Quarterly Report (10-q)

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, 2017 .



☐	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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ 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 6, 2017 there were 97,906,077 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, 2017

TABLE OF CONTENTS



	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	5

	Consolidated Balance Sheets as of September 30, 2017 (unaudited) and December 31, 2016	5
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016 (unaudited)	6
	Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2017 and 2016 (unaudited)	7
	Consolidated Statements of Stockholders’ Equity for the Nine Months Ended September 30, 2017 and 2016 (unaudited)	8
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016 (unaudited)	9
	Notes to Consolidated Financial Statements (unaudited)	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	55
Item 4.	Controls and Procedures	57

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	58
Item 1A.	Risk Factors	58
Item 6.	Exhibits	61
	Signatures	63

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 and other conditions, other weather conditions, availability and curtailment;


•	changes in law, including applicable tax laws;


•	public response to and changes in the local, state, provincial and federal regulatory framework affecting renewable energy projects, including the U.S. federal production tax credit (PTC), investment tax credit (ITC) and potential reductions in Renewable Portfolio Standards (RPS) requirements;


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


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


•	an increase in interest rates;


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


•	competition from other power project developers;


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


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


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


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


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


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


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


•	the effectiveness of our currency risk management program;


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


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


•	scarcity of necessary equipment;


•	negative public or community response to wind power projects;


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


•	other factors discussed under “Risk Factors.”

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, 2016 .

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,
	2017			2016
Assets
Current assets:
Cash and cash equivalents (Note 6)	$	91,057		$	83,932
Restricted cash (Note 6)	7,150			11,793
Funds deposited by counterparty	33,530			43,635
Trade receivables (Note 6)	48,960			37,510
Derivative assets, current	18,824			17,578
Prepaid expenses (Note 6)	18,405			13,803
Deferred financing costs, current, net of accumulated amortization of $11,360 and $9,350 as of September 30, 2017 and December 31, 2016, respectively	2,514			2,456
Other current assets (Note 6)	19,058			7,350
Total current assets	239,498			218,057
Restricted cash (Note 6)	19,866			13,646
Property, plant and equipment, net (Note 6)	4,023,355			3,135,162
Unconsolidated investments	303,833			233,294
Derivative assets	14,865			26,712
Deferred financing costs	4,339			4,052
Net deferred tax assets	6,107			5,559
Finite-lived intangible assets, net (Note 6)	138,516			91,895
Other assets (Note 6)	22,649			24,390
Total assets	$	4,773,028		$	3,752,767
Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities (Note 6)	$	53,200		$	31,305
Accrued construction costs (Note 6)	2,765			1,098
Counterparty deposit liability	33,530			43,635
Accrued interest (Note 6)	7,043			9,545
Dividends payable	37,645			35,960
Derivative liabilities, current	12,095			11,918
Revolving credit facility	253,000			180,000
Current portion of long-term debt, net	58,213			48,716
Other current liabilities (Note 6)	13,133			4,698
Total current liabilities	470,624			366,875
Long-term debt, net	1,871,607			1,334,956
Derivative liabilities	21,979			24,521
Net deferred tax liabilities	50,573			31,759
Finite-lived intangible liability, net	52,062			54,663
Contingent liabilities	58,820			576
Other long-term liabilities (Note 6)	98,519			60,673
Total liabilities	2,624,184			1,874,023
Commitments and contingencies (Note 15)
Equity:
Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 88,569,377 and 87,410,687 shares outstanding as of September 30, 2017 and December 31, 2016, respectively	886			875
Additional paid-in capital	1,062,252			1,145,760
Accumulated loss	(104,225		)	(94,270		)
Accumulated other comprehensive loss	(24,821		)	(62,367		)
Treasury stock, at cost; 115,146 and 110,964 shares of Class A common stock as of September 30, 2017 and December 31, 2016, respectively	(2,597		)	(2,500		)
Total equity before noncontrolling interest	931,495			987,498
Noncontrolling interest	1,217,349			891,246
Total equity	2,148,844			1,878,744
Total liabilities and equity	$	4,773,028		$	3,752,767

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,
	2017			2016			2017			2016
Revenue:
Electricity sales	$	89,807		$	89,919		$	293,977		$	266,952
Other revenue	2,223			1,995			6,646			6,039
Total revenue	92,030			91,914			300,623			272,991
Cost of revenue:
Project expense	33,932			31,271			96,437			96,711
Transmission costs	7,421			113			12,213			278
Depreciation and accretion	52,379			43,693			144,637			130,782
Total cost of revenue	93,732			75,077			253,287			227,771
Gross profit (loss)	(1,702		)	16,837			47,336			45,220
Operating expenses:
General and administrative (Note 16)	9,068			9,598			31,969			27,425
Related party general and administrative	3,587			3,553			10,589			7,381
Total operating expenses	12,655			13,151			42,558			34,806
Operating income (loss)	(14,357		)	3,686			4,778			10,414
Other income (expense):
Interest expense	(27,147		)	(19,798		)	(74,541		)	(62,134		)
Gain (loss) on undesignated derivatives, net	(4,081		)	1,825			(9,480		)	(17,685		)
Realized loss on designated derivatives	(2,207		)	—			(2,207		)	—
Earnings (loss) in unconsolidated investments, net	(3,964		)	4,685			27,431			15,755
Net loss on transactions	(466		)	(314		)	(1,585		)	(353		)
Other income, net	7			177			560			2,297
Total other expense	(37,858		)	(13,425		)	(59,822		)	(62,120		)
Net loss before income tax	(52,215		)	(9,739		)	(55,044		)	(51,706		)
Tax (benefit) provision	(3,839		)	1,311			5,477			4,038
Net loss	(48,376		)	(11,050		)	(60,521		)	(55,744		)
Net loss attributable to noncontrolling interest	(18,548		)	(7,037		)	(50,566		)	(24,838		)
Net loss attributable to Pattern Energy	$	(29,828	)	$	(4,013	)	$	(9,955	)	$	(30,906	)

Weighted-average number of common shares outstanding
Basic and diluted	87,370,979			81,531,775			87,146,465			76,821,811
Loss per share attributable to Pattern Energy
Basic and diluted	$	(0.34	)	$	(0.05	)	$	(0.12	)	$	(0.40	)
Dividends declared per Class A common share	$	0.42		$	0.40		$	1.25		$	1.17

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,
	2017			2016			2017			2016
Net loss	$	(48,376	)	$	(11,050	)	$	(60,521	)	$	(55,744	)
Other comprehensive loss:
Foreign currency translation, net of tax provision of $3,656, zero, $3,656 and zero, respectively	8,230			(1,768		)	17,979			9,874
Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax (provision) benefit of ($1,285), $198, ($1,344) and $4,300, respectively	1,920			(329		)	(2,498		)	(30,990		)
Reclassifications to net loss due to termination of interest rate swaps, net of zero tax impact	2,207			—			2,207			—
Other reclassifications to net loss, net of tax impact of $351, $284, $838 and $867, respectively	2,540			2,736			7,023			8,359
Total change in effective portion of change in fair market value of derivatives	6,667			2,407			6,732			(22,631		)
Proportionate share of equity investee’s derivative activity:
Effective portion of change in fair market value of derivatives, net of tax (provision) benefit of ($2,075), $244, ($2,360) and $4,213, respectively	5,756			(676		)	6,546			(11,684		)
Reclassifications to net loss, net of tax impact of $672, $70, $2,333 and $992, respectively	1,863			195			6,471			2,752
Total change in effective portion of change in fair market value of derivatives	7,619			(481		)	13,017			(8,932		)
Total other comprehensive income (loss), net of tax	22,516			158			37,728			(21,689		)
Comprehensive loss	(25,860		)	(10,892		)	(22,793		)	(77,433		)
Less comprehensive loss attributable to noncontrolling interest:
Net loss attributable to noncontrolling interest	(18,548		)	(7,037		)	(50,566		)	(24,838		)
Foreign currency translation, net of zero tax impact	(718		)	—			(718		)	—
Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax (provision) benefit of ($267), ($35), ($166) and $472, respectively	763			164			489			(1,206		)
Reclassifications to net loss, net of tax impact of $86, $39, $148 and $126, respectively	244			106			411			341
Total change in effective portion of change in fair market value of derivatives	1,007			270			900			(865		)
Comprehensive loss attributable to noncontrolling interest	(18,259		)	(6,767		)	(50,384		)	(25,703		)
Comprehensive (loss) income attributable to Pattern Energy	$	(7,601	)	$	(4,125	)	$	27,591		$	(51,730	)

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 Loss			Accumulated Other Comprehensive Loss			Total			Noncontrolling Interest				Total Equity
	Shares	Amount		Shares		Amount			Additional Paid-in Capital			Accumulated Loss			Accumulated Other Comprehensive Loss			Total			Noncontrolling Interest				Total Equity
Balances at December 31, 2015	74,709,442	$	747	(65,301	)	$	(1,577	)	$	982,814		$	(77,159	)	$	(73,325	)	$	831,500		$	944,262			$	1,775,762
Issuance of Class A common stock, net of issuance costs	12,540,504	125		—		—			286,115			—			—			286,240			—				286,240
Issuance of Class A common stock under equity incentive award plan	287,904	3		—		—			(3		)	—			—			—			—				—
Repurchase of shares for employee tax withholding	—	—		(3,043	)	(64		)	—			—			—			(64		)	—				(64		)
Stock-based compensation	—	—		—		—			4,362			—			—			4,362			—				4,362
Dividends declared	—	—		—		—			(92,818		)	—			—			(92,818		)	—				(92,818		)
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(11,771		)		(11,771		)
Other	—	—		—		—			42			—			—			42			(103		)		(61		)
Net loss	—	—		—		—			—			(30,906		)	—			(30,906		)	(24,838		)		(55,744		)
Other comprehensive loss, net of tax	—	—		—		—			—			—			(20,824		)	(20,824		)	(865		)		(21,689		)
Balances at September 30, 2016	87,537,850	$	875	(68,344	)	$	(1,641	)	$	1,180,512		$	(108,065	)	$	(94,149	)	$	977,532		$	906,685			$	1,884,217

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	—	—		—		—			(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

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,
	2017			2016
Operating activities
Net loss	$	(60,521	)	$	(55,744	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and accretion	144,637			130,782
Amortization of financing costs	5,879			5,242
Amortization of debt discount/premium, net	3,379			3,147
Amortization of power purchase agreements, net	2,435			2,278
Loss on derivatives, net	15,662			29,757
Realized loss on derivatives, net	2,207			—
Stock-based compensation	4,085			4,362
Deferred taxes	9,133			3,681
Intraperiod tax allocation	(3,656		)	—
Earnings in unconsolidated investments, net	(27,431		)	(15,755		)
Distributions from unconsolidated investments	43,093			377
Other reconciling items	(2,047		)	44
Changes in operating assets and liabilities:
Funds deposited by counterparty	10,105			(46,643		)
Trade receivables	(2,861		)	6,078
Prepaid expenses	(3,187		)	(1,005		)
Other current assets	(9,790		)	(3,709		)
Other assets (non-current)	2,457			865
Accounts payable and other accrued liabilities	16,389			(2,658		)
Counterparty deposit liability	(10,105		)	46,643
Accrued interest	(3,884		)	(6,017		)
Other current liabilities	8,040			811
Long-term liabilities	14,569			4,952
Contingent liabilities	742			(117		)
Net cash provided by operating activities	159,330			107,371
Investing activities
Cash paid for acquisitions, net of cash and restricted cash acquired	(289,329		)	(4,024		)
Capital expenditures	(44,295		)	(31,554		)
Distributions from unconsolidated investments	11,211			40,066
Other assets	7,607			1,619
Other investing activities	—			(136		)
Net cash provided by (used in) investing activities	(314,806		)	5,971

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

	Nine months ended September 30,
	2017			2016
Financing activities
Proceeds from public offering, net of issuance costs	$	22,431		$	286,583
Dividends paid	(107,943		)	(85,159		)
Capital distributions - noncontrolling interest	(13,701		)	(11,771		)
Payment for deferred financing costs	(7,763		)	(134		)
Proceeds from revolving credit facility	323,000			20,000
Repayment of revolving credit facility	(250,000		)	(340,000		)
Proceeds from debt	404,395			—
Repayment of debt	(192,109		)	(39,322		)
Payment for interest rate swaps	(14,372		)	—
Other financing activities	(3,712		)	(634		)
Net cash provided by (used in) financing activities	160,226			(170,437		)
Effect of exchange rate changes on cash, cash equivalents and restricted cash	3,952			1,750
Net change in cash, cash equivalents and restricted cash	8,702			(55,345		)
Cash, cash equivalents and restricted cash at beginning of period	109,371			146,292
Cash, cash equivalents and restricted cash at end of period	$	118,073		$	90,947
Supplemental disclosures
Cash payments for income taxes	$	335		$	233
Cash payments for interest expense	$	70,100		$	59,172
Schedule of non-cash activities
Change in property, plant and equipment	$	619		$	6,132

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 located in the United States, Canada and Chile. Pattern Energy Group LP (Pattern Development 1.0) owns a 9% interest in the Company. 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 and assets contributed by, or 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 projects and certain assets are consolidated into the Company's subsidiaries which are organized by geographic location 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), as well as the following consolidated controlling interest 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 Farm Fowler Ridge), and Broadview Project Finco Pledgor (Broadview Project) (which consists primarily of Broadview Energy KW, LLC and Broadview Energy JN, LLC (together, Broadview) and Western Interconnect 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 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) which are accounted for as unconsolidated investments); and


•	Pattern Chile Holdings LLC (which includes a controlling interest in Parque Eólico El Arrayán SpA (El Arrayán) and a controlling interest in Don Goyo Transmisi ó n S.A. (Don Goyo), a transmission asset of El Arrayán).

On July 27, 2017, the Company funded an initial $60 million capital call under the Second Amended and Restated Agreement of Limited Partnership of Pattern Energy Group Holdings 2 LP (PEGH 2), dated as of June 16, 2017, by and among PEGH 2, the Class A Limited Partners set forth therein and the Class B Limited Partners set forth therein. As a result of such funding, and the related funding by other investors in PEGH 2 and consummation of certain redemptions, the Company holds an approximate 20% ownership interest in PEGH 2 representing the Company's 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 presentation of the Company’s financial position at September 30, 2017 , the results of operations and comprehensive income (loss) for the three and nine months ended September 30, 2017 and 2016 , respectively, and the cash flows for the nine months ended September 30, 2017 and 2016 , respectively. The consolidated balance sheet at December 31, 2016 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, 2016 .

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.

The Company adopted the provisions of Accounting Standards Update (ASU) 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash as of December 31, 2016 and has revised its consolidated statements of cash flows for the nine months ended September 30, 2016 to reflect amounts described as restricted cash and restricted cash equivalents included with cash and cash equivalents in the reconciliation of beginning of period and end of period total amounts shown on the consolidated statements of cash flows.

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

Restricted cash consists of cash balances which are restricted as to withdrawal or usage and includes cash to collateralize bank letters of credit related primarily to interconnection rights, power sale agreements (PSA) and for certain reserves required under the Company's loan agreements. 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, 2017		December 31, 2016		September 30, 2016		December 31, 2015
Cash and cash equivalents	$	91,057	$	83,932	$	65,733	$	94,808
Restricted cash - current	7,150		11,793		11,562		14,609
Restricted cash	19,866		13,646		13,652		36,875
Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	118,073	$	109,371	$	90,947	$	146,292

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, 2016 .

In September 2017, the Financial Accounting Standards Board (FASB) issued ASU 2017-13, Revenue Recognition (Topic 605), Revenue from Contracts with Customers (Topic 606), Leases (Topic 840), and Leases (Topic 842): Amendments to SEC Paragraphs Pursuant to the Staff Announcement at the July 20, 2017 EITF Meeting and Rescission of Prior SEC Staff Announcements and Observer Comment s (ASU 2017-13), which amends the early adoption date option for certain companies related to the adoption of ASU 2014-09 and ASU 2016-02. The SEC staff stated the SEC would not object to a public business entity that otherwise would not meet the definition of a public business entity except for a requirement to include or the inclusion of its financial statements or financial information in another entity’s filing with the SEC adopting Topic 606 and Topic 842 using the adoption dates available for non-public entities. The Company does not expect the adoption of this update to have a material impact on its consolidated financial statements and related disclosures; however, certain of the Company's unconsolidated investments, for which the Company may be required to include in its Form 10-K, may elect to utilize the adoption date available for non-public entities.

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 January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business (ASU 2017-01), which provides a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those periods, with early application permitted. The Company adopted ASU 2017-01 on July 1, 2017. The adoption of ASU 2017-01 resulted in the acquisition of Meikle being accounted for as an asset acquisition.

In February 2016, the FASB issued ASU 2016-02, Leases (ASU 2016-02), which requires lessees to recognize right-of-use assets and lease liabilities, for all leases, with the exception of short-term leases, at the commencement date of each lease. Under the new guidance, lessor accounting is largely unchanged. ASU 2016-02 simplifies the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and liabilities. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. Early adoption is permitted. The Company does not plan to early adopt, and accordingly, will adopt the new standard effective January 1, 2019. The amendments of this update should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. The Company is in the initial stages of evaluating the impact of the new standard on its accounting policies, processes and system requirements. The Company has assigned internal resources in addition to the engagement of a third party service provider to assist in evaluation. The Company is also assessing the accounting impact of the ASU 2016-02 as it applies to its PPAs, land leases, office leases and equipment leases. As the Company progresses further in its analysis, the scope of this assessment could be expanded to review other types of contracts.

In May 2014, the FASB issued a new standard, ASU 2014-09, which creates Accounting Standards Codification (ASC) Topic 606 , Revenue from Contracts with Customers and supersedes ASC Topic 605, Revenue Recognition (ASU 2014-09). The new standard replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the new standard is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the new standard requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606) Principal versus Agent Considerations (Reporting Revenue Gross versus Net ), which clarifies how to apply the implementation guidance on principal versus agent considerations related to the sale of goods or services to a customer as updated by ASU 2014-09. In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers ( Topic 606 ) Identifying Performance Obligations and Licensing, which clarifies two aspects of Topic 606: identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas, as updated by ASU 2014-09. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients , which makes narrow scope amendments to Topic 606 including implementation issues on collectability, non-cash consideration and completed contracts at transition. In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers , which make additional narrow scope amendments to Topic 606 including loan guarantee fees, impairment testing of contract costs, provisions for losses on construction-type and production-type contracts.

The new standard permits adoption by either using (i) the full retrospective approach for all periods presented in the period of adoption or (ii) a modified retrospective approach with the cumulative effect of initially applying the new standard recognized at the date of initial application and providing certain additional disclosures. The Company plans to adopt using the modified retrospective approach. The new standard is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted for annual reporting periods beginning after December 15, 2016. The Company will adopt the new standard effective January 1, 2018.

The Company has reached preliminary conclusions on key accounting assessments related to the standard. Based on the Company’s assessment and review of the revenue transactions with its customers, the Company does not expect the adoption to have a material impact on its consolidated financial statements. The Company expects that the revenue recognition related to sales of electricity

and renewable energy credits to remain substantially unchanged. The Company will continue to monitor and assess the impact of any changes to the standard and interpretations as they become available.

3. Acquisitions

Business Combination

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 growth strategy to expand its portfolio of generating projects. The Company's indirect Class B membership interest in Broadview Holdings represents an 84% interest in initial 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 on the identified ROFO list being developed by Pattern Development 2.0 separately from Broadview, which is expected to begin full construction not earlier than 2018, and which will be interconnected through Western Interconnect. Following the commencement of commercial operations of the Grady Project, at which time the Grady Project will begin making transmission service payments to Western Interconnect, the Company will make the aforementioned contingent post-closing payment.

The identifiable assets, operating contracts and liabilities assumed for Broadview and Western Interconnect 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.

The fair values are as follows (in thousands):



	April 21, 2017
Cash and cash equivalents	$	3,022
Trade receivables	3,259
Prepaid expenses	187
Other current assets	9,830
Restricted cash	44,383
Deferred financing costs, net	1,890
Property, plant and equipment	627,648
Intangible assets	22,346
Accounts payable and other accrued liabilities	(2,956		)
Accrued interest	(108		)
Long-term debt, current portion	(51,053		)
Accrued construction costs	(38,960		)
Related party payable	(674		)
Contingent liability	(36,205		)
Asset retirement obligation	(6,296		)
Other long-term liabilities	(12,350		)
Total consideration before non-controlling interest	563,963
Less: noncontrolling interests	(325,600		)
Total consideration	$	238,363

Current assets, non-current restricted cash, accounts payable, other accrued liabilities, accrued interest, accrued construction costs, related party payable and current portion of long-term debt were recorded at carrying value, which was representative of the fair value on the date of acquisition. Property, plant and equipment, finite-lived intangible assets, contingent liabilities and long-term liabilities were recorded at fair value estimated using the cost and income approach. The fair value of asset retirement obligations was recorded at fair value using a combination of market data, operational data and discounted cash flows and was adjusted by a discount rate factor reflecting current market conditions at the time of acquisition.

Concurrent with the closing, certain tax equity investors made capital contributions to acquire 100% of the Class A membership interests in Broadview Holdings and have been admitted as noncontrolling members in the entity, with a 16% initial interest in the distributable cash flow from Broadview. The noncontrolling interest was recorded at fair value estimated using the purchase price from the purchase agreement executed on April 21, 2017 among the Company and the tax equity investors.

The Company recorded a $7.2 million contingent obligation, payable to a third party who holds a 1% interest in Western Interconnect, at fair value upon the acquisition of the Broadview Project. These contingent payments are subject to certain conditions, including the actual energy production of Broadview in a production year and the continued operation of Broadview. Additionally, the Company recorded a $29.0 million contingent obligation, payable to the same counterparty, at fair value upon the acquisition of the Broadview Project. These contingent payments are subject to certain conditions, including the commercial operation of the Grady Project. The contingent payment is calculated as a percentage of additional transmission revenue earned by Western Interconnect upon the Grady Project's commercial operation.

The Company incurred transaction-related expense of $0.4 million which were recorded in net loss on transactions in the consolidated statements of operations for the three and nine months ended September 30, 2017 .

The accounting for this acquisition is preliminary. The fair value estimates for the assets acquired and liabilities assumed were based on preliminary calculations and valuations, and the estimates and assumptions are subject to change as additional information is obtained for the estimates during the measurement period (up to one year from the acquisition date). During the three months ended September 30, 2017, the Company adjusted the initial valuation and decreased property, plant and equipment by $0.9 million , decreased accrued construction costs by $1.2 million and increased asset retirement obligations by $0.3 million . These changes are as a result of the updated inputs, assumptions and methodologies used in determining the fair value of these assets and liabilities.

The Company has determined that the operating partnership agreement does not allocate economic benefits pro rata to its two classes of investors for Broadview and will use the hypothetical liquidation at book value (HLBV) method to calculate the noncontrolling interest balance that reflects the substantive profit sharing arrangement.

Asset Acquisition

Meikle

On August 10, 2017, pursuant to a Purchase and Sale Agreement by and among the Company, Pattern Development 1.0, and Public Sector Pension Investment Board (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. 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 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 PSP pursuant to the Purchase and Sale Agreement. The preliminary fair value of the assets acquired and liabilities assumed in connection with the Meikle acquisition are as follows (in thousands):



	August 10, 2017
Cash and cash equivalents	$	3,865
Trade receivables	5,432
Prepaid expenses	1,194
Deferred financing costs, current	36
Other current assets	432
Restricted cash	6,808
Deferred financing costs	726
Property, plant and equipment	375,717
Finite lived intangible asset	29,287
Other assets	80
Accounts payable and other accrued liabilities	(4,676		)
Accrued construction costs	(1,762		)
Related party payable	(96		)
Accrued interest	(1,180		)
Derivative liabilities, current	(1,980		)
Current portion of long-term debt	(7,291		)
Long-term debt, net	(258,303		)
Derivative liabilities, noncurrent	(13,198		)
Other long-term liabilities	(1,816		)
Total consideration before non-controlling interest	133,275
Less: noncontrolling interests	(64,789		)
Total consideration	$	68,486

Supplemental Pro Forma Data (unaudited)

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 effects to the Broadview Project acquisition as if it had occurred on January 1, 2016 and actual data reported for the three and nine months ended September 30, 2017 and 2016.

Meikle was under construction throughout 2016 and did not reach commercial operations until February 1, 2017. Meikle's statements of operations and balance sheets for the year ended December 31, 2016 reflect development and construction activity, whose costs were primarily being capitalized to construction in progress, and include no revenue or operating expenses. Therefore, the Company has determined there is no material difference between pro forma data that give effects to the Meikle acquisition as if it had occurred on January 1, 2016 and the commercial operations date. 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 February 1, 2017 when Meikle reached commercial operations. The unaudited pro forma data should not be considered representative of the Company’s future financial condition or results of operations.



Unaudited pro forma data (in thousands)	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
Pro forma total revenue	$	94,820		$	312,116
Pro forma total expenses	(144,170		)	(376,980		)
Pro forma net loss	(49,350		)	(64,864		)
Less: pro forma net loss attributable to noncontrolling interest	(19,025		)	(52,694		)
Pro forma net loss attributable to Pattern Energy	$	(30,325	)	$	(12,170	)

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



Unaudited data (in thousands)	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
Total revenue	$	16,556		$	25,357
Total expenses	(22,859		)	(35,856		)
Net loss	(6,303		)	(10,499		)
Less: net loss attributable to noncontrolling interest	(7,019		)	(11,274		)
Net income attributable to Pattern Energy	$	716		$	775

Unconsolidated Investment

PEGH 2

On July 27, 2017, the Company funded an initial $60 million capital call under the Second Amended and Restated Agreement of Limited Partnership of PEGH 2, dated as of June 16, 2017, by and among PEGH 2, the Class A Limited Partners set forth therein and the Class B Limited Partners set forth therein. As a result of such funding, and the related funding by other investors in PEGH 2 and consummation of certain redemptions, the Company holds an approximate 20% ownership interest in PEGH 2. The Company is a noncontrolling investor in PEGH 2, but has significant influence over PEGH 2. Accordingly, the investment is accounted for under the equity method of accounting.

The Company capitalized $1.5 million of transaction costs for the nine months ended September 30, 2017. The cost of the Company's investment in PEGH 2 was $40.6 million higher than the Company's underlying equity in the net assets of PEGH 2. This equity method basis difference was primarily attributable to equity method goodwill.

4. Property, Plant and Equipment

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



	September 30,			December 31,
	2017			2016
Operating wind farms	$	4,740,532		$	3,707,823
Furniture, fixtures and equipment	12,631			9,307
Land	141			141
Subtotal	4,753,304			3,717,271
Less: accumulated depreciation	(729,949		)	(582,109		)
Property, plant and equipment, net	$	4,023,355		$	3,135,162

The Company recorded depreciation expense related to property, plant and equipment of $51.4 million and $141.9 million for the three and nine months ended September 30, 2017 , respectively, and recorded $43.0 million and $128.7 million for the same periods in the prior year.

5. Finite-Lived Intangible Assets and Liability

Finite-Lived Intangible Assets and Liability

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



	September 30, 2017
	Weighted Average Remaining Life	Gross		Accumulated Amortization			Net
Intangible assets
Power purchase agreement	16	$	127,330	$	(15,668	)	$	111,662
Industrial revenue bond tax savings	25	12,778		(223		)	12,555
Other intangible assets	34	15,234		(935		)	14,299
Total intangible assets		$	155,342	$	(16,826	)	$	138,516
Intangible liability
Power purchase agreement	15	$	60,300	$	(8,238	)	$	52,062



	December 31, 2016
	Weighted Average Remaining Life	Gross		Accumulated Amortization			Net
Intangible assets
Power purchase agreement	13	$	97,400	$	(10,632	)	$	86,768
Other intangible assets	15	5,666		(539		)	5,127
Total intangible assets		$	103,066	$	(11,171	)	$	91,895
Intangible liability
Power purchase agreement	16	$	60,300	$	(5,637	)	$	54,663

The Company presents amortization of the PPA assets and PPA liability as an offset to electricity sales in the consolidated statements of operations, which resulted in net expense of $0.9 million and $2.4 million in electricity sales for the three and nine months ended September 30, 2017 and net expense of $0.7 million and $2.3 million for the same periods in 2016 . For other intangible assets, the Company includes the amortization in depreciation and accretion in the consolidated statements of operations and recorded amortization expense of $0.1 million and $0.4 million for the three and nine months ended September 30, 2017 and amortization expense of $0.1 million and $0.2 million for the same periods in 2016 .

The acquisition of the Broadview Project provided for future property tax savings as a result of the issuance of industrial revenue bonds during construction of the Broadview Project. The Company considered the future tax savings an intangible asset and calculated the fair value of the asset at the acquisition date. The tax savings was calculated by forecasting the difference between the property tax payments that the Broadview Project would be liable for if the industrial revenue bond structure was not in place and the actual payments in lieu of tax. The fair value of the property tax savings was recorded to finite-lived intangible assets, net on the consolidated balance sheets at the acquisition date, and such value will be amortized to depreciation and accretion in the consolidated statements of operations over the 25 year exemption period that remains as of the acquisition date. The Company recorded amortization expense of $0.1 million and $0.2 million for the three and nine months ended September 30, 2017 , respectively, related to the industrial revenue bond tax savings intangible asset.

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
2017 (remainder)	$	1,079	$	128	$	152
2018	4,253		513		605
2019	4,253		513		605
2020	4,274		513		605
2021	4,253		513		605
Thereafter	41,488		10,375		11,727

6. Variable Interest Entities

The Company has determined that Logan's Gap, Panhandle 1, Panhandle 2, Post Rock, Amazon Wind Farm Fowler Ridge and Broadview Holdings are variable interest entities (VIEs) in accordance with ASU 2015-02 primarily because the tax equity interests in these operating entities lack substantive kick-out and participating rights. The Company determined that as the managing member it is the primary beneficiary of each VIE by reference to the power and benefits criterion under ASC 810, Consolidation . 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 PEGH 2 is considered to be a VIE in accordance with ASU 2015-02 primarily because the total equity at risk is not sufficient to permit PEGH 2 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 PEGH 2 was $59.3 million at September 30, 2017. The Company's maximum exposure to loss is equal to the carrying value of its investment in PEGH 2. See Note 3, Acquisitions , for additional information.

The following presents the carrying amounts of the consolidated VIEs' assets and liabilities included in the consolidated balance sheets (in thousands). Assets presented below are restricted for settlement of the consolidated VIEs' obligations and all liabilities presented below can only be settled using the VIE resources.



	September 30, 2017		December 31, 2016 ⁽¹⁾
Assets
Current assets:
Cash and cash equivalents	$	26,442	$	12,745
Restricted cash	4,305		4,291
Trade receivables	8,694		6,290
Prepaid expenses	4,964		4,468
Other current assets	4,274		1,456
Total current assets	48,679		29,250

Restricted cash	3,517		3,203
Property, plant and equipment, net	2,008,700		1,538,793
Finite-lived intangible assets, net	12,364		2,070
Other assets	13,499		13,622
Total assets	$	2,086,759	$	1,586,938

Liabilities
Current liabilities:
Accounts payable and other accrued liabilities	$	24,754	12,635
Accrued construction costs	1,560		709
Accrued interest	80		77
Other current liabilities	4,084		2,090
Total current liabilities	30,478		15,511

Finite-lived intangible liability, net	52,062		54,663
Other long-term liabilities	40,505		20,081
Total liabilities	$	123,045	$	90,255


⁽¹⁾	Does not include Broadview Holdings as it was acquired in April 2017.

7. 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,
	2017		2016		2017		2016
South Kent	$	3,732	$	1,537	50.0	%	50.0	%
Grand	5,758		3,459		45.0	%	45.0	%
K2	102,019		97,051		33.3	%	33.3	%
Armow	133,063		131,247		50.0	%	50.0	%
PEGH 2	59,261		—		20.2	%	NA
Unconsolidated investments	$	303,833	$	233,294

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, 2017 , the Company recorded basis difference amortization for its unconsolidated investments of $2.9 million and $8.5 million , respectively, and for the same periods in 2016 , the Company recorded basis difference amortization of $1.3 million and $3.8 million , respectively, in earnings (loss) in unconsolidated investments, net on the consolidated statements of operations.

Suspension of Equity Method Accounting

As discussed in Note 2 , Summary of Significant Accounting Policies in the Company's 2016 Form 10-K, the Company may suspend recognition of equity method earnings when the Company receives distributions in excess of the carrying value of its investment, and the Company is not liable for the obligations of the investee nor otherwise committed to provide financial support. The Company records gains resulting from such excess distributions in the period the distributions occur. Additionally, when the Company's carrying value in an unconsolidated investment is zero and the Company is not liable for the obligations of the investee nor otherwise committed to provide financial support, the Company does not recognize equity in earnings (losses) or equity in other comprehensive income of unconsolidated investments.

As of September 30, 2017 , none of the Company's unconsolidated investments were in suspension. As of September 30, 2016 , the Company's equity method balances for South Kent and Grand were zero . In accordance with ASC 323, Investments - Equity Method and Joint Ventures , the Company suspended recognition of South Kent's and Grand's equity method earnings or losses until the fourth quarter of 2016 when their cumulative equity method earnings exceeded cumulative distributions received and cumulative equity method losses. As the Company has no explicit or implicit commitment to fund losses at the unconsolidated investments, the Company recorded distributions received in excess of the carrying amount of its unconsolidated investments as gains. Earnings (loss) in unconsolidated investments, net as reported on the consolidated statements of operations attributable to South Kent and Grand included $5.8 million and $15.0 million for the three and nine months ended September 30, 2016 , respectively, in distributions received in excess of the carrying amount of the Company's investment.

During the suspension period, the Company maintains a memo ledger that records the components of the suspended activity. As of September 30, 2016 , the memo ledger balance was made up of distributions received in excess of the carrying amount of the Company's investment of $5.8 million , suspended equity losses of $2.7 million and suspended other comprehensive income of $0.5 million .

Significant Equity Method Investees

The following table presents summarized statements of operations information for the three and nine months ended September 30, 2017 and 2016 as required for the Company's significant equity method investees, South Kent, Grand, K2, Armow, and PEGH 2 pursuant to Regulation S-X Rule 10-01(b)(1) (in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2017			2016 ⁽¹⁾			2017		2016 ⁽¹⁾
Revenue	$	45,008		$	40,863		$	228,111	$	167,426
Cost of revenue	31,550			23,768			89,288		69,367
Operating expenses	11,030			459			12,663		1,928
Other expense	12,062			21,553			50,038		89,820
Net income (loss)	$	(9,634	)	$	(4,917	)	$	76,122	$	6,311


⁽¹⁾	Results for the three and nine months ended September 30, 2016 do not include Armow, which was acquired in October 2016 and PEGH 2, which was acquired in July 2017.

8. Debt

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



							As of September 30, 2017
	September 30, 2017			December 31, 2016			Contractual Interest Rate			Effective Interest Rate
	September 30, 2017			December 31, 2016			Contractual Interest Rate			Effective Interest Rate			Maturity
Corporate-level
Revolving Credit Facility	$	253,000		$	180,000		varies		⁽¹⁾	4.23	%	⁽¹⁾	December 2018
2020 Notes	225,000			225,000			4.00	%		6.60	%		July 2020
2024 Notes	350,000			—			5.88	%		5.88	%		February 2024
Project-level
Fixed interest rate
El Arrayán EKF term loan	99,112			103,904			5.56	%		5.56	%		March 2029
Santa Isabel term loan	104,540			107,090			4.57	%		4.57	%		September 2033
Variable interest rate
Ocotillo commercial term loan ⁽²⁾	179,298			193,257			3.33	%		4.09	%	⁽³⁾	August 2020
Lost Creek term loan ⁽⁴⁾	—			103,846			N/A			N/A			N/A
El Arrayán commercial term loan	90,102			94,458			4.25	%		5.72	%	⁽³⁾	March 2029
Spring Valley term loan	127,392			130,658			3.09	%		5.19	%	⁽³⁾	June 2030
Ocotillo development term loan	101,200			102,300			3.43	%		4.44	%	⁽³⁾	August 2033
St. Joseph term loan ⁽²⁾	174,413			162,356			3.04	%		3.89	%	⁽³⁾	November 2033
Western Interconnect term loan ⁽²⁾	54,395			—			3.34	%		4.23	%	⁽³⁾	April 2027
Meikle term loan ⁽²⁾	271,042			—			2.92	%		3.89	%	⁽³⁾	May 2024
Imputed interest rate
Hatchet Ridge financing lease obligation	196,363			202,593			1.43	%		1.43	%		December 2032
	2,225,857			1,605,462
Unamortized premium/discount, net ⁽⁴⁾	(14,673		)	(17,019		)
Unamortized financing costs	(28,364		)	(24,771		)
Total debt, net	$	2,182,820		1,563,672

As reflected on the consolidated balance sheets
Revolving credit facility	$	253,000		$	180,000
Current portion of long-term debt, net of financing costs	58,213			48,716
Long term debt, net of financing costs	1,871,607			1,334,956
Total debt, net	$	2,182,820		$	1,563,672


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


⁽²⁾	The amortization for the Ocotillo commercial term loan, the St. Joseph term loan, the Western Interconnect term loan and the Meikle term loan are through June 2030, 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 10 , Derivative Instruments , for discussion of interest rate swaps.


⁽⁴⁾	The discount relates to the 2020 Notes and the premium relates to the Lost Creek term loan as of December 31, 2016, as the Lost Creek term loan was terminated in September 2017.

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,
	2017		2016		2017		2016
Corporate-level interest and commitment fees incurred	$	9,215	$	4,200	$	24,827	$	14,205
Project-level interest and commitment fees incurred ⁽¹⁾	14,635		12,611		40,103		39,055
Amortization of debt discount/premium, net	1,153		1,073		3,379		3,147
Amortization of financing costs	2,028		1,745		5,879		5,242
Other interest	116		169		353		485
Interest expense	$	27,147	$	19,798	$	74,541	$	62,134


⁽¹⁾	Includes reclassification of realized gains (losses) on derivative instruments that qualifies as cash flow hedges from accumulated OCI into interest expense and the ineffective portion of the instruments.

Corporate Level Debt

Revolving Credit Facility

As of September 30, 2017 , $210.7 million was available for borrowing under the $500.0 million Revolving Credit Facility. The Revolving Credit Facility is secured by pledges of the capital stock and ownership interests in certain of the Company’s holding company subsidiaries. The Revolving Credit Facility contains a broad range of covenants that, subject to certain exceptions, restrict the Company’s 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, 2017 , the Company's holding company subsidiaries were in compliance with covenants contained in the Revolving Credit Facility.

The loans under the Company's Revolving Credit Facility are either base rate loans or Eurodollar rate loans. The base rate loans accrue interest at the fluctuating rate per annum equal to the greatest of the (i) the prime rate, (ii) the federal funds rate plus 0.50% and (iii) the Eurodollar rate that would be in effect for a Eurodollar rate loan with an interest period of one month plus 1.0% , plus an applicable margin ranging from 1.25% to 1.75% (corresponding to applicable leverage ratios of the borrower). The Eurodollar rate loans accrue interest at a rate per annum equal to International Continental Exchange London Interbank Offered Rate (LIBOR), as published by Reuters plus an applicable margin ranging from 2.25% to 2.75% (corresponding to applicable leverage ratios of the borrower). Under the Revolving Credit Facility, the Company pays a revolving commitment fee equal to the average of the daily difference between revolving commitments and the total utilization of revolving commitments times 0.50% . The Company also pays letter of credit fees.

As of September 30, 2017 and December 31, 2016 , letters of credit of $36.3 million and $31.7 million were issued under the Revolving Credit Facility.

Unsecured Senior Notes due 2024

In January 2017, the Company issued unsecured senior notes with an aggregate principal amount of $350.0 million (Unsecured Senior Notes or 2024 Notes). Net proceeds to the Company were approximately $345.0 million , after deducting the initial purchasers’ discount, commissions and transaction expenses. The 2024 Notes bear interest at a rate of 5.875% per year, payable semiannually in arrears on February 1 and August 1, beginning on August 1, 2017 and maturing on February 1, 2024, unless repurchased or redeemed at an earlier date. The 2024 Notes are guaranteed on a senior unsecured basis by Pattern US Finance Company, one of the Company's subsidiaries.

Convertible Senior Notes due 2020

In July 2015, the Company issued $225.0 million aggregate principal amount of 4.00% convertible senior notes due 2020 (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 2020 Notes are guaranteed on a senior unsecured basis by a subsidiary of the Company and are general unsecured obligations of the Company. The obligations rank senior in rights of payment to the Company’s subordinated debt, equal in right of payment

to the Company’s unsubordinated debt and effectively junior in right of payment to any of the Company’s secured indebtedness to the extent of the value of the assets securing such indebtedness.

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



	September 30, 2017			December 31, 2016
Principal	$	225,000		$	225,000
Less:
Unamortized debt discount	(14,673		)	(18,196		)
Unamortized financing costs	(3,072		)	(3,894		)
Carrying value of convertible senior notes	$	207,255		$	202,910
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 level debt

Western Interconnect

In April 2017, in connection with the Broadview Project acquisition, the Company assumed a $51.2 million senior construction loan facility, including accrued interest, which was immediately extinguished and concurrently, the Company entered into a variable rate term loan maturing on April 21, 2027 for $54.4 million . The interest rate on the term loan is LIBOR plus 2.00% (with periodic increases of 0.25% every four years ).

Collateral for the term loan includes Western Interconnect's tangible assets and contractual rights and cash on deposit with the depository agent. Such loan agreement contains a broad range of covenants that, subject to certain exceptions, restrict Western Interconnect's ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests, dissolve, make distributions, or change its business.

Meikle

In August 2017, in connection with the Meikle acquisition, the Company assumed a $265.6 million variable rate term loan maturing on May 12, 2024. The interest rate on the term loan is Canadian Dollar Offered Rate plus 1.50% .

Collateral for the term loan includes Meikle’s tangible assets and contractual rights and cash on deposit with the collateral agent. Such credit agreement contains a broad range of covenants that, subject to certain exceptions, restrict Meikle's ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests, dissolve, make distributions, or change its business.

Lost Creek

On September 28, 2017, the Company prepaid 100% of the outstanding balance of the Lost Creek project's term loan of $100.1 million . A $0.1 million loss on the debt extinguishment was recorded in other income, net in the consolidated statements of operations, primarily due to the offsetting impact of writing-off the debt premium and deferred financing costs. As a result of the early extinguishment of debt, the Company terminated the related interest rate swaps. See Note 10 , Derivative Instruments , for additional information.

9. 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.

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,
	2017		2016
Beginning asset retirement obligations	$	44,783	$	42,197
Net additions during the period ⁽¹⁾	8,112		—
Foreign currency translation adjustment	233		120
Accretion expense	2,130		1,892
Ending asset retirement obligations	$	55,258	$	44,209

⁽¹⁾ Reflects additions due to acquisition of the Broadview Project and Meikle. See Note 3 , Acquisitions , for discussion of the acquisitions.

10. 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 Chile. 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, 2017 , the Company 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, 2017
	Derivative Assets				Derivative Liabilities ⁽¹⁾
	Current		Long-Term		Current		Long-Term
Fair Value of Designated Derivatives
Interest rate swaps	$	—	$	2,044	$	6,490	$	18,014

Fair Value of Undesignated Derivatives
Interest rate swaps	$	—	$	863	$	2,005	$	2,970
Energy derivative	18,824		11,958		—		—
Foreign currency forward contracts	—		—		3,600		995

Total Fair Value	$	18,824	$	14,865	$	12,095	$	21,979

	December 31, 2016
	Derivative Assets				Derivative Liabilities
	Current		Long-Term		Current		Long-Term
Fair Value of Designated Derivatives
Interest rate swaps	$	—	$	40	$	8,289	$	21,058

Fair Value of Undesignated Derivatives
Interest rate swaps	$	—	$	1,788	$	3,238	$	3,463
Energy derivative	16,209		24,707		—		—
Foreign currency forward contracts	1,369		177		391		—

Total Fair Value	$	17,578	$	26,712	$	11,918	$	24,521


⁽¹⁾	Inclusive of Western Interconnect interest rate swaps which are effective as of June 30, 2017 and Meikle interest rate swaps which are effective as of August 10, 2017.

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	2017		2016
Designated Derivative Instruments
Interest rate swaps ⁽¹⁾	USD	$	337,531	$	365,443
Interest rate swaps	CAD	$	740,375	$	196,425

Undesignated Derivative Instruments
Interest rate swaps	USD	$	225,884	$	257,389
Energy derivative	MWh	818,168		1,201,691
Foreign currency forward contracts	CAD	$	120,500	$	95,800


⁽¹⁾	Inclusive of Western Interconnect interest rate swaps which are effective as of June 30, 2017 and Meikle interest rate swaps which are effective as of August 10, 2017.

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 6.2 years to 21.3 years .

On September 28, 2017, in connection with the early extinguishment of Lost Creek's term loan, the Company terminated the related interest rate swaps which resulted in the reclassification of $2.2 million in accumulated other comprehensive loss to realized loss on designated derivatives in the consolidated statements of operations.

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	2017			2016			2017			2016
Gains (losses) recognized in accumulated OCI	Effective portion of change in fair value	$	3,205		$	(527	)	$	(1,154	)	$	(35,290	)
Gains (losses) reclassified from accumulated OCI into:
Interest expense	Derivative settlements	$	(2,891	)	$	(3,020	)	$	(7,861	)	$	(9,226	)
Realized loss on designated derivatives	Termination of derivatives	$	(2,207	)	$	—		$	(2,207	)	$	—
Interest expense	Ineffective portion	$	329		$	365		$	252		$	(147	)

The Company estimates that $5.1 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	Description	2017			2016			2017			2016
Interest rate swaps	Gain (loss) on undesignated derivatives, net	Change in fair value, net of settlements	$	358		$	2,305		$	(29	)	$	(10,513	)
Interest rate swaps	Gain (loss) on undesignated derivatives, net	Derivative settlements	$	(494	)	$	(1,272	)	$	(2,327	)	$	(3,878	)
Energy derivative	Electricity sales	Change in fair value, net of settlements	$	(3,113	)	$	(818	)	$	(10,134	)	$	(14,970	)
Energy derivative	Electricity sales	Derivative settlements	$	3,196		$	3,144		$	14,278		$	16,629
Foreign currency forward contracts	Gain (loss) on undesignated derivatives, net	Change in fair value, net of settlements	$	(2,904	)	$	487		$	(5,749	)	$	(4,128	)
Foreign currency forward contracts	Gain (loss) on undesignated derivatives, net	Derivative settlements	$	(1,041	)	$	305		$	(1,375	)	$	834

Interest Rate Swaps

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 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 undesignated derivatives, net in the consolidated statements of operations as these hedges are not accounted for under hedge accounting. All of the Company's undesignated interest rate swaps have a remaining maturity of 12.8 years .

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 cash collateral related to the energy derivative agreement. The Company does not have the right to pledge, invest, or use the cash collateral for general corporate purposes. As of September 30, 2017 , the Company has recorded a current asset of $33.5 million to funds deposited by counterparty and a current liability of $33.5 million to counterparty deposit liability representing the cash collateral received and corresponding obligation to return the cash collateral, respectively. The cash was deposited into a separate custodial account for which the Company is not entitled to the interest earned on the cash collateral.

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. The Company enters into foreign currency forward contracts at various times to mitigate the currency exchange rate risk on Canadian dollar denominated cash flows. These instruments have remaining maturities ranging from two to twenty months. 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 undesignated derivatives, net in the consolidated statements of operations.

11. 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, 2015	$	(48,285	)	$	(13,462	)	$	(12,131	)	$	(73,878	)
Other comprehensive income (loss) before reclassifications	9,874			(30,990		)	(11,684		)	(32,800		)
Amounts reclassified from accumulated other comprehensive loss	—			8,359			2,752			11,111
Net current period other comprehensive income (loss)	9,874			(22,631		)	(8,932		)	(21,689		)
Balances at September 30, 2016	$	(38,411	)	$	(36,093	)	$	(21,063	)	$	(95,567	)
Less: accumulated other comprehensive loss attributable to noncontrolling interest, September 30, 2016	—			(1,418		)	—			(1,418		)
Accumulated other comprehensive loss attributable to Pattern Energy, September 30, 2016	$	(38,411	)	$	(34,675	)	$	(21,063	)	$	(94,149	)



	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 swaps	—			2,207			—			2,207
Other 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	)
Less: accumulated other comprehensive loss attributable to noncontrolling interest, September 30, 2017	—			(200		)	—			(200		)
Accumulated other comprehensive loss attributable to Pattern Energy, September 30, 2017	$	(25,521	)	$	(5,819	)	$	6,519		$	(24,821	)

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

12. Fair Value Measurements

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

Assets and liabilities recorded at fair value in the 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, 2017
	Level 1		Level 2		Level 3		Total
Assets
Interest rate swaps	$	—	$	2,907	$	—	$	2,907
Energy derivative	—		—		30,782		30,782
	$	—	$	2,907	$	30,782	$	33,689
Liabilities
Interest rate swaps	$	—	$	29,479	$	—	$	29,479
Foreign currency forward contracts	—		4,595		—		4,595
Contingent consideration	—		—		21,505		21,505
	$	—	$	34,074	$	21,505	$	55,579



	December 31, 2016
	Level 1		Level 2		Level 3		Total
Assets
Interest rate swaps	$	—	$	1,828	$	—	$	1,828
Energy derivative	—		—		40,916		40,916
Foreign currency forward contracts	—		1,546		—		1,546
	$	—	$	3,374	$	40,916	$	44,290
Liabilities
Interest rate swaps	$	—	$	36,048	$	—	$	36,048
Foreign currency forward contracts	—		391		—		391
	$	—	$	36,439	$	—	$	36,439

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 forward electricity prices which are derived from observable prices, such as forward gas curves, adjusted by a non-observable heat rate for when the contract term extends beyond a period for which market data is available. The significant unobservable input in calculating the fair value of the energy derivative instrument is forward electricity prices. Significant increases or decreases in this unobservable input would result in a significantly lower or higher fair value measurement.

Contingent Consideration

The Broadview Project acquisition includes contingent consideration, which requires the Company to make an additional payment upon the commercial operation of the Grady Project. 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 consideration was 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. As of September 30, 2017, there were no significant changes in the recognized amount for the contingent consideration recognized as a result of the acquisition of the Broadview Project. Significant changes in these unobservable inputs 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, 2017	Fair Value	Valuation Technique	Significant Unobservable Inputs	Range
Energy derivative	$30,782	Discounted cash flow	Forward electricity prices	$14.72 - $67.91 ⁽¹⁾
			Discount rate	1.33% - 1.67%

Contingent consideration	$21,505	Discounted cash flow	Discount rate	4.0% - 8.0%
			Annual energy production loss	1%

December 31, 2016	Fair Value	Valuation Technique	Significant Unobservable Inputs	Range
Energy derivative	$40,916	Discounted cash flow	Forward electricity prices	$15.83 - $81.76 ⁽¹⁾
			Discount rate	1.00% - 1.52%


⁽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	2017			2016			2017			2016
Balances, beginning of period	$	33,895		$	49,531		$	40,916		$	63,683
Total gain (loss) included in electricity sales	83			2,326			4,144			1,659
Settlements	(3,196		)	(3,144		)	(14,278		)	(16,629		)
Balances, end of period	$	30,782		$	48,713		$	30,782		$	48,713

During the three and nine months ended September 30, 2017 , the Company recognized an unrealized loss on the energy derivative of $3.1 million and $10.1 million , respectively, and $0.8 million and $15.0 million , respectively, for the same periods in the prior year, 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	2017		2016	2017		2016
Balances, beginning of period	$	21,502	N/A	$	—	N/A
Purchase	—		N/A	21,284		N/A
Total loss included in other income, net	3		N/A	221		N/A
Settlement	—		N/A	—		N/A
Balances, end of period	$	21,505	N/A	$	21,505	N/A

During the three and nine months ended September 30, 2017 , the Company recognized an immaterial amount and $0.2 million , of unrealized loss on the contingent consideration liability, which was recorded to other income, 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, 2017
Long-term debt, including current portion	$	2,182,820	$	—	$	2,187,346	$	—	$	2,187,346
December 31, 2016
Long-term debt, including current portion	$	1,383,672	$	—	$	1,382,038	$	—	$	1,382,038

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.

13. Stockholders' Equity

Common Stock

On May 9, 2016, the Company entered into an Equity Distribution Agreement with RBC Capital Markets, LLC, KeyBanc Capital Markets Inc. and Morgan Stanley & Co. LLC (collectively, the Agents). Pursuant to the terms of the Equity Distribution Agreement, 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 through the Agents, as the Company’s sales agents for the offer and sale of the shares, up to an aggregate sales price of $200.0 million . The Company intends 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, 2017 , the Company sold 931,561 shares under the Equity Distribution Agreement; net proceeds under the issuance were $22.5 million and the aggregate compensation paid by the Company to the Agents with respect to such sales was $0.2 million . As of September 30, 2017 , approximately $147.5 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
2017:
Third Quarter	$	0.4200	August 3, 2017	September 29, 2017	October 31, 2017
Second Quarter	$	0.4180	May 4, 2017	June 30, 2017	July 31, 2017
First Quarter	$	0.4138	February 24, 2017	March 31, 2017	April 28, 2017

Noncontrolling Interests

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



	September 30,		December 31,
	2017		2016
El Arrayán	$	31,476	$	32,237
Logan's Gap	171,882		180,092
Panhandle 1	178,471		190,415
Panhandle 2	155,989		170,139
Post Rock	165,572		178,676
Amazon Wind Farm Fowler Ridge	135,176		139,687
Broadview Project	313,275		—
Meikle	65,508		—
Noncontrolling interest	$	1,217,349	$	891,246

On June 16, 2017, the Company entered into a Purchase and Sale Agreement (the PH2 PSA) with PSP. Upon the terms and subject to the conditions set forth in the PH2 PSA, at the closing, the Company (or one or more of its affiliates) will sell to the investor 49% of the Class B membership interests in Panhandle 2 holdings (which holds 100% of the membership interests in Panhandle 2) for consideration of $58.8 million (subject to certain adjustments).

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



	Capital			Accumulated Loss				Accumulated Other Comprehensive Loss				Noncontrolling Interest
Balances at December 31, 2015	$	972,241		$	(27,426	)		$	(553	)		$	944,262
Distributions to noncontrolling interests	(11,771		)	—				—				(11,771		)
Other	(103		)	—				—				(103		)
Net loss	—			(24,838		)		—				(24,838		)
Other comprehensive income, net of tax	—			—				(865		)		(865		)
Balances at September 30, 2016	$	960,367		$	(52,264	)		$	(1,418	)		$	906,685

Balances at December 31, 2016	$	954,242		$	(62,614	)		$	(382	)		$	891,246
Acquisition of Broadview Project and Meikle	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

14. Loss Per Share

Basic earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stockholders by the weighted average number of common shares outstanding during the reportable period. Diluted earnings (loss) per share is computed by adjusting basic earnings (loss) 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 loss 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 (loss) attributable to common stockholders for purposes of calculating basic and diluted earnings (loss) 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 (loss) per share because their effect would have been anti-dilutive were 9,014,397 and 8,967,019 , respectively, for the three and nine months ended September 30, 2017 and 8,121,850 and 8,115,741 , respectively, for the three and nine months ended September 30, 2016 .

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



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Numerator for basic and diluted loss per share:
Net loss attributable to Pattern Energy	$	(29,828	)	$	(4,013	)	$	(9,955	)	$	(30,906	)
Less: loss allocated to participating securities	(29		)	(16		)	(74		)	(36		)
Net loss attributable to common stockholders	$	(29,857	)	$	(4,029	)	$	(10,029	)	$	(30,942	)

Denominator for loss per share:
Weighted average number of shares:
Class A common stock - basic	87,370,979			81,531,775			87,146,465			76,821,811
Class A common stock - diluted	87,370,979			81,531,775			87,146,465			76,821,811

Loss per share:
Class A common stock:
Basic and diluted	$	(0.34	)	$	(0.05	)	$	(0.12	)	$	(0.40	)

Dividends declared per Class A common share	$	0.42		$	0.40		$	1.25		$	1.17

15. Commitments and Contingencies

Commitments

Acquisition commitments

On June 16, 2017, the Company entered into a purchase and sale agreement with Pattern Development 1.0 to purchase (i) a 51% limited partner interest in a newly-formed limited partnership (which will hold 100% of the economic interests in Mont Sainte-Marguerite Wind Farm LP (MSM), (ii) a 70% interest in Pattern MSM GP Holdings Inc., and (iii) a 70% interest in Pattern Development MSM Management ULC, in exchange for aggregate consideration of CAD $53.0 million (subject to certain adjustments). MSM operates the approximately 143 MW wind farm located near Québec City, Canada.

Investment commitments

On June 16, 2017, the Company entered into the Second Amended and Restated Agreement of Limited Partnership (A&R PEGH 2 LPA) of PEGH 2. In July 2017, PEGH 2 made a capital call of its new limited partners under the A&R PEGH 2 LPA (the Initial PEGH 2 Capital Call). In connection with the Initial PEGH 2 Capital Call, the Company made a contribution to PEGH 2 of approximately $60.0 million . As a result of the funding under the Initial PEGH 2 Capital Call and the consummation of certain redemptions, the Company holds an approximate 20% ownership interest in PEGH 2. See Note 3, Acquisitions , for discussion of the acquisition . Under the A&R PEGH 2 LPA, the Company has also committed to contribute up to an additional approximately $240.0 million to PEGH 2 in one or more subsequent rounds of financing, which could result in the Company's ownership interest in PEGH 2 increasing to up to approximately 29% . If the Company elects not to participate in such subsequent rounds of financing, its ownership interest in PEGH 2 may be diluted on a pro rata basis based on fair market value.

Completed Acquisition Commitments

As part of the acquisitions completed in 2017, 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 2017 (in thousands) as of September 30, 2017 :



	Remainder of 2017		2018		2019		2020		2021		Thereafter		Total
Transmission service agreements ⁽¹⁾	$	6,723	$	23,600	$	23,600	$	23,600	$	23,600	$	543,246	$	644,369
Payments in lieu of taxes	121		481		476		412		406		9,635		11,531
Operating leases	55		1,504		1,956		1,957		1,958		57,982		65,412
Service and maintenance agreements	2,728		10,999		5,866		4,208		4,292		365		28,458
Other	270		701		714		498		430		3,536		6,149
Total commitments	$	9,897	$	37,285	$	32,612	$	30,675	$	30,686	$	614,764	$	755,919

(1) Future commitments under the transmission service agreements are based on current rates, which are subject to future changes.

Transmission Service Agreements

In connection with the Broadview Project acquisition, the Company became a party to various long-term transmission service agreements expiring between 25 - 30 years. The Company recorded transmission service costs related to such agreements of $7.4 million and $12.0 million for the three and nine months ended September 30, 2017 , respectively.

Payments in Lieu of Taxes

As discussed earlier in Note 5, Finite-Lived Intangible Assets and Liability, in connection with the Broadview Project acquisition, the Company is required to make payments in lieu of taxes as a result of tax savings realized as part of the issuance of the industrial revenue bonds.

Other Commitments

Operating Leases

The Company has entered into various long-term operating lease agreements related to lands for its wind farms. For the nine months ended September 30, 2017 and 2016 , the Company recorded rent expenses of $10.2 million and $9.8 million , respectively, in project expense in its consolidated statements of operations.

Service and Maintenance Agreements

In March 2017, the Company entered into revised Long-term Service Agreements (LTSAs) at certain of its projects pursuant to which the turbine manufacturer will continue to provide routine and corrective maintenance service, but the Company has become responsible for a portion of the maintenance and repairs, including on major component parts. As a result of the revised LTSAs, the fixed contract commitments were reduced from that disclosed in the Company's 2016 Form 10-K by $102.2 million over a period of ten years .

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 2042 . 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, 2017 , the Company issued irrevocable letters of credits to guarantee its performance for the duration of the agreements totaling $156.6 million .

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, 2017 , the Company issued irrevocable letters of credit totaling $162.0 million which includes letters of credit issued under the Revolving Credit Facility 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, 2017 , the Company recorded liabilities of $1.8 million associated with bonuses payable to the turbine manufacturers and service providers.

Contingencies in connection with the Broadview Project Acquisition

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.

16. 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. The Company reclassified its presentation of management service fees received from related party revenue, as disclosed in prior periods, to other revenue on the consolidated statements of operations.

Management Services Agreement and Shared Management

The Company has entered into a 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 Company reclassified its presentation of related party receivables and payables as disclosed in prior periods to be presented within other current assets and other current liabilities on the consolidated balance sheets, respectively. In addition, the Company reclassified its presentation of reimbursements received by the Pattern Development Companies under the MSA from related party income, as disclosed in prior periods, to a reduction to general and administrative expense on the consolidated statements of operations. The MSA costs incurred by the Company are included in related party general and administrative on the consolidated statements of operations. The MSA had been further amended and restated in June 2017.

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, 2017		December 31, 2016
Other current assets:
Amounts due from Pattern Development 1.0	$	6.1	$	0.4
Amounts due from Pattern Development 2.0	0.9		0.2
Amounts due from unconsolidated investments	0.5		0.5
Total due from related parties	$	7.5	$	1.1

Other current liabilities:
Amounts due to Pattern Development 1.0	$	11.3	$	1.3
Total due to related parties	$	11.3	$	1.3

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	2017			2016			2017			2016
Management fees	Other revenue	$	1,883		$	1,574		$	5,887		$	4,121
MSA reimbursement	General and administrative	$	2,194		$	1,593		$	6,083		$	3,697
MSA costs	Related party general and administrative expense	$	(3,587	)	$	(3,553	)	$	(10,589	)	$	(7,381	)

Purchase and Sales Agreements

During the nine months ended September 30, 2017, the Company consummated the following acquisitions with Pattern Development 1.0 and 2.0 which are further detailed in Note 3 , Acquisitions (in millions):



Acquisitions from Pattern Development 2.0	Date of Acquisition	Cash Consideration		Debt Assumed	Contingent Consideration
PEGH 2 Investment	July 27, 2017	$	60.0	N/A	N/A



Acquisitions from Pattern Development 1.0	Date of Acquisition	Cash Consideration		Debt Assumed		Contingent Consideration
Broadview Project	April 21, 2017	$	214.7	$	51.2	$	21.3
Meikle	August 10, 2017	$	67.4	265.6		N/A

PSP Joint Venture

The Company entered into a Joint Venture Agreement with PSP pursuant to which PSP will have the right to co-invest up to an aggregate amount of approximately $500 million in projects acquired by the Company under its ROFO with the Pattern Development Companies, including investments in Meikle, MSM and Panhandle 2. On June 16, 2017 , PSP purchased approximately 8.7 million shares of the Company's common stock from Pattern Development 1.0. As a result, PSP has an approximate 9.8% ownership interest in the Company as of September 30, 2017 . PSP purchased an additional 641,025 shares from the Company's public offering that occurred on October 23, 2017 . See Note 17, Subsequent Events for additional details of the Company's public offering.

17. Subsequent Events

On October 26, 2017 , the Company declared an increased dividend for the fourth quarter, payable on January 31, 2018 , to holders of record on December 29, 2017 , in the amount of $0.422 per Class A share, or $1.69 on an annualized basis. This is a 0.5% increase from the third quarter of 2017.

On October 23, 2017 , the Company completed an underwritten public offering of its Class A common stock. In total, 9,200,000 shares of the Company's Class A common stock were sold at a public offering price of $23.40 per share. This includes 1,200,000 shares purchased by the underwriters to cover over-allotments. Aggregate net proceeds of the equity offering, including the proceeds of the over-allotment option, were approximately $212.1 million after deduction of underwriting discounts, commissions, and transaction expenses.

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, 2016 and our unaudited consolidated financial statements for the three and nine months ended September 30, 2017 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 20 wind power projects, including the Mont Sainte-Marguerite (MSM) wind power project we have committed to acquire, with a total owned interest of 2,736 MW in the United States, Canada and Chile 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 or variable price power sale agreement (PPA). Ninety-two percent of the electricity to be generated by our projects will be sold under our power sale agreements which have a weighted average remaining contract life of approximately 14.3 years as of September 30, 2017 .

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 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 Class A share over time. The Pattern Development Companies (Pattern Energy Group LP (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. Our continuing relationship with the Pattern Development Companies, including a 20% 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 capacity of 5,000 MW by year end 2020 through a combination of acquisitions from Pattern Development Companies and third parties capitalizing on the large fragmented global renewable energy market. Our business is primarily focused in the U.S., Canada and Chile; however, we expect opportunities in Japan and Mexico will form part of our growth strategy.

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

On October 23, 2017, we completed an underwritten public offering of our Class A common stock. In total, 9,200,000 shares of our Class A common stock were sold at a public offering price of $23.40 per share. This includes 1,200,000 shares purchased by the underwriters to cover over-allotments. Aggregate net proceeds of the equity offering, including the proceeds of the over-allotment option, were approximately $212.1 million after deduction of underwriting discounts, commissions, and transaction expenses.

On August 10, 2017, pursuant to a Purchase and Sale Agreement with Pattern Development 1.0, we acquired 50.99% of the limited partner interests in Meikle Wind Energy Limited Partnership (Meikle) and 70% of the issued and outstanding shares of Meikle Wind Energy Corp. (Meikle Corp) for a purchase price of approximately $67.4 million , paid at closing, in addition to $1.1 million of capitalized transaction-related expenses. 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.

On June 16, 2017, we entered into several agreements with the Pattern Development Companies and the Public Sector Pension Investment Board (PSP), which owns a 9.8% interest in us, including the following:

•

We agreed to an initial investment of $60 million in Pattern Development 2.0 for an approximately 20% initial ownership, with a right, but not the obligation, to participate in subsequent capital calls for a total commitment of up to $300 million. If this right is exercised for all future capital calls, this would increase our ownership to approximately 29%. We funded such initial capital call on July 27, 2017.


•	We entered into a Joint Venture Agreement with PSP pursuant to which PSP will have the right to co-invest up to an aggregate amount of approximately $500 million in projects acquired by us under our Right of First Offer (ROFO) with the Pattern Development Companies, including investments in Meikle, MSM and Panhandle 2.


•	We committed to acquire a 51% interest in Meikle, a 179 MW wind power project from Pattern Development 1.0, as discussed above. We also committed to acquire from Pattern Development 1.0 a 51% interest in MSM, a 143MW wind power project, for approximately $40 million. The acquisition of Meikle was completed in August 2017.


•	We have agreed to sell 49% of the Class B membership interest in the 182 MW Panhandle 2 project to PSP for $59 million.

On April 21, 2017, we acquired an 84% initial distributable cash flow interest in Broadview and 99% ownership interest in Western Interconnect from Pattern Development 1.0. 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 part of the acquisition, we also assumed $51.2 million of construction debt and accrued interest outstanding at Western Interconnect which was immediately extinguished, and concurrently, we entered into a variable rate term loan for $54.4 million . The Grady Project is a wind project on the identified ROFO list being separately developed by Pattern Development 2.0 which is expected to begin full construction not earlier than 2018, and which intends to interconnect through Western Interconnect. Following the commencement of commercial operations of the Grady Project, at which time the Grady Project will begin making transmission service payments to Western Interconnect, the Company will make the aforementioned contingent post-closing payment.

In March 2017, we entered into revised Long-term Service Agreements (LTSAs) at certain of our projects pursuant to which the turbine manufacturer will continue to provide routine and corrective maintenance service, but we have become responsible for a portion of the maintenance and repairs, including on major component parts. The revised LTSAs reduce fixed contract commitments by approximately $102.2 million over a period of ten years.

In January 2017, we issued unsecured senior notes with an aggregate principal amount of $350.0 million (the Unsecured Senior Notes). Net proceeds to us were approximately $345.0 million, after deducting the initial purchasers’ discount, commissions and transaction expenses. We used approximately $215 million of the net proceeds to partially fund our acquisition of the Broadview Project and used $128 million of proceeds to repay borrowings incurred under the Revolving Credit Facility to finance the purchase of the Armow project. The Unsecured Senior Notes bear interest at a rate of 5.875% per year, payable semiannually in arrears on February 1 and August 1, beginning on August 1, 2017 and maturing on February 1, 2024, unless repurchased or redeemed at an earlier date. The Unsecured Senior Notes are guaranteed on a senior unsecured basis by Pattern US Finance Company, one of our subsidiaries.

Below is a summary of our Identified ROFO Projects that we expect to acquire 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
Otsuki Wind	Operational	Japan	n/a	2006	PPA	12	12
Kanagi Solar	Operational	Japan	2014	2016	PPA	10	10
Futtsu Solar	Operational	Japan	2014	2016	PPA	31	31
Conejo Solar ⁽⁵⁾	Operational	Chile	2015	2016	PPA	104	104
El Cabo	In construction	New Mexico	2016	2017	PPA	298	125
Belle River	In construction	Ontario	2016	2017	PPA	100	43
Ohorayama	In construction	Japan	2016	2018	PPA	33	33
North Kent	In construction	Ontario	2017	2018	PPA	100	35
Henvey Inlet	Late stage development	Ontario	2017	2019	PPA	300	150
Tsugaru	Late stage development	Japan	2017	2020	PPA	122	122
Sumita	Late stage development	Japan	2019	2021	PPA	100	62
Pattern Development 2.0 Projects
Stillwater Big Sky	Late stage development	Montana	2017	2018	PPA	79	67
Crazy Mountain	Late stage development	Montana	2017	2019	PPA	80	68
Grady	Late stage development	New Mexico	2018	2019	PPA	220	188
Ishikari	Late stage development	Japan	2019	2022	PPA	100	100
						1,689	1,150


⁽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.

⁽⁵⁾

From time to time, we conduct strategic reviews of our markets. We have been conducting a strategic review of the market, growth, and opportunities in Chile. In the event we believe we can utilize funds that have already been invested in Chile or funds that might otherwise be invested in Chile in a more productive manner elsewhere that could generate a higher return on investment, we may decide to exit Chile for other opportunities with greater potential. In addition, Pattern Development 1.0 is also concurrently exploring strategic alternatives for its assets in Chile.

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 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. Cash available for distribution is a non-U.S. GAAP measure and 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 service our 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,
	2017			2016			2017			2016
Net cash provided by operating activities ⁽¹⁾	$	2,147		$	37,395		$	159,330		$	107,371
Changes in operating assets and liabilities	25,481			(4,513		)	(22,475		)	800
Network upgrade reimbursement	346			—			8,936			—
Release of restricted cash to fund project and general and administrative costs	—			—			—			590
Operations and maintenance capital expenditures	(254		)	(133		)	(517		)	(879		)
Distributions from unconsolidated investments	2,821			8,292			11,211			40,066
Other	598			(195		)	1,974			(130		)
Less:
Distributions to noncontrolling interests	(4,537		)	(3,584		)	(13,701		)	(11,771		)
Principal payments paid from operating cash flows	(17,140		)	(17,060		)	(40,911		)	(39,322		)
Cash available for distribution	$	9,462		$	20,202		$	103,847		$	96,725

(1) Included in net cash provided by operating activities is the portion of distributions from unconsolidated investments paid from cumulative earnings representing the return on investment.

Cash available for distribution was $9.5 million for the three months ended September 30, 2017 as compared to $20.2 million for the same period in the prior year. This $10.7 million decrease in cash available for distribution was primarily due to a $7.3 million increase in transmission cost, a $7.3 million increase in interest expense primarily due to the issuance of the Unsecured Senior Notes in January 2017 and debt associated with our acquisitions in 2017, a $2.7 million increase in project expenses and a $ 1.0 million increase in distributions to noncontrolling interests. The decrease to cash was partially offset by a $5.9 million increase in total distributions from unconsolidated investments , a $2.6 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs) , a $0.3 million network upgrade reimbursement primarily related to Broadview, and a $0.5 million decrease in operating expense.

Cash available for distribution was $103.8 million for the nine months ended September 30, 2017 as compared to $96.7 million for the same period in the prior year. This $7.1 million increase in cash available for distribution was primarily due to a $23.0 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs) , a $13.8 million increase in total distributions from unconsolidated investment, an $8.9 million network upgrade reimbursement primarily related to Broadview and a $0.3 million decrease in project expense. These increases were partially offset by a $11.9 million increase in transmission cost, a $12.4 million increase in interest expense primarily due to the issuance of the Unsecured Senior Notes in January 2017 and debt associated with our acquisitions, a $7.8 million increase in operating expenses, a $1.9 million increase in distribution to noncontrolling interests, a $1.6 million increase in principal payments and a $2.2 million increase in transaction costs and other expenses.

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.

Adjustments from unconsolidated investments represent distributions received in excess of the carrying amount of our investment and suspended equity earnings, during periods of suspension of recognition of equity method earnings. We may suspend the recognition of equity method earnings when we receive distributions in excess of the carrying value of our investment. As we are not liable for the obligations of the investee nor otherwise committed to provide financial support, we record gains resulting from such excess distributions in the period the distributions occur. Additionally, when our carrying value in an unconsolidated investment is zero and we are not liable for the obligations of the investee nor otherwise committed to provide financial support, we will not recognize equity in earnings (losses) in other comprehensive income of unconsolidated investments.

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,
	2017			2016			2017			2016
Net loss	$	(48,376	)	$	(11,050	)	$	(60,521	)	$	(55,744	)
Plus:
Interest expense, net of interest income	26,710			19,583			73,009			60,906
Tax (benefit) provision	(3,839		)	1,311			5,477			4,038
Depreciation, amortization and accretion	56,650			45,755			156,629			136,974
EBITDA	31,145			55,599			174,594			146,174
Unrealized loss on energy derivative ⁽¹⁾	3,113			818			10,134			14,970
Gain (loss) on undesignated derivatives, net	4,081			(1,825		)	9,480			17,685
Realized loss on derivatives	2,207			—			2,207			—
Net loss on transactions	466			314			1,585			353
Adjustments from unconsolidated investments ⁽²⁾	—			(8,439		)	—			(19,573		)
Plus , proportionate share from unconsolidated investments:
Interest expense, net of interest income	10,270			7,634			29,108			22,778
Depreciation, amortization and accretion	9,361			6,660			26,390			19,624
(Gain) loss on undesignated derivatives, net	(5,908		)	1,544			(8,696		)	17,015
Adjusted EBITDA	$	54,735		$	62,305		$	244,802		$	219,026


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


⁽²⁾	See Note 7 . Unconsolidated Investments in the Notes to Consolidated Financial Statements in this Form 10-Q, for further discussion.

Adjusted EBITDA for the three months ended September 30, 2017 was $54.7 million compared to $62.3 million for the same period in the prior year, a decrease of $7.6 million , or approximately 12.1% . The decrease in Adjusted EBITDA was primarily due to a $2.7 million increase in project expense, a $0.7 million decrease in our proportionate share of Adjusted EBITDA from unconsolidated investments , and a $7.3 million increase in transmission costs. The decrease was partially offset by a $2.6 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs) and a $0.5 million decrease in operating expenses.

Adjusted EBITDA for the nine months ended September 30, 2017 was $244.8 million compared to $219.0 million for the same period in the prior year, an increase of $25.8 million , or approximately 11.8% . The increase in Adjusted EBITDA was primarily due to a $23.0 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs) , a $23.2

million increase in our proportionate share of Adjusted EBITDA from unconsolidated investments and a $0.3 million decrease in project expense. These increases were partially offset by a $7.8 million increase in operating expenses and an $11.9 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	2017			2016			Change			% Change		2017			2016			Change			% Change
Consolidated MWh sold	1,598,899			1,526,221			72,678			4.8	%	5,587,484			5,055,723			531,761			10.5	%
Less: noncontrolling MWh	(241,152		)	(200,122		)	(41,030		)	20.5	%	(781,880		)	(689,026		)	(92,854		)	13.5	%
Controlling interest in consolidated MWh	1,357,747			1,326,099			31,648			2.4	%	4,805,604			4,366,697			438,907			10.1	%
Unconsolidated investments proportional MWh	156,250			146,201			10,049			6.9	%	858,178			621,924			236,254			38.0	%
Proportional MWh sold	1,513,997			1,472,300			41,697			2.8	%	5,663,782			4,988,621			675,161			13.5	%

Average realized electricity price per MWh
Consolidated average realized electricity price per MWh	$	58		$	60		$	(2	)	(3.3	)%	$	54		$	56		$	(2	)	(3.6	)%
Unconsolidated investments proportional average realized electricity price per MWh	$	126		$	116		$	10		8.6	%	$	116		$	112		$	4		3.6	%
Proportional average realized electricity price per MWh	$	66		$	68		$	(2	)	(2.9	)%	$	66		$	66		$	—		—	%

Our consolidated MWh sold for the three months ended September 30, 2017 was 1,598,899 MWh, as compared to 1,526,221 MWh for the three months ended September 30, 2016 , an increase of 72,678 MWh, or 4.8% . Our consolidated MWh sold for the nine months ended September 30, 2017 was 5,587,484 MWh, as compared to 5,055,723 MWh for the nine months ended September 30, 2016, an increase of 531,761 MWh, or 10.5% . The increase in consolidated MWh sold for the three months ended September 30, 2017 compared to the three months ended September 30, 2016 was primarily due to volume increases as a result of our acquisitions in 2017 partially offset by unfavorable wind and availability. The increase in consolidated MWh sold for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 was primarily due to volume increases as a result of our acquisitions in 2017 and favorable wind conditions partially offset by lower availability.

Our proportional MWh sold for the three months ended September 30, 2017 was 1,513,997 MWh, as compared to 1,472,300 MWh for the three months ended September 30, 2016 , an increase of 41,697 MWh, or 2.8% . The increase in consolidated MWh sold was primarily attributable to:


•	a 31,648 MWh increase in controlling interest in consolidated MWh primarily due to our acquisitions in 2017 partially offset by unfavorable wind and availability; and


•	a 10,049 MWh increase from unconsolidated investments due primarily to the acquisition of Armow in the fourth quarter of 2016 partially offset by unfavorable wind conditions in the current period compared to the same period in 2016.

Our proportional MWh sold for the nine months ended September 30, 2017 was 5,663,782 MWh, as compared to 4,988,621 MWh for the nine months ended September 30, 2016, an increase of 675,161 MWh, or 13.5% . The change in proportional MWh sold was primarily attributable to:


•	a 438,907 MWh increase in controlling interest in consolidated MWh primarily due to our acquisitions in 2017 and favorable wind conditions partially offset by lower availability; and


•	a 236,254 MWh increase from unconsolidated investments primarily due to the acquisition of Armow in the fourth quarter of 2016 and favorable wind conditions in the current period compared to the same period in 2016.

Our consolidated average realized electricity price was $58 per MWh for the three months ended September 30, 2017 , as compared to $60 per MWh for the three months ended September 30, 2016 . The decrease of $2 per MWh was primarily due to an increase in volume of lower priced PPAs.

Our consolidated average realized electricity price was $54 per MWh for the nine months ended September 30, 2017 , as compared to $56 per MWh for the nine months ended September 30, 2016. The decrease of $2 per MWh was primarily due to an increase in volume of lower priced PPAs.

Our proportional average realized electricity price was $66 per MWh for the three months ended September 30, 2017 , as compared to $68 per MWh for the three months ended September 30, 2016 . The $2 per MWh decrease in the proportional average realized electricity price was primarily due to an increase in volume from lower priced PPAs.

Our proportional average realized electricity price of $66 per MWh for the nine months ended September 30, 2017 was comparable to the proportional average realized electricity price for the nine months ended September 30, 2016.

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,
	2017			2016			$ Change			% Change		2017			2016			$ Change			% Change
Revenue	$	92,030		$	91,914		$	116		0.1	%	$	300,623		$	272,991		$	27,632		10.1	%
Total cost of revenue	93,732			75,077			18,655			24.8	%	253,287			227,771			25,516			11.2	%
Total operating expenses	12,655			13,151			(496		)	(3.8	)%	42,558			34,806			7,752			22.3	%
Total other expense	37,858			13,425			24,433			182.0	%	59,822			62,120			(2,298		)	(3.7	)%
Net loss before income tax	(52,215		)	(9,739		)	(42,476		)	436.1	%	(55,044		)	(51,706		)	(3,338		)	6.5	%
Tax (benefit) provision	(3,839		)	1,311			(5,150		)	(392.8	)%	5,477			4,038			1,439			35.6	%
Net loss	(48,376		)	(11,050		)	(37,326		)	337.8	%	(60,521		)	(55,744		)	(4,777		)	8.6	%
Net loss attributable to noncontrolling interest	(18,548		)	(7,037		)	(11,511		)	163.6	%	(50,566		)	(24,838		)	(25,728		)	103.6	%
Net loss attributable to Pattern Energy	$	(29,828	)	$	(4,013	)	$	(25,815	)	643.3	%	$	(9,955	)	$	(30,906	)	$	20,951		(67.8	)%

Total revenue

Total revenue for the three months ended September 30, 2017 was $92.0 million compared to $91.9 million for the three months ended September 30, 2016 , an increase of $0.1 million , or approximately 0.1% . The slight increase was primarily attributable to:


•	a $16.5 million increase in electricity sales primarily due to volume increases as a result of our acquisitions in 2017.

This increase in electricity sales was largely offset by:


•	a decrease of $11.6 million due to unfavorable wind condition and availability;


•	a decrease of $3.0 million in electricity sales driven by lower floating prices to sell and higher floating prices to purchase electricity at delivery points under power sales agreements in our Texas markets and other regional market price fluctuations; and


•	a $2.3 million increase in unrealized loss on energy derivative due to an increase in the forward gas price curves when compared to the prior period.

Total revenue for the nine months ended September 30, 2017 was $300.6 million compared to $273.0 million for the nine months ended September 30, 2016 , an increase of $27.6 million , or approximately 10.1% . The increase was primarily attributable to:


•	a $31.0 million increase in electricity sales primarily due to volume increases as a result of our acquisitions in 2017 and an increase in PPA contractual volume for Amazon Wind Farm Fowler Ridge;


•	a $5.3 million net increase in electricity sales due to favorable wind conditions offset by lower availability; and


•	a $4.8 million decrease in unrealized losses primarily due to a larger decrease in the change in the forward gas price curves when compared to the prior period.

This increase was largely offset by a decrease of $15.0 million in electricity sales driven by lower floating prices to sell and higher floating prices to purchase electricity at delivery points under power sales agreements in our Texas markets and other regional market price fluctuations.

Cost of revenue

Cost of revenue for the three months ended September 30, 2017 was $93.7 million compared to $75.1 million for the three months ended September 30, 2016 , an increase of $18.7 million , or approximately 24.8% . Acquisitions completed in 2017 resulted in increases of $4.3 million in project expense, $8.3 million in depreciation and $7.3 million in transmission costs. These increases were partially offset by a decrease in turbine maintenance expense.

Cost of revenue for the nine months ended September 30, 2017 was $253.3 million compared to $227.8 million for the nine months ended September 30, 2016 , an increase of $25.5 million , or approximately 11.2% . Acquisitions completed in 2017 resulted in increases of $6.2 million in project expense, $11.9 million in transmission costs and $13.1 million in depreciation. These increases were partially offset by a $5.5 million decrease in turbine maintenance expense.

Operating expenses

Operating expenses for the three months ended September 30, 2017 were comparable to operating expenses for the three months ended September 30, 2016 .

Operating expenses for the nine months ended September 30, 2017 were $42.6 million compared to $34.8 million for the nine months ended September 30, 2016 , an increase of $7.8 million , or approximately 22.3% . The increase in operating expenses was primarily attributable to a $3.9 million increase in consulting, legal and audit fees related to control remediation efforts, a $3.2 million increase in related party expenses and a $0.7 million increase in employee related and other expenses.

Other expense

Other expense for the three months ended September 30, 2017 was $37.9 million compared to $13.4 million for the three months ended September 30, 2016 , an increase of $24.4 million , or approximately 182.0% . The increase was primarily attributable to:


•	an $8.6 million decrease in earnings in unconsolidated investments, net primarily due to gains recognized in 2016 as a result of the 2016 suspension of equity method accounting for certain of our unconsolidated investments with decreased project income primarily due to unrealized losses on undesignated derivatives;


•	a $7.3 million increase in interest expense primarily due to the issuance of the Unsecured Senior Notes in January 2017 and debt associated with our acquisitions in 2017;


•	a $5.9 million increase in loss on undesignated derivatives, net primarily due to losses from foreign currency hedges; and


•	a $2.2 million increase in realized loss due to the termination of the interest rate swaps at Lost Creek.

Other expense for the nine months ended September 30, 2017 was $59.8 million compared to $62.1 million for the nine months ended September 30, 2016 , a decrease of $2.3 million , or approximately 3.7% . Contributing to the decrease in other expense was:


•	a $11.7 million increase in earnings in unconsolidated investments, net primarily due to unrealized gains on undesignated derivatives, the acquisition of Armow in the fourth quarter 2016, increased wind production partially offset by gains recognized in 2016 as a result of the 2016 suspension of equity method accounting for certain of our unconsolidated investments; and


•	an $8.2 million decrease in loss on undesignated derivatives, net primarily due to higher LIBOR curve in the current period compared to the same period in the prior year; partially offset by:


•	a $12.4 million increase in interest expense primarily due to the issuance of the Unsecured Senior Notes in January 2017 and debt associated with our acquisitions in 2017;


•	a $2.3 million increase in transaction costs and accretion expense primarily related to the acquisition of the Broadview Project; and


•	a $2.2 million increase in realized loss due to the termination of the interest rate swaps at Lost Creek.

Tax (benefit) provision

Tax benefit for the three months ended September 30, 2017 was $3.8 million compared to the tax provision of $1.3 million for the three months ended September 30, 2016 , a change of $5.2 million . 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 in the current year. This exception resulted in a tax benefit for the three months ended September 30, 2017.

Tax provision for the nine months ended September 30, 2017 was $5.5 million compared to the tax provision of $4.0 million for the nine months ended September 30, 2016 an increase of $1.4 million . The tax provision for the nine months ended September 30, 2017 was primarily the result of recording the tax effects on the recognized equity income from operations in unconsolidated investments and local taxes on foreign operations, offset by a tax benefit allocated from the exception to the general rule of intraperiod allocation, as discussed above.

Net loss

Net loss for the three months ended September 30, 2017 was $48.4 million compared to $11.1 million for the same period in the prior year; an increase of $37.3 million or 337.8% . The increase in losses was primarily attributable to:


•	a $18.7 million increase in cost of revenues due to our acquisitions in 2017; and


•	a $24.4 million increase in other expense primarily related to a decrease in earnings in unconsolidated investments, net, an increase in interest expense, an increase in loss on undesignated derivatives, and an increase in realized loss on derivatives.

The decrease to earnings was partially offset by an increase in tax benefit of $5.2 million .

Net loss for the nine months ended September 30, 2017 was $60.5 million compared to $55.7 million for the same period in the prior year; an increase of $4.8 million or 8.6% . The increase in losses was primarily attributable to:


•	a $25.5 million increase in cost of revenues due to our acquisitions in 2017;


•	a $7.8 million increase in operating expenses; and


•	a $1.4 million increase in tax provision.

These increases in net loss were partially offset by increased revenue of $27.6 million and lower other expense of $2.3 million primarily related to an increase in earnings in unconsolidated investments and decreased losses on undesignated derivatives, net.

Noncontrolling interest

The net loss attributable to noncontrolling interest was $18.5 million for the three months ended September 30, 2017 compared to $7.0 million for the three months ended September 30, 2016 . The increased loss of $11.5 million was attributable to increased allocations of losses to tax equity projects, including allocations to Broadview which was acquired during the second quarter of 2017.

The net loss attributable to noncontrolling interest was $50.6 million for the nine months ended September 30, 2017 compared to $24.8 million for the nine months ended September 30, 2016 . The increased loss of $25.7 million was attributable to increased allocations of losses to tax equity projects, including allocations to Broadview which was acquired during the second quarter of 2017.

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) unforeseen events and (viii) other business expenses. As a part of our liquidity strategy, we plan to retain a portion of our cash flows in above-average wind years in order to have additional liquidity in below-average wind years.

Sources of Liquidity

Our sources of liquidity include cash generated by our operations, cash reserves, borrowings under our corporate and project-level credit agreements and further issuances of equity and debt securities.

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



	September 30, 2017
Unrestricted cash	$	91.1
Restricted cash	27.0
Revolving credit facility availability ⁽¹⁾	210.7
Project facilities:
Post construction use	137.4
Total available liquidity	$	466.2


⁽¹⁾	As of November 6, 2017 , the amount available on the Revolving Credit Facility is $401.7 million.

We believe that for the remainder of 2017, we will have sufficient liquid assets, cash flows from operations, and borrowings available under our Revolving Credit Facility to meet our financial commitments, debt service obligations, contingencies and anticipated required capital expenditures for at least the next 24 months, 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, 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.

On October 23, 2017, we completed an underwritten public offering of our Class A common stock. In total, 9,200,000 shares of our Class A common stock were sold at a public offering price of $23.40 per share including 1,200,000 shares purchased by the underwriters to cover over-allotments. Aggregate net proceeds of the equity offering, including the proceeds of the over-allotment option, were approximately $212.1 million after deduction of underwriting discounts, commissions, and transaction expenses.

In June 2017, PSP agreed to cooperate with us on future third-party acquisitions and to support our funding through potential bridge financing for projects under construction.

In January 2017, we issued the Unsecured Senior Notes with an aggregate principal amount of $350.0 million . Net proceeds to us were approximately $345.0 million , after deducting the initial purchasers’ discount, commissions and transaction expenses. We used approximately $215 million of the net proceeds to partially fund our acquisition of the Broadview Project and used $128 million of proceeds to repay borrowings incurred under the Revolving Credit Facility to finance the purchase of the Armow project. The Unsecured Senior Notes bear interest at a rate of 5.875% per year, payable semiannually in arrears on February 1 and August 1, beginning on August 1, 2017 and maturing on February 1, 2024, unless repurchased or redeemed at an earlier date. The Unsecured Senior Notes are guaranteed on a senior unsecured basis by Pattern US Finance Company, one of our subsidiaries.

On May 9, 2016, we entered into an Equity Distribution Agreement with RBC Capital Markets, LLC, KeyBanc Capital Markets Inc. and Morgan Stanley & Co. LLC (collectively, the “Agents”). 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 through the Agents, as our sales agents for the offer and sale of the shares, 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, 2017 , we sold 931,561 shares under the Equity Distribution Agreement; net proceeds under the issuance were $22.5 million and the aggregate compensation paid by the Company to the Agents with respect to such sales was $0.2 million . As of September 30, 2017 , approximately $147.5 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, 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,
	2017			2016
Net cash provided by operating activities	$	159.3		$	107.4
Net cash provided by (used in) investing activities	(314.8		)	6.0
Net cash provided by (used in) financing activities	160.2			(170.4		)
Effect of exchange rate changes on cash, cash equivalents and restricted cash	4.0			1.8
Net change in cash, cash equivalents and restricted cash	$	8.7		$	(55.3	)

Net cash provided by operating activities

Net cash provided by operating activities was $159.3 million for the nine months ended September 30, 2017 as compared to $107.4 million in the prior year, an increase of $52.0 million , or approximately 48.4% . The increase in cash provided by operating activities was primarily due to a $23.0 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs) , increased distributions from unconsolidated investments of $42.7 million and an increase of $19.0 million in payables and accrued liabilities due primarily to the timing of payments; partially offset by increased transmission costs of $11.9 million, increased operating expenses of $7.8 million , and increased interest payments of $10.9 million.

Net cash provided by (used in) investing activities

Net cash used in investing activities was $314.8 million for the nine months ended September 30, 2017 , which consisted of $289.3 million in cash paid, net of cash and restricted cash acquired, for our acquisitions completed in 2017, and $44.3 million for capital expenditures, which primarily relates to payments for construction liabilities assumed with our acquisitions completed in 2017, partially offset by $11.2 million in distributions from unconsolidated investments and $7.6 million in reimbursement of interconnection costs.

Net cash provided by investing activities was $6.0 million for the nine months ended September 30, 2016 , which consisted primarily of $40.1 million in distributions received from unconsolidated investments, partially offset by $31.6 million for capital expenditures including $ 20.7 million related to payments for a project that became commercially operable in the fourth quarter of 2015.

Net cash provided by (used in) financing activities

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 as discussed previously;


•	$377.4 million in proceeds from other long-term debt and the Revolving Credit Facility; and


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

Net cash provided by financing activities was partially offset by:


•	$250.0 million in repayments of the Revolving Credit Facility;


•	$107.9 million of dividend payments;


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


•	$7.8 million in payments for deferred financing costs primarily associated with the issuance of the Unsecured Senior Notes;


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


•	$13.7 million in distributions to noncontrolling interests.

Net cash used in financing activities for the nine months ended September 30, 2016 was $170.4 million . Net cash used in financing activities consisted primarily of the following:


•	$85.2 million of dividend payments;


•	$11.8 million in distributions to noncontrolling interests;


•	$39.3 million in repayments of debt; and


•	$340.0 million in repayment of the Revolving Credit Facility.

Net cash used in financing activities were partially offset by:


•	$286.6 million of net proceeds from equity issuances, net of expenses; and


•	$20.0 million in proceeds from the Revolving Credit Facility.

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 26, 2017 , we increased our dividend to $0.4220 per share, or $1.688 per share on an annualized basis, commencing with respect to dividends to be paid on January 31, 2018 to holders of record on December 29, 2017 . 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
2017:
Fourth Quarter	$	0.4220	October 26, 2017	December 29, 2017	January 31, 2018
Third Quarter	$	0.4200	August 3, 2017	September 29, 2017	October 31, 2017
Second Quarter	$	0.4180	May 4, 2017	June 30, 2017	July 31, 2017
First Quarter	$	0.41375	February 24, 2017	March 31, 2017	April 28, 2017

We established our quarterly dividend level based on a cash available for distribution payout ratio after considering the annual cash available for distribution that we expect our projects will be able to generate and with due regard to retaining a portion of the cash available for distribution to grow our business. We intend to grow our business primarily through the acquisition of operational and construction-ready power projects, which, we believe, will facilitate the growth of our cash available for distribution and enable us to increase our dividend per share of Class A common stock over time. We may in the future raise capital and make investments in new power projects upon or near the commencement of construction of such projects and therefore prior to the expected commencement of operations of the new projects, which could result in a passage of time of twelve or more months before we begin to receive any cash flow contributions from such projects to our cash available for distribution. In connection with these investments, we may increase our dividends prior to the receipt of such cash flow contributions, which would likely cause our payout ratio to temporarily exceed our targeted run-rate payout ratio. However, the determination of the amount of cash dividends to be paid to holders of our Class A common stock will be made by our Board of Directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant. Refer to Item 1A “Risk Factors—Risks Related to Ownership of our Class A Shares—Risks Regarding our Cash Dividend Policy” in our Annual Report on Form 10-K for the year ended December 31, 2016 .

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. As discussed above, on August 10, 2017, we acquired Meikle from Pattern Development 1.0 for $67.4 million of cash paid at closing. On April 21, 2017, we acquired the Broadview Project from Pattern Development 1.0. The total purchase consideration included $214.7 million of cash paid at closing. In addition, we funded an initial investment of $60 million in Pattern Development 2.0 for an approximately 20% initial ownership interest on July 27, 2017.

We also evaluate, from time to time, third-party acquisition opportunities. We believe that we will have sufficient cash and Revolving Credit Facility capacity to complete the funding of future construction commitments we may have, 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, 2017 , we have budgeted $4.4 million for operational capital expenditures and $5.5 million for expansion capital expenditures, not including construction liabilities acquired as part of our acquisitions completed in 2017. We will also evaluate participation in future potential capital calls by Pattern Development 2.0.

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 8, Debt , and Note 15, Commitments and Contingencies , in the notes to consolidated financial statements for additional discussion of contractual obligations.

As part of our acquisitions completed in 2017, 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 the acquisitions completed in 2017 (in thousands) as of September 30, 2017 :



Contractual Obligations	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Project-level debt principal payments	$	2,835	$	24,876	$	26,513	$	338,172	$	392,396
Project-level interest payments on debt instruments	3,084		22,245		20,788		31,355		77,472
Transmission Service Agreements	6,723		47,200		47,200		543,246		644,369
Payments in lieu of taxes	121		957		818		9,635		11,531
Other	270		1,415		928		3,536		6,149
Operating leases	55		3,460		3,915		57,982		65,412
Service and maintenance agreements	2,728		16,865		8,500		365		28,458
Asset retirement obligations	—		—		—		8,302		8,302
Total	$	15,816	$	117,018	$	108,662	$	992,593	$	1,234,089

Other Commitments

Service and Maintenance Agreements

In March 2017, we entered into revised LTSAs at certain of our projects pursuant to which the turbine manufacturer will continue to provide routine and corrective maintenance service, but we have become responsible for a portion of the maintenance and repairs, including on major component parts. The revised LTSAs reduced fixed contract commitments by approximately $102 million over the next ten years.

Acquisition commitments

On June 16, 2017, we entered into a purchase and sale agreement with Pattern Development 1.0 to purchase (i) a 51% limited partner interest in a newly-formed limited partnership (which will hold 100% of the economic interests in Mont Sainte-Marguerite Wind Farm LP (MSM)), (ii) a 70% interest in Pattern MSM GP Holdings Inc., and (iii) a 70% interest in Pattern Development MSM Management ULC, in exchange for aggregate consideration of CAD $53.0 million (subject to certain adjustments). MSM operates the approximately 143 MW wind farm located near Québec City, Canada.

Investment commitments

On June 16, 2017, we entered into the Second Amended and Restated Agreement of Limited Partnership (A&R PEGH 2 LPA) of PEGH 2. In July 2017, PEGH 2 made a capital call of its new limited partners under the A&R PEGH 2 LPA (the Initial PEGH 2 Capital Call). In connection with the Initial PEGH 2 Capital Call, we made a contribution to PEGH 2 of approximately $60.0 million . As a result of the funding under the Initial PEGH 2 Capital Call and the consummation of certain redemptions, we hold an approximate 20% ownership interest in PEGH 2. Under the A&R PEGH 2 LPA, we have also committed to contribute up to an additional approximately $240.0 million to PEGH 2 in one or more subsequent rounds of financing, which could result in our ownership interest in PEGH 2 increasing to up to approximately 29% . If we elect not to participate in such subsequent rounds of financing, our ownership interest in PEGH 2 may be diluted on a pro rata basis based on fair market value.

Off-Balance Sheet Arrangements

As of September 30, 2017 , 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, 2017 (in thousands):



	Total Project Debt		Percentage of Ownership		Our Portion of Unconsolidated Project Debt
Armow	$	410,096	50.0	%	$	205,048
South Kent	495,991		50.0	%	247,996
Grand	286,205		45.0	%	128,792
K2	605,799		33.3	%	201,913
PEGH 2	$	82,951	20.2	%	$	16,756
Unconsolidated investments - debt	$	1,881,042			$	800,505

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, 2016 .

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 553,513 MWh of electricity sales during the nine months ended September 30, 2017 that were subject to spot market pricing. A hypothetical increase or decrease of 10% or $1.71 per MWh in the merchant market prices would have increased or decreased revenue by $0.9 million for the nine months ended September 30, 2017 .

Interest Rate Risk

As of September 30, 2017 , 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, 2017 , the estimated fair value of our debt was $ 2.2 billion and the carrying value of our debt was $2.2 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 $50.0 million decrease or $54.0 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 Revolving Credit Facility. As of September 30, 2017 , $253 million was outstanding under the Revolving Credit Facility. A hypothetical increase or decrease in interest rates by 1% would have a $2.5 million impact to interest expense related to our Revolving Credit Facility for the nine months ended September 30, 2017 .

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, 2017 , the unhedged portion of our variable rate debt was $80.6 million . A hypothetical increase or decrease in interest rates by 1% would have a $0.8 million impact to interest expense for the nine months ended September 30, 2017 .

Foreign Currency Exchange Rate Risk

Our wind power projects are located in the United States, Canada and Chile. As a result, our financial results could be significantly affected by factors such as changes in foreign currency exchange rates or weak economic conditions in the foreign markets in which we operate. When the U.S. dollar strengthens against foreign currencies, the relative value in revenue earned in the respective foreign currency decreases. When the U.S. dollar weakens against foreign currencies, the relative value in revenue earned in the respective foreign currency increases. A majority of our power sale agreements and operating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. For the nine months ended September 30, 2017 , our financial results included C$40.6 million , or $30.4 million calculated based on the monthly average exchange rate, in Canadian dollar denominated net income, from our Canadian operations. A hypothetical increase or decrease of 10% in exchange rates between the Canadian and U.S. dollar would have increased or decreased net earnings of our Canadian operations by $3.0 million for the nine months ended September 30, 2017 .

In January 2015, we established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in our cash flow, which may have an adverse impact to our short-term liquidity or financial condition. For the nine months ended September 30, 2017 , we recognized an unrealized loss on foreign currency forward contracts of $5.7 million in loss on undesignated derivatives, net in the consolidated statements of operations. We also recognized a realized loss of $1.4 million in gain (loss) on undesignated derivatives, net in the consolidated statements of operations related to foreign currency forward contracts that matured during the nine months ended September 30, 2017 .

As of September 30, 2017 , a 10% devaluation in the Canadian dollar to the United States dollar would result in our consolidated balance sheets being negatively impacted by a $36.4 million cumulative translation adjustment in accumulated other comprehensive loss.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of September 30, 2017 . Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of September 30, 2017 , our disclosure controls and procedures were not effective at the reasonable assurance level as a result of the material weaknesses previously disclosed under Item 9A. "Controls and Procedures" in our Annual Report on Form 10-K for our fiscal year ended December 31, 2016 . During the year ended December 31, 2016 , our internal control over financial reporting was not effective due to the aggregation of internal control deficiencies related to the implementation, design, maintenance and operating effectiveness of various transaction, process level, and monitoring controls. These deficiencies largely have arisen during fiscal 2016 because of growth of the Company, increases in employee headcount to support growth, and frequent changes in organizational structure that were not adequately supported by elements of our internal control over financial reporting. The deficiencies can be grouped generally as ineffective training programs, accounting policies and procedures, monitoring and management review controls, contract review, and procure-to-pay procedures.

However, after giving full consideration to these material weaknesses, and the additional analyses and other procedures that we performed to ensure that our consolidated financial statements included in this Quarterly Report on Form 10-Q were prepared in accordance with U.S. generally accepted accounting principles (GAAP), our management has concluded that our consolidated financial statements present fairly, in all material respects, our financial position, results of operations and cash flows for the periods disclosed in conformity with GAAP.

Remediation Plan and Efforts with Respect to Material Weaknesses

Our management has developed a plan to remediate the material weaknesses in our internal control over financial reporting including the following:


•	providing SOX 404 and internal control training to accounting, executive management, and various department personnel;


•	documenting accounting, entity level, and IT policies and procedures that support our internal control infrastructure;


•	redesigning the contract review process that improves communication and informational flow between the various company departments including legal and accounting for the complete and accurate recording of contract provisions; and


•	redesigning and implementing changes to certain processes and internal controls.

Through September 30, 2017, substantial progress has been made and efforts continue to track with management’s overall remediation plan. Throughout the year, management has provided additional training, improved documentation of policies and procedures, and has established a new contract review process.

As a part of its overall plan to remediate the material weaknesses that were identified in the prior year, management has undertaken an extensive effort to redesign certain of its processes and internal controls and to update all documentation related to its system of internal controls. Through September 30, 2017, that redesign and documentation was largely completed and we have confirmed the majority of the redesign through walk-throughs of our redesigned controls.

In completing its assessment of internal control over financial reporting as of December 31, 2017, management will complete all design considerations including those not yet confirmed through walk-throughs and those relating to annual controls performed as part of year-end processes and controls. Through our tests of controls, we will evaluate the operating effectiveness of our internal control over financial reporting as of December 31, 2017.

Change in Internal Control Over Financial Reporting

Other than the steps taken set forth above as a part of our remediation plan, there was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) of the Exchange Act that occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject, from time to time, to routine legal proceedings and claims arising out of the normal course of business. There has been no material change in the nature of our legal proceedings from the description provided in our Annual Report on Form 10-K for the year ended December 31, 2016 , as supplemented by the description provided in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should consider the risks described under the caption “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2016 . There have been no material changes in our risk factors as described in such document except for the following:

Our projects rely on a limited number of key power purchasers.

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

For example, our 101 MW Santa Isabel project located on the south coast of Puerto Rico sells 100% of its electricity generation including environmental attributes to PREPA under a 20-year PPA. On July 2, 2017, the Financial Oversight and Management Board (or Oversight Board) established pursuant to the Puerto Rico Oversight, Management, and Economic Stability Act (or PROMESA) with oversight authority over the Commonwealth of Puerto Rico and its agencies, including the Puerto Rico Electric Power Authority (or PREPA), filed a voluntary petition for relief for PREPA in the U.S. District Court for the District of Puerto Rico. The petition was filed pursuant to PROMESA thereby commencing a case under Title III thereof which is a specific statutory vehicle that allows the Commonwealth of Puerto Rico and its instrumentalities, such as PREPA, to adjust their debt (similar to a bankruptcy proceeding). We plan to file a notice of appearance in the proceeding as a creditor of PREPA affected by the Title III filing. While PREPA has previously made payments of amounts due under the PPA for production, as of the date of this Quarterly Report on Form 10-Q, PREPA is approximately two weeks late with respect to a payment due under the PPA for certain production prior to Hurricane Maria (see further discussion under the additional risk factor below). No assurances can be given that PREPA will pay such overdue receivable or continue to pay future receivables. Furthermore, under the Title III proceeding, PREPA and the Oversight Board will eventually need to determine whether to assume the PPA or reject the PPA, subject to court approval. A rejection of the PPA and our inability to find satisfactory alternatives for the offtaker of energy produced by the Santa Isabel facility would likely have a material adverse effect on our business prospects, financial condition and results of operations.

The fact of PREPA’s insolvency and its filing under Title III each constituted an event of default under the project’s financing agreement. However, on August 7, 2017, the lender issued a letter withdrawing the event of default associated with the PREPA insolvency. Pursuant to our agreement with the lender, the Santa Isabel project may not make distributions to us until such time as lender consents (lender’s consent will not be unreasonably withheld if PREPA assumes the PPA). Despite such agreement, no assurances can be given that PREPA will determine to assume the PPA, will not take actions that separately constitute an event of default under our financing agreement, or that Santa Isabel will be able to remain current with respect to its payments under the financing agreement (see further discussion under the additional risk factor below). In any such event, another event of default under the financing agreement would occur and no assurances can be given that the lender would agree to a further withdrawal, waiver or other standstill of any such other event of default, or the lender would not otherwise decide in such circumstance to accelerate and declare the entire amount of debt under the financing agreement immediately due and payable. Even though the

Santa Isabel financing agreement is non-recourse to us, it is secured by the Santa Isabel project and any an exercise of remedies by the lender could have a material adverse effect on our business prospects, financial condition and results of operations.

Our Santa Isabel project in Puerto Rico has been shut-in as a result of Hurricane Maria.

On September 20, 2017, Hurricane Maria, a category 4 hurricane, made direct landfall on Puerto Rico and caused substantial damage to PREPA’s electricity transmission and distribution assets. PREPA declared a force majeure under the PPA with respect to its assets, relieving it of its obligations to perform substantially all of its obligations under the PPA, excluding its obligation to make payments thereunder. While initial indications are that our equipment did not suffer significant damage, we are still completing an assessment and could still find damage that has not yet been identified which could compromise the ability of the facility to operate. In addition, to date PREPA has demanded a completed inspection and a technical report prior to allowing our facility to receive backfeed electrical service or begin generating. It is uncertain what conditions PREPA will place on our return to service in terms of timeline or output restrictions, and this could have a material impact on our ability to generate revenues at the facility for an indeterminate amount of time into the future.

As indicated in the preceding risk factor, PREPA is approximately two weeks late with respect to a payment due under the PPA for production prior to Hurricane Maria. In addition to such outstanding receivable amounting to $2.3 million, an additional receivable of $0.4 million for production prior to the hurricane is due and expected in mid-to-late November. While these payments are not relieved under the force majeure, no assurances can be given that PREPA will pay these receivables or any future receivables. PREPA’s failure to make payments when due (after an applicable cure period) may constitute an event of default under the Santa Isabel financing agreement and subject us to the risks of such default described in the preceding risk factor which may materially adversely affect the value of the Santa Isabel project and could have a material adverse effect on our business prospects, financial condition and results of operations. Further, given the current condition of PREPA’s transmission and distribution assets and the logistical complexity associated with remediating the damage, no assurances can be given as to when the force majeure under the PPA will abate and PREPA’s performance will resume under the PPA, or how the disruption will affect PREPA’s bankruptcy-like proceedings under Title III of the PROMESA described in the preceding risk factor.

Our projects rely on interconnections to transmission lines and other transmission facilities that are owned and operated by third parties which exposes us to risks. Our projects are also exposed to interconnection and transmission facility development and curtailment risks, which may delay the completion of any construction projects or reduce the return to us on those investments.

Our projects depend upon interconnection to electric transmission lines owned and operated by regulated utilities to deliver the electricity we generate. A failure or delay in the operation or development of these interconnection or transmission facilities could result in our losing revenues because such a failure or delay could limit the amount of power our operating projects deliver or delay the completion of any construction projects. For example, in late October 2017, Arizona Public Service, one of the transmission service providers the Broadview project utilizes to transmit power from New Mexico to California, provided notice that the substation to which the project is required to deliver power under its PPA would be shut down for approximately 60 days for maintenance. While we have taken steps to mitigate the transmission outage at the delivery substation, including making alternative transmission arrangements to deliver power at an alternative substation through alternative short term transmission and revenue arrangement, no assurances can be given that the revenues produced from such alternative arrangements will be equivalent to the revenues that would have been generated had such transmission outage not occurred. Furthermore, there are risks associated with each of the individual alternative arrangements we have made to mitigate the transmission outage, such as possible curtailment risks on the alternative transmission arrangements or pricing risks in the merchant power market, which could adversely affect the overall efficacy of our mitigation efforts. Any sustained transmission outage at the delivery substation or failure in our mitigation efforts, individually or in aggregate, could have a material adverse effect on our business prospects, financial condition and results of operation.

In addition, certain of our operating projects’ generation of electricity may be curtailed without compensation due to transmission limitations or limitations on the electricity grid’s ability to accommodate intermittent electricity generating sources, reducing our revenues and impairing our ability to capitalize fully on a particular project’s potential. Such a failure or curtailment at levels above our expectations could have a material adverse effect on our business prospects, financial condition and results of operations.

In the future we may acquire projects with their own generator leads to available electricity transmission or distribution networks. In some cases, these facilities may cover significant distances. A failure in our operation of these facilities that causes the facilities to be temporarily out of service, or subject to reduced service, could result in lost revenues because it could limit the amount of electricity our operating projects are able to deliver. In addition, in many of the markets in which we operate or are looking to expand, should there be any excess capacity available in those generator lead facilities, and should a third party request access to such capacity, the relevant regulatory authority in such jurisdiction, such as FERC in the United States, or other authorities might,

require our projects to provide service over such facilities for that excess capacity to the requesting third party at regulated rates. Should this occur in markets with such regulations, the projects could be subject to additional regulatory risks and costly compliance burdens associated with being considered the owner and operator of a transmission facility.

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		Amended and Restated Purchase Rights Agreement by and among Pattern Development 1.0, the Company, Pattern Energy Group Holdings LP (solely with respect to Article IV therein) and Pattern Energy GP LLC, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed June 19, 2017).

10.2		Amended and Restated Purchase Rights Agreement by and among Pattern Development 2.0, the Company, Pattern Energy Group Holdings 2 LP (solely with respect to Article III therein) and Pattern Energy Group Holdings 2 GP LLC, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed June 19, 2017).

10.3		Second Amended and Restated Non-Competition Agreement by and among Pattern Development 1.0, the Company and Pattern Development 2.0, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed June 19, 2017).

10.4		Amended and Restated Multilateral Management Services Agreement by and among the Company, Pattern Development 1.0 and Pattern Development 2.0, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed June 19, 2017).

10.5		Second Amended and Restated Limited Partnership Agreement of Pattern Energy Group Holdings 2 LP, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed June 19, 2017).

10.6		Joint Venture Agreement between PSP Investments and the Company, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K filed June 19, 2017).

10.7		Sponsor Services Agreement between the Company and PSP Investments, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K filed June 19, 2017).

10.8		Purchase and Sale Agreement by and among the Company, Vertuous Energy Canada Inc. and Pattern Development 1.0, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K filed June 19, 2017).

10.9		Purchase and Sale Agreement by and among the Company, Vertuous Energy Canada Inc. and Pattern Development 1.0, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.9 to the Company's Current Report on Form 8-K filed June 19, 2017).

10.10		Purchase and Sale Agreement by and among Vertuous Energy LLC and the Company, dated as of June 16, 2017 (Incorporated by reference to Exhibit 10.10 to the Company's Current Report on Form 8-K filed June 19, 2017).



10.11		Amended and Restated Limited Partnership Agreement among Pattern Canada Finance Company ULC, Vertuous Energy Canada Inc. and Meikle Wind Energy Corp. dated as of August 10, 2017 (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed August 14, 2017).

10.12		Shareholders Agreement among Pattern Canada Finance Company ULC, Vertuous Energy Canada Inc. and Meikle Wind Energy Corp. dated as of August 10, 2017 (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed August 14, 2017).
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 9, 2017	By:	/s/ Michael J. Lyon
			Michael J. Lyon
			Chief Financial Officer

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