Pattern Energy Group Inc. - FORM 10-Q

Attached files

file	filename
EX-32 - EXHIBIT 32 - Pattern Energy Group Inc.	pegi2018033110qexhibit32.htm
EX-31.2 - EXHIBIT 31.2 - Pattern Energy Group Inc.	pegi2018033110qexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - Pattern Energy Group Inc.	pegi2018033110qexhibit311.htm
EX-10.7 - EXHIBIT 10.7 - Pattern Energy Group Inc.	pegi2018033110qexhibit107.htm
EX-10.6 - EXHIBIT 10.6 - Pattern Energy Group Inc.	pegi2018033110qexhibit106.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2018.



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

Commission File Number 001-36087

PATTERN ENERGY GROUP INC.

(Exact name of Registrant as specified in its charter)



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

Pier 1, Bay 3, San Francisco, CA 94111

(Address of principal executive offices) (Zip Code)

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

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

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

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



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



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

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

As of May 7, 2018 there were 98,096,760 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 MARCH 31, 2018

TABLE OF CONTENTS



	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	5

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

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	50
Item 4.	Controls and Procedures	53

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 6.	Exhibits	55
	Signatures	57

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

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


•	our ability to complete acquisitions of power projects;


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


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


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


•	changes in law, including applicable tax laws;


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


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


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


•	an increase in interest rates;


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


•	competition from other power project developers;


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


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


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


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


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


•	the effects of litigation, including administrative and other proceedings or investigations, relating to our 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, solar panels and other equipment;


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


•	scarcity of necessary equipment;


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


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


•	other factors discussed under “Risk Factors.”

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

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

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

	March 31,			December 31,
	2018			2017
Assets
Current assets:
Cash and cash equivalents (Note 7)	$	162,144		$	116,753
Restricted cash (Note 7)	8,698			9,065
Funds deposited by counterparty	17,744			29,780
Trade receivables (Note 7)	62,895			54,900
Derivative assets, current	15,747			19,445
Prepaid expenses (Note 7)	17,707			17,847
Deferred financing costs, current, net of accumulated amortization of $2,111 and $2,580 as of March 31, 2018 and December 31, 2017, respectively	1,230			1,415
Other current assets (Note 7)	28,948			21,105
Total current assets	315,113			270,310
Restricted cash (Note 7)	9,524			12,162
Major equipment advances	38,452			—
Property, plant and equipment, net (Note 7)	4,340,973			3,965,121
Unconsolidated investments	347,831			311,223
Derivative assets	13,779			9,628
Deferred financing costs	8,046			7,784
Net deferred tax assets	7,215			6,349
Finite-lived intangible assets, net (Note 7)	235,952			136,048
Goodwill	60,302			—
Other assets (Note 7)	44,455			22,906
Total assets	$	5,421,642		$	4,741,531

Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities (Note 7)	$	39,468		$	53,615
Accrued construction costs (Note 7)	2,045			1,369
Counterparty deposit liability	17,744			29,780
Accrued interest (Note 7)	7,529			16,460
Dividends payable	42,041			41,387
Derivative liabilities, current	5,685			8,409
Revolving credit facility	248,000			—
Current portion of long-term debt, net	61,191			51,996
Contingent liabilities, current	21,708			2,592
Other current liabilities (Note 7)	15,525			11,426
Total current liabilities	460,936			217,034
Long-term debt, net	2,128,063			1,878,735
Derivative liabilities	28,425			20,972
Net deferred tax liabilities	130,257			56,491
Finite-lived intangible liabilities, net	59,579			51,194
Contingent liabilities	168,183			62,398
Other long-term liabilities (Note 7)	151,430			106,565
Total liabilities	3,126,873			2,393,389
Commitments and contingencies (Note 16)
Equity:
Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 98,096,760 and 97,860,048 shares outstanding as of March 31, 2018 and December 31, 2017, respectively	983			980
Additional paid-in capital	1,218,077			1,234,846
Accumulated income (loss)	—			(112,175		)
Accumulated other comprehensive loss	(26,810		)	(25,691		)
Treasury stock, at cost; 177,909 and 157,812 shares of Class A common stock as of March 31, 2018 and December 31, 2017, respectively	(3,884		)	(3,511		)
Total equity before noncontrolling interest	1,188,366			1,094,449
Noncontrolling interest	1,106,403			1,253,693
Total equity	2,294,769			2,348,142
Total liabilities and equity	$	5,421,642		$	4,741,531

See accompanying notes to consolidated financial statements.

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

	Three months ended March 31,
	2018			2017
Revenue:
Electricity sales	$	102,147		$	98,434
Other revenue	9,512			2,399
Total revenue	111,659			100,833
Cost of revenue:
Project expense	34,562			29,100
Transmission costs	7,190			70
Depreciation, amortization and accretion	55,452			43,740
Total cost of revenue	97,204			72,910
Gross profit	14,455			27,923
Operating expenses:
General and administrative	10,706			11,124
Related party general and administrative	4,068			3,426
Total operating expenses	14,774			14,550
Operating income (loss)	(319		)	13,373
Other expense:
Interest expense	(25,444		)	(22,555		)
Gain (loss) on derivatives	5,660			(648		)
Earnings in unconsolidated investments, net	18,212			16,876
Net loss on transactions	(1,098		)	(312		)
Other income (expense), net	(2,847		)	580
Total other expense	(5,517		)	(6,059		)
Net income (loss) before income tax	(5,836		)	7,314
Tax provision	6,784			4,775
Net income (loss)	(12,620		)	2,539
Net loss attributable to noncontrolling interest	(148,542		)	(3,114		)
Net income attributable to Pattern Energy	$	135,922		$	5,653

Weighted-average number of common shares outstanding
Basic	97,428,388			87,062,612
Diluted	105,564,491			87,131,280
Earnings per share attributable to Pattern Energy
Basic	$	1.39		$	0.06
Diluted	$	1.32		$	0.06
Dividends declared per Class A common share	$	0.42		$	0.41

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 March 31,
	2018			2017
Net income (loss)	$	(12,620	)	$	2,539
Other comprehensive income (loss):
Foreign currency translation, net of zero tax impact	(9,102		)	2,463
Derivative activity:
Effective portion of change in fair value of derivatives, net of tax benefit of $946 and $39, respectively	3,745			(541		)
Reclassifications to net income (loss), net of tax impact of $265 and $251, respectively	1,396			2,319
Total change in effective portion of change in fair value of derivatives	5,141			1,778
Proportionate share of equity investee’s derivative activity:
Effective portion of change in fair value of derivatives, net of tax (provision) benefit of ($291) and $779, respectively	808			(2,160		)
Reclassifications to net income (loss), net of tax impact of $490 and $1,032, respectively	1,360			2,861
Total change in effective portion of change in fair value of derivatives	2,168			701
Total other comprehensive income (loss), net of tax	(1,793		)	4,942
Comprehensive income (loss)	(14,413		)	7,481
Less comprehensive income (loss) attributable to noncontrolling interest:
Net loss attributable to noncontrolling interest	(148,542		)	(3,114		)
Foreign currency translation, net of zero tax impact	(1,627		)	—
Derivative activity:
Effective portion of change in fair value of derivatives, net of tax (provision) benefit of ($150) and $8, respectively	606			(21		)
Reclassifications to net income (loss), net of tax impact of $28 and $33, respectively	347			88
Total change in effective portion of change in fair value of derivatives	953			67
Comprehensive loss attributable to noncontrolling interest	(149,216		)	(3,047		)
Comprehensive income attributable to Pattern Energy	$	134,803		$	10,528

See accompanying notes to consolidated financial statements.



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

	Class A Common Stock			Treasury Stock					Additional Paid-in Capital			Accumulated Income (Loss)			Accumulated Other Comprehensive Income (Loss)			Total			Noncontrolling Interest				Total Equity
	Shares	Amount		Shares		Amount			Additional Paid-in Capital			Accumulated Income (Loss)			Accumulated Other Comprehensive Income (Loss)			Total			Noncontrolling Interest				Total Equity
Balances at December 31, 2016	87,521,651	$	875	(110,964	)	$	(2,500	)	$	1,145,760		$	(94,270	)	$	(62,367	)	$	987,498		$	891,246			$	1,878,744
Issuance of Class A common stock under equity incentive award plan	206,060	2		—		—			(2		)	—			—			—			—				—
Stock-based compensation	—	—		—		—			985			—			—			985			—				985
Dividends declared	—	—		—		—			(36,258		)	—			—			(36,258		)	—				(36,258		)
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(2,647		)		(2,647		)
Other	—	—		—		—			(73		)	—			—			(73		)	—				(73		)
Net income (loss)	—	—		—		—			—			5,653			—			5,653			(3,114		)		2,539
Other comprehensive income, net of tax	—	—		—		—			—			—			4,875			4,875			67				4,942
Balances at March 31, 2017	87,727,711	$	877	(110,964	)	$	(2,500	)	$	1,110,412		$	(88,617	)	$	(57,492	)	$	962,680		$	885,552			$	1,848,232

Balances at December 31, 2017	98,017,860	$	980	(157,812	)	$	(3,511	)	$	1,234,846		$	(112,175	)	$	(25,691	)	$	1,094,449		$	1,253,693			$	2,348,142
Issuance of Class A common stock under equity incentive award plan	256,809	3		—		—			(3		)	—			—			—			—				—
Repurchase of shares for employee tax withholding	—	—		(20,097	)	(373		)	—			—			—			(373		)	—				(373		)
Stock-based compensation	—	—		—		—			1,051			—			—			1,051			—				1,051
Dividends declared	—	—		—		—			(17,574		)	(23,747		)	—			(41,321		)	—				(41,321		)
Acquisitions	—	—		—		—			—			—			—			—			11,113			—	11,113
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(9,187		)		(9,187		)
Other	—	—		—		—			(243		)	—			—			(243		)	—				(243		)
Net income (loss)	—	—		—		—			—			135,922			—			135,922			(148,542		)		(12,620		)
Other comprehensive loss, net of tax	—	—		—		—			—			—			(1,119		)	(1,119		)	(674		)		(1,793		)
Balances at March 31, 2018	98,274,669	$	983	(177,909	)	$	(3,884	)	$	1,218,077		$	—		$	(26,810	)	$	1,188,366		$	1,106,403			$	2,294,769

See accompanying notes to consolidated financial statements.

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

	Three months ended March 31,
	2018			2017
Operating activities
Net income (loss)	$	(12,620	)	$	2,539
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and accretion	55,451			43,740
Amortization of financing costs	1,249			1,858
Amortization of debt discount/premium, net	1,227			1,102
Amortization of power purchase agreements, net	1,422			736
Loss on derivatives	3,655			2,350
Stock-based compensation	1,051			985
Deferred taxes	6,647			4,693
Earnings in unconsolidated investments, net	(18,212		)	(16,876		)
Distributions from unconsolidated investments	13,548			16,487
Other reconciling items	2,982			(439		)
Changes in operating assets and liabilities:
Funds deposited by counterparty	12,036			1,658
Trade receivables	(5,742		)	(8,432		)
Prepaid expenses	2,193			946
Other current assets	62			(4,083		)
Other assets (non-current)	(1,346		)	2,992
Accounts payable and other accrued liabilities	(18,716		)	(4,418		)
Counterparty deposit liability	(12,036		)	(1,658		)
Accrued interest	(9,144		)	(2,725		)
Other current liabilities	72			(975		)
Long-term liabilities	3,904			3,272
Contingent liabilities	(87		)	—
Derivatives	228			—
Net cash provided by operating activities	27,824			43,752
Investing activities
Cash paid for acquisitions, net of cash and restricted cash acquired	(157,543		)	(275		)
Capital expenditures	(61,282		)	(1,328		)
Distributions from unconsolidated investments	—			4,205
Other assets	(16,720		)	83
Investment in Pattern Development 2.0	(35,156		)	—
Net cash provided by (used in) investing activities	(270,701		)	2,685

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

	Three months ended March 31,
	2018			2017
Financing activities
Dividends paid	(41,358		)	(35,522		)
Capital distributions - noncontrolling interest	(9,187		)	(2,647		)
Payment for financing fees	(5,448		)	(5,025		)
Proceeds from revolving credit facility	283,000			—
Repayment of revolving credit facility	(35,000		)	(180,000		)
Proceeds from long-term debt	113,116			350,000
Repayment of long-term debt	(19,166		)	(10,326		)
Repayment of note payable - related party	(909		)	—
Other financing activities	826			(2,003		)
Net cash provided by financing activities	285,874			114,477
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(611		)	—
Net change in cash, cash equivalents and restricted cash	42,386			160,914
Cash, cash equivalents and restricted cash at beginning of period	137,980			109,371
Cash, cash equivalents and restricted cash at end of period	$	180,366		$	270,285
Supplemental disclosures
Cash payments for income taxes	$	60		$	247
Cash payments for interest expense	$	32,617		$	22,607
Business combination:
Assets acquired, net of cash and restricted cash acquired	$	627,241		$	—
Liabilities assumed	352,570			—
Less: Noncontrolling interests	11,113			—
Net assets acquired, net of cash and restricted cash acquired	$	263,558		$	—
Schedule of non-cash activities
Change in property, plant and equipment	$	122,161		$	956
Accrual of dividends	$	45		$	—
Accrual of deferred financing costs	$	—		$	1,640

See accompanying notes to consolidated financial statements.

Pattern Energy Group Inc.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

Pattern Energy Group Inc. (Pattern Energy or the Company) was organized in the state of Delaware on October 2, 2012. Pattern Energy is an independent energy generation company focused on constructing, owning and operating energy projects with long-term energy sales contracts located in the United States, Canada and Chile. Pattern Energy Group LP (Pattern Development 1.0) owns a 7.5% interest in the Company. The Pattern Development Companies (Pattern Development 1.0, Pattern Energy Group 2 LP (Pattern Development 2.0) and their respective subsidiaries) are leading developers of renewable energy and transmission projects.

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

•

Pattern US Operations Holdings LLC (which consists primarily of 100% ownership of Hatchet Ridge Wind, LLC (Hatchet Ridge), Spring Valley Wind LLC (Spring Valley), Pattern Santa Isabel LLC (Santa Isabel), Ocotillo Express LLC (Ocotillo), Pattern Gulf Wind LLC (Gulf Wind) and Lost Creek Wind, LLC (Lost Creek), as well as the following consolidated controlling interest in Panhandle Wind LLC (Panhandle 1), Panhandle Wind 2 LLC (Panhandle 2), Post Rock Wind Power Project, LLC (Post Rock), Logan's Gap Wind LLC (Logan's Gap), Fowler Ridge IV Wind Farm LLC (Amazon Wind), and Broadview Finco Pledgor LLC ((Broadview Project) (which consists primarily of Broadview Energy KW, LLC and Broadview Energy JN, LLC (together, Broadview) and Western Interconnect LLC, a transmission line (Western Interconnect)));

•

Pattern Canada Operations Holdings ULC (which consists primarily of 100% ownership of St. Joseph Windfarm Inc. (St. Joseph), a consolidated controlling interest in Meikle Wind Energy Limited Partnership (Meikle) and noncontrolling interests in South Kent Wind LP (South Kent), Grand Renewable Wind LP (Grand), K2 Wind Ontario Limited Partnership (K2), and SP Armow Wind Ontario LP (Armow) which are accounted for as unconsolidated investments);


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


•	Green Power Tsugaru Holdings G.K. (Tsugaru Holdings) (which consists primarily of 100% ownership of Green Power Tsugaru G.K. (Tsugaru)) and Green Power Generation G.K. (which consists primarily of 100% ownership in GK Green Power Otsuki (Ohorayama), Otsuki Wind Power Corporation (Otsuki), and GK Green Power Kanagi (Kanagi), and consolidated controlling interest in GK Green Power Futtsu (Futtsu)).

In February 2018, the Company funded $35.2 million into Pattern Development 2.0 of which approximately $27 million was used by Pattern Development 2.0 to fund the purchase of Green Power Investments (GPI). As of March 31, 2018, the Company has funded $102.5 million in aggregate and holds an approximately 23% ownership interest in Pattern Development 2.0.

2. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the results of wholly-owned and partially-owned subsidiaries in which the Company has a controlling interest with all significant intercompany accounts and transactions eliminated in consolidation.

Unaudited Interim Financial Information

The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (U.S. GAAP) for interim financial information and Article 10 of Regulation S-X issued by the U.S. Securities and Exchange Commission (SEC). Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, the interim financial information reflects all adjustments of a normal recurring nature, necessary for a fair presentation of the Company’s financial position at March 31, 2018, the results of operations and comprehensive income (loss) for the three months ended March 31, 2018 and 2017, respectively, and the cash flows for the three months ended March 31, 2018 and 2017, respectively. The consolidated balance sheet at December 31, 2017 has been derived from the audited financial statements at that date, but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements. This Form 10-Q should be read in conjunction with the consolidated financial statements and accompanying notes contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

Use of Estimates

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

Reclassification

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

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

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



	March 31, 2018		March 31, 2017
Cash and cash equivalents	$	162,144	$	244,675
Restricted cash - current	8,698		8,493
Restricted cash	9,524		17,117
Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	180,366	$	270,285

Major Equipment Advances

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

Goodwill

Goodwill is not amortized, but is subject to an assessment for impairment at least annually or more frequently if events occur or circumstances change that will more likely than not reduce the fair value of the reporting unit below its carrying amount.

The 2017 Tax Act

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

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

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

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

Recently Issued Accounting Standards

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

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

In February 2016, the FASB issued ASU 2016-02, Leases (ASU 2016-02), which requires lessees to recognize right-of-use assets and lease liabilities, for all leases, with the exception of short-term leases, at the commencement date of each lease. Under the new guidance, lessor accounting is largely unchanged. ASU 2016-02 simplifies the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and liabilities. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. Early adoption is permitted. The amendments of this update should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. The Company is implementing a number of system enhancements to facilitate the identification, tracking and reporting of leases based upon the requirements of the new lease standard. The Company is also assessing the accounting impact of the ASU 2016-02 as it applies to its PPAs, land leases, office leases and equipment leases. As the Company progresses further in its analysis, the scope of this assessment could be expanded to review other types of contracts. The Company is continuing to assess the transition options and practical expedients, and monitoring industry implementation issues. The Company will adopt ASU 2016-02 beginning January 1, 2019.

3. Revenue

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

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

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

Revenue Recognition

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

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



	Three Months Ended March 31,
	2018		2017⁽¹⁾
Revenue from contracts with customers
Electricity sales under PSA	$	20,686	$	18,821
Electricity sales to market	2,193		3,399
REC sales	1,947		2,282
Total revenue from contracts with customers	$	24,826	$	24,502
Other electricity sales ⁽²⁾	77,321		73,932
Related party other revenue	9,512		2,399
Total revenue	$	111,659	$	100,833

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

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

Electricity Sales

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

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

Renewable Energy Credits Sales

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

Remaining performance obligations represent the transaction price of standalone RECs for which RECs have not been delivered to the customer's account. The transaction price is determined on the basis of the stated contract price multiplied by RECs to be delivered. As of March 31, 2018, approximately $23.7 million of revenue is expected to be recognized from remaining performance obligations associated with the standalone sale of RECs. The Company expects to recognize revenue on approximately half of these remaining performance obligations over the next 24 months, with the balance recognized thereafter.

Contract Balances

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

4. Acquisitions

Business Combination

Japan Acquisition

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

Total consideration for the Japan Acquisition was $282.5 million, which consisted of approximately $176.6 million of cash and post-closing contingent payments with fair value of approximately $105.9 million. As part of the acquisition, the Company also assumed $181.3 million of debt. The Company incurred transaction-related expenses of $1.3 million which were recorded in net loss on transactions in the consolidated statements of operations for the three months ended March 31, 2018.

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

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



	March 7, 2018
Consideration paid:	$	282,548
Identifiable assets acquired:
Cash and cash equivalents ⁽¹⁾	$	10,100
Restricted cash, current ⁽¹⁾	8,325
Trade receivables ⁽¹⁾	3,005
Prepaid expenses ⁽¹⁾	2,207
Other current assets ⁽¹⁾	8,368
Major equipment advances ⁽¹⁾	1,240
Restricted cash, noncurrent ⁽¹⁾	565
Deferred financing costs, net ⁽¹⁾	1,337
Property, plant and equipment	262,681
Construction in progress	181,549
Land ⁽¹⁾	112
Goodwill	60,302
Finite lived intangible assets	103,170
Other noncurrent assets ⁽¹⁾	3,270
Identifiable liabilities assumed:
Accounts payable and other accrued liabilities ⁽¹⁾	(6,607		)
Accrued interest ⁽¹⁾	(474		)
Accrued construction costs ⁽¹⁾	(4,128		)
Contingent liabilities, current	(16,249		)
Current portion of long-term debt	(7,511		)
Other current liabilities ⁽¹⁾	(22,094		)
Long-term debt	(173,828		)
Deferred tax liabilities	(67,179		)
Asset retirement obligations	(39,872		)
Finite lived intangible liability	(9,252		)
Derivative liabilities	(5,376		)
Assets and liabilities assumed before noncontrolling interests	293,661
Less: noncontrolling interests	(11,113		)
Total consideration	$	282,548

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

Property, plant and equipment, construction in progress, and finite-lived intangible assets were recorded at fair value estimated using the cost and income approach. The fair value of asset retirement obligations, long-term debt, finite lived intangible liability and derivative liabilities were recorded at fair value using a combination of market data, operational data and discounted cash flows and were adjusted by a discount rate factor reflecting current market conditions at the time of acquisition. The noncontrolling interest in Futtsu was recorded at fair value estimated using a projected cash flow stream of distributable cash, discounted to present value with a discount rate reflecting the cost of equity adjusted for control premium.

Certain deferred tax liabilities were carried over to the Company as a result of the Japan Acquisition based on the Company's ability to utilize them in the future. Additionally, deferred tax liabilities and goodwill were established for acquisition accounting fair value adjustments as the future accretion of the fair value adjustments represent temporary differences between book income and taxable income.

The Company assumed a $16.2 million contingent liability as part of the acquisition. This contingent payment is subject to the completion of a construction milestone at Tsugaru and is calculated based on the nameplate capacity of Tsugaru.

The contingent purchase consideration with fair value of $102.9 million, subject to foreign currency exchange rate changes, is contingent upon term conversion of the Tsugaru construction loan and to the extent such term conversion does not occur such consideration will be made upon the commencement of commercial operations of Tsugaru, both of which are expected to occur in 2020. The remaining contingent purchase consideration of $3.0 million, subject to foreign currency exchange rate changes, is contingent upon term conversion of the Ohorayama construction loan, expected to occur in mid-2018. See Note 13, Fair Value Measurements for further discussion in the fair value of the contingent consideration.

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

Supplemental Pro Forma Data (unaudited)

Ohorayama commenced operations in March 2018 and until approximately one week before acquisition, Ohorayama was still under construction. In addition, Tsugaru is expected to commence commercial operations in early to mid-2020. Therefore, pro forma data for Ohorayama and Tsugaru have not been provided as there is no material difference between pro forma data that give effects to the Japan Acquisition as if it had occurred on January 1, 2017 and the actual data reported for the three months ended March 31, 2018 and 2017.

The unaudited pro forma statement of operations data below gives effect to the Japan Acquisition, as if it had occurred on January 1, 2017. The 2018 pro forma net loss was adjusted to exclude nonrecurring transaction related expenses of $1.3 million. The unaudited pro forma data is presented for illustrative purposes only and is not intended to be indicative of actual results that would have been achieved had the acquisition been consummated as of January 1, 2017. The unaudited pro forma data should not be considered representative of the Company’s future financial condition or results of operations.



Unaudited pro forma data (in thousands)	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017
Pro forma total revenue	$	115,394		$	107,043
Pro forma total expenses	(127,354		)	(104,840		)
Pro forma net (loss) income	(11,960		)	2,203
Less: pro forma net loss attributable to noncontrolling interest	(148,336		)	(3,042		)
Pro forma net income attributable to Pattern Energy	$	136,376		$	5,245

The following table presents the amounts included in the consolidated statements of operations for the acquisition discussed above since the date of the acquisition:



Unaudited data (in thousands)	Three Months Ended March 31, 2018
Total revenue	$	4,040
Total expenses	(3,055		)
Net income	985
Less: net income attributable to noncontrolling interest	179
Net income attributable to Pattern Energy	$	806

5. Property, Plant and Equipment

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



	March 31,			December 31,
	2018			2017
Operating wind farms	$	4,885,871		$	4,640,718
Transmission line	93,849			93,849
Construction in progress	182,123			—
Furniture, fixtures and equipment	12,882			12,643
Land	253			141
Subtotal	5,174,978			4,747,351
Less: accumulated depreciation	(834,005		)	(782,230		)
Property, plant and equipment, net	$	4,340,973		$	3,965,121

The Company recorded depreciation expense related to property, plant and equipment of $54.3 million and $43.0 million for the three months ended March 31, 2018 and 2017, respectively.

6. Finite-Lived Intangible Assets and Liabilities and Goodwill

Finite-Lived Intangible Assets and Liabilities

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



	March 31, 2018
	Weighted Average Remaining Life	Gross		Accumulated Amortization			Net
Intangible assets
Power purchase agreements	16	$	229,502	$	(19,848	)	$	209,654
Industrial revenue bond tax savings	24	12,778		(479		)	12,299
Other intangible assets	34	15,234		(1,235		)	13,999
Total intangible assets		$	257,514	$	(21,562	)	$	235,952
Intangible liabilities
Power purchase agreement	15	$	60,300	$	(9,973	)	$	50,327
Leasehold interest	23	9,252		—			9,252
Total intangible liabilities		$	69,552	$	(9,973	)	$	59,579



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

The Company presents amortization of the PPA assets and PPA liabilities as an offset to electricity sales in the consolidated statements of operations, which resulted in net expense of $1.4 million and $0.7 million for the three months ended March 31, 2018 and 2017, respectively. For other intangible assets, the Company includes the amortization in depreciation, amortization and accretion in the consolidated statements of operations and recorded amortization expense of $0.1 million and $0.1 million for the three months ended March 31, 2018 and 2017, respectively.

As part of the 2017 Broadview acquisition, the Company acquired an intangible asset related to future property tax savings resulting from the issuance of industrial revenue bonds during construction of the project. The intangible asset is being amortized to depreciation, amortization and accretion in the consolidated statements of operations. The Company recorded amortization expense of $0.1 million for the three months ended March 31, 2018 related to the industrial revenue bond tax savings intangible asset. The Company did not record any amortization expense for the three months ended March 31, 2017 as the Broadview Project was acquired in May 2017.

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

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



Year ended December 31,	Power purchase agreements, net		Industrial revenue bond tax savings		Other intangible assets		Leasehold interests
2018 (remainder)	$	7,597	$	385	$	454	$	(303	)
2019	10,011		513		605		(404		)
2020	10,049		513		605		(404		)
2021	10,011		513		605		(404		)
2022	10,011		513		605		(404		)
Thereafter	111,648		9,862		11,125		(7,333		)

Goodwill

In connection with the Japan Acquisition, deferred tax liabilities were established for acquisition accounting fair value adjustments as the future accretion of the fair value adjustments represents temporary differences between book income and taxable income. These fair value adjustments resulted in goodwill of $60.3 million being recorded.

7. Variable Interest Entities

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

The Company’s equity method investment in Pattern Development 2.0 is considered to be a VIE primarily because the total equity at risk is not sufficient to permit Pattern Development 2.0 to finance its activities without additional subordinated financial support by the equity holders. The Company does not hold the power or benefits to be the primary beneficiary and does not consolidate the VIE. The carrying value of its unconsolidated investment in Pattern Development 2.0 was $93 million as of March 31, 2018. The Company's maximum exposure to loss is equal to the carrying value of the investment.

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



	March 31, 2018		December 31, 2017
Assets
Current assets:
Cash and cash equivalents	$	20,421	$	33,273
Restricted cash	4,324		4,314
Trade receivables	18,829		12,769
Prepaid expenses	5,499		4,965
Other current assets	1,703		2,597
Total current assets	50,776		57,918

Restricted cash	614		3,330
Property, plant and equipment, net	1,959,617		1,984,606
Finite-lived intangible assets, net	12,056		12,210
Other assets	13,051		12,984
Total assets	$	2,036,114	$	2,071,048

Liabilities
Current liabilities:
Accounts payable and other accrued liabilities	$	14,135	26,826
Accrued construction costs	13		759
Accrued interest	76		78
Other current liabilities	4,691		4,789
Total current liabilities	18,915		32,452

Finite-lived intangible liability, net	50,327		—
Contingent liabilities	—		87
Other long-term liabilities	52,123		47,345
Total liabilities	$	121,365	$	79,884

8. Unconsolidated Investments

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



					Percentage of Ownership
	March 31,		December 31,		March 31,		December 31,
	2018		2017		2018		2017
South Kent	$	12,732	$	6,151	50.0	%	50.0	%
Grand	9,213		6,611		45.0	%	45.0	%
K2	98,219		103,328		33.3	%	33.3	%
Armow	134,678		132,890		50.0	%	50.0	%
Pattern Development 2.0	92,989		62,243		23.2	%	20.9	%
Unconsolidated investments	$	347,831	$	311,223

Pattern Development 2.0

In February 2018, the Company funded $35.2 million into Pattern Development 2.0 of which approximately $27 million was used by Pattern Development 2.0 to fund the purchase of GPI. As of March 31, 2018, the Company has funded $102.5 million in aggregate and holds an approximately 23% ownership interest in Pattern Development 2.0.

Basis Amortization of Unconsolidated Investments

The cost of the Company’s investment in the net assets of unconsolidated investments was higher than the fair value of the Company’s equity interest in the underlying net assets of its unconsolidated investments. The basis differences were primarily attributable to property, plant and equipment, PPAs, and equity method goodwill. The Company amortizes the basis difference attributable to property, plant and equipment, and PPAs over their useful life and contractual life, respectively. The Company does not amortize equity method goodwill. For the three months ended March 31, 2018 and 2017, the Company recorded basis difference amortization for its unconsolidated investments of $2.7 million and $2.8 million, respectively, in earnings in unconsolidated investments, net on the consolidated statements of operations.

Significant Equity Method Investees

The following table presents summarized statements of operations information for the three months ended March 31, 2018 and 2017 as required for the Company's significant equity method investees, South Kent, Grand, K2, Armow and Pattern Development 2.0 pursuant to Regulation S-X Rule 10-01(b)(1) (in thousands):



	Three months ended March 31,
	2018		2017⁽¹⁾
Revenue	$	109,533	$	100,359
Cost of revenue	30,337		29,589
Operating expenses	19,154		714
Other expense	20,851		22,841
Net income	$	39,191	$	47,215


⁽¹⁾	Results for the three months ended March 31, 2017 do not include Pattern Development 2.0, which the Company invested in during July 2017.

9. Debt

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



							As of March 31, 2018
	March 31, 2018			December 31, 2017			Contractual Interest Rate			Effective Interest Rate
	March 31, 2018			December 31, 2017			Contractual Interest Rate			Effective Interest Rate			Maturity
Corporate-level
Revolving Credit Facility	$	248,000		$	—		varies		⁽¹⁾	3.31	%	⁽¹⁾
2020 Notes	225,000			225,000			4.00	%		6.60	%		July 2020
2024 Notes	350,000			350,000			5.88	%		5.88	%		February 2024
Project-level
Fixed interest rate
El Arrayán EKF term loan	96,974			99,112			5.56	%		5.56	%		March 2029
Santa Isabel term loan	102,840			103,878			4.57	%		4.57	%		September 2033
Variable interest rate
Ocotillo commercial term loan	289,201			289,339			3.81	%		4.06	%	⁽³⁾	June 2033
El Arrayán commercial term loan	88,158			90,102			4.25	%		5.75	%	⁽³⁾	March 2029
Spring Valley term loan	123,660			125,678			4.06	%		5.03	%	⁽³⁾	June 2030
St. Joseph term loan ⁽²⁾	165,699			171,487			3.36	%		3.93	%	⁽³⁾	November 2033
Western Interconnect term loan ⁽²⁾	53,507			54,395			4.31	%		4.33	%	⁽³⁾	April 2027
Meikle term loan ⁽²⁾	255,746			266,557			3.23	%		3.92	%	⁽³⁾	May 2024
Futtsu term loan	81,064			—			1.07	%		1.85	%		December 2033
Ohorayama term loan	94,857			—			0.87	%		0.87	%		February 2036
Tsugaru construction loan	50,862			—			0.72	%		0.72	%		March 2038
Tsugaru Holdings loan	60,912			—			3.09	%		3.09	%		July 2022
Imputed interest rate
Hatchet Ridge financing lease obligation	192,079			192,079			1.43	%		1.43	%		December 2032
	2,478,559			1,967,627
Unamortized premium/discount, net⁽⁴⁾	(12,243		)	(13,470		)
Unamortized financing costs	(29,062		)	(23,426		)
Total debt, net	$	2,437,254		1,930,731

As reflected on the consolidated balance sheets
Revolving Credit Facility	$	248,000		$	—
Current portion of long-term debt, net of financing costs	61,191			51,996
Long term debt, net of financing costs	2,128,063			1,878,735
Total debt, net	$	2,437,254		$	1,930,731


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


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


⁽³⁾	Includes impact of interest rate swaps. See Note 11, Derivative Instruments, for discussion of interest rate swaps.


⁽⁴⁾	The discount relates to the 2020 Notes.

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



	Three months ended March 31,
	2018		2017
Corporate-level interest and commitment fees incurred	$	8,665	$	7,115
Project-level interest and commitment fees incurred	14,192		12,361
Amortization of debt discount/premium, net	1,227		1,102
Amortization of financing costs	1,249		1,858
Other interest	111		119
Interest expense	$	25,444	$	22,555

Corporate Level Debt

Revolving Credit Facility

Certain of the Company's subsidiaries have entered into a Second Amended and Restated Credit and Guaranty Agreement to the Revolving Credit Facility (the Revolving Credit Facility). The Revolving Credit Facility provides for a revolving credit facility of $440 million. The facility has a five-year term and is comprised of a revolving loan facility, a letter of credit facility and a swingline facility. The facility is secured by pledges of the capital stock and ownership interests in certain of the Company's holding company subsidiaries, in addition to other customary collateral.

As of March 31, 2018, $153.3 million was available for borrowing under the $440 million Revolving Credit Facility. 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 March 31, 2018, the Company's holding company subsidiaries were in compliance with covenants contained in the Revolving Credit Facility.

As of March 31, 2018 and December 31, 2017, letters of credit of $38.7 million and $47.5 million, respectively, were issued under the Revolving Credit Facility.

2020 Notes

In July 2015, the Company issued $225.0 million aggregate principal amount of 4.00% convertible senior notes due 2020 (Convertible Senior Notes or 2020 Notes). The 2020 Notes bear interest at a rate of 4.00% per year, payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2016. The 2020 Notes will mature on July 15, 2020. The 2020 Notes were sold in a private placement. The following table presents a summary of the equity and liability components of the 2020 Notes (in thousands):



	March 31, 2018			December 31, 2017
Principal	$	225,000		$	225,000
Less:
Unamortized debt discount	(12,243		)	(13,470		)
Unamortized financing costs	(2,523		)	(2,794		)
Carrying value of convertible senior notes	$	210,234		$	208,736
Carrying value of the equity component ⁽¹⁾	$	23,743		$	23,743


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

Project Debt

Tsugaru Credit Facility

In March 2018, Tsugaru entered into a credit agreement for a Construction Facility, a Term Facility, a Letter of Credit Facility (the LC Facility) and a Japanese Consumption Tax Facility (the JCT Facility). Under the Construction Facility, the Company may borrow up to $371.4 million to fund the construction of Tsugaru which automatically converts to a Term Facility upon the earlier of completion of construction of the project (expected to be March 2020) or September 2020 (the Term Conversion Date). The credit agreement, including the Term Facility and LC Facility, mature 18 years following the Term Conversion Date, not later than March 2039. The interest rate on the Construction Facility and Term Facility is the Tokyo Interbank Offered Rate (TIBOR) plus 0.65%. The LC Facility establishes a $19.7 million debt service reserve account letter of credit and an $8.0 million operations and maintenance reserve account letter of credit with amounts outstanding under the letters of credit owing interest at a rate of 1.10% and fees on the undrawn amounts of 0.30%. The JCT Facility provides for up to $33.8 million to pay Japanese consumption taxes arising from payment of project costs, with an interest rate of TIBOR plus 0.30% and a maturity date corresponding to the Term Conversion Date. The Company owes a commitment fee of 0.30% on any available amounts under the Construction Facility and the JCT Facility and on any undrawn amounts on the letters of credit up to the Term Conversion Date. Collateral for the credit facility includes Tsugaru's tangible assets and contractual rights and cash on deposit with the depository agent. The credit agreement contains a broad range of covenants that, subject to certain exceptions, restrict Tsugaru's ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests, dissolve, make distributions or change its business. As of March 31, 2018, outstanding borrowings under the Construction Facility totaled $50.9 million.

Tsugaru Holdings Loan Agreement

In March 2018, Tsugaru Holdings entered into a loan agreement (Loan Agreement) that provides for borrowings of up to $70.1 million during the Tsugaru construction period, until no later than September 2020. The interest rate on outstanding borrowings under the Loan Agreement is TIBOR plus 3.0% with principal due July 2022 and a commitment fee of 0.50% on the unused portion of the facility. The Loan Agreement is subject to certain covenants and is secured by the membership interests and other rights. As of March 31, 2018, outstanding borrowings under the Loan Agreement totaled $60.9 million.

10. Asset Retirement Obligation

The Company's asset retirement obligations represent the estimated cost of decommissioning the turbines, removing above-ground installations and restoring the sites at the end of its estimated economic useful life.

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



	Three months ended March 31,
	2018			2017
Beginning asset retirement obligations	$	56,619		$	44,783
Net additions during the period ⁽¹⁾	39,872			—
Foreign currency translation adjustment	(179		)	22
Accretion expense	896			640
Ending asset retirement obligations	$	97,208		$	45,445

⁽¹⁾Reflects additions due to the Japan Acquisition. See Note 4, Acquisitions, for discussion of the acquisition.

11. Derivative Instruments

The Company employs a variety of derivative instruments to manage its exposure to fluctuations in electricity prices, interest rates and foreign currency exchange rates. Energy prices are subject to wide swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists primarily on variable-rate debt for which the cash flows vary based upon movement in interest rates. Additionally, the Company is exposed to foreign currency exchange rate risk primarily from its business operations in Canada, Japan 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 March 31, 2018, 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):



	March 31, 2018
	Derivative Assets				Derivative Liabilities
	Current		Long-Term		Current		Long-Term
Fair Value of Designated Derivatives
Interest rate swaps	$	66	$	7,458	$	4,221	$	22,966

Fair Value of Undesignated Derivatives
Interest rate swaps	—		—		465		1,207
Energy derivative	13,791		2,033		—		—
Foreign currency forward contracts	1,890		4,288		999		4,252
Total Fair Value	$	15,747	$	13,779	$	5,685	$	28,425

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

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

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



	Unit of Measure	March 31,		December 31,
	Unit of Measure	2018		2017
Designated Derivative Instruments
Interest rate swaps	USD	$	516,233	$	253,271
Interest rate swaps	CAD	$	729,719	$	736,136
Interest rate swaps	JPY	¥	56,082,930	¥	—

Undesignated Derivative Instruments
Interest rate swaps	USD	$	62,749	$	85,474
Energy derivative	MWh	556,858		697,471
Foreign currency forward contracts	CAD	$	121,750	$	127,500
Foreign currency forward contracts	JPY	¥	12,255,630	¥	—

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

The Company has interest rate swap agreements to hedge variable rate project-level debt. Under these interest rate swaps, the projects make fixed-rate interest payments and the counterparties to the agreements make variable-rate interest payments. For interest swaps that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive loss and reclassified into earnings in the period or periods during which cash settlement occurs. The designated interest rate swaps have remaining maturities ranging from approximately 5.8 years to 20.8 years.

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



		Three months ended March 31,
	Description	2018			2017
Gains (losses) recognized in accumulated OCI	Effective portion of change in fair value	$	2,799		$	(580	)
Gains (losses) reclassified from accumulated OCI into:
Interest expense	Derivative settlements	$	(1,661	)	$	(2,570	)
Interest expense	Ineffective portion	$	538		$	(11	)

The Company estimates that $4.6 million in accumulated other comprehensive loss will be reclassified into earnings over the next twelve months.

Derivatives Not Designated as Hedging Instruments

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



	Financial Statement Line Item	Three months ended March 31,
Derivative Type	Financial Statement Line Item	2018			2017
Interest rate swaps	Gain (loss) on derivatives	$	1,527		$	122
Energy derivative	Electricity sales	$	(5,553	)	$	3,657
Foreign currency forward contracts	Gain (loss) on derivatives	$	4,133		$	(770	)

Interest Rate Swaps

The Company has an interest rate swap agreement to hedge variable rate project-level debt. Under this interest rate swap, the project makes fixed-rate interest payments and the counterparties to the agreement make variable-rate interest payments. For interest rate swaps that are not designated and do not qualify as cash flow hedges, the changes in fair value are recorded in gain (loss) on derivatives in the consolidated statements of operations as these hedges are not accounted for under hedge accounting. The Company's undesignated interest rate swap has a remaining maturity of 12.3 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 March 31, 2018, the Company has recorded a current asset of $17.7 million to funds deposited by counterparty and a current liability of $17.7 million to counterparty deposit liability representing the cash collateral received and corresponding obligation to return the cash collateral, respectively. The cash was deposited into a separate custodial account for which the Company is not entitled to the interest earned on the cash collateral.

Foreign Currency Forward Contracts

The Company has established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in the Company’s cash flow, which may have an adverse impact to the Company's short-term liquidity or financial condition. A majority of the Company’s power sale agreements and operating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar and Japanese yen. The Company enters into foreign currency forward contracts at various times to mitigate the currency exchange rate risk on Canadian dollar and, beginning in 2018, Japanese yen denominated cash flows. These instruments have remaining maturities ranging from three to 12.0 years. The foreign currency forward contracts are considered non-designated derivative instruments and are not used for trading or speculative purposes. As a result, changes in fair value and settlements are recorded in gain (loss) on derivatives in the consolidated statements of operations.

12. Accumulated Other Comprehensive Loss

The following tables summarize the changes in the accumulated other comprehensive loss balance, net of tax, by component (in thousands):



	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI			Total
Balances at December 31, 2016	$	(43,500	)	$	(12,751	)	$	(6,498	)	$	(62,749	)
Other comprehensive income (loss) before reclassifications	2,463			(541		)	(2,160		)	(238		)
Amounts reclassified from accumulated other comprehensive loss	—			2,319			2,861			5,180
Net current period other comprehensive income	2,463			1,778			701			4,942
Balances at March 31, 2017	$	(41,037	)	$	(10,973	)	$	(5,797	)	$	(57,807	)



	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI		Total
Balances at December 31, 2017	$	(28,187	)	$	(4,347	)	$	7,315	$	(25,219	)
Other comprehensive income (loss) before reclassifications	(9,102		)	3,745			808		(4,549		)
Amounts reclassified from accumulated other comprehensive loss	—			1,396			1,360		2,756
Net current period other comprehensive income (loss)	(9,102		)	5,141			2,168		(1,793		)
Balances at March 31, 2018	$	(37,289	)	$	794		$	9,483	$	(27,012	)

13. Fair Value Measurements

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

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

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

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

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

Financial Instruments

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

Financial Instruments Measured at Fair Value on a Recurring Basis

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



	March 31, 2018
	Level 1		Level 2		Level 3		Total
Assets
Interest rate swaps	$	—	$	7,524	$	—	$	7,524
Energy derivative	—		—		15,824		15,824
Foreign currency forward contracts	—		6,178		—		6,178
	$	—	$	13,702	$	15,824	$	29,526
Liabilities
Interest rate swaps	$	—	$	28,859	$	—	$	28,859
Foreign currency forward contracts	—		5,251		—		5,251
Contingent consideration	—		—		130,901		130,901
	$	—	$	34,110	$	130,901	$	165,011



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

Level 2 Inputs

Derivative instruments subject to re-measurement are presented in the financial statements at fair value. The Company's interest rate swaps were valued by discounting the net cash flows using the forward LIBOR curve with the valuations adjusted by the Company’s credit default hedge rate. The Company’s foreign currency forward contracts were valued using the income approach based on the present value of the forward rates less the contract rates, multiplied by the notional amounts.

Level 3 Inputs

Energy Hedge

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

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

Contingent Consideration

As part of the Japanese Acquisition, the Company is required to pay an additional earn-out of $114.2 million, which may be increased by $9.3 million if the final Tsugaru cost is less than or equal to the construction budget or may be decreased by $9.3 million if the final Tsugaru cost is greater than the construction budget, upon term conversion of the Tsugaru construction loan. The fair value of the contingent consideration at the acquisition date was $102.9 million. Additionally, the Company is obligated to make a $3.0 million cash distribution payment to Pattern Development 1.0 when the Ohorayama construction loan converts to a term loan. The term conversion is expected to occur in the near future as result the carrying value of the contingent consideration approximates fair value.

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

The estimated fair value of the contingent considerations were calculated by using a discounted cash flow technique which utilized unobservable inputs presented in the table below. This fair value measurement is based on significant inputs not observable in the market and thus represents a Level 3 measurement as defined in ASC 820, Fair Value Measurement. As of March 31, 2018, there were no significant changes in these unobservable inputs that may result in significant changes in fair value.

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



March 31, 2018	Fair Value	Valuation Technique	Significant Unobservable Inputs	Range
Energy derivative	$15,824	Discounted cash flow	Forward electricity prices	$26.73- $202.78⁽¹⁾
			Discount rate	2.31% - 2.42%

Broadview contingent consideration	$24,458	Discounted cash flow	Discount rate	4.0% - 8.0%
			Annual energy production loss	0.7%
Tsugaru contingent consideration	$103,469	Discounted cash flow	Deferred purchase price	$105 - $124 million
			Discount rate	6.9%

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

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


⁽¹⁾	Represents price per MWh.

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



	Three months ended March 31,
Energy Derivative	2018			2017
Balances, beginning of period	$	26,872		$	40,916
Total gain (loss) included in electricity sales	(5,553		)	3,658
Settlements	(5,495		)	(6,015		)
Balances, end of period	$	15,824		$	38,559

During the three months ended March 31, 2018 and 2017, the Company recognized unrealized losses of $11.0 million and $2.4 million relating to the energy derivative asset held at March 31, 2018 and 2017, respectively, which were recorded to electricity sales on the consolidated statements of operations.



	Three months ended March 31,
Contingent Consideration Liability	2018		2017
Balances, beginning of period	$	21,943	N/A
Purchase	105,922		N/A
Gain (loss) included in other income (expense), net	2,515		N/A
Gain (loss) included in construction in progress	521		N/A
Balances, end of period	$	130,901	N/A

During the three months ended March 31, 2018, the Company recognized $2.5 million of unrealized loss on the contingent consideration liability, which was recorded to other income (expense), net on the consolidated statements of operations and recognized $0.5 million of loss on the contingent consideration liability in property, plant and equipment, net in the consolidated balance sheets.

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
March 31, 2018
Long-term debt, including current portion	$	2,437,254	$	—	$	2,418,071	$	—	$	2,418,071
December 31, 2017
Long-term debt, including current portion	$	1,930,731	$	—	$	1,937,671	$	—	$	1,937,671

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

14. Stockholders' Equity

Common Stock

The Company has an equity distribution agreement (Equity Distribution Agreement) pursuant to the terms of which, the Company may offer and sell shares of the Company's Class A common stock, par value $0.01 per share, from time to time, up to an aggregate sales price of $200 million. For the three months ended March 31, 2018, the Company did not sell any shares under the Equity Distribution Agreement. As of March 31, 2018, approximately $144.2 million in aggregate offering price remained available to be sold under the agreement.

Dividends

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



	Dividends Per Share		Declaration Date	Record Date	Payment Date
2018:
First Quarter	$	0.4220	February 22, 2018	March 30, 2018	April 30, 2018

Noncontrolling Interests

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



	March 31,		December 31,
	2018		2017
El Arrayán	$	32,106	$	31,828
Logan's Gap	140,718		171,137
Panhandle 1	142,198		174,518
Panhandle 2	193,118		208,397
Post Rock	129,665		160,206
Amazon Wind	108,647		133,950
Broadview Project	285,911		307,672
Futtsu	11,292		—
Meikle	62,748		65,985
Noncontrolling interest	$	1,106,403	$	1,253,693

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



	Capital			Accumulated Loss				Accumulated Other Comprehensive Loss				Noncontrolling Interest
Balances at December 31, 2016	$	954,242		$	(62,614	)		$	(382	)		$	891,246
Distributions to noncontrolling interests	(2,647		)	—				—				(2,647		)
Net loss	—			(3,114		)		—				(3,114		)
Other comprehensive income, net of tax	—			—				67				67
Balances at March 31, 2017	$	951,595		$	(65,728	)		$	(315	)		$	885,552

Balances at December 31, 2017	$	1,380,340		$	(127,119	)		$	472			$	1,253,693
Acquisitions	11,113			—			—	—			—	11,113
Distributions to noncontrolling interests	(9,187		)	—				—				(9,187		)
Net loss ⁽¹⁾	—			(148,542		)		—				(148,542		)
Other comprehensive loss, net of tax	—			—				(674		)		(674		)
Balances at March 31, 2018	$	1,382,266		$	(275,661	)		$	(202	)		$	1,106,403

⁽¹⁾

On December 22, 2017, the Tax Act was signed into law, which enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Reduction in the corporate income tax rate resulted in one-time reduction in the noncontrolling interest attributable to partners in its tax equity partnerships. As part of the liquidation waterfall, the Company allocated significantly lower portions of the hypothetical liquidation proceeds to compensate certain noncontrolling interest investors for tax gains on the hypothetical sale calculated at the lowered rate of 21% as compared to the rate of 35% that was previously utilized. For the three months ended March 31, 2018, included in net loss attributable to noncontrolling interest is a one-time adjustment of $150 million as a result of the decrease in the federal corporate income tax rate.

15. Earnings Per Share

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

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

Potentially dilutive securities excluded from the calculation of diluted earnings (loss) per share because their effect would have been anti-dilutive were 0.5 million and 8.0 million, respectively, for the three months ended March 31, 2018 and 2017.

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



	Three months ended March 31,
	2018			2017
Numerator for basic and diluted earnings per share:
Net income attributable to Pattern Energy	$	135,922		$	5,653
Less: earnings allocated to participating securities	(121		)	(23		)
Numerator for basic earnings per share - net income attributable to common stockholders	$	135,801		$	5,630
Add back allocation of earnings to participating securities	121			23
Add back convertible senior notes interest	3,715			—
Reallocation of earnings to participating securities considering potentially dilutive securities	(115		)	(23		)
Numerator for diluted earnings per share - net income attributable to common stockholders	$	139,522		$	5,630

Denominator for earnings per share:
Weighted average number of shares:
Class A common stock - basic	97,428,388			87,062,612
Add dilutive effect of:
Restricted stock awards	58,233			57,759
Restricted stock units	437			10,909
Convertible senior notes	8,077,433			—
Class A common stock - diluted	105,564,491			87,131,280

Earnings per share:
Class A common stock:
Basic	$	1.39		$	0.06
Diluted	$	1.32		$	0.06

Dividends declared per Class A common share	$	0.42		$	0.41

16. Commitments and Contingencies

Commitments

Acquisition commitments

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

Completed Acquisition Commitments

As part of the Japan Acquisition completed in the first quarter of 2018, the Company became party to various agreements and future commitments. The following table summarizes estimates of future commitments related to the various agreements entered into as part of the Japan Acquisition as of March 31, 2018 (in thousands):



	Remainder of 2018		2019		2020		2021		2022		Thereafter		Total
Operating leases	$	2,292	$	3,056	$	2,451	$	2,249	$	2,249	$	31,405	$	43,702
Service and maintenance agreements	2,367		3,322		6,055		6,563		6,541		46,847		71,695
Other	54,678		156,770		35,581		—		—				247,029
Total commitments ⁽¹⁾	$	59,337	$	163,148	$	44,087	$	8,812	$	8,790	$	78,252	$	362,426

(1) The accounting for the Japan Acquisition is preliminary. Refer to Note 4, Acquisitions for details.

Operating Leases

The Company has entered into various long-term operating lease agreements related to lands for its wind and solar farms. For the three months ended March 31, 2018 and 2017, the Company recorded rent expenses of $4.1 million and $3.6 million, respectively, in project expense in its consolidated statements of operations.

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

Other Commitments

Other commitments consist of construction commitments related to the development of Tsugaru which is expected to commence commercial operations in early to mid-2020.

Letters of Credit

Power Sale Agreements

The Company owns and operates wind power projects and has entered into various long-term power sale agreements that terminate from 2019 to 2042. The terms of these agreements generally provide for the annual delivery of a minimum amount of electricity at fixed prices and in some cases include price escalation over the term of the agreement. Under the terms of these agreements, as of March 31, 2018, irrevocable letters of credits totaling $156.4 million were available to be issued to guarantee the Company's performance for the duration of the agreements.

Project Finance and Lease Agreements

The Company has various project finance and lease agreements which obligate the Company to provide certain reserves to enhance its credit worthiness and facilitate the availability of credit. As of March 31, 2018, irrevocable letters of credit totaling $197.0 million, which includes letters of credit available under the Revolving Credit Facility, were available to be issued to ensure performance under the various project finance and lease agreements.

Contingencies

Turbine Operating Warranties and Service Guarantees

The Company has various turbine availability warranties from its turbine manufacturers and service guarantees from its service and maintenance providers. Pursuant to these guarantees, if a turbine operates at less than minimum availability during the guarantee measurement period, the service provider is obligated to pay, as liquidated damages at the end of the warranty measurement period, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, pursuant to certain of these guarantees, if a turbine operates at more than a specified availability during the guarantee measurement period, the Company has an obligation to pay a bonus to the service provider at the end of the warranty measurement period. As of March 31, 2018, the Company recorded liabilities of $2.0 million associated with bonuses payable to the turbine manufacturers and service providers.

Contingencies in connection with the Broadview Project

The Company recorded a $7.2 million contingent obligation upon the acquisition of the Broadview Project in 2017, which is subject to certain conditions, including the actual energy production of Broadview in a production year and the continued operation of Broadview. Also as part of the acquisition, the Company recorded an additional $29.0 million contingent obligation, payable to the same counterparty, which is subject to certain conditions, including the commercial operation of the Grady Project, expected in April 2019. This contingent payment is calculated as a percentage of additional transmission revenue earned by Western Interconnect upon the Grady Project's commercial operation. As of March 31, 2018, the balance of the contingencies totaled $37.1 million of which $0.5 million is current and $36.6 million is long-term.

Contingencies in connection with the Sale of Panhandle 2 interests

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

Contingencies in connection with the Japan Acquisition

Legal Matters

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

Indemnity

The Company provides a variety of indemnities in the ordinary course of business to contractual counterparties and to its lenders and other financial partners. The Company is party to certain indemnities for the benefit of project finance lenders and tax equity partners of certain projects. These consist principally of indemnities that protect the project finance lenders from, among other things, the potential effect of any recapture by the U.S. Department of the Treasury of any amount of the cash grants previously received by the projects and eligibility of production tax credits and certain legal matters, limited to the amount of certain related costs and expenses.

17. Related Party Transactions

Management Fees

The Company provides management services and receives a fee for such services under agreements with its joint venture investees, South Kent, Grand, K2, and Armow, in addition to various Pattern Development 1.0 subsidiaries and equity method investments. In connection with the Japan Acquisition, the Company receives management services related to the acquired projects and incurs a fee for such services under agreements with a subsidiary of Pattern Development 2.0.

Management Services Agreement and Shared Management

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

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

Related Party Transactions

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



	March 31, 2018		December 31, 2017
Other current assets	$	8.5	$	13.2
Total due from related parties	$	8.5	$	13.2

Other current liabilities	$	14.1	$	10.8
Contingent liabilities, current	19.2		—
Contingent liabilities	125.7		—
Total due to related parties	$	159.0	$	10.8

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



		Three months ended March 31,
Related Party Agreement	Financial Statement Line Item	2018			2017
Management fees	Other revenue	$	2,056		$	2,224
MSA reimbursement	General and administrative	$	2,231		$	1,791
MSA costs	Related party general and administrative expense	$	(4,068	)	$	(3,426	)

Purchase and Sales Agreements

During the three months ended March 31, 2018, the Company consummated the following acquisitions with Pattern Development 1.0 which are further detailed in Note 4, Acquisitions (in millions):



Acquisitions from Pattern Development 1.0	Date of Acquisition	Cash Consideration		Debt Assumed		Contingent Consideration
Japan projects	March 7, 2018	$	176.6	$	181.3	$	105.9

Investment in Pattern Development 2.0

18. Subsequent Events

On May 3, 2018, the Company declared a dividend for the second quarter, payable on July 31, 2018, to holders of record on June 29, 2018, in the amount of $0.4220 per Class A share, or $1.688 on an annualized basis. This is unchanged from the first quarter of 2018.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes thereto included as part of our Annual Report on Form 10-K for the year ended December 31, 2017 and our unaudited consolidated financial statements for the three months ended March 31, 2018 and other disclosures (including the disclosures under “Part II. Item 1A. Risk Factors”) included in this Quarterly Report on Form 10-Q. Our consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles and are presented in U.S. dollars. Unless the context provides otherwise, references herein to “we,” “our,” “us,” “our company” and “Pattern Energy” refer to Pattern Energy Group Inc., a Delaware corporation, together with its consolidated subsidiaries.

Overview

We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued growth of our business. We hold interests in 25 wind and solar power projects, including the Mont Sainte-Marguerite (MSM) wind power project we have committed to acquire, with a total owned interest of 2,942 MW in the United States, Canada, Japan and Chile that use proven and best-in-class technology. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price power sale agreements (PSAs), some of which are subject to price escalation. Ninety-two percent of the electricity to be generated by our projects will be sold under our PSAs which have a weighted average remaining contract life of approximately 14 years as of March 31, 2018.

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

Our growth strategy is focused on the acquisition of operational and construction-ready power projects from Pattern Development Companies and other third parties that, together with measured investments into the development business, we believe will contribute to the growth of our business and enable us to increase our dividend per share of Class A common stock over time. The Pattern Development Companies (Pattern Energy Group LP (Pattern Development 1.0), Pattern Energy Group 2 LP (Pattern Development 2.0) and their respective subsidiaries) are leading developers of renewable energy and transmission projects. Our continuing relationship with the Pattern Development Companies, including a 23% interest in Pattern Development 2.0, provides us with access to a pipeline of acquisition opportunities. Currently, the Pattern Development Companies have a more than 10 GW pipeline of development projects, all of which are subject to our right of first offer. We target achieving a total owned or managed capacity of 5,000 MW by year end 2020 through a combination of acquisitions from the Pattern Development Companies and other third parties capitalizing on the large and fragmented global renewable energy market. Our business is primarily focused in the U.S., Canada, Japan and Chile; however, we expect opportunities in 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

Japan Acquisition

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

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

Noncontrolling Interests - Impact of the 2017 Tax Act

On December 22, 2017, the 2017 Tax Act (Tax Act) was signed into law, which enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Reduction in the corporate income tax rate resulted in one-time reduction in the noncontrolling interest attributable to partners in our tax equity partnerships. As part of the liquidation waterfall, we allocated significantly lower portions of the hypothetical liquidation proceeds to compensate certain noncontrolling interest investors for tax gains on the hypothetical sale calculated at the lowered rate of 21% as compared to the rate of 35% that was previously utilized. For the three months ended March 31, 2018, included in net loss attributable to noncontrolling interest is a one-time adjustment of $150 million as a result of the decrease in the federal corporate income tax rate. We do not expect the Tax Act to significantly change the flip point or the timing of expected cash distributions.

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



						Capacity (MW)
Identified ROFO Projects	Status	Location	Construction Start⁽¹⁾	Commercial Operations ⁽²⁾	Contract Type	Rated ⁽³⁾	Pattern Development- Owned ⁽⁴⁾
Pattern Development 1.0 Projects
Conejo Solar⁽⁵⁾	Operational	Chile	2015	2016	PPA	104	104
Belle River	Operational	Ontario	2016	2017	PPA	100	43
El Cabo	Operational	New Mexico	2016	2017	PPA	298	125
North Kent	Operational	Ontario	2017	2018	PPA	100	35
Henvey Inlet	In construction	Ontario	2017	2019	PPA	300	150
Pattern Development 2.0 Projects
Stillwater Big Sky	In construction	Montana	2017	2018	PPA	79	67
Crazy Mountain	Late stage development	Montana	2017	2019	PPA	80	68
Grady	Late stage development	New Mexico	2018	2019	PPA	220	188
Sumita	Late stage development	Japan	2019	2021	PPA	100	55
Ishikari	Late stage development	Japan	2019	2022	PPA	100	100
						1,481	935


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


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


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


⁽⁴⁾	Pattern Development-Owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW multiplied by Pattern Development 1.0's or Pattern Development 2.0's percentage ownership interest in the distributable cash flow of the project.

⁽⁵⁾

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

Key Metrics

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

Limitations to Key Metrics

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


•	excludes depreciation, amortization and accretion;


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


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


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

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

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

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


•	Adjusted EBITDA


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


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


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


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


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


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

•

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


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

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

Cash Available for Distribution

We define cash available for distribution as net cash provided by operating activities as adjusted for certain other cash flow items that we associate with our operations. It is a non-U.S. GAAP measure of our ability to generate cash to pay dividends.

Cash available for distribution represents cash provided by operating activities as adjusted to:

(i) add or subtract changes in operating assets and liabilities;

(ii) subtract net deposits into restricted cash accounts, which are required pursuant to the cash reserve requirements of financing agreements, to the extent they are paid from operating cash flows during a period;

(iii) subtract cash distributions paid to noncontrolling interests;

(iv) subtract scheduled project-level debt repayments in accordance with the related loan amortization schedule, to the extent they are paid from operating cash flows during a period;

(v) subtract non-expansionary capital expenditures, to the extent they are paid from operating cash flows during a period;

(vi) add cash distributions received from unconsolidated investments (as reported in net cash provided by investing activities), to the extent such distributions were derived from operating cash flows; and

(vii) add or subtract other items as necessary to present the cash flows we deem representative of our core business operations.

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



	Three months ended March 31,
	2018			2017
Net cash provided by operating activities⁽¹⁾	$	27,824		$	43,752
Changes in operating assets and liabilities	28,576			13,423
Network upgrade reimbursement	282			317
Release of restricted cash	2,488			—
Operations and maintenance capital expenditures	(261		)	(146		)
Distributions from unconsolidated investments⁽²⁾	6,281			4,205
Other	860			(3,432		)
Less:
Distributions to noncontrolling interests	(9,187		)	(2,647		)
Principal payments paid from operating cash flows	(13,803		)	(10,326		)
Cash available for distribution	$	43,060		$	45,146

(1) Included in net cash provided by operating activities for the three months ended March 31, 2017 is the portion of distributions from unconsolidated investments paid from cumulative earnings representing the return on investment.

(2) Distributions from unconsolidated investments includes project cash flow transferred to the project's distribution account in March 2018 and received subsequently in April 2018.

Cash available for distribution was $43.1 million for the three months ended March 31, 2018 as compared to $45.1 million for the same period in the prior year. This $2.1 million decrease in cash available for distribution was primarily due to:


•	a $12.6 million increase to project expense and transmission costs primarily due to acquisitions in 2017 and 2018;


•	a $6.5 million increase in distributions to noncontrolling interests;


•	a $0.9 million decrease in distributions from unconsolidated investments;


•	a $3.9 million increase in interest expense (excluding amortization of financing costs and debt discount/premium); and


•	a $3.5 million increase in principal payments of project-level debt.

The decrease was partially offset by:


•	a $20.2 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PSAs);


•	a $2.5 million increase in release of restricted cash; and


•	a $4.3 million increase in cash from other, primarily related to a $3.4 million project reserve funding requirement made in the first quarter of 2017.

Adjusted EBITDA

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

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

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



	Three months ended March 31,
	2018			2017
Net income (loss)	$	(12,620	)	$	2,539
Plus:
Interest expense, net of interest income	25,110			22,061
Tax provision	6,784			4,775
Depreciation, amortization and accretion	62,650			47,227
EBITDA	81,924			76,602
Unrealized loss on energy derivative⁽¹⁾	11,047			2,358
(Gain) loss on derivatives	(5,660		)	648
Other	—			312
Plus, proportionate share from unconsolidated investments:
Interest expense, net of interest income	9,468			9,340
Depreciation, amortization and accretion	8,768			8,454
(Gain) loss on derivatives	(1,335		)	484
Adjusted EBITDA	$	104,212		$	98,198


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

Adjusted EBITDA for the three months ended March 31, 2018 was $104.2 million compared to $98.2 million for the same period in the prior year, an increase of $6.0 million, or approximately 6.1%. The increase in Adjusted EBITDA was primarily due to a $20.2 million increase in revenue (excluding unrealized loss on energy derivative and amortization of PPAs) primarily attributable to volume increases as a result of our 2017 and 2018 acquisitions and an insurance settlement for Santa Isabel partially offset by lower electricity sales as a result of changing prices, unfavorable wind and curtailment primarily at projects in our Texas market and Santa Isabel.

The increase was partially offset by:


•	a $5.5 million increase in project expenses;


•	a $7.1 million increase in transmission costs; and


•	a $0.8 million increase in transaction costs primarily related to the Japan Acquisition.

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 March 31,
MWh sold	2018			2017			Change			% Change
Consolidated MWh sold	2,139,484			1,914,259			225,225			11.8	%
Less: noncontrolling MWh	(416,190		)	(259,594		)	(156,596		)	60.3	%
Controlling interest in consolidated MWh	1,723,294			1,654,665			68,629			4.1	%
Unconsolidated investments proportional MWh	403,368			383,494			19,874			5.2	%
Proportional MWh sold	2,126,662			2,038,159			88,503			4.3	%

Average realized electricity price per MWh
Consolidated average realized electricity price per MWh	$	53		$	53		$	—		—	%
Unconsolidated investments proportional average realized electricity price per MWh	$	119		$	115		$	4		3.5	%
Proportional average realized electricity price per MWh	$	67		$	67		$	—		—	%

Our consolidated MWh sold for the three months ended March 31, 2018 was 2,139,484 MWh, as compared to 1,914,259 MWh for the three months ended March 31, 2017, an increase of 225,225 MWh, or 11.8%. The increase in consolidated MWh sold for the three months ended March 31, 2018 compared to the three months ended March 31, 2017 was primarily due to volume increases as a result of acquisitions in 2017 and 2018 partially offset by unfavorable wind, curtailment at our Santa Isabel project and curtailment and congestion in our Texas market.

Our proportional MWh sold for the three months ended March 31, 2018 was 2,126,662 MWh, as compared to 2,038,159 MWh for the three months ended March 31, 2017, an increase of 88,503 MWh, or 4.3%. The increase in consolidated MWh sold was primarily attributable to:


•	a 68,629 MWh increase in controlling interest in consolidated MWh primarily due to our acquisitions in 2017 and 2018 partially offset by unfavorable wind, curtailment at our Santa Isabel project and curtailment and congestion in our Texas market; and


•	a 19,874 MWh increase from unconsolidated investments primarily due to favorable winds.

Our consolidated average realized electricity price was $53 per MWh for the three months ended March 31, 2018, as compared to $53 per MWh for the three months ended March 31, 2017 which was comparable.

Our proportional average realized electricity price was $67 per MWh for the three months ended March 31, 2018, as compared to $67 per MWh for the three months ended March 31, 2017which was comparable.

Results of Operations

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



	Three months ended March 31,
	2018			2017			$ Change			% Change
Revenue	$	111,659		$	100,833		$	10,826		10.7	%
Total cost of revenue	97,204			72,910			24,294			33.3	%
Total operating expenses	14,774			14,550			224			1.5	%
Total other expense	5,517			6,059			(542		)	(8.9	)%
Net income (loss) before income tax	(5,836		)	7,314			(13,150		)	(179.8	)%
Tax provision	6,784			4,775			2,009			42.1	%
Net income (loss)	(12,620		)	2,539			(15,159		)	(597.0	)%
Net loss attributable to noncontrolling interest	(148,542		)	(3,114		)	(145,428		)	4,670.1	%
Net income attributable to Pattern Energy	$	135,922		$	5,653		$	130,269		2,304.4	%

Total revenue

Total revenue for the three months ended March 31, 2018 was $111.7 million compared to $100.8 million for the three months ended March 31, 2017, an increase of $10.8 million, or approximately 10.7%. The increase was primarily attributable to:


•	a $29.4 million increase in electricity sales primarily due to volume increases as a result of acquisitions in 2017 and in the first quarter 2018; and


•	a $5.8 million settlement for business interruption insurance related to our Santa Isabel project.

This increase in revenue was largely offset by:


•	a $15.8 million decrease in electricity sales primarily due to lower production as a result of unfavorable wind conditions, curtailment at our Santa Isabel project and curtailment and congestion in our Texas market.


•	an $8.7 million increase in unrealized loss on energy derivative due to an increase in the forward gas price curves when compared to the prior period.

Cost of revenue

Cost of revenue for the three months ended March 31, 2018 was $97.2 million compared to $72.9 million for the three months ended March 31, 2017, an increase of $24.3 million, or approximately 33.3%. The increase in cost of revenue is primarily attributable to acquisitions completed in 2017 and 2018 which resulted in increases of $5.5 million in project expense, $7.1 million in transmission costs and $11.7 million in depreciation.

Operating expenses

Operating expenses for the three months ended March 31, 2018 were comparable to operating expenses for the three months ended March 31, 2017.

Other expense

Other expense for the three months ended March 31, 2018 was $5.5 million compared to $6.1 million for the three months ended March 31, 2017, a decrease of $0.5 million, or approximately 8.9%. The decrease was primarily attributable to:


•	a $6.3 million increase in gain on derivatives, net primarily due to gains from foreign currency hedges; and


•	a $1.3 million increase in earnings in unconsolidated investments, net primarily due to an increase in project income.

The decrease in other expense was partially offset by:


•	a $3.4 million increase in other income (expense), net primarily due to adjustments to contingent consideration;


•	a $2.9 million increase in interest expense primarily due to the issuance of the unsecured senior notes due 2024 in late January 2017 and debt associated with our acquisitions in 2017 and 2018; and


•	a $0.8 million increase in transaction costs primarily related to the Japan Acquisition.

Tax provision

Tax provision for the three months ended March 31, 2018 was $6.8 million compared to the tax provision of $4.8 million for the three months ended March 31, 2017, a change of $2.0 million. The tax provision for the three months ended March 31, 2018 was primarily the result of recording the tax effects on the recognized equity income from operations in unconsolidated investments and local taxes on foreign operations.

Net income (loss)

Net loss for the three months ended March 31, 2018 was $12.6 million compared to net income of $2.5 million for the same period in the prior year; an increase of $15.2 million or 597.0%. The increase in loss was primarily attributable to a $24.3 million increase in cost of revenues due to our acquisitions in 2017 and 2018 and an increase of $2.0 million in the tax provision.

This increase in loss was partially offset by:


•	a $10.8 million increase in revenues primarily due to acquisition in 2017 and 2018 and the settlement of business interruption insurance related to our Santa Isabel project; and


•	a $0.5 million decrease in other expense.

Noncontrolling interest

The net loss attributable to noncontrolling interest was $148.5 million for the three months ended March 31, 2018 compared to $3.1 million for the three months ended March 31, 2017. The increased loss of $145.4 million was attributable to increased allocations of losses to tax equity projects. The Tax Act, as discussed previously, reduced the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. As a result, for the three months ended March 31, 2018, included in net loss attributable to noncontrolling interest is a one-time adjustment of $150 million as a result of the decrease in the federal corporate income tax rate. See "Recent Developments - Noncontrolling Interests - Impact of the 2017 Tax Act."

Liquidity and Capital Resources

Our business requires substantial liquidity to fund (i) equity investments in our construction projects, (ii) current operational costs, (iii) debt service payments, (iv) dividends to our stockholders, (v) potential investments in new acquisitions, (vi) modifications to our projects, (vii) construction commitments, (viii) unforeseen events and (ix) other business expenses. As a part of our liquidity strategy, we plan to retain a portion of our cash flows in above-average wind years in order to have additional liquidity in below-average wind years.

Sources of Liquidity

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

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



	March 31, 2018
Unrestricted cash	$	162.1
Restricted cash	18.2
Revolving Credit Facility availability⁽¹⁾	153.3
Project facilities:
Post construction use	170.0
Construction facilities and loans	376.3
Total available liquidity	$	879.9


⁽¹⁾	As of May 7, 2018, the amount available on the Revolving Credit Facility is $174.3 million.

We expect that for the remainder of 2018, we will have sufficient liquid assets, cash flows from operations, and borrowings available under our Revolving Credit Facility and construction facilities to meet our financial commitments, debt service obligations, dividend payments, contingencies and anticipated required capital expenditures for at least the next 24 months, not including capital required for additional project acquisitions or capital call on Pattern Development 2.0. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corresponding adverse effect on our borrowing capacity.

In connection with our future capital expenditures and other investments, including any project acquisitions that we may make, or capital call on Pattern Development 2.0 we elect to participate in, we may, from time to time, issue debt or equity securities. Our ability to access the debt and equity markets is dependent on, among other factors, the overall state of the debt and equity markets and investor appetite for investment in clean energy projects in general and our Class A shares in particular. Volatility in the market price of our Class A shares may prevent or limit our ability to utilize our equity securities as a source of capital to help fund acquisitions. An inability to obtain debt or equity financing on commercially reasonable terms could significantly limit our timing and ability to consummate future acquisitions, and to effectuate our growth strategy.

We have an equity distribution agreement (Equity Distribution Agreement). Pursuant to the terms of the Equity Distribution Agreement, we may offer and sell shares of our Class A common stock, par value $0.01 per share, from time to time, up to an aggregate sales price of $200 million. We intend to use the net proceeds from the sale of the shares for general corporate purposes, which may include the repayment of indebtedness and the funding of acquisitions and investments. For the three months ended March 31, 2018, we did not sell any shares under the Equity Distribution Agreement. As of March 31, 2018, approximately $144.2 million in aggregate offering price remained available to be sold under the agreement.

Subject to market conditions, we will continue to consider various forms of repricings, refinancings, and/or repayments of our project level finance facilities. No assurances, however, can be given that we will be able to consummate any such transactions, that the transactions can be consummated on terms that are financially favorable to us, or that such transactions will have the intended financial effects of improving the consolidated statements of operations, net cash provided by operating activities, or cash available for distribution.

Cash Flows

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



	Three months ended March 31,
	2018			2017
Net cash provided by operating activities	$	27.8		$	43.8
Net cash provided by (used in) investing activities	(270.7		)	2.7
Net cash provided by financing activities	285.9			114.5
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(0.6		)	—
Net change in cash, cash equivalents and restricted cash	$	42.4		$	160.9

Net cash provided by operating activities

Net cash provided by operating activities was $27.8 million for the three months ended March 31, 2018 as compared to $43.8 million in the prior year, a decrease of $15.9 million, or approximately 36.4%. The decrease in cash provided by operating activities was primarily due to $12.6 million in increased transmission and projects costs primarily due to acquisitions in 2017 and 2018, decreased distributions from unconsolidated investments of $2.9 million, and increased interest payments of $10.0 million. The decrease to net cash provided by operating activities was partially offset by a $10.8 million increase in revenue.

Net cash provided by (used in) investing activities

Net cash used in investing activities was $270.7 million for the three months ended March 31, 2018, which consisted of $157.5 million in cash paid, net of cash and restricted cash acquired, for the Japan Acquisition, $61.3 million primarily for construction costs related to the Tsugaru project acquired in the Japan Acquisition, and an additional investment of $35.2 million in Pattern Development 2.0.

Net cash provided by investing activities was $2.7 million for the three months ended March 31, 2017, which consisted primarily of $4.2 million in distributions received from unconsolidated investments, partially offset by $1.3 million for capital expenditures and $0.3 million in costs associated with the acquisition of an unconsolidated investment in the fourth quarter of 2016.

Net cash provided by financing activities

Net cash provided by financing activities for the three months ended March 31, 2018 was $285.9 million. Net cash provided by financing activities consisted primarily of the following:


•	$113.1 million in proceeds related to the loans issued at Tsugaru Holdings and Tsugaru subsequent to the acquisition; and


•	$283.0 million in proceeds from other long-term debt and the Revolving Credit Facility.

Net cash provided by financing activities was partially offset by:


•	$35.0 million in repayments of the Revolving Credit Facility;


•	$41.4 million of dividend payments;


•	$19.2 million in repayments and termination of long-term debt;


•	$5.4 million in payments for deferred financing costs primarily associated with the issuance of debt associated with Tsugaru Holdings as described above; and


•	$9.2 million in distributions to noncontrolling interests.

Net cash provided by financing activities for the three months ended March 31, 2017 was $114.5 million. Net cash provided by financing activities consisted primarily of $350.0 million in proceeds from the issuance of the unsecured senior notes due 2024.

Net cash provided by financing activities were partially offset by:


•	$180.0 million in repayment of the Revolving Credit Facility.


•	$35.5 million of dividend payments;


•	$10.3 million in repayments of long-term debt;


•	$5.0 million in payments for deferred financing costs associated with the issuance of the unsecured senior notes due 2024; and


•	$2.6 million in distributions to noncontrolling interests.

Uses of Liquidity

Cash Dividends to Investors

We intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A common stock. On May 3, 2018, we declared an unchanged dividend of $0.4220 per share, or $1.688 per share on an annualized basis, to be paid on July 31, 2018 to holders of record on June 29, 2018. The following table sets forth the dividends declared on shares of Class A common stock for the periods indicated.



	Dividends Per Share		Declaration Date	Record Date	Payment Date
2018:
Second Quarter	$	0.4220	May 3, 2018	June 29, 2018	July 31, 2018
First Quarter	$	0.4220	February 22, 2018	March 30, 2018	April 30, 2018

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

Capital Expenditures and Investments

We expect to make investments in additional projects in 2018 and provide further capital to Pattern Development 2.0, as well as fund the construction costs at Tsugaru. We have committed to acquire MSM from Pattern Development 1.0 for a purchase price of approximately CAD $53.0 million, which is currently expected to occur in mid-2018. As discussed above, on March 7, 2018, we completed the Japan Acquisition which included cash consideration of $176.6 million, which does not include contingent post-closing payments of approximately $105.9 million. In February 2018, we invested an additional $35.2 million into Pattern Development 2.0.

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

Contractual Obligations

We have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to our capital expenditure programs. See also Note 9, Debt, and Note 16, Commitments and Contingencies, in the notes to consolidated financial statements for additional discussion of contractual obligations.

As part of our acquisitions completed in the first quarter of 2018, we became party to various agreements and future commitments. The following table summarizes estimates of future commitments related to the various agreements entered into as part of those acquisitions (in thousands) as of March 31, 2018:



Contractual Obligations	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Project-level debt principal payments	$	4,989	$	31,932	$	123,877	$	126,897	$	287,695
Project-level interest payments on debt instruments	3,698		9,747		7,474		13,033		33,952
Other	54,678		192,350		—		—		247,028
Operating leases	2,292		5,507		4,498		31,405		43,702
Service and maintenance agreements	2,367		9,377		13,105		46,847		71,696
Asset retirement obligations	—		—		—		39,827		39,827
Total	$	68,024	$	248,913	$	148,954	$	258,009	$	723,900

Operating Leases

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

Off-Balance Sheet Arrangements

As of March 31, 2018, we did not have any significant off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K.

Credit Agreements for Unconsolidated Investments

Below is a summary of our proportion of debt in unconsolidated investments, as of March 31, 2018 (in thousands):



	Total Project Debt		Percentage of Ownership		Our Portion of Unconsolidated Project Debt
Armow	$	389,461	50.0	%	$	194,731
South Kent	468,568		50.0	%	234,284
Grand	269,345		45.0	%	121,205
K2	574,087		33.3	%	191,343
Pattern Development 2.0	95,903		23.2	%	22,211
Unconsolidated investments - debt	$	1,797,364			$	763,774

Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

We manage our commodity price risk for electricity sales primarily through the use of fixed price long-term power purchase agreements with creditworthy counterparties. Our financial results reflect approximately 67,046 MWh of electricity sales during the three months ended March 31, 2018 that were subject to spot market pricing. A hypothetical increase or decrease of 10% or $2.59 per MWh in the merchant market prices would have increased or decreased revenue by $0.2 million for the three months ended March 31, 2018.

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

Interest Rate Risk

As of March 31, 2018, our long-term debt includes both fixed and variable rate debt. As long-term debt is not carried at fair value on the consolidated balance sheets, changes in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments prior to their maturity. The fair market value of our outstanding convertible senior notes, or "debentures," is subject to interest rate risk, market price risk and other factors due to the convertible feature of the debentures. The fair market value of the debentures will generally increase as interest rates fall and decrease as interest rates rise. In addition, the fair market value of the debentures will generally increase as the market price of our Class A common stock increases and decrease as the market price of our Class A common stock falls. The interest and market value changes affect the fair market value of the debentures, but do not impact our financial position, cash flows or results of operations due to the fixed nature of the debt obligations, except to the extent that changes in the fair value of the debentures or value of Class A common stock permit the holders of the debentures to convert into shares. As of March 31, 2018, the estimated fair value of our debt was $2.4 billion and the carrying value of our debt was $2.4 billion. The fair value of variable interest rate long-term debt is approximated by its carrying cost. A hypothetical increase or decrease in market interest rates by 1% would have resulted in a $44.7 million decrease or $48.2 million increase in the fair value of our fixed rate debt.

We are exposed to fluctuations in interest rate risk as a result of our variable rate debt and outstanding amounts due under our Revolving Credit Facility. As of March 31, 2018, $248 million was outstanding under the Revolving Credit Facility. A hypothetical increase or decrease in interest rates by 1% would have a $2.5 million impact to interest expense related to our Revolving Credit Facility for the three months ended March 31, 2018.

We may use a variety of derivative instruments, with respect to our variable rate debt, to manage our exposure to fluctuations in interest rates, including interest rate swaps. As a result, our interest rate risk is limited to the unhedged portion of the variable rate debt. As of March 31, 2018, the unhedged portion of our variable rate debt was $277.3 million. A hypothetical increase or decrease in interest rates by 1% would have a $2.8 million impact to interest expense for the three months ended March 31, 2018.

Foreign Currency Exchange Rate Risk

Our power projects are located in the United States, Canada, Japan 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 and Japanese Yen. For the three months ended March 31, 2018, our financial results included C$24.7 million and ¥85.7 million of net income from our Canadian and Japanese operations, respectively. A hypothetical 10% weakening or strengthening of U.S. dollar would have increased or decreased net earnings of our Canadian and Japanese operations by $2.0 million for the three months ended March 31, 2018.

We have established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in our cash flow, which may have an adverse impact to our short-term liquidity or financial condition. For the three months ended March 31, 2018, we recognized a gain on foreign currency forward contracts of $4.1 million in gain (loss) on derivatives in the consolidated statements of operations.

As of March 31, 2018, a 10% devaluation in the Canadian dollar and Japanese Yen to the United States dollar would result in our consolidated balance sheets being negatively impacted by a $52.3 million cumulative translation adjustment in accumulated other comprehensive loss.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act). In designing and evaluating the disclosure controls and procedures, management recognizes that any disclosure controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily is required to apply its judgment in evaluating the cost-benefit of possible controls and procedures.

Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2018.

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject, from time to time, to routine legal proceedings and claims arising out of the normal course of business. 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, 2017.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should consider the risks described under the caption “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2017. There have been no material changes in our risk factors as described in our Annual Report on Form 10-K.

ITEM 6. EXHIBITS



Exhibit No.		Description

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

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

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

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

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

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

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

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

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

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

10.6		Form of Restricted Stock Agreement under 2013 Equity Incentive Award Plan

10.7		Form of TSR Performance Restricted Stock Agreement under 2013 Equity Incentive Award Plan

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

31.2		Certifications of the Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32*		Certifications of the Company’s Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document




101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document



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

SIGNATURE

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



			Pattern Energy Group Inc.

Dated:	May 10, 2018	By:	/s/ Michael J. Lyon
			Michael J. Lyon
			Chief Financial Officer

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

Attached files

Pattern Energy Group Inc. Reports

Also read