	(136	)	$	3,824		$	(2,356	)
Energy derivative	Electricity sales	$	1,714	$	83		$	(2,356	)	$	4,144
Foreign currency forward contracts	Gain (loss) on derivatives	$	1,303	$	(3,945	)	$	12,173		$	(7,124	)

Interest Rate Swaps

The Company has an interest rate swap agreement to hedge variable rate project-level debt. Under this interest rate swap, the project makes fixed-rate interest payments and the counterparties to the agreement make variable-rate interest payments. For interest rate swaps that are not designated and do not qualify as cash flow hedges, the changes in fair value are recorded in gain (loss) on derivatives in the consolidated statements of operations as these hedges are not accounted for under hedge accounting. The Company's undesignated interest rate swap has a remaining maturity of 11.8 years as of September 30, 2018.

Energy Derivative

In 2010, Gulf Wind acquired an energy derivative instrument to manage its exposure to variable electricity prices over the life of the arrangement. The energy price swap fixes the price for a predetermined volume of production (the notional volume) over the life of the swap contract, through April 2019, by locking in a fixed price per MWh. The notional volume agreed to by the parties is approximately 504,220 MWh per year. The energy derivative instrument does not meet the criteria required to adopt hedge accounting. As a result, changes in fair value are recorded in electricity sales in the consolidated statements of operations.

As a result of the counterparty's credit rating downgrade, the Company received collateral related to the energy derivative agreement. As of September 30, 2018, the Company has recorded a current asset of $5.9 million to counterparty collateral and a current liability of $5.9 million to counterparty collateral liability representing the collateral received and corresponding obligation to return the collateral, respectively.

Foreign Currency Forward Contracts

The Company has 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 the Company's 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 and Japanese yen. The Company enters into foreign currency forward contracts at various times to mitigate the currency exchange rate risk on Canadian dollar and, beginning in 2018, Japanese yen denominated cash flows. These instruments have remaining maturities ranging from three months to 11.5 years. The foreign currency forward contracts are considered non-designated derivative instruments and are not used for trading or speculative purposes. As a result, changes in fair value and settlements are recorded in gain (loss) on derivatives in the consolidated statements of operations.

13. Accumulated Other Comprehensive Loss

The following tables summarize the changes in the accumulated other comprehensive loss balance, net of tax, by component (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, 2016	$	(43,500	)	$	(12,751	)	$	(6,498	)	$	(62,749	)
Other comprehensive income (loss) before reclassifications	17,979			(2,498		)	6,546			22,027
Amounts reclassified from accumulated other comprehensive loss due to termination of interest rate derivatives	—			2,207			—			2,207
Amounts reclassified from accumulated other comprehensive loss	—			7,023			6,471			13,494
Net current period other comprehensive income	17,979			6,732			13,017			37,728
Balances at September 30, 2017	$	(25,521	)	$	(6,019	)	$	6,519		$	(25,021	)



	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI		Total
Balances at December 31, 2017	$	(28,187	)	$	(4,347	)	$	7,315	$	(25,219	)
Other comprehensive income (loss) before reclassifications	(19,547		)	20,888			5,492		6,833
Amounts reclassified from accumulated other comprehensive loss due to de-designation of interest rate swaps	—			(1,529		)	—		(1,529		)
Amounts reclassified from accumulated other comprehensive loss	—			3,437			3,530		6,967
Net current period other comprehensive income (loss)	(19,547		)	22,796			9,022		12,271
Balances at September 30, 2018	$	(47,734	)	$	18,449		$	16,337	$	(12,948	)

14. Fair Value Measurements

Fair Value

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

Assets and liabilities recorded at fair value in the consolidated financial statements are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to valuation of these assets or liabilities are set forth below. Transfers between levels are recognized at the end of each quarter. The Company did not recognize any transfers between levels during the periods presented.

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

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

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

Financial Instruments

The carrying value of financial instruments classified as current assets and current liabilities approximates their fair value, based on the nature and short maturity of these instruments, and they are presented in the Company’s financial statements at carrying cost. Certain other assets and liabilities were measured at fair value upon initial recognition and unless conditions give rise to an impairment, are not remeasured.

Financial Instruments Measured at Fair Value on a Recurring Basis

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):



	September 30, 2018
	Level 1		Level 2		Level 3		Total
Assets
Interest rate swaps	$	—	$	18,673	$	—	$	18,673
Energy derivative	—		—		11,880		11,880
Foreign currency forward contracts	—		10,046		—		10,046
	$	—	$	28,719	$	11,880	$	40,599
Liabilities
Interest rate swaps	$	—	$	15,091	$	—	$	15,091
Foreign currency forward contracts	—		2,084		—		2,084
Contingent consideration	—		—		124,848		124,848
	$	—	$	17,175	$	124,848	$	142,023



	December 31, 2017
	Level 1		Level 2		Level 3		Total
Assets
Interest rate swaps	$	—	$	2,196	$	—	$	2,196
Energy derivative	—		—		26,872		26,872
Foreign currency forward contracts	—		5		—		5
	$	—	$	2,201	$	26,872	$	29,073
Liabilities
Interest rate swaps	$	—	$	25,758	$	—	$	25,758
Foreign currency forward contracts	—		3,623		—		3,623
Contingent consideration	—		—		21,943		21,943
	$	—	$	29,381	$	21,943	$	51,324

Level 2 Inputs

Derivative instruments subject to re-measurement are presented in the financial statements at fair value. The Company's interest rate swaps 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.

Level 3 Inputs

Energy Hedge

The fair value of the energy derivative instrument is determined based on a third-party valuation model. The methodology and inputs are evaluated by management for consistency and reasonableness by comparing inputs used by the third-party valuation provider to another third-party pricing service for identical or similar instruments and also reconciling inputs used in the third-party valuation model to the derivative contract for accuracy. Any significant changes are further evaluated for reasonableness by obtaining additional documentation from the third-party valuation provider.

The energy derivative instrument is valued by discounting the projected net cash flows over the remaining life of the derivative instrument using future electricity price curves with little or no market activity. Significant increases or decreases in this input would result in a significantly lower or higher fair value measurement.

Contingent Consideration

As part of the Japan Acquisition, the Company is required to pay an additional earn-out of $114.2 million, which may be increased by $9.3 million if the final Tsugaru cost is less than or equal to the construction budget or may be decreased by $9.3 million if the final Tsugaru cost is greater than the construction budget, upon term conversion of the Tsugaru Construction Loan. The discounted fair value of the contingent consideration at the acquisition date was $102.9 million, subject to foreign currency exchange rate changes. In July 2018, the Company made a $2.8 million cash distribution payment to Pattern Development 1.0 upon term conversion of the Ohorayama construction loan in June 2018.

The Broadview Project acquisition includes contingent consideration, which requires the Company to make an additional payment upon the commercial operation of the Grady Project, a wind project being separately developed by Pattern Development 2.0. The contingent post-closing payment reflects the fair value of the Company's interest in the increase in the projected 25-year transmission wheeling revenue Western Interconnect will receive from the Grady Project, adjusted for the estimated production loss incurred by Broadview due to wake effects and transmission losses induced by the operation of the Grady Project. The fair value of the contingent consideration at the acquisition date was $21.3 million.

The estimated fair value of the contingent considerations were calculated by using a discounted cash flow technique which utilized unobservable inputs presented in the table below. This fair value measurement is based on significant inputs not observable in the market and thus represents a Level 3 measurement as defined in ASC 820, Fair Value Measurement. As of September 30, 2018, there were no significant changes in these unobservable inputs that may result in significant changes in fair value.

The valuation techniques and significant unobservable inputs used in recurring Level 3 fair value measurements were as follows (in thousands, for fair value):



September 30, 2018	Fair Value	Valuation Technique	Significant Unobservable Inputs	Range
Energy derivative	$11,880	Discounted cash flow	Forward electricity prices	$20.65-$32.70 ⁽¹⁾
			Discount rate	2.40%-2.60%

Broadview contingent consideration	$24,771	Discounted cash flow	Discount rate	4.0%-8.0%
			Annual energy production loss	0.7%
Tsugaru contingent consideration	$100,097	Discounted cash flow	Deferred purchase price	$109 - $128 million
			Discount rate	6.9%

December 31, 2017	Fair Value	Valuation Technique	Significant Unobservable Inputs	Range
Energy derivative	$26,872	Discounted cash flow	Forward electricity prices	$14.44 - $71.45⁽¹⁾
			Discount rate	1.69% - 1.96%

Contingent consideration	$21,943	Discounted cash flow	Discount rate	4.0% - 8.0%
			Annual energy production loss	1.0%


⁽¹⁾	Represents price per MWh.

The following tables present a reconciliation of the energy derivative contract and contingent consideration liability measured at fair value on a recurring basis using significant unobservable inputs (in thousands):



	Three months ended September 30,						Nine months ended September 30,
Energy Derivative	2018			2017			2018			2017
Balances, beginning of period	$	12,198		$	33,895		$	26,872		$	40,916
Total gain (loss) included in electricity sales	1,714			83			(2,356		)	4,144
Settlements	(2,032		)	(3,196		)	(12,636		)	(14,278		)
Balances, end of period	$	11,880		$	30,782		$	11,880		$	30,782

During the three and nine months ended September 30, 2018, the Company recognized unrealized losses of $0.3 million and $15.0 million, respectively, and $3.1 million and $10.1 million for the same periods in 2017, respectively, which were recorded to electricity sales on the consolidated statements of operations.



	Three months ended September 30,					Nine months ended September 30,
Contingent Consideration Liability	2018			2017		2018			2017
Balances, beginning of period	128,000			21,502		21,943			—
Purchase	—			—		105,922			21,284
Total gain (loss) included in other income (expense), net	(311		)	3		(176		)	221
Settlement	(2,821		)	—		(2,821		)	—
Balances, end of period	$	124,868		$	21,505	$	124,868		$	21,505

During the three and nine months ended September 30, 2018, the Company recognized unrealized gain on the contingent consideration liability of $0.3 million and $0.2 million, respectively, which was recorded to other income (expense), net on the consolidated statements of operations.

Financial Instruments Not Measured at Fair Value

The following table presents the carrying amount and fair value and the fair value hierarchy of the Company’s financial liabilities that are not measured at fair value in the consolidated balance sheets, but for which fair value is disclosed (in thousands):



			Fair Value
	As reflected on the balance sheet		Level 1		Level 2		Level 3		Total
September 30, 2018
Long-term debt, including current portion	$	2,379,637	$	—	$	2,348,240	$	—	$	2,348,240
December 31, 2017
Long-term debt, including current portion	$	1,930,731	$	—	$	1,937,671	$	—	$	1,937,671

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

15. Stockholders' Equity

Common Stock

The Company has an equity distribution agreement (Equity Distribution Agreement) pursuant to the terms of which, the Company may offer and sell shares of the Company's Class A common stock, par value $0.01 per share, from time to time, up to an aggregate sales price of $200 million. For the nine months ended September 30, 2018, the Company did not sell any shares under the Equity Distribution Agreement. As of September 30, 2018, approximately $144.2 million in aggregate offering price remained available to be sold under the agreement.

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
2018:
Third Quarter	$	0.4220	August 2, 2018	September 28, 2018	October 31, 2018
Second Quarter	$	0.4220	May 3, 2018	June 29, 2018	July 31, 2018
First Quarter	$	0.4220	February 22, 2018	March 30, 2018	April 30, 2018

Noncontrolling Interests

The following table presents the balances for noncontrolling interests by project (in thousands):



	September 30,		December 31,
	2018		2017
El Arrayán ⁽¹⁾	$	—	$	31,828
Logan's Gap	135,762		171,137
Panhandle 1	134,416		174,518
Panhandle 2	178,385		208,397
Post Rock	120,533		160,206
Amazon Wind	97,706		133,950
Broadview Project	263,524		307,672
Futtsu	10,568		—
Meikle	62,923		65,985
MSM	41,534		$	—
Noncontrolling interest	$	1,045,351	$	1,253,693


⁽¹⁾	Noncontrolling interest of El Arrayán was derecognized as a result of the sale of the Company's operation in Chile.

The following table presents the components of total noncontrolling interest as reported in the stockholders’ equity statements and the consolidated balance sheets (in thousands):



	Capital			Accumulated Loss				Accumulated Other Comprehensive Income (Loss)				Noncontrolling Interest
Balances at December 31, 2016	$	954,242		$	(62,614	)		$	(382	)		$	891,246
Acquisitions	390,389			—				—				390,389
Distributions to noncontrolling interests	(13,701		)	—				—				(13,701		)
Other	(201		)	—				—				(201		)
Net loss	—			(50,566		)		—				(50,566		)
Other comprehensive income, net of tax	—			—				182				182
Balances at September 30, 2017	$	1,330,729		$	(113,180	)		$	(200	)		$	1,217,349

Balances at December 31, 2017	$	1,380,340		$	(127,119	)		$	472			$	1,253,693
Acquisitions	52,493			—			—	—			—	52,493
Sale of subsidiaries	(36,910		)	4,632				—				(32,278		)
Distributions to noncontrolling interests	(28,867		)	—				—				(28,867		)
Net loss ⁽¹⁾	—			(201,986		)		—				(201,986		)
Other comprehensive income, net of tax	—			—				2,296				2,296
Balances at September 30, 2018	$	1,367,056		$	(324,473	)		$	2,768			$	1,045,351

⁽¹⁾

On December 22, 2017, the Tax Act was signed into law, which enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Reduction in the corporate income tax rate resulted in one-time reduction in the noncontrolling interest attributable to partners in its tax equity partnerships. As part of the liquidation waterfall, the Company allocated significantly lower portions of the hypothetical liquidation proceeds to compensate certain noncontrolling interest investors for tax gains on the hypothetical sale calculated at the lowered rate of 21% as compared to the rate of 35% that was previously utilized. For the nine months ended September 30, 2018, included in net loss attributable to noncontrolling interest is a one-time adjustment of $150 million as a result of the decrease in the federal corporate income tax rate.

16. Earnings Per Share

Basic earnings per share is computed by dividing net earnings attributable to common stockholders by the weighted average number of common shares outstanding during the reportable period. Diluted earnings per share is computed by adjusting basic earnings per share for the effect of all potential common shares unless they are anti-dilutive. For purpose of this calculation, 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 (RSAs) and release of deferred restricted stock units (RSUs). Potentially dilutive securities related to convertible senior notes are determined using the if-converted method.

The Company's vested deferred RSUs have non-forfeitable rights to dividends prior to release and are considered participating securities. Accordingly, they are included in the computation of basic and diluted earnings per share, pursuant to the two-class method. Under the two-class method, distributed and undistributed earnings allocated to participating securities are excluded from net earnings attributable to common stockholders for purposes of calculating basic and diluted earnings per share. However, net losses are not allocated to participating securities since they are not contractually obligated to share in the losses of the Company.

Potentially dilutive securities excluded from the calculation of diluted earnings per share because their effect would have been anti-dilutive were 9.1 million shares and 0.4 million shares, respectively, for the three and nine months ended September 30, 2018, and 9.0 million shares and 9.0 million shares, respectively, for the three and nine months ended September 30, 2017.

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



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Numerator for basic and diluted earnings per share:
Net earnings (loss) attributable to controlling interest	$	(12,595	)	$	(29,828	)	$	156,045		$	(9,955	)
Less: earnings allocated to participating securities	(44		)	(29		)	(154		)	(74		)
Numerator for basic EPS - net income (loss) attributable to common stockholders	$	(12,639	)	$	(29,857	)	$	155,891		$	(10,029	)
Add back allocation of earnings to participating securities	44			29			154			74
Add back convertible senior notes interest	—			—			11,305			—
Reallocation of earnings to participating securities considering potentially dilutive securities	(44		)	(29		)	(151		)	(74		)
Numerator for diluted earnings per share - net income (loss) attributable to common stockholders	$	(12,639	)	$	(29,857	)	$	167,199		$	(10,029	)

Denominator for earnings per share:
Weighted average number of shares:
Class A common stock - basic	97,460,492			87,370,979			97,464,012			87,146,465
Add dilutive effect of:
Restricted stock awards	—			—			153,444			—
Restricted stock units	—			—			652			—
Convertible senior notes	—			—			8,170,740			—
Class A common stock - diluted	97,460,492			87,370,979			105,788,848			87,146,465

Earnings (loss) per share:
Class A common stock:
Basic	$	(0.13	)	$	(0.34	)	$	1.60		$	(0.12	)
Diluted	$	(0.13	)	$	(0.34	)	$	1.58		$	(0.12	)

Dividends declared per Class A common share	$	0.42		$	0.42		$	1.27		$	1.25

17. Commitments and Contingencies

Commitments

Completed Acquisition Commitments

As part of the acquisitions completed in 2018, the Company became party to various agreements and future commitments. The following table summarizes estimates of future commitments related to the various agreements entered into as part of the acquisitions completed in 2018 (in thousands) as of September 30, 2018:



	2018 (remainder)		2019		2020		2021		2022		Thereafter		Total
Operating leases	$	905	$	4,023	$	3,481	$	3,316	$	3,340	$	60,300	$	75,365
Service and maintenance agreements	1,112		4,631		5,932		6,144		6,124		43,856		67,799
Other⁽¹⁾	27,696		146,763		33,310		—		—		—		207,769
Total commitments ⁽²⁾	$	29,713	$	155,417	$	42,723	$	9,460	$	9,464	$	104,156	$	350,933


⁽¹⁾	Other commitments consist of acquired construction commitments related to MSM, and the development of Tsugaru which is expected to commence commercial operations in early to mid-2020.


⁽²⁾	The accounting for the Japan Acquisition is preliminary. Refer to Note 5, Acquisitions for details.

Operating Leases

The Company has entered into various long-term operating lease agreements related to lands for its wind and solar farms. For the nine months ended September 30, 2018 and 2017, the Company recorded rent expenses of $13.3 million and $10.2 million, respectively, in project expense in its consolidated statements of operations.

In March 2018, the Company entered into an operating lease for its new corporate headquarters in San Francisco, California. Total operating lease payments are approximately $35 million over the term of the lease which expires in December 2028.

Gulf Wind Re-Powering Commitment

In September 2018, the Company committed to a plan to re-power the Gulf Wind facility. In connection with the re-powering plan, the Company entered into a turbine purchase agreement for a maximum purchase price of $150.6 million, depending upon the number of turbines purchased. The Company has the option, exercisable by September 2, 2019, to reduce the number of turbines.

Separately, in September 2018, the Company exercised its option to purchase turbines from an affiliate of Pattern Development 2.0. Such affiliate of Pattern Development 2.0 has until August 30, 2019 to determine the number of turbines to sell to the Company. The purchase price will be equal to the cost paid for the turbines by such affiliate of Pattern Development 2.0 in 2016.

Letters of Credit

Power Sale Agreements

The Company owns and operates wind power projects and has entered into various long-term power sale agreements that terminate from 2019 to 2043. The terms of these agreements 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 agreement. Under the terms of these agreements, as of September 30, 2018, irrevocable letters of credits totaling $156.4 million were available to be issued to guarantee the Company's performance for the duration of the agreements.

Project Finance and Lease Agreements

The Company has various project finance and lease agreements which obligate the Company to provide certain reserves to enhance its credit worthiness and facilitate the availability of credit. As of September 30, 2018, irrevocable letters of credit totaling $196.9 million, which includes letters of credit available under the Corporate Revolving Credit Facility, were available to be issued to ensure performance under the various project finance and lease agreements.

Contingencies

Turbine Operating Warranties and Service Guarantees

The Company has various turbine availability warranties from its turbine manufacturers and service guarantees from its service and maintenance providers. Pursuant to these guarantees, if a turbine operates at less than minimum availability during the guarantee measurement period, the service provider is obligated to pay, as liquidated damages at the end of the warranty measurement period, 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 measurement period, the Company has an obligation to pay a bonus to the service provider at the end of the warranty measurement period. As of September 30, 2018, the Company recorded liabilities of $0.3 million associated with bonuses payable to the turbine manufacturers and service providers.

Contingencies in connection with the Broadview Project

The Company recorded a $7.2 million contingent obligation upon the acquisition of the Broadview Project in 2017, which is subject to certain conditions, including the actual energy production of Broadview in a production year and the continued operation of Broadview. Also as part of the acquisition, the Company recorded an additional $29.0 million contingent obligation, payable to the same counterparty, which is subject to certain conditions, including the commercial operation of the Grady Project, expected in April 2019. This contingent payment is calculated as a percentage of additional transmission revenue earned by Western Interconnect upon the Grady Project's commercial operation. As of September 30, 2018, the balance of the contingencies totaled $30.7 million of which $1.1 million is current and $29.6 million is long-term.

Contingencies in connection with the Sale of Panhandle 2 interests

In connection with the sale of Panhandle 2, the Company agreed to indemnify PSP up to $5.0 million to cover PSP's pro rata share of the economic impacts resulting from planned transmission outages in the Texas market until December 31, 2019. As of September 30, 2018, the Company has recorded a contingent liability of $3.7 million associated with the indemnity.

Legal Matters

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.

Indemnity

The Company provides a variety of indemnities in the ordinary course of business to contractual counterparties and to its lenders and other financial partners. The Company is party to certain indemnities for the benefit of project finance lenders and tax equity partners of certain projects. These consist principally of indemnities that protect the project finance lenders from, among other things, 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 and certain legal matters, limited to the amount of certain related costs and expenses.

18. Related Party Transactions

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 Armow, in addition to various Pattern Development 1.0 subsidiaries and equity method investments. In connection with the Japan Acquisition, the Company receives management services related to the acquired projects and incurs a fee for such services under agreements with a subsidiary of Pattern Development 2.0.

Management Services Agreement and Shared Management

The Company has entered into an Amended and Restated Multilateral Management Services Agreement (MSA) with the Pattern Development Companies, which provides for the Company and the Pattern Development Companies to benefit, primarily on a cost-reimbursement basis, from the parties’ respective management and other professional, technical and administrative personnel, all of whom report to the Company’s executive officers. Costs and expenses incurred at the Pattern Development Companies or their respective subsidiaries on the Company's behalf will be allocated to the Company. Conversely, costs and expenses incurred at the Company or its respective subsidiaries on the behalf of a Pattern Development Company will be allocated to the respective Pattern Development Company.

Pursuant to the MSA, certain of the Company’s executive officers, including its Chief Executive Officer (shared PEG executives), also serve as executive officers of the Pattern Development Companies and devote their time to both the Company and the Pattern Development Companies as is prudent in carrying out their executive responsibilities and fiduciary duties. The shared PEG executives have responsibilities for both the Company and the respective Pattern Development Companies and, as a result, these individuals do not devote all of their time to the Company’s business. Under the terms of the MSA, each of the respective Pattern Development Companies is required to reimburse the Company for an allocation of the compensation paid to such shared PEG executives reflecting the percentage of time spent providing services to such Pattern Development Company. The MSA costs incurred by the Company are included in related party general and administrative on the consolidated statements of operations.

Related Party Transactions

The table below presents amounts due from and to related parties as included in the consolidated balance sheets for the following periods (in millions):



	September 30, 2018		December 31, 2017
Other current assets	$	6.7	$	13.2
Total due from related parties	$	6.7	$	13.2

Other current liabilities	9.0		10.8
Contingent liabilities, current	24.8		—
Contingent liabilities	124.9		21.3
Total due to related parties	$	158.7	$	32.1

The table below presents revenue, reimbursement and (expenses) recognized for management fees and the MSA, as included in the statements of operations for the following periods (in thousands):



		Three months ended September 30,						Nine months ended September 30,
Related Party Agreement	Financial Statement Line Item	2018			2017			2018			2017
Management fees	Other revenue	$	2,040		$	1,883		$	6,820		$	5,887
Management fees	Project expense	$	173		$	—		$	899		$	—
MSA reimbursement	General and administrative	$	2,681		$	2,194		$	7,390		$	6,083
MSA costs	Related party general and administrative expense	$	(4,285	)	$	(3,587	)	$	(12,016	)	$	(10,589	)

Purchase and Sales Agreements

During the nine months ended September 30, 2018, the Company consummated the following acquisitions with Pattern Development 1.0 which are further detailed in Note 5, Acquisitions (in millions):



Acquisitions from Pattern Development 1.0	Date of Acquisition	Cash Consideration		Debt Assumed		Contingent Consideration
Japan projects	March 7, 2018	$	176.6	$	181.3	$	105.9
MSM	August 10, 2018	$	76.9	$	196.0	$	0.1

Investment in Pattern Development 2.0

During 2018, the Company funded $86.3 million into Pattern Development 2.0 of which approximately $27 million was used by Pattern Development 2.0 to fund the purchase of GPI. As of September 30, 2018, the Company has funded $153.6 million in aggregate and holds an approximately 29% ownership interest in Pattern Development 2.0.

Development Fee

In September 2018, upon reaching a project development milestone, Tsugaru paid a development fee of approximately $15.2 million to an affiliate of Pattern Development 2.0. Due to the Company's equity ownership in Pattern Development 2.0, the Company has eliminated its portion of the profits realized by Pattern Development 2.0 with respect to this transaction.

19. Subsequent Events

On October 30, 2018, the Company declared a dividend for the fourth quarter, payable on January 31, 2019, to holders of record on December 31, 2018, in the amount of $0.4220 per Class A share, or $1.688 on an annualized basis. This is unchanged from the third quarter of 2018.

On October 5, 2018, the Company funded approximately $29.2 million into Pattern Development 2.0.

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, 2017 and our unaudited consolidated financial statements for the three and nine months ended September 30, 2018 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 24 wind and solar power projects, with a total owned interest of 2,861 MW in the United States, Canada and Japan that use proven and best-in-class technology. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price power sale agreements (PSAs), some of which are subject to price escalation. Ninety-two percent of the electricity to be generated by our projects will be sold under our PSAs which have a weighted average remaining contract life of approximately 13.5 years as of September 30, 2018.

We intend to maximize long-term value for our stockholders in an environmentally responsible manner and with respect for the communities in which we operate. Our business is built around three core values of creative energy and spirit, pride of ownership and follow-through, and a team first attitude, which guide us in creating a safe, high-integrity work environment, applying rigorous analysis to all aspects of our business, and proactively working with our stakeholders to address environmental and community concerns. Our financial objectives, which we believe will maximize long-term value for our stockholders, are to produce stable and sustainable cash available for distribution, selectively grow our project portfolio and our dividend per Class A share and maintain a strong balance sheet and flexible capital structure.

Our growth strategy is focused on the acquisition of operational and construction-ready power projects from Pattern Development Companies (Pattern Energy Group LP (Pattern Development 1.0), Pattern Energy Group 2 LP (Pattern Development 2.0) and their respective subsidiaries) and other third parties that, together with measured investments into the development business, we believe will contribute to the growth of our business and enable us to increase our dividend per share of Class A common stock over time. The Pattern Development Companies are leading developers of renewable energy and transmission projects. Our continuing relationship with the Pattern Development Companies, including an approximate 29% interest in Pattern Development 2.0, provides us with access to a pipeline of acquisition opportunities. Currently, the Pattern Development Companies have a more than 10 GW pipeline of development projects, all of which are subject to our right of first offer. We target achieving a total owned or managed capacity of 5,000 MW by year end 2020 through a combination of acquisitions from the Pattern Development Companies and other third parties capitalizing on the large and fragmented global renewable energy market. Our business is primarily focused in the U.S., Canada, and Japan.

The discussion and analysis below has been organized as follows:


•	Recent Developments


•	Key Metrics


•	Results of Operations


•	Liquidity and Capital Resources


◦	Sources of Liquidity


◦	Uses of Liquidity


•	Critical Accounting Policies and Estimates

Recent Developments

Gulf Wind Re-Powering

In September 2018, we committed to a plan to re-power our Gulf Wind facility. In connection with the re-powering plan, we entered into a turbine purchase agreement for a maximum purchase price of $150.6 million, depending upon the number of turbines purchased. We have the option, exercisable by September 2, 2019, to reduce the number of turbines.

Separately, in September 2018, we exercised our option to purchase turbines from an affiliate of Pattern Development 2.0. Such affiliate of Pattern Development 2.0 has until August 30, 2019 to determine the number of turbines to sell to us. The purchase price will be equal to the cost paid for the turbines by such affiliate of Pattern Development 2.0 in 2016.

Chilean Sale

On May 21, 2018, we, through our indirect wholly-owned subsidiaries, entered into a stock purchase agreement with a third party pursuant to which we agreed to sell, and the buyer agreed to purchase, certain subsidiaries which hold approximately a 71% interest in El Arrayán Wind and assets and rights relating to ownership and operation of an extension of the trunk transmission system in Chile (Chilean Sale). El Arrayán Wind is a wind electric generation facility located approximately 400 kilometers north of Santiago on the coast of Chile in which we had an owned interest of approximately 81 MW. On August 20, 2018, we completed the Chilean Sale for cash proceeds of $70.4 million. As a result, we recorded a total impairment expense of $2.3 million and $6.6 million as for the three and nine months September 30, 2018, respectively, in the consolidated statements of operations.

Mont Sainte-Marguerite

On August 10, 2018, pursuant to a Purchase and Sale Agreement by and among us, Pattern Development 1.0, and an affiliate of Public Sector Pension Investment Board (PSP), we subscribed for 50.99% of the limited partner interests in MSM LP Holdings LP (which holds 99.98% of the economic interests in Mont Sainte-Marguerite Wind Farm Limited Partnership (MSM)) and purchased, from an affiliate of Pattern Development 1.0, 70% of the issued and outstanding shares in the capital of Pattern MSM GP Holdings Inc. (Pattern MSM Corp) and 70% of the issued and outstanding shares in the capital of Pattern Development MSM Management ULC (MSM ULC), in exchange for aggregate consideration of $39.3 million. Concurrently, an affiliate of PSP subscribed for a 48.99% limited partner interest in MSM LP Holdings LP and purchased, from an affiliate of Pattern Development 1.0, 30% of the issued and outstanding shares of Pattern MSM Corp, and 30% of the issued and outstanding shares in the capital of MSM ULC for a purchase price of $37.7 million. MSM operates the approximately 143 megawatt wind farm located in the Chaudière-Appalaches region south of Québec City, Canada, which achieved commercial operation in the first quarter of 2018.

Pattern Development 2.0 Investment

In October 2018, we funded approximately $29.2 million into Pattern Development 2.0, for a total of $182.8 million in aggregate funding and hold an approximately 29% ownership interest in Pattern Development 2.0.

Japan Acquisition

On March 7, 2018, pursuant to a series of purchase and sale agreements with Pattern Development 1.0 and Green Power Investments (GPI), we acquired Green Power Tsugaru Holdings G.K. which owns Tsugaru, a project company currently constructing a 122 MW name plate capacity wind facility in Aomori Prefecture, Japan expected to commence commercial operations in early to mid-2020; Ohorayama, a wind project located in Kochi Prefecture, Japan, with a name plate capacity of 33 MW that commenced commercial operations in March 2018; Kanagi, a solar project located in Shimane Prefecture, Japan, with a name plate capacity of 10 MW that commenced commercial operations in 2016; Otsuki, a wind project located in Kochi Prefecture, Japan, with a name plate capacity of 12 MW that began commercial operations in 2006; and Futtsu, a solar project located in Chiba Prefecture, Japan, with a name plate capacity of 29 MW that commenced commercial operations in 2016, collectively referred to as the Japan Acquisition.

Total consideration for the Japan Acquisition was $282.5 million, which consisted of approximately $176.6 million of cash and post-closing contingent payments with fair value of approximately $105.9 million. As part of the acquisition, we also assumed $181.3 million of debt. Subsequent to the acquisition, we extinguished debt of $5.7 million at Otsuki.

Noncontrolling Interests - Impact of the 2017 Tax Act

On December 22, 2017, the 2017 Tax Act (Tax Act) was signed into law, which enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Reduction in the corporate income tax rate resulted in one-time reduction in the noncontrolling interest attributable to partners in our tax equity partnerships. As part of the liquidation waterfall, we allocated significantly lower portions of the hypothetical liquidation proceeds to compensate certain noncontrolling interest investors for tax gains on the hypothetical sale calculated at the lowered rate of 21% as compared to the rate of 35% that was previously utilized. For the nine months ended September 30, 2018, included in net loss attributable to noncontrolling interest is a one-time adjustment of $150 million as a result of the decrease in the federal corporate income tax rate. We do not expect the Tax Act to significantly change the flip point or the timing of expected cash distributions.

Identified ROFO Projects

Below is a summary of our Identified ROFO Projects that we have the right to purchase from the Pattern Development Companies in connection with our respective purchase rights.



						Capacity (MW)
Identified ROFO Projects	Status	Location	Construction Start⁽¹⁾	Commercial Operations ⁽²⁾	Contract Type	Rated ⁽³⁾	Pattern Development- Owned ⁽⁴⁾
Pattern Development 1.0 Projects
Belle River	Operational	Ontario	2016	2017	PPA	100	43
North Kent	Operational	Ontario	2017	2018	PPA	100	35
Henvey Inlet	In construction	Ontario	2017	2019	PPA	300	150
Pattern Development 2.0 Projects
Stillwater Big Sky	Operational	Montana	2018	2018	PPA	80	80
Crazy Mountain	Late stage development	Montana	2019	2019	PPA	80	80
Grady	In construction	New Mexico	2018	2019	PPA	220	188
Sumita	Late stage development	Japan	2019	2022	PPA	99	55
Ishikari	Late stage development	Japan	2020	2022	PPA	112	112
						1,091	743


⁽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 in MW multiplied by Pattern Development 1.0's or Pattern Development 2.0's percentage ownership interest in the distributable cash flow of the project.

We waived our ROFO rights with respect to Conejo Solar, a solar project in Chile, in connection with the sale of such project pursuant to a joint marketing process that was undertaken with our sale of El Arrayán Wind, a project also located in Chile. We declined to exercise our ROFO rights with respect to El Cabo, and Pattern Development 1.0 entered agreements to sell their interests in such project back to the party from whom it had acquired such interests. In August 2018, we waived our right of first offer with respect to three renewable projects currently under development in Mexico by Pattern Development 2.0.

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 total revenue, cost of revenue, net loss and net cash provided by operating activities, we also consider cash available for distribution as a supplemental liquidity measure and Adjusted EBITDA, MWh sold and average realized electricity price in evaluating our operating performance. We disclose cash available for distribution, which is a non-U.S. GAAP measure, because management recognizes that it will be used as a supplemental measure by investors and analysts to evaluate our liquidity. We disclose Adjusted EBITDA, which is a non-U.S. GAAP measure, because management believes this metric assists investors and analysts in comparing our operating performance across reporting periods on a consistent basis by excluding items that our management believes are not indicative of our core operating performance. Each of these key metrics is discussed below.

Limitations to Key Metrics

We disclose cash available for distribution, which is a non-U.S. GAAP measure, because management recognizes that it will be used as a supplemental measure by investors and analysts to evaluate our liquidity. However, cash available for distribution has limitations as an analytical tool because it:


•	excludes depreciation, amortization and accretion;


•	does not capture the level of capital expenditures necessary to maintain the operating performance of our projects;


•	is not reduced for principal payments on our project indebtedness except to the extent they are paid from operating cash flows during a period; and


•	excludes the effect of certain other cash flow items, all of which could have a material effect on our financial condition and results from operations.

Because of these limitations, cash available for distribution should not be considered an alternative to net cash provided by operating activities or any other liquidity measure determined in accordance with U.S. GAAP, nor is it indicative of funds available to fund our cash needs. In addition, our calculation of cash available for distribution is not necessarily comparable to cash available for distribution as calculated by other companies.

We disclose Adjusted EBITDA, which is a non-U.S. GAAP measure, because management believes this metric assists investors and analysts in comparing our operating performance across reporting periods on a consistent basis by excluding items that our management believes are not indicative of our core operating performance. We use Adjusted EBITDA to evaluate our operating performance. You should not consider Adjusted EBITDA as an alternative to net income (loss), determined in accordance with U.S. GAAP.

Adjusted EBITDA has limitations as an analytical tool. Some of these limitations are:


•	Adjusted EBITDA


•	does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;


•	does not reflect changes in, or cash requirements for, our working capital needs;


•	does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our debt, or our proportional interest in the interest expense of our unconsolidated investments or the cash requirements necessary to service interest or principal payments on the debt borne by our unconsolidated investments;


•	does not reflect our income taxes or the cash requirement to pay our taxes; or our proportional interest in income taxes of our unconsolidated investments or the cash requirements necessary to pay the taxes of our unconsolidated investments;


•	does not reflect depreciation, amortization and accretion which are non-cash charges; or our proportional interest in depreciation, amortization and accretion of our unconsolidated investments. The assets being depreciated, amortized and accreted will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and


•	does not reflect the effect of certain mark-to-market adjustments and non-recurring items or our proportional interest in the mark-to-market adjustments at our unconsolidated investments.

•

We do not have control, nor have any legal claim to the portion of the unconsolidated investees' revenues and expenses allocable to our joint venture partners. As we do not control, but do exercise significant influence, we account for the unconsolidated investments in accordance with the equity method of accounting. Net earnings from these investments are reflected within our consolidated statements of operations in "Earnings in unconsolidated investments, net." Adjustments related to our proportionate share from unconsolidated investments include only our proportionate amounts of interest expense, income taxes, depreciation, amortization and accretion, and mark-to-market adjustments included in "Earnings in unconsolidated investments, net;" and


•	Other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure.

Because of these limitations, Adjusted EBITDA should not be considered in isolation or as a substitute for performance measures calculated in accordance with U.S. GAAP.

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 pay dividends.

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 (as reported in net cash provided by investing activities), 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,
	2018			2017			2018			2017
Net cash provided by operating activities⁽¹⁾	$	106,922		$	2,147		$	230,466		$	159,330
Changes in operating assets and liabilities	(54,936		)	25,481			(36,439		)	(22,475		)
Network upgrade reimbursement	303			346			879			8,936
Release of restricted cash	759			—			3,247			—
Operations and maintenance capital expenditures	(169		)	(254		)	(440		)	(517		)
Distributions from unconsolidated investments	419			2,821			4,752			11,211
Other	(2,779		)	598			228			1,974
Less:
Distributions to noncontrolling interests	(7,592		)	(4,537		)	(28,867		)	(13,701		)
Principal payments paid from operating cash flows	(11,255		)	(17,140		)	(40,432		)	(40,911		)
Cash available for distribution	$	31,672		$	9,462		$	133,394		$	103,847


⁽¹⁾	Included in net cash provided by operating activities for the three and nine months ended September 30, 2018 and 2017 are the portions of distributions from unconsolidated investments paid from cumulative earnings representing the return on investment.

Cash available for distribution was $31.7 million for the three months ended September 30, 2018 as compared to $9.5 million for the same period in the prior year. This $22.2 million increase in cash available for distribution was primarily due to:


•	$24.3 million increase in revenues (excluding unrealized loss on energy derivative and amortization in electricity sales) primarily due to acquisitions in 2017 and 2018;


•	$5.9 million decrease in principal payments of project-level debt;


•	$1.7 million decrease in transmission costs; and


•	$0.8 million increase in the release of restricted cash.

These increases were partially offset by:


•	$3.0 million increase in distributions to noncontrolling interests;


•	$4.0 million decrease in distributions from unconsolidated investments; and


•	$1.4 million of costs related to the sale of Chile.

Cash available for distribution was $133.4 million for the nine months ended September 30, 2018 as compared to $103.8 million for the same period in the prior year. This $29.5 million increase in cash available for distribution was primarily due to:


•	$75.7 million increase in revenue (excluding unrealized loss on energy derivative and amortization in electricity sales);


•	$3.2 million release of restricted cash; and


•	$1.5 million decrease in general and administrative expenses.

These increases were partially offset by:


•	$15.2 million increase in distributions to noncontrolling interests;


•	$9.0 million increase in project expenses related to projects acquired in 2017 and 2018;


•	$8.3 million increase in transmission costs primarily due to acquisitions in 2017;


•	$8.1 million decrease in network upgrade reimbursements;


•	$6.7 million decrease in distributions from unconsolidated investments; and


•	$1.4 million of costs related to the sale of Chile.

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 unconsolidated investments. 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, realized derivative gain or loss from refinancing transactions, gain or loss related to acquisitions or divestitures, and adjustments from unconsolidated investments. 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.

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



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Net loss	$	(31,547	)	$	(48,376	)	$	(45,941	)	$	(60,521	)
Plus:
Interest expense, net of interest income	27,021			26,710			79,415			73,009
Tax provision (benefit)	3,043			(3,839		)	14,237			5,477
Depreciation, amortization and accretion	63,013			56,650			188,429			156,629
EBITDA	61,530			31,145			236,140			174,594
Unrealized loss on energy derivative⁽¹⁾	318			3,113			14,991			10,134
(Gain) loss on derivatives	(1,536		)	6,288			(15,997		)	11,687
Impairment expense	2,325			—			6,563			—
Other	2,180			466			2,180			1,585
Plus, proportionate share from unconsolidated investments:
Interest expense, net of interest income	9,306			10,270			28,280			29,108
Tax provision	1,142			—			935			—
Depreciation, amortization and accretion	8,888			9,361			26,397			26,390
Gain on derivatives	(4,619		)	(5,908		)	(7,333		)	(8,696		)
Adjusted EBITDA	$	79,534		$	54,735		$	292,156		$	244,802


⁽¹⁾	Amount is included in electricity sales on the consolidated statements of operations.

Adjusted EBITDA for the three months ended September 30, 2018 was $79.5 million compared to $54.7 million for the same period in the prior year, an increase of $24.8 million, or approximately 45.3%. The increase in Adjusted EBITDA was primarily due to a $24.3 million increase in revenue (excluding unrealized loss on energy derivative and amortization in electricity sales) primarily attributable to volume increases as a result of 2017 and 2018 acquisitions, favorable wind and increased availability compared to 2017.

Adjusted EBITDA for the nine months ended September 30, 2018 was $292.2 million compared to $244.8 million for the same period in the prior year, an increase of $47.4 million, or approximately 19.3%. The increase in Adjusted EBITDA was primarily due to a $75.7 million increase in revenue (excluding unrealized loss on energy derivative and amortization in electricity sales) primarily attributable to volume increases as a result of our 2017 and 2018 acquisitions, favorable wind compared to 2017, and an insurance settlement for Santa Isabel partially offset by curtailment at Santa Isabel.

The increase was partially offset by:


•	$14.3 million decrease in earnings from unconsolidated investments;


•	$9.0 million increase in project expenses; and


•	$8.3 million increase in transmission costs.

MWh Sold and Average Realized Electricity Price

The number of consolidated MWh, unconsolidated investments proportional MWh and proportional MWh sold, as well as consolidated average realized price per MWh and the proportional average realized price per MWh sold, are the operating metrics that help explain trends in our revenue, earnings from our unconsolidated investments and net income (loss) attributable to us.


•	Consolidated MWh sold for any period presented, represents 100% of MWh sold by wholly-owned and partially-owned subsidiaries in which we have a controlling interest and are consolidated in our consolidated financial statements;


•	Noncontrolling interest MWh represents that portion of partially-owned subsidiaries not attributable to us;


•	Controlling interest in consolidated MWh is the difference between the consolidated MWh sold and the noncontrolling interest MWh;


•	Unconsolidated investments proportional MWh is our proportion in MWh sold from our equity method investments;


•	Proportional MWh sold for any period presented, represents the sum of the controlling interest and our percentage interest in our unconsolidated investments; and

•

Average realized electricity price for each of consolidated MWh sold, unconsolidated investments proportional MWh sold and proportional MWh sold represents (i) total revenue from electricity sales for each of the respective MWh sold, discussed above, excluding unrealized gains and losses on our energy derivative and the amortization of finite-lived intangible assets and liabilities, divided by (ii) the respective MWh sold.

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



	Three months ended September 30,											Nine months ended September 30,
MWh sold	2018			2017			Change			% Change		2018			2017			Change			% Change
Consolidated MWh sold	1,799,378			1,598,899			200,479			12.5	%	6,407,788			5,587,484			820,304			14.7	%
Less: noncontrolling MWh	(362,213		)	(241,152		)	(121,061		)	50.2	%	(1,234,568		)	(781,880		)	(452,688		)	57.9	%
Controlling interest in consolidated MWh	1,437,165			1,357,747			79,418			5.8	%	5,173,220			4,805,604			367,616			7.6	%
Unconsolidated investments proportional MWh	185,826			156,250			29,576			18.9	%	848,295			858,178			(9,883		)	(1.2	)%
Proportional MWh sold	1,622,991			1,513,997			108,994			7.2	%	6,021,515			5,663,782			357,733			6.3	%

Average realized electricity price per MWh
Consolidated average realized electricity price per MWh	$	66		$	58		$	8		13.8	%	$	59		$	54		$	5		9.3	%
Unconsolidated investments proportional average realized electricity price per MWh	$	116		$	126		$	(10	)	(7.9	)%	$	118		$	116		$	2		1.7	%
Proportional average realized electricity price per MWh	$	77		$	66		$	11		16.7	%	$	71		$	66		$	5		7.6	%

Our consolidated MWh sold for the three months ended September 30, 2018 was 1,799,378 MWh, as compared to 1,598,899 MWh for the three months ended September 30, 2017, an increase of 200,479 MWh, or 12.5%. Our consolidated MWh sold for the nine months ended September 30, 2018 was 6,407,788 MWh, as compared to 5,587,484 MWh for the nine months ended September 30, 2017, an increase of 820,304 MWh, or 14.7%. The increase in consolidated MWh sold was primarily due to volume increases as a result of acquisitions in 2017 and 2018, favorable wind and increased availability compared to 2017, and in the case of the nine months period, partially offset by curtailment at Santa Isabel.

Our proportional MWh sold for the three months ended September 30, 2018 was 1,622,991 MWh, as compared to 1,513,997 MWh for the three months ended September 30, 2017, an increase of 108,994 MWh, or 7.2%. The increase in proportional MWh sold was primarily attributable to:


•	79,418 MWh increase in controlling interest in consolidated MWh primarily due to our acquisitions in 2017 and 2018, favorable wind and increased availability compared to 2017; and


•	29,576 MWh increase from unconsolidated investments primarily due to less curtailment compared to 2017.

Our proportional MWh sold for the nine months ended September 30, 2018 was 6,021,515 MWh, as compared to 5,663,782 MWh for the nine months ended September 30, 2017, an increase of 357,733 MWh, or 6.3%. The increase in proportional MWh sold was primarily attributable to:


•	367,616 MWh increase in controlling interest in consolidated MWh primarily due to our acquisitions in 2017 and 2018, favorable wind and increased availability compared to 2017, partially offset by curtailment at Santa Isabel and curtailment and congestion in our Texas market; offset by


•	9,883 MWh decrease from unconsolidated investments primarily due to unfavorable winds compared to 2017.

Our consolidated average realized electricity price was $66 per MWh for the three months ended September 30, 2018, compared to $58 per MWh for the three months ended September 30, 2017 due to higher PPA prices associated with our Japan acquisition.

Our consolidated average realized electricity price was $59 per MWh for the nine months ended September 30, 2018, compared to $54 per MWh for the nine months ended September 30, 2017 due to acquisitions in 2017 and early 2018.

Our proportional average realized electricity price was $77 per MWh for the three months ended September 30, 2018, compared to $66 per MWh for the three months ended September 30, 2017 due to higher PPA prices associated with our Japan acquisition partially offset by a decrease in curtailment revenue.

Our proportional average realized electricity price was $71 per MWh for the nine months ended September 30, 2018 compared to $66 per MWh for the nine months ended September 30, 2017 due to higher PPA prices associated with our 2017 and 2018 acquisitions.

Results of Operations

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



	Three months ended September 30,											Nine months ended September 30,
	2018			2017			$ Change			% Change		2018			2017			$ Change			% Change
Revenue	$	118,393		$	92,030		$	26,363		28.6	%	$	369,992		$	300,623		$	69,369		23.1	%
Total cost of revenue	98,196			93,732			4,464			4.8	%	291,687			253,287			38,400			15.2	%
Total operating expenses	15,915			12,655			3,260			25.8	%	47,679			42,558			5,121			12.0	%
Total other expense	32,786			37,858			(5,072		)	(13.4	)%	62,330			59,822			2,508			4.2	%
Net loss before income tax	(28,504		)	(52,215		)	23,711			(45.4	)%	(31,704		)	(55,044		)	23,340			(42.4	)%
Tax provision (benefit)	3,043			(3,839		)	6,882			(179.3	)%	14,237			5,477			8,760			159.9	%
Net loss	(31,547		)	(48,376		)	16,829			(34.8	)%	(45,941		)	(60,521		)	14,580			(24.1	)%
Net loss attributable to noncontrolling interest	(18,952		)	(18,548		)	(404		)	2.2	%	(201,986		)	(50,566		)	(151,420		)	299.5	%
Net income (loss) attributable to Pattern Energy	$	(12,595	)	$	(29,828	)	$	17,233		(57.8	)%	$	156,045		$	(9,955	)	$	166,000		(1,667.5	)%

Total revenue

Total revenue for the three months ended September 30, 2018 was $118.4 million compared to $92.0 million for the three months ended September 30, 2017, an increase of $26.4 million, or approximately 28.6%. The increase was primarily attributable to:


•	$17.3 million increase in electricity sales primarily due to volume increases as a result of acquisitions in 2017 and 2018;


•	$10.2 million increase in electricity sales primarily due to higher production as a result of favorable wind conditions compared to 2017, increased availability and less curtailment; and


•	$2.8 million increase in electricity sales primarily due to unrealized losses on our energy derivative compared to 2017.

This increase in revenue was largely offset by:


•	$2.4 million decrease in electricity sales attributable to the sale of El Arrayán.

Total revenue for the nine months ended September 30, 2018 was $370.0 million compared to $300.6 million for the nine months ended September 30, 2017, an increase of $69.4 million, or approximately 23.1%. The increase was primarily attributable to:


•	$62.3 million increase in electricity sales due primarily to increases in volume as a result of acquisitions in 2017 and 2018;


•	$11.8 million increase in electricity sales due to increased wind and availability; and


•	$9.8 million increase in other revenue, primarily due to a $5.8 million settlement for business interruption insurance for Santa Isabel.

These increases were partially offset by:


•	$12.0 million decrease in electricity sales primarily due to curtailment at Santa Isabel and unrealized losses on our energy derivative compared to 2017.

Cost of revenue

Cost of revenue for the three months ended September 30, 2018 was $98.2 million compared to $93.7 million for the three months ended September 30, 2017, an increase of $4.5 million, or approximately 4.8%. The increase in cost of revenue is primarily attributable to increases of $3.3 million in project expense and $2.9 million in depreciation related to acquisitions completed in 2018 offset by a decrease of $1.7 million in transmission costs.

Cost of revenue for the nine months ended September 30, 2018 was $291.7 million compared to $253.3 million for the nine months ended September 30, 2017, an increase of $38.4 million, or approximately 15.2%. The increase in cost of revenue is primarily attributable to increases of $9.0 million in project expense, $8.3 million in transmission costs, and $21.1 million in depreciation related to acquisitions completed in 2017 and 2018.

Operating expenses

Operating expenses for the three months ended September 30, 2018 were $15.9 million compared to $12.7 million for the three months ended September 30, 2017, an increase of $3.3 million or 25.8%. The increase in operating expenses was primarily attributable to a $2.3 million impairment charge related to the Chilean Sale.

Operating expenses for the nine months ended September 30, 2018 were $47.7 million compared to $42.6 million for the nine months ended September 30, 2017, an increase of $5.1 million, or approximately 12.0%. The increase in operating expenses was primarily attributable to $6.6 million impairment expense related to the Chilean Sale offset by a $1.5 million decrease in general and administrative costs.

Other expense

Other expense for the three months ended September 30, 2018 was $32.8 million compared to $37.9 million for the three months ended September 30, 2017, a decrease of $5.1 million, or approximately 13.4%. The change was primarily attributable to a $7.8 million increase in gain on derivatives, net primarily due to gains from foreign currency hedges and interest rate swaps, partially offset by a $3.7 million increase in other income (expense), net due to loss recognized as a result of the sublease losses and increased contingent liability accretion.

Other expense for the nine months ended September 30, 2018 was $62.3 million compared to $59.8 million for the nine months ended September 30, 2017, an increase of $2.5 million, or approximately 4.2%. The change was primarily attributable to:


•	$14.3 million decrease in earnings in unconsolidated investments, net primarily due to a decrease in project income;


•	$6.1 million increase in interest expense primarily due to debt associated with our acquisitions in 2017 and 2018; and


•	$9.5 million increase in other income (expense), net due to loss recognized as a result of the sublease losses and increased contingent liability accretion.

The increase in other expense was partially offset by a $27.7 million increase in gain on derivatives, primarily due to gains from foreign currency hedges and interest rate swaps.

Tax provision (benefit)

Tax provision for the three months ended September 30, 2018 was $3.0 million compared to a tax benefit of $3.8 million for the three months ended September 30, 2017, an increase of $6.9 million, or approximately 179.3%. The recognition of a tax provision for the three months ended September 30, 2018, was mostly driven by the income generated by our Japan projects. Generally, the amount of tax expense or benefit allocated to continuing operations is determined without regard to the tax effects of other categories of income or loss, such as other comprehensive income (loss). However, an exception to the general rule is provided within the intraperiod tax allocation rules when there is a pre-tax loss from continuing operations and pre-tax income from other categories within the same period. This exception resulted in a tax benefit for the three months ended September 30, 2017.

The tax provision was $14.2 million for the nine months ended September 30, 2018 compared $5.5 million for the nine months ended September 30, 2017, a change of $8.8 million. The tax provision for the nine months ended September 30, 2018 increased primarily due to income generated by our U.S. and Japan projects.

Net loss

Net loss for the three months ended September 30, 2018 was $31.5 million compared to net loss of $48.4 million for the same period in the prior year; a decrease of $16.8 million, or 34.8%. The decrease in net loss was primarily attributable to:


•	$26.4 million increase in revenue primarily due to our 2018 acquisitions; and


•	$5.1 million decrease in other expense as discussed above.

The decrease in net loss was partially offset by;


•	$4.5 million increase in cost of revenue related to our 2017 and 2018 acquisitions;


•	$3.3 million increase in operating expenses primarily related to impairment expense related to the Chilean Sale; and


•	$6.9 million increase in tax provision.

Net loss for the nine months ended September 30, 2018 was $45.9 million compared to $60.5 million for the same period in the prior year; an increase of $14.6 million or 24.1%. The decrease in net loss was primarily attributable to:


•	$69.4 million increase in revenues primarily associated with our 2017 and 2018 acquisitions; and


•	$2.9 million decrease in general and administrative expenses.

The decrease in net loss was partially offset by:


•	$38.4 million increase in cost of revenue related to our 2017 and 2018 acquisitions;


•	$8.8 million increase in tax provision;


•	$6.6 million increase in impairment expense related to the Chilean Sale; and


•	$2.5 million increase in other expense primarily related to decreased earnings from unconsolidated investments.

Noncontrolling interest

The net loss attributable to noncontrolling interest was $19.0 million for the three months ended September 30, 2018 compared to $18.5 million for the three months ended September 30, 2017. The increased loss of $0.4 million was attributable to increased allocations of losses to tax equity projects.

The net loss attributable to noncontrolling interest was $202.0 million for the nine months ended September 30, 2018 compared to $50.6 million for the nine months ended September 30, 2017. The increased loss of $151.4 million was attributable to increased allocations of losses to tax equity projects. The Tax Act reduced the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. As a result, for the nine months ended September 30, 2018, included in net loss attributable to noncontrolling interest is a one-time adjustment of $150 million as a result of the decrease in the federal corporate income tax rate. See "Recent Developments - Noncontrolling Interests - Impact of the 2017 Tax Act.

Liquidity and Capital Resources

Our business requires substantial liquidity to fund (i) equity investments in our construction projects, (ii) current operational costs, (iii) debt service payments, (iv) dividends to our stockholders, (v) potential investments in new acquisitions, (vi) modifications to our projects, (vii) construction commitments, (viii) unforeseen events and (ix) 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.

Sources of Liquidity

Our sources of liquidity include cash generated by our operations, cash reserves, proceeds from asset sales, borrowings under our corporate and project-level credit agreements, construction financing arrangements and further issuances of equity and debt securities.

The principal indicators of our liquidity are our unrestricted and restricted cash balances and availability under our revolving credit facilities and project level facilities. Our available liquidity is as follows (in millions):



	September 30, 2018
Unrestricted cash	$	125.7
Restricted cash	20.2
Revolving credit facilities availability⁽¹⁾	220.2
Project facilities:
Post construction use	168.2
Construction facilities and loans	297.9
Total available liquidity	$	832.2


⁽¹⁾	As of November 1, 2018, the amount available on our revolving credit facilities is $213.4 million.

We expect that for the remainder of 2018, we will have sufficient liquid assets, cash flows from operations, and borrowings available under our revolving credit facilities and construction facilities to meet our financial commitments, debt service obligations, dividend payments, contingencies and anticipated required capital expenditures for at least the next 24 months, not including capital required for additional project acquisitions or capital call on Pattern Development 2.0. 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, or capital call on Pattern Development 2.0 we elect to participate in, we may, from time to time, engage in asset recycling, or issue debt or equity securities. Our ability to access the debt and equity markets is dependent on, among other factors, the overall state of the debt and equity markets and investor appetite for investment in clean energy projects in general and our Class A shares in particular. Volatility in the market price of our Class A shares may prevent or limit our ability to utilize our equity securities as a source of capital to help fund acquisitions. An inability to obtain debt or equity financing on commercially reasonable terms could significantly limit our timing and ability to consummate future acquisitions, and to effectuate our growth strategy.

We have an equity distribution agreement (Equity Distribution Agreement). Pursuant to the terms of the Equity Distribution Agreement, we may offer and sell shares of our Class A common stock, par value $0.01 per share, from time to time, up to an aggregate sales price of $200 million. We intend to use the net proceeds from the sale of the shares for general corporate purposes, which may include the repayment of indebtedness and the funding of acquisitions and investments. For the nine months ended September 30, 2018, we did not sell any shares under the Equity Distribution Agreement. As of September 30, 2018, approximately $144.2 million in aggregate offering price remained available to be sold under the agreement.

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



	Nine months ended September 30,
	2018			2017
Net cash provided by operating activities	$	230.5		$	159.3
Net cash used in investing activities	(343.6		)	(314.8		)
Net cash provided by financing activities	124.1			160.2
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(3.0		)	4.0
Net change in cash, cash equivalents and restricted cash	$	7.9		$	8.7

Net cash provided by operating activities

Net cash provided by operating activities was $230.5 million for the nine months ended September 30, 2018 as compared to $159.3 million in the prior year, an increase of $71.1 million, or approximately 44.6%. The increase in cash provided by operating activities was primarily due to a $77.9 million increase in revenue (excluding unrealized loss on energy derivatives and amortization in electricity sales), and $33.8 million advanced lease revenue. The increase to net cash provided by operating activities was partially offset by $8.3 million in increased transmission costs primarily due to acquisition in 2017, $9.0 million increase in project expenses related to projects acquired in 2018, increased interest payments of $9.2 million and increased payments of $17.7 million in payables, current and accrued liabilities due primarily to the timing of payments.

Net cash used in investing activities

Net cash used in investing activities was $343.6 million for the nine months ended September 30, 2018, which consisted primarily of $188.5 million in cash paid, net of cash and restricted cash acquired, for the Japan and MSM acquisitions, $128.6 million primarily for construction costs related to projects acquired in the Japan Acquisition, and an additional investment of $86.3 million in Pattern Development 2.0, offset by $55.8 million in proceeds from the Chilean Sale, net of cash sold and $4.8 million in distributions from unconsolidated investments.

Net cash used in investing activities was $314.8 million for the nine months ended September 30, 2017, which consisted primarily of $289.3 million in cash paid, net of cash and restricted cash acquired for the acquisitions completed in 2017 and $44.3 million for capital expenditures, offset by $11.2 million in distributions received from unconsolidated investments, and $7.6 million in reimbursements of interconnection costs.

Net cash provided by financing activities

Net cash provided by financing activities for the nine months ended September 30, 2018 was $124.1 million. Net cash provided by financing activities consisted primarily of the following:


•	$653.6 million in proceeds from other long-term debt and the revolving credit facilities.

Net cash provided by financing activities was partially offset by:


•	$370.2 million in repayments of debt and the revolving credit facilities;


•	$123.6 million of dividend payments;


•	$7.5 million in payments for deferred financing costs primarily associated with the issuance of debt associated with Tsugaru Holdings as described above; and


•	$28.9 million in distributions to noncontrolling interests.

Net cash provided by financing activities for the nine months ended September 30, 2017 was $160.2 million. Net cash provided by financing activities consisted primarily of the following:


•	$350.0 million in proceeds from the issuance of the unsecured senior notes due 2024;


•	$377.4 million in proceeds from other long-term debt and the revolving credit facilities; and


•	$22.4 million in proceeds from the issuances under our at-the-market equity program.

Net cash provided by financing activities were partially offset by:


•	$250.0 million in repayment of the revolving credit facilities;


•	$107.9 million of dividend payments;


•	$192.1 million in repayments of long-term debt;


•	$7.7 million in payments for deferred financing costs associated with the issuance of the unsecured senior notes due 2024;


•	$14.4 million in payments for the termination of interest rate swaps at Lost Creek; and


•	$13.7 million in distributions to noncontrolling interests.

Uses of Liquidity

Cash Dividends to Investors

We intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A common stock. On October 30, 2018, we declared an unchanged dividend of $0.4220 per share, or $1.688 per share on an annualized basis, to be paid on January 31, 2019 to holders of record on December 31, 2018. 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
2018:
Fourth Quarter	$	0.4220	October 30, 2018	December 31, 2018	January 31, 2019
Third Quarter	$	0.4220	August 2, 2018	September 28, 2018	October 31, 2018
Second Quarter	$	0.4220	May 3, 2018	June 29, 2018	July 31, 2018
First Quarter	$	0.4220	February 22, 2018	March 30, 2018	April 30, 2018

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

We expect to make investments in additional projects in 2018, provide further capital to Pattern Development 2.0, fund the construction costs at Tsugaru and, in 2019, we expect to provide further capital for the Gulf Wind re-powering. On August 10, 2018, we acquired MSM for cash consideration of $39.3 million. On March 7, 2018, we completed the Japan Acquisition which included cash consideration of $176.6 million and post-closing contingent payments with an acquisition date fair value of approximately $105.9 million. During the nine months ended September 30, 2018, we have funded $86.3 million into Pattern Development 2.0, and on October 5, 2018, we funded an additional $29.2 million.

We also evaluate, from time to time, third-party acquisition opportunities. We believe that we will have sufficient cash and capacity from our revolving credit facilities to complete the funding of future commitments, but this may be affected by any other acquisitions or investments that we make. To the extent that we make any such investments or acquisitions, we will evaluate capital markets and other corporate financing sources available to us at the time. In addition, we will make investments, from time to time, at our operating projects. Operational capital expenditures are those capital expenditures required to maintain our long-term operating capacity. Capital expenditures for the projects are generally made at the project level using project cash flows and project reserves, although funding for major capital expenditures may be provided by additional project debt or equity. Therefore, the distributions that we receive from the projects may be made net of certain capital expenditures needed at the projects. For the year ending December 31, 2018, we have budgeted $2.3 million for operational capital expenditures and $17.3 million for expansion capital expenditures.

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. See also Note 10, Debt, and Note 17, Commitments and Contingencies, in the notes to consolidated financial statements for additional discussion of contractual obligations.

As part of our acquisitions completed through the third quarter of 2018, we became party to various agreements and future commitments. The following table summarizes estimates of future commitments related to the various agreements entered into as part of those acquisitions (in thousands) as of September 30, 2018:



Contractual Obligations	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Project-level debt principal payments	$	2,449	$	27,200	$	152,313	$	316,397	$	498,359
Project-level interest payments on debt instruments	2,926		26,046		24,365		92,086		145,423
Other⁽¹⁾	27,696		180,073		—		—		207,769
Operating leases	905		7,504		6,656		60,300		75,365
Service and maintenance agreements	1,112		10,563		12,268		43,856		67,799
Asset retirement obligations	—		—		—		49,338		49,338
Total	$	35,088	$	251,386	$	195,602	$	561,977	$	1,044,053


⁽¹⁾	Other commitments consist of acquired construction commitments related to MSM, and the development of Tsugaru which is expected to commence commercial operations in early to mid-2020.

Operating Leases

In March 2018, we entered into an operating lease for our new corporate headquarters in San Francisco, California. Total operating lease payments are approximately $35 million over the term of the lease which expires in December 2028.

Gulf Wind Re-Powering Commitment

Off-Balance Sheet Arrangements

As of September 30, 2018, we did not have any significant off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K.

Credit Agreements for Unconsolidated Investments

Below is a summary of our proportion of debt in unconsolidated investments, as of September 30, 2018 (in thousands):



	Total Project Debt		Percentage of Ownership		Our Portion of Unconsolidated Project Debt
Armow	$	380,081	50.0	%	$	190,041
South Kent	458,269		50.0	%	229,135
Grand	263,097		45.0	%	118,394
K2	559,941		33.3	%	186,628
Pattern Development 2.0	182,229		29.3	%	53,328
Unconsolidated investments - debt	$	1,843,617			$	777,526

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, 2017.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

We manage our commodity price risk for electricity sales primarily through the use of fixed price long-term power purchase agreements with creditworthy counterparties. Our financial results reflect approximately 468,675 MWh of electricity sales during the nine months ended September 30, 2018 that were subject to spot market pricing. A hypothetical increase or decrease of 10% or $2.30 per MWh in the merchant market prices would have increased or decreased revenue by $1.1 million for the nine months ended September 30, 2018.

In addition to the risks we face in broad commodity markets, many of our projects, especially in ERCOT, also face project-specific risks related to transmission system limitations which can result in local prices that are lower than the broader market prices (congestion). In the case of adverse congestion, our revenues are negatively impacted, and our PSAs do not protect us from these impacts, since under those contracts, this risk is fully allocated to our projects and not to the counterparty (e.g. we sell our power at the lower local price, but still have to buy power for the counterparty at the higher broad market or hub price). In the past, these impacts have been material to our economic results, and we expect that congestion will continue to be a material risk in the future.

Interest Rate Risk

As of September 30, 2018, our long-term debt includes both fixed and variable rate debt. As long-term debt is not carried at fair value on the consolidated balance sheets, changes in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments prior to their maturity. The fair market value of our outstanding convertible senior notes, or "debentures," is subject to interest rate risk, market price risk and other factors due to the convertible feature of the debentures. The fair market value of the debentures will generally increase as interest rates fall and decrease as interest rates rise. In addition, the fair market value of the debentures will generally increase as the market price of our Class A common stock increases and decrease as the market price of our Class A common stock falls. The interest and market value changes affect the fair market value of the debentures, but do not impact our financial position, cash flows or results of operations due to the fixed nature of the debt obligations, except to the extent that changes in the fair value of the debentures or value of Class A common stock permit the holders of the debentures to convert into shares. As of September 30, 2018, the estimated fair value of our debt was $2.3 billion and the carrying value of our debt was $2.4 billion. The fair value of variable interest rate long-term debt is approximated by its carrying cost. A hypothetical increase or decrease in market interest rates by 1% would have resulted in a $48.7 million decrease or $53.3 million increase in the fair value of our fixed rate debt.

We are exposed to fluctuations in interest rate risk as a result of our variable rate debt and outstanding amounts due under our Corporate Revolving Credit Facility and Japan Credit Facility. As of September 30, 2018, $210.1 million was outstanding under the Corporate Revolving Credit Facility and Japan Credit Facility. A hypothetical increase or decrease in interest rates by 1% would have a $2.1 million impact to interest expense for the nine months ended September 30, 2018.

We may use a variety of derivative instruments, with respect to our variable rate debt, to manage our exposure to fluctuations in interest rates, including interest rate swaps. As a result, our interest rate risk is limited to the unhedged portion of the variable rate debt. As of September 30, 2018, the unhedged portion of our variable rate debt was $215.9 million. A hypothetical increase or decrease in interest rates by 1% would have a $2.2 million impact to interest expense for the nine months ended September 30, 2018.

Foreign Currency Exchange Rate Risk

Our power projects are located in the United States, Canada, and Japan. 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 and Japanese Yen. For the nine months ended September 30, 2018, our financial results included C$33.0 million and ¥278.6 million of net income from our Canadian and Japanese operations, respectively. A hypothetical 10% weakening or strengthening of U.S. dollar would have increased or decreased net earnings of our Canadian and Japanese operations by $2.8 million for the nine months ended September 30, 2018.

We have established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in our cash flow, which may have an adverse impact to our short-term liquidity or financial condition. For the nine months ended September 30, 2018, we recognized a gain on foreign currency forward contracts of $12.2 million in gain (loss) on derivatives in the consolidated statements of operations.

As of September 30, 2018, a 10% devaluation in the Canadian dollar and Japanese Yen to the United States dollar would result in our consolidated balance sheets being negatively impacted by a $50.7 million cumulative translation adjustment in accumulated other comprehensive loss.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (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 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, 2018.

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject, from time to time, to routine legal proceedings and claims arising out of the normal course of business. While the outcome of these legal proceedings and claims cannot be predicted with certainty, we believe the outcome of any of such currently existing proceedings, even if determined adversely, would not have a material adverse effect on our financial condition or results of operations.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors described under the caption “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2017 and Quarterly Report on Form 10-Q for the period ended June 30, 2018.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The table below provides information with respect to repurchases of our Class A common stock during the third quarter ended September 30, 2018. All shares were tendered to us in satisfaction of tax withholding obligations upon the vesting of certain director restricted stock grants under our 2013 Equity Incentive Award Plan. We currently do not have a stock repurchase plan in place.



Period⁽¹⁾⁽²⁾	Total Number of Shares Purchased	Average Price Paid Per Share
July 1, 2018 through July 31, 2018	—	$	—
August 1, 2018 through August 31, 2018	—	$	—
September 1, 2018 through September 30, 2018	437	$	20.45


⁽¹⁾	In addition, 437 shares were tendered to us on each of March 20, 2018 and June 30, 2018 in satisfaction of tax withholding obligations upon the vesting of certain director restricted stock grants under our 2013 Equity Incentive Award Plan at an average price per share of $18.30 and $19.47, respectively. Such withholdings were reported in relevant Form 4s filed concurrently with such vesting.


⁽²⁾	In addition, an aggregate of 19,660 shares were tendered to us on March 15, 2018 in satisfaction of employee tax withholding obligations upon the vesting of certain performance awards issued in 2015 under our 2013 Equity Incentive Award Plan at an average price per share of $18.55. Such withholdings were reported in relevant Form 4s filed concurrently with such vesting.

ITEM 6. EXHIBITS



Exhibit No.		Description

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

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

4.2		Indenture, dated July 28, 2015, among the Company, 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).

4.3		Indenture, dated as of January 25, 2017, among the Company, Pattern US Finance Company LLC, as guarantor, and Deutsche Bank Trust Company Americas, as trustee, related to 5.875% Senior Notes due 2024 (Incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K dated January 20, 2017).

10.1		Purchase and Sale Agreement by and between the Company and Pattern Energy Group LP dated as of February 26, 2018 related to indirect interests in Green Power Tsugaru GK (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated February 27, 2018).

10.2		Purchase and Sale Agreement by and between the Company and Green Power Investment Corporation dated as of February 26, 2018 related to indirect interests in Green Power Tsugaru GK (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K dated February 27, 2018).

10.3		Purchase and Sale Agreement by and between the Company and Pattern Energy Group LP dated as of February 26, 2018 related to indirect interests in GK Green Power Kanagi, GK Green Power Otsuki and GK Green Power Futtsu (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K dated February 27, 2018).

10.4		Purchase and Sale Agreement by and between the Company and Green Power Investment Corporation dated as of February 26, 2018 related to indirect interests in GK Green Power Kanagi, GK Green Power Otsuki and Otsuki Wind Power Corporation (Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K dated February 27, 2018).

10.5		Deferred Payment Agreement by and between the Company and Pattern Energy Group LP dated as of February 26, 2018 (Incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K dated February 27, 2018).

10.6		Form of Restricted Stock Agreement under 2013 Equity Incentive Award Plan (Incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2018).

10.7		Form of TSR Performance Restricted Stock Agreement under 2013 Equity Incentive Award Plan (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2018).

10.8		Consent and Waiver Agreement dated as of May 21, 2018 entered into by Public Sector Pension Investment Board and the Company related to the Conejo Solar project (Incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated May 25, 2018).

10.9		Waiver Agreement dated as of May 21, 2018 entered into by Pattern Energy Group LP and the Company related to the Conejo Solar project (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 25, 2018).

10.10		Unanimous Shareholder Agreement of Pattern MSM GP Holdings Inc. among Pattern Canada Finance Company ULC, Vertuous Energy Canada Inc. and Pattern MSM GP Holdings Inc., dated as of August 10, 2018 (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated August 10, 2018).

10.11		Amended and Restated Limited Partnership Agreement of MSM LP Holdings LP among Pattern Canada Finance Company ULC, Vertuous Energy Canada Inc. and Pattern MSM GP Holdings Inc., dated as of August 10, 2018 (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K dated August 10, 2018).



10.12		Shareholders Agreement of Pattern Development MSM Management ULC among Pattern Canada Finance Company ULC, Vertuous Energy Canada Inc. and Pattern Development MSM Management ULC, dated as of August 10, 2018 (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K dated August 10, 2018).

10.13		Amendment No. 2018-2 to Members' Agreement (Futtsu) dated as of August 14, 2018 by and between Green Power Generation GK and Green Power Investment Corporation (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated August 14, 2018).

10.14		Memorandum of Understanding dated as of August 16, 2018 entered into by Pattern Gulf Wind Holdings LLC and Pattern Western Development LLC (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated August 28, 2018).

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

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

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

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document



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

SIGNATURE

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



			Pattern Energy Group Inc.

Dated:	November 5, 2018	By:	/s/ Michael J. Lyon
			Michael J. Lyon
			Chief Financial Officer

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

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