Edgar Filing: Pattern Energy Group Inc.

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended June 30, 2016.



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

Commission File Number 001-36087

PATTERN ENERGY GROUP INC.

(Exact name of Registrant as specified in its charter)



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

Pier 1, Bay 3, San Francisco, CA 94111

(Address of principal executive offices) (Zip Code)

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

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

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

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



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

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

As of August 3, 2016, there were 76,170,183 shares of Class A common stock outstanding with par value of $0.01 per share.

PATTERN ENERGY GROUP INC.

REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2016

TABLE OF CONTENTS



	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	5
	Consolidated Balance Sheets as of June 30, 2016 (unaudited) and December 31, 2015	5
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2016 and 2015 (unaudited)	6
	Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2016 and 2015 (unaudited)	7
	Consolidated Statements of Stockholders’ Equity for the Six Months Ended June 30, 2016 and 2015 (unaudited)	8
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2016 and 2015 (unaudited)	9
	Notes to Consolidated Financial Statements (unaudited)	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	41
Item 4.	Controls and Procedures	44

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 6.	Exhibits	45
	Signatures	47

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 the acquisition 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, 2015.

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

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

	June 30,			December 31,
	2016			2015
Assets
Current assets:
Cash and cash equivalents (Note 5)	$	87,641		$	94,808
Restricted cash (Note 5)	12,228			14,609
Funds deposited by counterparty	49,480			—
Trade receivables (Note 5)	49,329			45,292
Related party receivable	689			734
Reimbursable interconnection costs	—			38
Derivative assets, current	18,381			24,338
Prepaid expenses (Note 5)	11,128			14,498
Other current assets (Note 5)	10,102			6,891
Deferred financing costs, current, net of accumulated amortization of $6,310 and $5,192 as of June 30, 2016 and December 31, 2015, respectively	2,158			2,121
Total current assets	241,136			203,329
Restricted cash (Note 5)	16,372			36,875
Property, plant and equipment, net of accumulated depreciation of $498,867 and $409,161 as of June 30, 2016 and December 31, 2015, respectively (Note 5)	3,225,658			3,294,620
Unconsolidated investments	92,792			116,473
Derivative assets	31,704			44,014
Deferred financing costs	3,572			4,572
Net deferred tax assets	10,888			6,804
Finite-lived intangible assets, net of accumulated amortization of $7,734 and $4,357 as of June 30, 2016 and December 31, 2015, respectively (Note 5)	94,256			97,722
Other assets (Note 5)	23,930			25,183
Total assets	$	3,740,308		$	3,829,592

Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities (Note 5)	$	29,923		$	42,776
Accrued construction costs (Note 5)	4,494			23,565
Counterparty deposit liability	49,480			—
Related party payable	833			1,646
Accrued interest (Note 5)	8,916			9,035
Dividends payable	29,711			28,022
Derivative liabilities, current	15,711			14,343
Revolving credit facility	335,000			355,000
Current portion of long-term debt, net of financing costs of $3,638 and $3,671 as of June 30, 2016 and December 31, 2015, respectively	45,721			44,144
Other current liabilities (Note 5)	2,557			2,156
Total current liabilities	522,346			520,687
Long-term debt, net of financing costs of $21,036 and $22,632 as of June 30, 2016 and December 31, 2015, respectively	1,163,229			1,174,380
Convertible senior notes, net of financing costs of $4,449 and $5,014 as of June 30, 2016 and December 31, 2015, respectively	200,103			197,362
Derivative liabilities	69,842			28,659
Net deferred tax liabilities	22,860			22,183
Finite-lived intangible liability, net of accumulated amortization of $3,902 and $2,168 as of June 30, 2016 and December 31, 2015, respectively	56,398			58,132
Other long-term liabilities (Note 5)	60,004			52,427
Total liabilities	2,094,782			2,053,830
Commitments and contingencies (Note 15)
Equity:
Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 74,930,002 and 74,644,141 shares outstanding as of June 30, 2016 and December 31, 2015, respectively	750			747
Additional paid-in capital	927,812			982,814
Accumulated loss	(104,052		)	(77,159		)
Accumulated other comprehensive loss	(94,037		)	(73,325		)
Treasury stock, at cost; 67,344 and 65,301 shares of Class A common stock as of June 30, 2016 and December 31, 2015, respectively	(1,617		)	(1,577		)
Total equity before noncontrolling interest	728,856			831,500
Noncontrolling interest	916,670			944,262
Total equity	1,645,526			1,775,762
Total liabilities and equity	$	3,740,308		$	3,829,592

See accompanying notes to consolidated financial statements.

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

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Revenue:
Electricity sales	$	91,370		$	82,871		$	177,033		$	146,996
Related party revenue	1,332			872			2,547			1,675
Other revenue	736			928			1,497			866
Total revenue	93,438			84,671			181,077			149,537
Cost of revenue:
Project expense	33,359			27,981			65,605			53,227
Depreciation and accretion	43,678			34,342			87,089			63,398
Total cost of revenue	77,037			62,323			152,694			116,625
Gross profit	16,401			22,348			28,383			32,912
Operating expenses:
General and administrative	10,362			8,870			19,931			15,091
Related party general and administrative	1,931			1,621			3,828			3,429
Total operating expenses	12,293			10,491			23,759			18,520
Operating income	4,108			11,857			4,624			14,392
Other income (expense):
Interest expense	(21,275		)	(18,943		)	(42,336		)	(36,861		)
Gain (loss) on undesignated derivatives, net	(5,879		)	4,178			(19,510		)	778
Earnings in unconsolidated investments, net	7,240			13,801			11,070			10,719
Related party income	1,097			756			2,104			1,424
Net loss on transactions	(72		)	(1,305		)	(39		)	(2,589		)
Other income (expense), net	564			(1,084		)	2,120			(1,408		)
Total other expense	(18,325		)	(2,597		)	(46,591		)	(27,937		)
Net income (loss) before income tax	(14,217		)	9,260			(41,967		)	(13,545		)
Tax provision	1,429			3,603			2,727			2,857
Net income (loss)	(15,646		)	5,657			(44,694		)	(16,402		)
Net loss attributable to noncontrolling interest	(12,423		)	(8,660		)	(17,801		)	(10,820		)
Net income (loss) attributable to Pattern Energy	$	(3,223	)	$	14,317		$	(26,893	)	$	(5,582	)

Weighted average number of shares:
Class A common stock - Basic	74,443,901			68,943,707			74,440,950			67,426,286
Class A common stock - Diluted	74,443,901			69,147,260			74,440,950			67,426,286
Earnings (loss) per share
Class A common stock:
Basic earnings (loss) per share	$	(0.04	)	$	0.21		$	(0.36	)	$	(0.08	)
Diluted earnings (loss) per share	$	(0.04	)	$	0.21		$	(0.36	)	$	(0.08	)
Dividends declared per Class A common share	$	0.39		$	0.35		$	0.77		$	0.71

See accompanying notes to consolidated financial statements.

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

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Net income (loss)	$	(15,646	)	$	5,657		$	(44,694	)	$	(16,402	)
Other comprehensive income (loss):
Foreign currency translation, net of zero tax impact	780			(498		)	11,642			(9,692		)
Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax benefit (provision) of $1,379, ($628), $4,102, and $56, respectively	(9,964		)	10,100			(30,661		)	(657		)
Reclassifications to net loss, net of tax impact of $281, $168, $583 and $341, respectively	2,721			3,465			5,623			6,956
Total change in effective portion of change in fair market value of derivatives	(7,243		)	13,565			(25,038		)	6,299
Proportionate share of equity investee’s derivative activity:
Effective portion of change in fair market value of derivatives, net of tax benefit (provision) of $1,296, ($7), $3,969 and $859, respectively	(3,594		)	20			(11,008		)	(2,382		)
Reclassifications to net loss, net of tax impact of $470, $206, $922 and $377, respectively	1,304			571			2,557			1,045
Total change in effective portion of change in fair market value of derivatives	(2,290		)	591			(8,451		)	(1,337		)
Total other comprehensive income (loss), net of tax	(8,753		)	13,658			(21,847		)	(4,730		)
Comprehensive income (loss)	(24,399		)	19,315			(66,541		)	(21,132		)
Less comprehensive loss attributable to noncontrolling interest:
Net loss attributable to noncontrolling interest	(12,423		)	(8,660		)	(17,801		)	(10,820		)
Derivative activity:
Effective portion of change in fair market value of derivatives, net of tax benefit (provision) of $164, ($188), $507 and $17, respectively	(442		)	955			(1,370		)	(985		)
Reclassifications to net loss, net of tax impact of $40, $50, $87 and $102, respectively	107			905			235			1,821
Total change in effective portion of change in fair market value of derivatives	(335		)	1,860			(1,135		)	836
Comprehensive loss attributable to noncontrolling interest	(12,758		)	(6,800		)	(18,936		)	(9,984		)
Comprehensive income (loss) attributable to Pattern Energy	$	(11,641	)	$	26,115		$	(47,605	)	$	(11,148	)

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
	Shares	Amount		Shares		Amount			Additional Paid-in Capital			Accumulated Loss			Accumulated Other Comprehensive Loss			Total			Noncontrolling Interest			Total Equity
Balances at December 31, 2014	62,088,306	$	621	(25,465	)	$	(717	)	$	723,938		$	(44,626	)	$	(45,068	)	$	634,148		$	530,586		$	1,164,734
Issuance of Class A common stock related to the public offering, net of issuance costs	7,000,000	70		—		—			196,089			—			—			196,159			—			196,159
Issuance of Class A common stock under equity incentive award plan	186,136	2		—		—			(2		)	—			—			—			—			—
Repurchase of shares for employee tax withholding	—	—		(11,058	)	(310		)	—			—			—			(310		)	—			(310		)
Stock-based compensation	—	—		—		—			1,989			—			—			1,989			—			1,989
Dividends declared	—	—		—		—			(48,003		)	—			—			(48,003		)	—			(48,003		)
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(1,511		)	(1,511		)
Acquisition of Post Rock	—	—		—		—			—			—			—			—			205,100			205,100
Other	—	—		—		—			4			—			—			4			—			4
Net loss	—	—		—		—			—			(5,582		)	—			(5,582		)	(10,820		)	(16,402		)
Other comprehensive income (loss), net of tax	—	—		—		—			—			—			(5,566		)	(5,566		)	836			(4,730		)
Balances at June 30, 2015	69,274,442	$	693	(36,523	)	$	(1,027	)	$	874,015		$	(50,208	)	$	(50,634	)	$	772,839		$	724,191		$	1,497,030

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 under equity incentive award plan	287,904	3		—		—			(3		)	—			—			—			—			—
Repurchase of shares for employee tax withholding	—	—		(2,043	)	(40		)	—			—			—			(40		)	—			(40		)
Stock-based compensation	—	—		—		—			2,777			—			—			2,777			—			2,777
Dividends declared	—	—		—		—			(57,810		)	—			—			(57,810		)	—			(57,810		)
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(8,187		)	(8,187		)
Other	—	—		—		—			34			—			—			34			(469		)	(435		)
Net loss	—	—		—		—			—			(26,893		)	—			(26,893		)	(17,801		)	(44,694		)
Other comprehensive loss, net of tax	—	—		—		—			—			—			(20,712		)	(20,712		)	(1,135		)	(21,847		)
Balances at June 30, 2016	74,997,346	$	750	(67,344	)	$	(1,617	)	$	927,812		$	(104,052	)	$	(94,037	)	$	728,856		$	916,670		$	1,645,526

See accompanying notes to consolidated financial statements.

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

	Six months ended June 30,
	2016			2015
Operating activities
Net loss	$	(44,694	)	$	(16,402	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and accretion	87,089			63,841
Amortization of financing costs	3,498			3,636
Amortization of debt discount/premium, net	2,074			—
Amortization of power purchase agreements, net	1,507			—
Loss on derivatives, net	32,209			333
Stock-based compensation	2,777			1,989
Deferred taxes	2,487			2,616
Earnings in unconsolidated investments	(11,070		)	(10,719		)
Distributions from unconsolidated investments	377			—
Other reconciling items	(965		)	1,170
Changes in operating assets and liabilities:
Funds deposited by counterparty	(49,480		)	—
Trade receivables	(3,753		)	(4,924		)
Prepaid expenses	3,400			3,107
Other current assets	(2,998		)	334
Other assets (non-current)	1,839			(99		)
Accounts payable and other accrued liabilities	(9,631		)	615
Counterparty deposit liability	49,480			—
Related party receivable/payable	(735		)	(7		)
Accrued interest	(178		)	689
Other current liabilities	381			1,151
Long-term liabilities	6,363			1,270
Increase in restricted cash	(986		)	—
Net cash provided by operating activities	68,991			48,600
Investing activities
Cash paid for acquisitions, net of cash acquired	—			(404,377		)
Decrease in restricted cash	20,561			25,277
Increase in restricted cash	(64		)	(6,966		)
Capital expenditures	(25,953		)	(216,499		)
Distributions from unconsolidated investments	31,774			13,847
Reimbursable interconnection receivable	38			1,246
Other assets (non-current)	—			(6,074		)
Other investing activities	(163		)	—
Net cash provided by (used in) investing activities	26,193			(593,546		)

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

	Six months ended June 30,
	2016			2015
Financing activities
Proceeds from public offering, net of issuance costs	$	—		$	196,591
Repurchase of shares for employee tax withholding	(40		)	(310		)
Dividends paid	(56,097		)	(39,170		)
Payment for deferred equity issuance costs	(677		)	(2,204		)
Capital distributions - noncontrolling interest	(8,187		)	(1,511		)
Decrease in restricted cash	25,714			18,532
Increase in restricted cash	(22,342		)	(21,718		)
Refund of deposit for letters of credit	—			3,425
Payment for deferred financing costs	(134		)	(5,614		)
Proceeds from revolving credit facility	20,000			250,000
Repayment of revolving credit facility	(40,000		)	(50,000		)
Proceeds from construction loans	—			206,184
Repayment of long-term debt	(22,262		)	(25,383		)
Other financing activities	(343		)	—
Net cash provided by (used in) financing activities	(104,368		)	528,822
Effect of exchange rate changes on cash and cash equivalents	2,017			(2,596		)
Net change in cash and cash equivalents	(7,167		)	(18,720		)
Cash and cash equivalents at beginning of period	94,808			101,656
Cash and cash equivalents at end of period	$	87,641		$	82,936
Supplemental disclosures
Cash payments for income taxes	$	155		$	186
Cash payments for interest expense, net of capitalized interest	36,535			24,447
Acquired property, plant and equipment from acquisitions	—			579,712
Schedule of non-cash activities
Change in property, plant and equipment	1,302			21,094

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 Development owns a 23% interest in the Company. Pattern Development is a leading developer 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, 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 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 Pattern Panhandle Wind LLC (Panhandle 1), Pattern Panhandle Wind 2 LLC (Panhandle 2), Post Rock Wind Power Project, LLC (Post Rock), Logan's Gap Wind LLC (Logan's Gap) and Fowler Ridge IV Wind Farm LLC (Amazon Wind Farm Fowler Ridge));


•	Pattern Canada Operations Holdings ULC (which consists primarily of 100% ownership of St. Joseph Windfarm Inc. (St. Joseph) and noncontrolling interests in South Kent Wind LP (South Kent), Grand Renewable Wind LP (Grand) and K2 Wind Ontario Limited Partnership (K2), which are accounted for as equity method investments); and


•	Pattern Chile Holdings LLC (which includes a controlling interest in Parque Eólico El Arrayán SpA (El Arrayán)).

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 June 30, 2016, the results of operations and comprehensive income (loss) for the three and six months ended June 30, 2016 and 2015, respectively, and the cash flows for the six months ended June 30, 2016 and 2015, respectively. The consolidated balance sheet at December 31, 2015 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, 2015.

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.

Funds Deposited by Counterparty

As a result of a counterparty's credit rating downgrade, the Company received cash collateral related to an energy derivative agreement, as discussed in Note 10, Derivative Instruments. The Company does not have the right to pledge, invest, or use the cash collateral for general corporate purposes. As of June 30, 2016, the Company has recorded a current asset of $49.5 million to funds deposited by counterparty and a current liability of $49.5 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.

Recently Issued Accounting Standards

In addition to 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, 2015, the Company is evaluating or has adopted the following recently issued accounting standards.

In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13, Financial Instruments —Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (ASU 2016-13), which requires the measurement of all expected credit losses for financial assets including trade receivables held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. ASU 2016-13 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The Company is currently assessing the future impact of this update on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU 2014-09, which creates FASB Accounting Standards Codification (ASC) Topic 606, Revenue from Contracts with Customers and supersedes ASC Topic 605, Revenue Recognition (ASU 2014-09). The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance 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 guidance 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. The effective date of ASU 2014-09 was deferred by the issuance of ASU 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date, (Topic 606) by one year to make the guidance of ASU 2014-09 effective for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, but not prior to the original effective date, which was for annual reporting periods beginning after December 15, 2016. 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 (ASU 2016-12), which makes narrow scope amendments to Topic 606 including implementation issues on collectability, non-cash consideration and completed contracts at transition. The Company is currently assessing the future impact of this guidance on its consolidated financial statements and related disclosures and expects to adopt these updates beginning January 1, 2018.

In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), which simplifies several aspects of the accounting for share-based payment award transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The Company is currently assessing the future impact of this update on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships (ASU 2016-05), which clarifies that a change in the counterparty to a derivative

instrument that has been designated as the hedging instrument does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria remain intact. ASU 2016-05 is effective for annual periods beginning after December 15, 2017, including interim reporting periods therein, with early adoption permitted. The adoption of ASU 2016-05 on January 1, 2016 had no impact on the Company's consolidated financial statements and related disclosures.

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

In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis (ASU 2015-02), which modifies the analysis that companies must perform in order to determine whether a legal entity should be consolidated. ASU 2015-02 simplifies current guidance by reducing the number of consolidation models; eliminating the risk that a reporting entity may have to consolidate based on a fee arrangement with another legal entity; placing more weight on the risk of loss in order to identify the party that has a controlling financial interest; reducing the number of instances that related party guidance needs to be applied when determining the party that has a controlling financial interest; and changing rules for companies in certain industries that ordinarily employ limited partnership or variable interest entity (VIE) structures. ASU 2015-02 is effective for public companies for fiscal years beginning after December 15, 2015 and interim periods within those fiscal periods. The adoption of ASU 2015-02 in the quarter ended March 31, 2016 resulted in certain entities formerly consolidated under the voting interest consolidation model to be consolidated in accordance with the variable interest model as further described in Note 5, Variable Interest Entities. The adoption of ASU 2015-02 did not result in the deconsolidation of any previously consolidated entities or the consolidation of any previously unconsolidated entities and had no impact on the Company's results of operations, and cash flows.

In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation (ASU 2014-12), which requires an entity to treat a performance target that affects vesting that could be achieved after an employee completes the requisite service period as a performance condition. The performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. ASU 2014-12 is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted either prospectively or retrospectively to all prior periods presented. The adoption of ASU 2014-12 on January 1, 2016 had no impact on the Company's consolidated financial statements and related disclosures.

3. Acquisitions

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

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

Supplemental pro forma data

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



	Three months ended			Six months ended
Unaudited pro forma data (in thousands)	June 30, 2015			June 30, 2015
Pro forma total revenue	$	92,196		$	170,800
Pro forma total expenses	86,865			188,725
Pro forma net income (loss)	5,331			(17,925		)
Less: pro forma net loss attributable to noncontrolling interest	(10,233		)	(17,612		)
Pro forma net income (loss) attributable to Pattern Energy	$	15,564		$	(313	)

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



	Three months ended			Six months ended
Unaudited data (in thousands)	June 30, 2015			June 30, 2015
Total revenue	$	5,172		$	5,172
Total expenses	6,350			6,350
Net loss	(1,178		)	(1,178		)
Less: net loss attributable to noncontrolling interest	(800		)	(800		)
Net loss attributable to Pattern Energy	$	(378	)	$	(378	)

4. Property, Plant and Equipment

The table below presents the categories within property, plant and equipment as follows (in thousands):



	June 30,			December 31,
	2016			2015
Operating wind farms	$	3,718,625		$	3,700,140
Furniture, fixtures and equipment	5,759			3,500
Land	141			141
Subtotal	3,724,525			3,703,781
Less: accumulated depreciation	(498,867		)	(409,161		)
Property, plant and equipment, net	$	3,225,658		$	3,294,620

The Company recorded depreciation expense related to property, plant and equipment of $43.0 million and $85.7 million for the three and six months ended June 30, 2016, respectively, and recorded $33.2 million and $62.5 million for the same periods in the prior year.

5. Variable Interest Entities

As of January 1, 2016, certain operating entities that were formerly consolidated under the voting interest consolidation model are now consolidated in accordance with the VIE consolidation model as a result of the adoption of ASU 2015-02 as further discussed in Note 2, Summary of Significant Accounting Policies.

The operating entities determined to be VIEs by the Company are Logan's Gap, Panhandle 1, Panhandle 2, Post Rock and Amazon Wind Farm Fowler Ridge primarily because the tax equity interests 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 following presents the carrying amounts of the consolidated VIEs' assets and liabilities included in the consolidated balance sheet (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.



	June 30, 2016
Assets
Current assets:
Cash and cash equivalents	$	10,473
Restricted cash	4,286
Trade receivables	8,032
Prepaid expenses	3,200
Other current assets	5,231
Total current assets	31,222
Restricted cash	5,922
Property, plant and equipment, net	1,459,110
Finite-lived intangible assets, net	2,156
Other assets	14,331
Total assets	$	1,512,741

Liabilities
Current liabilities:
Accounts payable and other accrued liabilities	$	8,211
Accrued construction costs	4,081
Accrued interest	76
Other current liabilities	1,524
Total current liabilities	13,892
Other long-term liabilities	17,640
Total liabilities	$	31,532

6. Unconsolidated Investments

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



					Percentage of Ownership
	June 30,		December 31,		June 30,		December 31,
	2016		2015		2016		2015
South Kent ⁽¹⁾	$	—	$	6,185	50.0	%	50.0	%
Grand ⁽¹⁾	—		5,735		45.0	%	45.0	%
K2	92,792		104,553		33.3	%	33.3	%
Unconsolidated investments	$	92,792	$	116,473

⁽¹⁾As of June 30, 2016, the equity method investment balances in South Kent and Grand were $0. In accordance with ASC 323, Investments - Equity Method and Joint Ventures, the Company has suspended recognition of South Kent's and Grand's equity method earnings or losses and accumulated other comprehensive income (loss), if applicable, until such time as South Kent's and Grand's subsequent cumulative equity method earnings and other comprehensive income exceed cumulative distributions received, cumulative equity method losses and, where applicable, cumulative other comprehensive income (loss) during the suspension period. During the periods when South Kent's and Grand's equity method earnings or losses are suspended, the Company will record cash distributions received as gains in earnings (losses) in unconsolidated investments, net on the Company's consolidated statements of operations.

The following table summarizes the components of suspension during the period which are included in earnings in unconsolidated investments, net on the Company's consolidated statements of operations and components of suspension included in other comprehensive income (in thousands):



	Three months ended June 30,			Six months ended June 30,
	2016			2016
Earnings in unconsolidated investments, net
Gains on distributions from unconsolidated investments	$	7,528		$	9,240
Suspended equity losses	$	1,894		$	1,894
Suspended other comprehensive income	$	(124	)	$	(124	)

The following table summarizes the aggregated operating results of the unconsolidated investments for the three and six months ended June 30, 2016 and 2015, respectively (in thousands):



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016		2015
Revenue	$	54,147		$	42,155		$	126,563	$	86,786
Cost of revenue	21,282			15,361			41,009		27,676
Operating expenses	2,914			2,908			6,059		5,314
Other expense (income)	30,177			(6,842		)	68,267		28,449
Net income (loss)	$	(226	)	$	30,728		$	11,228	$	25,347

Significant Equity Method Investees

The following table presents summarized statements of operations information for the three and six months ended June 30, 2016 and 2015, in thousands, as required for each of the Company's significant equity method investees, South Kent and Grand, pursuant to Regulation S-X Rule 10-01 (b)(1):

South Kent



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016		2015
Revenue	$	21,376		$	20,210		$	49,905	$	52,746
Cost of revenue	7,650			6,733			14,775		15,122
Operating expenses	978			1,152			2,037		2,707
Other expense (income)	13,268			(9,208		)	32,957		19,432
Net income (loss)	$	(520	)	$	21,533		$	136	$	15,485

Grand



	Three months ended June 30,					Six months ended June 30,
	2016			2015		2016			2015
Revenue	$	11,051		$	14,683	$	25,088		$	26,778
Cost of revenue	4,686			5,429		9,054			9,355
Operating expenses	819			1,182		1,563			2,033
Other expenses	9,207			562		20,431			7,213
Net income (loss)	$	(3,661	)	$	7,510	$	(5,960	)	$	8,177

7. Accounts Payable and Other Accrued Liabilities

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



	June 30, 2016		December 31, 2015
Accounts payable	$	517	$	625
Other accrued liabilities	10,834		9,583
Operating wind farm upgrade liability	1,024		4,909
Turbine operations and maintenance payable	2,251		985
Purchase agreement obligations	1,725		5,749
Land lease rent payable	1,466		2,513
Spare-parts inventory payables	922		1,181
Payroll liabilities	4,382		5,345
Property tax payable	5,752		11,145
Sales tax payable	1,050		741
Accounts payable and other accrued liabilities	$	29,923	$	42,776

8. Revolving Credit Facility

As of June 30, 2016, $133.3 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 June 30, 2016, the Company's holding company subsidiaries were in compliance with covenants contained in the Revolving Credit Facility.

As of June 30, 2016 and December 31, 2015, outstanding loan balances under the Revolving Credit Facility were $335.0 million and $355.0 million, respectively. In addition, as of June 30, 2016 and December 31, 2015, letters of credit of $31.7 million and $27.2 million, respectively, were issued under the Revolving Credit Facility.

9. Long-term Debt

The Company’s long-term debt for the following periods is presented below (in thousands):



							As of June 30, 2016
	June 30,			December 31,			Contractual Interest Rate		Effective Interest Rate			Maturity
	2016			2015			Contractual Interest Rate		Effective Interest Rate			Maturity
Project-level
Fixed interest rate
El Arrayán EKF term loan	$	105,262		$	107,160		5.56	%	5.56	%		March 2029
Santa Isabel term loan	108,992			109,973			4.57	%	4.57	%		September 2033
Variable interest rate
Ocotillo commercial term loan ⁽¹⁾	203,934			208,119			2.38	%	3.77	%	⁽²⁾	August 2020
Lost Creek term loan	107,324			110,846			2.57	%	6.51	%	⁽²⁾	September 2027
El Arrayán commercial term loan	95,692			97,418			3.21	%	5.22	%	⁽²⁾	March 2029
Spring Valley term loan	131,411			132,670			2.39	%	4.89	%	⁽²⁾	June 2030
Ocotillo development term loan	103,400			104,500			2.73	%	4.37	%	⁽²⁾	August 2033
St. Joseph term loan ⁽¹⁾	169,150			158,181			2.50	%	3.84	%	⁽²⁾	November 2033
Imputed interest rate
Hatchet Ridge financing lease obligation	207,181			214,580			1.43	%	1.43	%		December 2032
	1,232,346			1,243,447
Unamortized premium, net⁽³⁾	1,278			1,380
Unamortized financing costs	(24,674		)	(26,303		)
Current portion ⁽⁴⁾	(45,721		)	(44,144		)
Long-term debt, less current portion	$	1,163,229		$	1,174,380


⁽¹⁾	The amortization for the Ocotillo commercial term loan and the St. Joseph term loan are through June 2030 and September 2036, respectively, which differs from the stated maturity date of such loans due to prepayment requirements.


⁽²⁾	Includes impact of interest rate derivatives. Refer to Note 10, Derivative Instruments, for discussion of interest rate derivatives.


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


⁽⁴⁾	Amount is presented net of the current portion of unamortized financing costs of $3.6 million and $3.7 million as of June 30, 2016 and December 31, 2015, respectively.

Interest and commitment fees incurred and interest expense for long-term debt, the revolving credit facility, Convertible Senior Notes and other finance related interest expense consisted of the following (in thousands):



	Three months ended June 30,					Six months ended June 30,
	2016		2015			2016		2015
Interest and commitment fees incurred	$	18,352	$	19,177		$	36,502	$	36,538
Capitalized interest, commitment fees, and letter of credit fees	—		(2,258		)	—		(3,573		)
Amortization of debt discount/premium, net	1,042		(32		)	2,074		(32		)
Amortization of financing costs	1,752		1,925			3,498		3,665
Other interest	$	129	$	131		$	262	$	263
Interest expense	$	21,275	$	18,943		$	42,336	$	36,861

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



	June 30, 2016			December 31, 2015
Principal	$	225,000		$	225,000
Less:
Unamortized debt discount	(20,448		)	(22,624		)
Unamortized financing costs	(4,449		)	(5,014		)
Carrying value of convertible senior notes	$	200,103		$	197,362
Carrying value of the equity component ⁽¹⁾	$	23,743		$	23,743


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

During the three and six months ended June 30, 2016, in relation to the 2020 Notes, the Company recorded contractual coupon interest of $2.3 million and $4.5 million, amortization of financing costs of $0.2 million and $0.5 million and amortization of debt discount of $1.1 million and $2.2 million, respectively, in interest expense in the consolidated statements of operations.

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 market prices. 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 June 30, 2016, 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):



	June 30, 2016
	Derivative Assets				Derivative Liabilities
	Current		Long-Term		Current		Long-Term
Fair Value of Designated Derivatives:
Interest rate swaps	$	—	$	—	$	10,224	$	53,291

Fair Value of Undesignated Derivatives:
Interest rate swaps	$	—	$	—	$	4,753	$	16,226
Energy derivative	17,827		31,704		—		—
Foreign currency forward contracts	554		—		734		325

Total Fair Value	$	18,381	$	31,704	$	15,711	$	69,842

	December 31, 2015
	Derivative Assets				Derivative Liabilities
	Current		Long-Term		Current		Long-Term
Fair Value of Designated Derivatives:
Interest rate swaps	$	—	$	—	$	10,034	$	24,360

Fair Value of Undesignated Derivatives:
Interest rate swaps	$	—	$	559	$	4,309	$	4,299
Energy derivative	20,856		42,827		—		—
Foreign currency forward contracts	3,482		628		—		—

Total Fair Value	$	24,338	$	44,014	$	14,343	$	28,659

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



	Unit of Measure	June 30,		December 31,
	Unit of Measure	2016		2015
Designated Derivative Instruments
Interest rate swaps	USD	$	372,861	$	379,808
Interest rate swaps	CAD	$	196,650	$	196,988

Undesignated Derivative Instruments
Interest rate swaps	USD	$	268,747	$	275,424
Energy derivative	MWh	1,415,245		1,707,350
Foreign currency forward contracts	CAD	$	60,200	$	62,300

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 income (loss) and reclassified into earnings in the period or periods

during which a cash settlement occurs. The designated interest rate swaps have remaining maturities ranging from approximately 11.3 years to 20.3 years.

The following table presents gains and losses on derivative contracts designated and qualifying as cash flow hedges recognized in accumulated other comprehensive income (loss), as well as amounts reclassified to earnings for the following periods (in thousands):



		Three months ended June 30,						Six months ended June 30,
	Description	2016			2015			2016			2015
Gains (losses) recognized in accumulated OCI	Effective portion of change in fair value	$	(9,964	)	$	10,100		$	(30,661	)	$	(657	)
Gains (losses) reclassified from accumulated OCI into:
Interest expense, net of tax	Derivative settlements	$	(2,721	)	$	(3,465	)	$	(5,623	)	$	(6,956	)
Gains (losses) recognized in interest expense	Ineffective portion	$	(423	)	$	—		$	(512	)	$	—

The Company estimates that $10.2 million in accumulated other comprehensive income (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 June 30,						Six months ended June 30,
Derivative Type	Financial Statement Line Item	Description	2016			2015			2016			2015
Interest rate derivatives	Gain (loss) on undesignated derivatives, net	Change in fair value, net of settlements	$	(3,937	)	$	5,378		$	(12,818	)	$	2,306
Interest rate derivatives	Gain (loss) on undesignated derivatives, net	Derivative settlements	$	(1,280	)	$	(960	)	$	(2,606	)	$	(1,919	)
Energy derivative	Electricity sales	Change in fair value, net of settlements	$	(9,327	)	$	(6,002	)	$	(14,152	)	$	(3,030	)
Energy derivative	Electricity sales	Derivative settlements	$	6,752		$	5,928		$	13,485		$	12,097
Foreign currency forward contracts	Gain (loss) on undesignated derivatives, net	Change in fair value, net of settlements	$	(654	)	$	(240	)	$	(4,615	)	$	391
Foreign currency forward contracts	Gain (loss) on undesignated derivatives, net	Derivative settlements	$	(8	)	$	—		$	529		$	—

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. The undesignated interest rate swaps have remaining maturities ranging from approximately 4.8 years to 14.0 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 June 30, 2016, the Company has recorded a current asset of $49.5 million to funds deposited by counterparty and a current liability of $49.5 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 our short-term liquidity or financial condition. A majority of the Company’s power sale agreements and operating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. 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 one to eighteen months. The foreign currency forward contracts are considered non-designated derivative instruments and are not used for trading or speculative purposes. As a result, changes in fair value and settlements are recorded in 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 as follows (in thousands):



	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI			Total
Balances at December 31, 2014	$	(19,338	)	$	(26,672	)	$	(7,903	)	$	(53,913	)
Other comprehensive loss before reclassifications	(9,692		)	(657		)	(2,382		)	(12,731		)
Amounts reclassified from accumulated other comprehensive loss	—			6,956			1,045			8,001
Net current period other comprehensive loss	(9,692		)	6,299			(1,337		)	(4,730		)
Balances at June 30, 2015	$	(29,030	)	$	(20,373	)	$	(9,240	)	$	(58,643	)
Less: accumulated other comprehensive loss attributable to noncontrolling interest, June 30, 2015	—			(8,009		)	—			(8,009		)
Accumulated other comprehensive loss attributable to Pattern Energy, June 30, 2015	$	(29,030	)	$	(12,364	)	$	(9,240	)	$	(50,634	)



	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	11,642			(30,661		)	(11,008		)	(30,027		)
Amounts reclassified from accumulated other comprehensive loss	—			5,623			2,557			8,180
Net current period other comprehensive income (loss)	11,642			(25,038		)	(8,451		)	(21,847		)
Balances at June 30, 2016	$	(36,643	)	$	(38,500	)	$	(20,582	)	$	(95,725	)
Less: accumulated other comprehensive loss attributable to noncontrolling interest, June 30, 2016	—			(1,688		)	—			(1,688		)
Accumulated other comprehensive loss attributable to Pattern Energy, June 30, 2016	$	(36,643	)	$	(36,812	)	$	(20,582	)	$	(94,037	)

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 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. The fair values of cash and cash equivalents and restricted cash are classified as Level 1 in the fair value hierarchy. 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):



	June 30, 2016
	Level 1		Level 2		Level 3		Total
Assets
Energy derivative	$	—	$	—	$	49,531	$	49,531
Foreign currency forward contracts	—		554		—		554
	$	—	$	554	$	49,531	$	50,085
Liabilities
Interest rate swaps	$	—	$	84,494	$	—	$	84,494
Foreign currency forward contracts	—		1,059		—		1,059
	$	—	$	85,553	$	—	$	85,553



	December 31, 2015
	Level 1		Level 2		Level 3		Total
Assets
Interest rate swaps	$	—	$	559	$	—	$	559
Energy derivative	—		—		63,683		63,683
Foreign currency forward contracts	—		4,110		—		4,110
	$	—	$	4,669	$	63,683	$	68,352
Liabilities
Interest rate swaps	$	—	$	43,002	$	—	$	43,002
	$	—	$	43,002	$	—	$	43,002

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

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 agreeing 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.

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



June 30, 2016	Fair Value	Valuation Technique	Significant Unobservable Inputs	Range
Energy derivative	$49,531	Discounted cash flow	Forward electricity prices	$15.25 - $74.81⁽¹⁾
			Discount rate	0.65% - 0.79%

December 31, 2015	Fair Value	Valuation Technique	Significant Unobservable Inputs	Range
Energy derivative	$63,683	Discounted cash flow	Forward electricity prices	$12.48 - $74.94⁽¹⁾
			Discount rate	0.61% - 1.46%


(1)	Represents price per MWh

The following table presents a reconciliation of the energy derivative contract measured at fair value on a recurring basis using significant unobservable inputs (in thousands):



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Balances, beginning of period	$	58,858		$	67,447		$	63,683		$	64,475
Total gains (losses) included in electricity sales	(2,575		)	(74		)	(667		)	9,067
Settlements	(6,752		)	(5,928		)	(13,485		)	(12,097		)
Balances, end of period	$	49,531		$	61,445		$	49,531		$	61,445

During the three and six months ended June 30, 2016, the Company recognized unrealized losses on the energy derivative of $9.3 million and $14.2 million, respectively, and $6.0 million and $3.0 million, respectively, for the same periods in the prior year, which were all recorded to electricity sales 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
June 30, 2016
Convertible senior notes	$	200,103	$	—	$	210,913	$	—	$	210,913
Long-term debt, including current portion	$	1,208,950	$	—	$	1,204,088	$	—	$	1,204,088
December 31, 2015
Convertible senior notes	$	197,362	$	—	$	189,863	$	—	$	189,863
Long-term debt, including current portion	$	1,218,524	$	—	$	1,192,286	$	—	$	1,192,286

Long-term debt and the convertible senior notes are 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 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. As of June 30, 2016, the Company did not sell any shares under the Equity Distribution 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
2016:
Second Quarter	$	0.3900	May 4, 2016	June 30, 2016	July 29, 2016
First Quarter	$	0.3810	February 24, 2016	March 31, 2016	April 29, 2016

Noncontrolling Interests

The table below presents the balances for noncontrolling interests by project as follows (in thousands):



	June 30,		December 31,
	2016		2015
El Arrayán	$	31,836	$	34,224
Logan's Gap	185,464		190,397
Panhandle 1	193,505		195,791
Panhandle 2	178,463		184,773
Post Rock	187,573		196,346
Amazon Wind Farm Fowler Ridge	139,829		142,731
Noncontrolling interest	$	916,670	$	944,262

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



	Capital			Accumulated Income (Loss)			Accumulated Other Comprehensive Loss			Noncontrolling Interest
Balances at December 31, 2014	$	529,539		$	9,892		$	(8,845	)	$	530,586
Distributions to noncontrolling interests	(1,511		)	—			—			(1,511		)
Acquisition of Post Rock	205,100			—			—			205,100
Net loss	—			(10,820		)	—			(10,820		)
Other comprehensive income, net of tax	—			—			836			836
Balances at June 30, 2015	$	733,128		$	(928	)	$	(8,009	)	$	724,191

Balances at December 31, 2015	$	972,241		$	(27,426	)	$	(553	)	$	944,262
Distributions to noncontrolling interests	(8,187		)	—			—			(8,187		)
Other	(469		)	—			—			(469		)
Net loss	—			(17,801		)	—			(17,801		)
Other comprehensive loss, net of tax	—			—			(1,135		)	(1,135		)
Balances at June 30, 2016	$	963,585		$	(45,227	)	$	(1,688	)	$	916,670

14. Earnings (Loss) Per Share

Basic earnings (loss) per share is computed by dividing net income (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 antidilutive. For purpose of this calculation, potentially dilutive securities are determined by applying the treasury stock method to the assumed exercise of in-the-money stock options and the assumed vesting of outstanding restricted stock awards (RSAs) and release of deferred restricted stock units (RSUs). Potentially dilutive securities related to convertible senior notes are determined using the if-converted method.

The Company's vested deferred RSUs have non-forfeitable rights to dividends prior to release and are considered participating securities. Accordingly, they are included in the computation of basic and diluted earnings (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 income (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.

For the three and six months ended June 30, 2016, the Company excluded 8,006,242 and 8,050,844, respectively, and excluded zero and 191,299 for the same periods in the prior year, of potentially dilutive securities from the diluted earnings (loss) per share calculation as their effect is anti-dilutive.

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



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Numerator for basic and diluted earnings (loss) per share:
Net income (loss) attributable to Pattern Energy	$	(3,223	)	$	14,317		$	(26,893	)	$	(5,582	)
Less: dividends declared on Class A common stock	(29,223		)	(24,380		)	(57,771		)	(48,003		)
Less: earnings allocated to participating securities	(13		)	—			(22		)	—
Undistributed loss attributable to common stockholders	$	(32,459	)	$	(10,063	)	$	(84,686	)	$	(53,585	)

Denominator for earnings (loss) per share:
Weighted average number of shares:
Class A common stock - basic	74,443,901			68,943,707			74,440,950			67,426,286
Add dilutive effect of:
Stock options	—			67,564			—			—
Restricted stock awards	—			126,558			—			—
Restricted stock units	—			9,431			—			—
Class A common stock - diluted	74,443,901			69,147,260			74,440,950			67,426,286

Calculation of basic and diluted earnings (loss) per share:
Dividends	$	0.39		$	0.35		$	0.78		$	0.71
Undistributed loss	(0.44		)	(0.15		)	(1.14		)	(0.79		)
Basic earnings (loss) per share	$	(0.04	)	$	0.21		$	(0.36	)	$	(0.08	)
Diluted earnings (loss) per share	$	(0.04	)	$	0.21		$	(0.36	)	$	(0.08	)

Dividends declared per Class A common share	$	0.39		$	0.35		$	0.77		$	0.71

15. Commitments and Contingencies

Acquisition Commitment

On June 30, 2016, the Company committed to acquire from Pattern Development an 84% interest in Broadview, a 324 MW wind project and a 99% interest in the associated independent 35-mile 345 kV Western Interconnect transmission line for a purchase price of approximately $269 million (Broadview Acquisition), which will be funded at the commencement of commercial operations, currently estimated to occur in the first half of 2017.

Letters of Credit

Power Sale Agreements

The Company owns and operates wind power projects, and has entered into various long-term PSAs that terminate from 2019 to 2039. 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 June 30, 2016, the Company issued irrevocable letters of credits to guarantee its performance for the duration of the agreements totaling $107.1 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 June 30, 2016, the Company issued irrevocable letters of credit totaling $109.1 million to ensure performance under these various project finance and lease agreements, including the Revolving Credit Facility.

Contingencies

Turbine Operating Warranties and Service Guarantees

The Company has various turbine availability warranties and service guarantees from either its turbine manufacturers or service and maintenance providers. The service guarantees, primarily from one provider, are associated with long-term turbine service arrangements which commenced on various dates in 2014 and 2015 for certain wind projects. Pursuant to these warranties and service guarantees, if a turbine operates at less than minimum availability during the warranty period, the turbine manufacturer or service provider is obligated to pay, as liquidated damages, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, if a turbine operates at more than a specified availability during the warranty period, the Company has an obligation to pay a bonus to the turbine manufacturer or service provider. As of June 30, 2016, the Company recorded liabilities of $2.6 million associated with bonuses payable to the turbine manufacturers and service providers.

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 Services Agreement and Shared Management

The Company has entered into a bilateral Management Services Agreement with Pattern Development which provides for the Company and Pattern Development to benefit, primarily on a cost-reimbursement basis plus a 5% fee on certain direct costs, including 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 Pattern Development or its subsidiaries on the Company's behalf will be allocated to the Company. Conversely, costs and expenses incurred at the Company or its subsidiaries on the behalf of Pattern Development will be allocated to Pattern Development.

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

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



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Related party general and administrative	$	(1,931	)	$	(1,621	)	$	(3,828	)	$	(3,429	)
Related party income	1,097			756			$	2,104		1,424
Total	$	(834	)	$	(865	)	$	(1,724	)	$	(2,005	)

As of June 30, 2016 and December 31, 2015, the net amounts payable to Pattern Development for bilateral management service cost reimbursements were $0.8 million and $1.6 million, respectively. In addition, the Company recorded a receivable of $0.1 million and $0.1 million as of June 30, 2016 and December 31, 2015, respectively, related to expense reimbursements due from Pattern Development.

Management Fees

The Company provides management services and receives a fee for such services under agreements with its joint venture investees, South Kent, Grand and K2, in addition to various Pattern Development subsidiaries. The following table presents revenue for these agreements included in the consolidated statements of operations (in thousands):



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
Related party revenue	$	1,332	$	872	$	2,547	$	1,675
Total	$	1,332	$	872	$	2,547	$	1,675

A related party receivable of $0.6 million and $0.6 million was recorded in the consolidated balance sheets as of June 30, 2016 and December 31, 2015, respectively.

17. Subsequent Events

On August 3, 2016, the Company declared an increased dividend for the third quarter, payable on October 31, 2016, to holders of record on September 30, 2016, in the amount of $0.4000 per Class A share, or $1.60 on an annualized basis. This is a 2.6% increase from the second quarter.

As of August 3, 2016, the Company has issued 1,240,504 shares under the Equity Distribution Agreement. Net proceeds under the issuance were $28.9 million and the aggregate compensation paid by the Company to the agents with respect to such sales was $0.3 million.

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, 2015 and our unaudited consolidated financial statements for the three and six months ended June 30, 2016 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 17 wind power projects, including the Broadview project which we have committed to acquire, located in the United States, Canada and Chile that use proven, best-in-class technology and have a total owned capacity of 2,554 MW. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price power sale agreement (PPA). Ninety 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 years.

We intend to maximize long-term value for our stockholders in an environmentally responsible manner and with respect for the communities in which we operate. Our business is built around 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 and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per Class A share over time. Pattern Development is a leading developer of renewable energy and transmission projects. We believe Pattern Development’s ownership position in our company incentivizes Pattern Development to support the successful execution of our objectives and business strategy, including through the development of projects to the stage where they are at least construction-ready. Currently, Pattern Development has a 5,900 MW pipeline of development projects, all of which are subject to our right of first offer. We target achieving a total owned capacity of 5,000 MW by year end 2019 through a combination of acquisitions from Pattern Development and third parties capitalizing on the large fragmented global renewable energy market. In addition, 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 June 30, 2016, we committed to acquire from Pattern Development an 84% interest in Broadview, a 324 MW wind project and a 99% interest in the associated independent 35-mile 345 kV Western Interconnect transmission line for a purchase price of approximately $269 million (Broadview Acquisition), which will be funded at the commencement of commercial operations, currently estimated to occur in the first half of 2017. We can meet the contemplated cash purchase consideration using part of our available liquidity and long-term project holding company debt financing commitments arranged at the time of the purchase commitment which total up to $160 million with various maturities from five to ten years. We believe that we do not need to raise equity in order to complete the Broadview Acquisition; however, we retain the flexibility to use retained cash flow or raise equity, corporate debt, project holding company debt or other financing arrangements prior to the closing of the Broadview Acquisition in lieu of using one or more of project holding company debt financing commitments.

Below is a summary of our Identified Right of First Offer Projects that we expect to acquire from Pattern Development in connection with our purchase right.



						Capacity (MW)
Identified ROFO Projects	Status	Location	Construction Start⁽¹⁾	Commercial Operations ⁽²⁾	Contract Type	Rated ⁽³⁾	Pattern Development- Owned ⁽⁴⁾
Armow	Operational	Ontario	2014	2015	PPA	180	90
Kanagi Solar	Operational	Japan	2014	2016	PPA	14	6
Futtsu Solar	Operational	Japan	2014	2016	PPA	42	19
Meikle	In construction	British Columbia	2015	2016	PPA	180	180
Conejo Solar	In construction	Chile	2015	2016	PPA	104	84
Belle River	Securing final permits	Ontario	2016	2017	PPA	100	43
North Kent	Securing final permits	Ontario	2017	2018	PPA	100	43
Grady	Late stage development	New Mexico	2016	2017	PPA	220	176
Henvey Inlet	Late stage development	Ontario	2017	2018	PPA	300	150
Mont Sainte-Marguerite	Late stage development	Québec	2016	2017	PPA	147	147
Ohorayama	Late stage development	Japan	2017	2018	PPA	33	31
Tsugaru	Late stage development	Japan	2017	2019	PPA	126	63
						1,546	1,032


(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’s percentage ownership interest in the distributable cash flow of the project.

Corporate Management Developments

On August 3, 2016, Mr. Kevin Devlin was appointed as an officer in the role of Senior Vice President, Special Operations. In this role, Mr. Devlin has executive responsibility for various strategic change initiatives in our corporate and operational activities. He also has oversight responsibility for corporate functions such as human resources, information technology, and procurement. Mr. Devlin joined us in September 2015. He has almost 30 years commercial, developmental, and operational experience in the energy sector covering all forms of renewables, oil and gas, and conventional thermal power generation. Prior to joining us, he held executive responsibility for the operations of Iberdrola Renewables in the US, a unit of Iberdrola (formerly PPM Energy). Prior to PPM Energy, Mr. Devlin was director of commercial development for Scottish Power, one of the largest utilities in the United Kingdom. Mr. Devlin holds a bachelor’s degree in mechanical engineering from Queens University.

On May 4, 2016, Mr. Kevin Deters was appointed as an officer in the role of Vice President, Engineering, Siting and Construction. In this role, Mr. Deters and the teams he works with will support siting, meteorological review, layout, engineering and construction of the generation and transmission facilities. Mr. Deters joined us in August 2014. Prior to joining us, Mr. Deters had worked at Mortenson for 14 years where he most recently was the vice president and general manager of their electrical division. He had also served as the director of operations for Mortenson’s US and Canadian wind farm construction. Mr. Deters has managed a

variety of construction projects in his career, including manufacturing facilities, gas fired energy projects, wind farms, solar facilities, and high voltage transmission. He holds a bachelor’s degree in civil engineering from Iowa State University.

Mr. Dean Russell, as an initial step towards retirement, has transitioned to Vice President for special projects.

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.

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, to the extent such distributions were derived from operating cash flows and (vii) add or subtract other items as necessary to present the cash flows we deem representative of our core business operations.

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



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Net cash provided by operating activities	$	54,270		$	32,361		$	68,991		$	48,600
Changes in operating assets and liabilities	(12,669		)	2,521			6,298			(2,136		)
Network upgrade reimbursement	—			618			—			1,236
Release of restricted cash to fund project and general and administrative costs	—			1,501			590			1,501
Operations and maintenance capital expenditures	(516		)	(283		)	(746		)	(321		)
Transaction costs for acquisitions	52			1,357			65			1,777
Distributions from unconsolidated investments	11,960			7,771			31,774			13,847
Other	—			(148		)	—			(292		)
Less:
Distributions to noncontrolling interests	(4,270		)	(763		)	(8,187		)	(1,511		)
Principal payments paid from operating cash flows	(13,319		)	(16,948		)	(22,262		)	(25,383		)
Cash available for distribution	$	35,508		$	27,987		$	76,523		$	37,318

Cash available for distribution was $35.5 million for the three months ended June 30, 2016 as compared to $28.0 million for the same period in the prior year. This $7.5 million increase in cash available for distribution was due to additional revenues of $13.6 million (excluding unrealized loss on energy derivative and amortization of PPAs) primarily from projects which were acquired since May 2015 or which commenced commercial operations since the third quarter of 2015. In addition, we received an increase of $4.2 million in cash distributions from our unconsolidated investments when compared to the same period in the

prior year due to full operation at each of our unconsolidated investments in 2016. These increases were partially offset by increases in project expenses of $5.4 million and operating expenses of $1.8 million, primarily from projects which commenced commercial operations or were acquired during 2015, as well as, increased distributions to noncontrolling interests of $3.5 million.

Cash available for distribution was $76.5 million for the six months ended June 30, 2016 as compared to $37.3 million for the same period in the prior year. This $39.2 million increase in cash available for distribution was due to additional revenues of $43.8 million (excluding unrealized loss on energy derivative and amortization of PPAs) primarily from projects which were acquired since May 2015 or which commenced commercial operations since the third quarter of 2015. In addition, we received an increase of $17.9 million in cash distributions from our unconsolidated investments when compared to the same period in the prior year due to a full period of operation at each of our unconsolidated investments in 2016. These increases were partially offset by increases in project expenses of $12.4 million and operating expenses of $5.2 million, primarily from projects which commenced commercial operations or were acquired during 2015, as well as, increased distributions to noncontrolling interests of $6.7 million.

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.

During the six months ended June 30, 2016, we suspended the equity method of accounting for our investments at South Kent and Grand as the carrying value of our investments were reduced to zero. Our definition of Adjusted EBITDA has accordingly been modified within the current periods to include adjustments (gains on distributions and suspended equity losses) from 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 June 30,						Six months ended June 30,
	2016			2015			2016			2015
Net income (loss)	$	(15,646	)	$	5,657		$	(44,694	)	$	(16,402	)
Plus:
Interest expense, net of interest income	21,008			18,715			41,323			36,414
Tax provision	1,429			3,603			2,727			2,857
Depreciation, amortization and accretion	45,835			34,785			91,219			63,841
EBITDA	52,626			62,760			90,575			86,710
Unrealized loss on energy derivative⁽¹⁾	9,327			6,002			14,152			3,030
(Gain) loss on undesignated derivatives, net	5,879			(4,178		)	19,510			(778		)
Net loss on transactions	72			1,305			39			2,589
Adjustments from unconsolidated investments ⁽²⁾	(9,422		)	—			(11,134		)	—
Plus, proportionate share from unconsolidated investments:
Interest expense, net of interest income	7,925			5,181			15,144			10,619
Depreciation, amortization and accretion	6,671			4,991			12,964			9,500
(Gain) loss on undesignated derivatives, net	5,555			(9,240		)	15,471			1,894
Adjusted EBITDA	$	78,633		$	66,821		$	156,721		$	113,564


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


(2)	Amount consists of gains on distributions from unconsolidated investments and suspended equity losses of $7.5 million and $1.9 million for the three months ended June 30, 2016, respectively and $9.2 million and $1.9 million for the six months ended June 30, 2016, respectively.

Adjusted EBITDA for the three months ended June 30, 2016 was $78.6 million compared to $66.8 million for the same period in the prior year, an increase of $11.8 million, or approximately 17.7%. The increase in Adjusted EBITDA for the three months ended June 30, 2016 as compared to the same period in the prior year was primarily attributable to projects which commenced commercial operations or were acquired since May 2015.

Adjusted EBITDA for the six months ended June 30, 2016 was $156.7 million compared to $113.6 million for the same period in the prior year, an increase of $43.2 million or approximately 38.0%. The increase in Adjusted EBITDA for the six months ended June 30, 2016 as compared to the same period in the prior year was primarily attributable to projects which commenced commercial operations or were acquired since May 2015.

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 June 30,											Six months ended June 30,
MWh sold	2016			2015			$ Change			% Change		2016			2015			Change			% Change
Consolidated MWh sold	1,746,088			1,327,889			418,199			31.5	%	3,529,502			2,244,212			1,285,290			57.3	%
Less: noncontrolling MWh	(226,859		)	(253,405		)	26,546			(10.5	)%	(488,904		)	(411,731		)	(77,173		)	18.7	%
Controlling interest in consolidated MWh	1,519,229			1,074,484			444,745			41.4	%	3,040,598			1,832,481			1,208,117			65.9	%
Unconsolidated investments proportional MWh	196,057			150,890			45,167			29.9	%	475,723			328,927			146,796			44.6	%
Proportional MWh sold	1,715,286			1,225,374			489,912			40.0	%	3,516,321			2,161,408			1,354,913			62.7	%

Average realized electricity price per MWh
Consolidated average realized electricity price per MWh	$	58		$	67		$	(9	)	(13.4	)%	$	55		$	67		$	(12	)	(17.9	)%
Unconsolidated investments proportional average realized electricity price per MWh	$	116		$	123		$	(7	)	(5.7	)%	$	111		$	122		$	(11	)	(9.0	)%
Proportional average realized electricity price per MWh	$	68		$	77		$	(9	)	(11.7	)%	$	65		$	78		$	(13	)	(16.7	)%

Our consolidated MWh sold for the three months ended June 30, 2016 was 1,746,088 MWh, as compared to 1,327,889 MWh for the three months ended June 30, 2015, an increase of 418,199 MWh, or 31.5%. The change in consolidated MWh sold was primarily

attributable to an increase in volume of 259,980 MWh from projects which commenced commercial operations since the third quarter of 2015 and an increase in volume of 169,203 MWh from projects acquired in May 2015. The increase in volume was partially offset by a decrease in volume of 10,804 MWh from projects in operation prior to 2015.

Our consolidated MWh sold for the six months ended June 30, 2016 was 3,529,502 MWh, as compared to 2,244,212 MWh for the six months ended June 30, 2015, an increase of 1,285,290 MWh, or 57.3%. The change in consolidated MWh sold was primarily attributable to:


•	an increase in volume of 628,651 MWh from projects which commenced commercial operations since the third quarter of 2015;


•	an increase in volume of 512,799 MWh from projects acquired in May 2015; and


•	an increase in volume of 143,840 MWh from projects in operation prior to 2015.

Our proportional MWh sold for the three months ended June 30, 2016 was 1,715,286 MWh, as compared to 1,225,374 MWh for the three months ended June 30, 2015, an increase of 489,912 MWh, or 40.0%. The change in proportional MWh sold was primarily attributable to:


•	an increase in volume of 444,745 MWh from controlling interest in consolidated MWh; and


•	an increase in volume of 45,167 MWh from unconsolidated investments due primarily to the acquisition of K2 in June 2015.

Our proportional MWh sold for the six months ended June 30, 2016 was 3,516,321 MWh, as compared to 2,161,408 MWh for the six months ended June 30, 2015, an increase of 1,354,913 MWh, or 62.7%. The change in proportional MWh sold was primarily attributable to:


•	an increase in volume of 1,208,117 MWh from controlling interest in consolidated MWh; and


•	an increase in volume of 146,796 MWh from unconsolidated investments due primarily to the acquisition of K2 in June 2015.

Our consolidated average realized electricity price was $58 per MWh for the three months ended June 30, 2016 as compared to $67 per MWh for the three months ended June 30, 2015. The decrease of $9 per MWh was primarily due to new projects which were acquired or commenced commercial operations since June 2014 with lower priced power sales agreements, on average, than projects in operation prior to June 2014.

Our consolidated average realized electricity price was $55 per MWh for the six months ended June 30, 2016 as compared to $67 per MWh for the six months ended June 30, 2015. The decrease of $12 per MWh was primarily due to new projects which were acquired or commenced commercial operation since June 2014 with lower priced power sales agreements, on average, than projects in operation prior to June 2014.

Our proportional average realized electricity price was $68 per MWh for the three months ended June 30, 2016 as compared to $77 per MWh for the three months ended June 30, 2015. The $9 per MWh decrease in the proportional average realized electricity price was primarily due to new projects which were acquired or commenced commercial operation since June 2014 with lower priced power sales agreements, on average, than projects in operation prior to June 2014.

Our proportional average realized electricity price was $65 per MWh for the six months ended June 30, 2016 as compared to $78 per MWh for the six months ended June 30, 2015. The $13 per MWh decrease in the proportional average realized electricity price was primarily due to new projects which were acquired or commenced commercial operation since June 2014 with lower priced power sales agreements, than projects in operation prior to June 2014.

Results of Operations

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



	Three months ended June 30,											Six months ended June 30,
	2016			2015			$ Change			% Change		2016			2015			$ Change			% Change
Revenue	$	93,438		$	84,671		$	8,767		10.4	%	$	181,077		$	149,537		$	31,540		21.1	%
Total cost of revenue	77,037			62,323			14,714			23.6	%	152,694			116,625			36,069			30.9	%
Total operating expenses	12,293			10,491			1,802			17.2	%	23,759			18,520			5,239			28.3	%
Total other expense	18,325			2,597			15,728			605.6	%	46,591			27,937			18,654			66.8	%
Net income (loss) before income tax	(14,217		)	9,260			(23,477		)	(253.5	)%	(41,967		)	(13,545		)	(28,422		)	209.8	%
Tax provision	1,429			3,603			(2,174		)	(60.3	)%	2,727			2,857			(130		)	(4.6	)%
Net income (loss)	(15,646		)	5,657			(21,303		)	(376.6	)%	(44,694		)	(16,402		)	(28,292		)	172.5	%
Net loss attributable to noncontrolling interest	(12,423		)	(8,660		)	(3,763		)	43.5	%	(17,801		)	(10,820		)	(6,981		)	64.5	%
Net income (loss) attributable to Pattern Energy	$	(3,223	)	$	14,317		$	(17,540	)	(122.5	)%	$	(26,893	)	$	(5,582	)	$	(21,311	)	381.8	%

Total revenue

Total revenue for the three months ended June 30, 2016 was $93.4 million compared to $84.7 million for the three months ended June 30, 2015, an increase of $8.8 million, or approximately 10.4%. The increase in total revenue for the three months ended June 30, 2016 as compared to the same period in the prior year was primarily attributable to:


•	$7.6 million from projects acquired in May 2015;


•	$7.6 million in additional electricity sales from projects which commenced commercial operations since the third quarter of 2015; and


•	$3.8 million from projects in operation prior to 2015.

The increases were partially offset by:


•	$7.1 million in lower electricity sales from projects in operation prior to 2015; and


•	$3.3 million in higher unrealized losses due to higher forward electricity price curves when compared to the prior period.

Total revenue for the six months ended June 30, 2016 was $181.1 million compared to $149.5 million for the six months ended June 30, 2015, an increase of $31.5 million, or approximately 21.1%. The increase in total revenue for the six months ended June 30, 2016 as compared to the same period in the prior year was primarily attributable to:


•	$23.2 million from projects acquired in May 2015;


•	$17.0 million in additional electricity sales from projects which commenced commercial operations since the third quarter of 2015; and


•	$8.4 million from projects in operation prior to 2015.

These increases were partially offset by:


•	$11.1 million in higher unrealized losses due to higher forward electricity price curves when compared to the prior period; and


•	$7.5 million in lower electricity sales from projects in operation prior to 2015.

Cost of revenue

Cost of revenue for the three months ended June 30, 2016 was $77.0 million compared to $62.3 million for the three months ended June 30, 2015, an increase of $14.7 million, or approximately 23.6%. The increase in cost of revenue for the three months ended June 30, 2016 as compared to the same period in the prior year was primarily attributable to a $9.3 million increase in depreciation expense and a $5.7 million increase in turbine operations and maintenance expense primarily for new projects which were acquired in May 2015 or became commercially operable since the third quarter of 2015. The increases were partially offset by decreases in donations and property taxes of $2.4 million.

Cost of revenue for the six months ended June 30, 2016 was $152.7 million compared to $116.6 million for the six months ended June 30, 2015, an increase of $36.1 million, or approximately 30.9%. The increase in cost of revenue for the six months ended June 30, 2016 as compared to the same period in the prior year was primarily attributable to a $23.6 million increase in depreciation expense and a $10.9 million increase in turbine operations and maintenance expense, and $1.6 million for land leases and royalties primarily for new projects which were acquired in May 2015 or became commercially operable since the third quarter of 2015.

Operating expenses

Operating expenses for the three months ended June 30, 2016 were $12.3 million compared to $10.5 million for the three months ended June 30, 2015, an increase of $1.8 million, or approximately 17.2%. The increase in operating expenses for the three months ended June 30, 2016 as compared to the same period in the prior year was primarily attributable to $1.9 million increase in payroll and non-cash stock based compensation to support new projects which were acquired in May 2015 or became commercially operable since the third quarter of 2015.

Operating expenses for the six months ended June 30, 2016 were $23.8 million compared to $18.5 million for the six months ended June 30, 2015, an increase of $5.2 million, or approximately 28.3%. The increase in operating expenses for the six months ended June 30, 2016 as compared to the same period in the prior year was primarily attributable to a $3.5 million increase in payroll and non-cash stock based compensation and a $1.7 million increase in office lease and professional fees.

Other expense

Other expense for the three months ended June 30, 2016 was $18.3 million compared to $2.6 million for the three months ended June 30, 2015, an increase of $15.7 million, or approximately 605.6%. The change was primarily attributable to:


•	a $10.1 million increase in loss on undesignated derivatives, net primarily due to losses from lower interest rate price curves compared to the interest rate price curves in the prior year;


•	a $6.6 million decrease in earnings in unconsolidated investments, net due primarily to decreased project income as a result of derivative losses offset by gains on distributions due to the 2016 suspension of equity method accounting for certain of our investments; and


•	a $2.3 million increase in interest expense primarily due to the issuance of convertible debt in July 2015, increased loan balances on the Revolving Credit Facility and an additional loan for an acquired project in 2015.

These increases were partially offset by the following:


•	a $1.6 million increase in income from foreign currency transactions; and


•	a $1.2 million decrease in net losses on transactions.

Other expense for the six months ended June 30, 2016 was $46.6 million compared to $27.9 million for the six months ended June 30, 2015, an increase of $18.7 million or approximately 66.8%. The change was primarily attributable to:


•	a $20.3 million increase in loss on undesignated derivatives, net primarily due to losses from lower interest rate price curves compared to the interest rate price curves in the prior year; and


•	a $5.5 million increase in interest expense primarily due to the issuance of convertible debt in July 2015, increased loan balances on the Revolving Credit Facility and an additional loan for an acquired project in 2015.

These increases were partially offset by the following:


•	a $2.5 million decrease in net losses on transactions; and


•	a $1.9 million increase in income from foreign currency transactions.

Tax provision

The tax provision was $1.4 million for the three months ended June 30, 2016 compared to a tax provision of $3.6 million for the three months ended June 30, 2015. The expense provision for the three months ended June 30, 2016 was primarily the result of recording a deferred tax liability on the recognized equity income from operations in unconsolidated investments, tax expense in our Canadian and Puerto Rican operations and the foreign withholding taxes on intercompany transactions in certain foreign jurisdictions offset by recognizing a deferred tax asset on the recognized losses in Chile. The tax provision in the second quarter of 2015 was also the result of recording deferred tax liabilities on equity in earnings in unconsolidated investments, tax expense at our Canadian and Puerto Rican operations, and foreign withholding taxes on intercompany transactions in certain foreign jurisdictions, partially offset by recognizing a deferred tax asset on losses in Chile.

The tax provision was $2.7 million for the six months ended June 30, 2016 compared to a tax provision of $2.9 million for the six months ended June 30, 2015. The expense provision for the six months ended June 30, 2016 was primarily the result of recording a deferred tax liability on the recognized equity income from operations in unconsolidated investments, tax expense in our Canadian and Puerto Rican operations and the foreign withholding taxes on intercompany transactions in certain foreign jurisdictions offset by recognizing a deferred tax asset on the recognized losses in Chile. The tax provision for the first six months of 2015 was attributable to the recognition of deferred tax liabilities on equity earnings in unconsolidated investments, tax expense at our Canadian and Puerto Rican operations, and foreign withholding taxes on intercompany transactions in certain foreign jurisdictions, partially offset by the recognition of a deferred tax asset on losses in Chile.

Net income (loss)

For the three months ended June 30, 2016, we recognized net (loss) of $(15.6) million compared to net income of $5.7 million for the same period in the prior year. For the six months ended June 30, 2016, we recognized net (loss) of $(44.7) million compared to net (loss) of $(16.4) million for the same period in the prior year. The increase in net loss for the three and six month periods of $21.3 million and $28.3 million, respectively, were primarily due to additional projects acquired since May 2015 and projects that commenced commercial operations in late 2015. Also contributing to the three and six month increase to net loss were increases in other expense items related to interest expense of $2.3 million and $5.5 million, respectively, and losses on undesignated derivatives, net of $10.1 million and $20.3 million as discussed above.

Noncontrolling interest

The net loss attributable to noncontrolling interest was $12.4 million for the three months ended June 30, 2016 compared to an $8.7 million net loss attributable to noncontrolling interest for the three months ended June 30, 2015. The increased loss of $3.8 million was primarily attributable to allocations of losses for tax equity projects which commenced commercial operations or were acquired since May 2015.

The net loss attributable to noncontrolling interest was $17.8 million for the six months ended June 30, 2016 compared to a $10.8 million net loss attributable to noncontrolling interest for the six months ended June 30, 2015. The increased loss of $7.0 million was primarily attributable to allocations of losses for tax equity projects which commenced commercial operations or were acquired since May 2015.

Liquidity and Capital Resources

Our business requires substantial capital to fund (i) equity investments in our construction projects, (ii) current operational costs, (iii) debt service payments, (iv) dividends to our 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):



	June 30, 2016
Unrestricted cash	$	87.6
Restricted cash	28.6
Revolving credit facility availability	133.3
Project facilities:
Post construction use	99.8
	$	349.3

We believe for the next twelve months, we will have sufficient liquid assets, cash flows from operations, and borrowings available under our revolving credit facility to meet our financial commitments, including our commitment for the Broadview Acquisition, debt service obligations, contingencies and anticipated required capital expenditures, but not including capital required for additional project acquisitions. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corresponding adverse effect on our borrowing capacity.

In connection with our future capital expenditures and other investments, including any project acquisitions that we may make, we may, from time to time, issue debt or equity securities. 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.

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):



	Six months ended June 30,
	2016			2015
Net cash provided by operating activities	$	69.0		$	48.6
Net cash provided by (used in) investing activities	26.2			(593.5		)
Net cash provided by (used in) financing activities	(104.4		)	528.8
Effect of exchange rate changes on cash and cash equivalents	2.0			(2.6		)
Net change in cash and cash equivalents	$	(7.2	)	$	(18.7	)

Net cash provided by operating activities

Net cash provided by operating activities was $69.0 million for the six months ended June 30, 2016 as compared to $48.6 million in the prior year, an increase of $20.4 million, or approximately 42.0%. The increase in cash provided by operating activities was primarily due to higher revenues of $43.8 million (excluding unrealized loss on energy derivative and amortization of PPAs) from projects which were acquired since May 2015 or which commenced commercial operations since the third quarter of 2015. These increases were partially offset by increases of $12.4 million in project expenses and $5.2 million in operating expenses. Further offsetting higher revenues in cash provided by operating activities was a $5.2 million increase in the timing of payments associated primarily with property taxes, accruals, and other long-term liabilities from December 2015.

Net cash provided by (used in) investing activities

Net cash provided by investing activities was $26.2 million for the six months ended June 30, 2016, which consisted primarily of a $20.5 million decrease in restricted cash, $31.8 million in distributions from unconsolidated investments, offset by $26.0 million for capital expenditures including $18.0 million related to payments for a project that became commercially operable in the fourth quarter of 2015.

Net cash used in investing activities was $593.5 million for the six months ended June 30, 2015, which consisted primarily of $404.4 million of acquisitions, net of cash acquired, which includes $238.5 million for projects operational in May 2015, $37.5 million for the Amazon Wind Farm Fowler Ridge construction project and $128.4 million for an unconsolidated investment in K2, in addition to, $216.5 million for capital expenditures, related to the construction at Logan’s Gap and the Amazon Wind Farm Fowler Ridge. These increases were partially offset by $13.8 million of distributions from unconsolidated investments.

Net cash provided by (used in) financing activities

Net cash used in financing activities for the six months ended June 30, 2016 was $104.4 million, which consisted primarily of dividend payments of $56.1 million, distributions to noncontrolling interests of $8.2 million and repayment of the revolving credit facility net of proceeds of $20.0 million, and repayment of long-term debt of $22.3 million.

Net cash provided by financing activities for the six months ended June 30, 2015 was $528.8 million, which consisted of $250.0 million drawn from our revolving credit facility, proceeds of $206.2 million from construction debt related to our construction projects, $196.6 million of net proceeds from our February 2015 equity offering, net of expenses, partially offset by $39.2 million of dividend payments, $50.0 million repayment of our revolving credit facility, and $25.4 million in repayments of debt.

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 November 26, 2013, we announced the initiation of a quarterly dividend on our Class A common stock. On August 3, 2016, we increased our dividend to $0.40 per share, or $1.60 per share on an annualized basis, commencing with respect to dividends paid on October 31, 2016 to holders of record on September 30, 2016. 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
2016:
Third Quarter	0.4000		August 3, 2016	September 30, 2016	October 31, 2016
Second Quarter	$	0.3900	May 4, 2016	June 30, 2016	July 29, 2016
First Quarter	$	0.3810	February 24, 2016	March 31, 2016	April 29, 2016

We established our initial quarterly dividend level based on a targeted cash available for distribution payout ratio of 80% after considering the annual cash available for distribution that we expect our projects will be able to generate following the commencement of commercial operations at all of our construction projects and with due regard to retaining a portion of the cash available for distribution to grow our business. We intend to grow our business primarily through the acquisition of operational and construction-ready power projects, which, we believe, will facilitate the growth of our cash available for distribution and enable us to increase our dividend per share of Class A common stock over time. We may in the future raise capital and make investments in new power projects upon or near the commencement of construction of such projects and therefore prior to the expected commencement of operations of the new projects, which could result in a passage of time of twelve or more months before we begin to receive any cash flow contributions from such projects to our cash available for distribution. In connection with these investments, we may increase our dividends prior to the receipt of such cash flow contributions, which would likely cause our payout ratio to temporarily exceed our targeted run-rate payout ratio. However, the determination of the amount of cash dividends to be paid to holders of our Class A common stock will be made by our Board of Directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant. Refer to Item 1A “Risk Factors—Risks Related to Ownership of our Class A Shares—Risks Regarding our Cash Dividend Policy” in our Annual Report on Form 10-K for the year ended December 31, 2015.

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. We have committed to acquire from Pattern Development the Broadview Acquisition for a purchase price of approximately of $269 million, which is currently estimated to occur in the first half of 2017.

We can meet the contemplated cash purchase consideration using part of our available liquidity and long-term project holding company debt financing commitments arranged at the time of the purchase commitment which total up to $160 million with various maturities from five to ten years. We believe that we will not need to raise equity in order to complete the Broadview Acquisition; however, we retain the flexibility to use retained cash flow or raise equity, corporate debt, project holding company debt or other financing arrangements prior to the closing of the Broadview Acquisition in lieu of using one or more of project holding company debt financing commitments.

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, 2016, we have budgeted $2.5 million for operational capital expenditures and $5.3 million for expansion capital expenditures.

Contractual Obligations

There have been no material changes in our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015, except for the commitment discussed in Recent Developments for the Broadview Acquisition.

Off-Balance Sheet Arrangements

As of June 30, 2016, we are not a party to any off-balance sheet arrangements.

Credit Agreements for Unconsolidated Investments

Below is a summary of our proportion of debt, net of deferred financing costs, in unconsolidated investments, as of June 30, 2016 (in thousands):



	Total Project Debt		Percentage of Ownership		Our Portion of Unconsolidated Project Debt
South Kent	$	486,213	50.0	%	$	243,107
Grand	281,440		45.0	%	126,648
K2	602,154		33.3	%	200,718
Unconsolidated investments - debt	$	1,369,807			$	570,473

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, 2015.

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 371,456 MWh of electricity sales during the six months ended June 30, 2016 that were subject to spot market pricing. A hypothetical increase or decrease of 10% or $1.42 per MWh in these spot market prices would have increased or decreased revenue by $0.5 million for the six months ended June 30, 2016.

Interest Rate Risk

As of June 30, 2016, 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. As of June 30, 2016, the estimated fair value of our debt was $1.2 billion and the carrying value of our debt was $1.2 billion. The fair value of variable interest rate long-term debt is approximated by its carrying cost. We estimate that a 1% change in market interest rates would have changed the fair value of our fixed rate debt by $31.9 million.

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. A hypothetical increase or decrease in interest rates by 1% would have increased or decreased interest expense related to our revolving credit facility by $1.8 million for the six months ended June 30, 2016.

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 June 30, 2016, the unhedged portion of our variable rate debt was $51.7 million. A hypothetical increase or decrease in interest rates by 1% would not have a material impact to interest expense for the six months ended June 30, 2016.

Interest Rate Risk and Market Price Risk Involving Convertible Senior Notes

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 common stock increases and decrease as the market price of our 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 changes in the fair value of the debentures, or value of common stock, permit the holders of the debentures to convert into shares. See Note 9, Long-term Debt, in the notes to consolidated financial statements for further discussion of the convertible debt. The estimated fair value of convertible debt was $210.9 million as of June 30, 2016. A hypothetical increase or decrease in interest rates by 1% would have resulted in a $7.4 million decrease or $7.7 million increase in the fair value.

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 six months ended June 30, 2016, our financial results included C$17.5 million, or $12.8 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 $1.3 million for the six months ended June 30, 2016.

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 six months ended June 30, 2016, we recognized an unrealized loss on foreign currency forward contracts of $4.6 million in loss on undesignated derivatives, net in the consolidated statements of operations. We also recognized a realized gain of $0.5 million in loss on undesignated derivatives, net in the consolidated statements of operations related to foreign currency forward contracts that matured during the six months ended June 30, 2016.

As of June 30, 2016, a 10% devaluation in the Canadian dollar to the United States dollar would result in our consolidated balance sheets being negatively impacted by an $11.6 million cumulative translation adjustment in accumulated other comprehensive loss.

ITEM 4. CONTROLS AND PROCEDURES

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

Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2016.

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject, from time to time, to routine legal proceedings and claims arising out of the normal course of business. There has been no material change in the nature of our legal proceedings from the description provided in our Annual Report on Form 10-K for the year ended December 31, 2015.

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, 2015. There have been no material changes in our risk factors as described in such document.

ITEM 6. EXHIBITS



Exhibit No.		Description

2.1		Purchase and Sale Agreement, dated as of June 30, 2016, by and between Pattern Energy Group Inc., Pattern Renewables LP, and Pattern Energy Group LP (Incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed July 1, 2016).

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

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

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

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

10.1		Assignment and Assumption of Lease and Consent of Landlord Agreement, effective as of January 1, 2016, by and between Pattern Energy Group LP, Pattern Energy Group Inc., and AMB Pier One, LLC (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated January 25, 2016).

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

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

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

99.1		Amendment No. 4 dated as of May 27, 2016 to the Amended and Restated Credit and Guaranty Agreement dated as of December 17, 2014, among Pattern US Finance Company LLC, Pattern Canada Finance Company ULC, Royal Bank of Canada (acting through its New York Branch), as Administrative Agent and the other parties party thereto.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

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:	August 5, 2016	By:	/s/ Michael J. Lyon
			Michael J. Lyon
			Chief Financial Officer

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