ORMAT TECHNOLOGIES, INC. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - ORMAT TECHNOLOGIES, INC.	ex32-2.htm
EX-32.1 - EXHIBIT 32.1 - ORMAT TECHNOLOGIES, INC.	ex32-1.htm
EX-31.2 - EXHIBIT 31.2 - ORMAT TECHNOLOGIES, INC.	ex31-2.htm
EX-31.1 - EXHIBIT 31.1 - ORMAT TECHNOLOGIES, INC.	ex31-1.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

	For the quarterly period ended March 31, 2017

	or

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

	For the transition period from to

Commission file number: 001-32347

ORMAT TECHNOLOGIES, INC.

(Exact name of registrant as specified in its charter)

DELAWARE	88-0326081
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

6225 Neil Road, Reno, Nevada	89511-1136
(Address of principal executive offices)	(Zip Code)

(775) 356-9029

(Registrant’s telephone number, including area code)

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, 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. (Check one):

Large accelerated filer ☑	Accelerated filer ☐	Non-accelerated filer ☐	Smaller reporting company ☐

Emerging growth company ☐
		(Do not check if a smaller reporting 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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: As of May 8, 2017, the number of outstanding shares of common stock, par value $0.001 per share, was 49,706,450.

ORMAT TECHNOLOGIES, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2017


PART I — FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS	4

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	23

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	54

ITEM 4.	CONTROLS AND PROCEDURES	55

PART II — OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	56

ITEM 1A.	RISK FACTORS	57

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	57

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	57

ITEM 4.	MINE SAFETY DISCLOSURES	57

ITEM 5.	OTHER INFORMATION	57

ITEM 6.	EXHIBITS	57

SIGNATURES		58

Certain Definitions

Unless the context otherwise requires, all references in this quarterly report to “Ormat”, “the Company”, “we”, “us”, “our company”, “Ormat Technologies” or “our” refer to Ormat Technologies, Inc. and its consolidated subsidiaries.

iii

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
	2017			2016
	(Dollars in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	174,138		$	230,214
Restricted cash and cash equivalents (primarily related to VIEs)		59,879			34,262
Receivables:
Trade		68,920			80,807
Other		10,976			17,482
Inventories		17,804			12,000
Costs and estimated earnings in excess of billings on uncompleted contracts		56,550			52,198
Prepaid expenses and other		40,482			45,867
Total current assets		428,749			472,830
Investment in an unconsolidated company		2,806			—
Deposits and other		20,075			18,553
Deferred charges		43,960			43,773
Property, plant and equipment, net ($1,468,459 and $1,483,224 related to VIEs, respectively)		1,542,687			1,556,378
Construction-in-process ($129,965 and $120,853 related to VIEs, respectively)		351,636			306,709
Deferred financing and lease costs, net		3,465			3,923
Intangible assets, net		86,800			52,753
Goodwill		19,710			6,650
Total assets	$	2,499,888		$	2,461,569
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	95,518		$	91,650
Short term revolving credit lines with banks (full recourse)		30,000			—
Billings in excess of costs and estimated earnings on uncompleted contracts		17,595			31,630
Current portion of long-term debt:
Limited and non-recourse (primarily related to VIEs):
Senior secured notes		32,285			32,234
Other loans		21,495			21,495
Full recourse		10,598			12,242
Total current liabilities		207,491			189,251
Long-term debt, net of current portion:
Limited and non-recourse (primarily related to VIEs):
Senior secured notes (less deferred financing costs of $8,997 and $9,177, respectively)		344,397			350,388
Other loans (less deferred financing costs of $6,197 and $6,409, respectively)		256,787			261,845
Full recourse:
Senior unsecured bonds (less deferred financing costs of $683 and $755, respectively)		203,649			203,577
Other loans (less deferred financing costs of $1,276 and $1,346, respectively)		56,890			57,063
Investment in an unconsolidated company in excess of accumulated losses		—			11,081
Liability associated with sale of tax benefits		51,122			54,662
Deferred lease income		53,798			54,561
Deferred income taxes		42,283			35,382
Liability for unrecognized tax benefits		6,312			5,738
Liabilities for severance pay		19,530			18,600
Asset retirement obligation		23,803			23,348
Other long-term liabilities		32,130			21,294
Total liabilities		1,298,192			1,286,790
Commitments and contingencies (Note 10)

Reedemable noncontrolling interest		5,195			4,772

Equity:
The Company's stockholders' equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 49,706,450 and 49,667,340 shares issued and outstanding as of March 31, 2017 and December 31, 2016, respectively		50			50
Additional paid-in capital		871,176			869,463
Retained earnings		243,508			216,644
Accumulated other comprehensive income (loss)		(7,076	)		(7,732	)
		1,107,658			1,078,425
Noncontrolling interest		88,843			91,582
Total equity		1,196,501			1,170,007
Total liabilities and equity	$	2,499,888		$	2,461,569

The accompanying notes are an integral part of the consolidated financial statements.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND
COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended March 31,
	2017			2016
	(Dollars in thousands, except per share data)
Revenues:
Electricity	$	115,776		$	107,868
Product		74,122			43,726
Total revenues		189,898			151,594
Cost of revenues:
Electricity		66,036			63,686
Product		49,452			24,035
Total cost of revenues		115,488			87,721
Gross profit		74,410			63,873
Operating expenses:
Research and development expenses		602			349
Selling and marketing expenses		4,363			3,675
General and administrative expenses		9,949			8,749
Write-off of unsuccessful exploration activities		—			557
Operating income		59,496			50,543
Other income (expense):
Interest income		244			320
Interest expense, net		(14,923	)		(16,023	)
Derivatives and foreign currency transaction gains (losses)		1,338			1,962
Income attributable to sale of tax benefits		6,157			4,398
Other non-operating income (expense), net		(92	)		191
Income from continuing operations before income taxes and equity in losses of investees		52,220			41,391
Income tax (provision) benefit		(10,886	)		(9,509	)
Equity in losses of investees, net		(1,599	)		(937	)
Income from continuing operations		39,735			30,945
Net income attributable to noncontrolling interest		(4,423	)		(1,674	)
Net income attributable to the Company's stockholders	$	35,312		$	29,271
Comprehensive income:
Net income		39,735			30,945
Other comprehensive income (loss), net of related taxes:
Change in unrealized gains or losses in respect of the Company's share in derivatives instruments of unconsolidated investment		569			(3,179	)
Loss in respect of derivative instruments designated for cash flow hedge		22			21
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(24	)		(24	)
Comprehensive income		40,302			27,763
Comprehensive income attributable to noncontrolling interest		(4,412	)		(1,674	)
Comprehensive income attributable to the Company's stockholders	$	35,890		$	26,089
Earnings per share attributable to the Company's stockholders:
Basic:
Net income	$	0.71		$	0.60
Diluted:
Net income	$	0.70		$	0.59
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic		49,680			49,173
Diluted		50,491			49,782
Dividend per share declared	$	0.17		$	0.31

The accompanying notes are an integral part of the consolidated financial statements.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

	The Company's Stockholders' Equity
							Retained			Accumulated
					Additional		Earnings			Other
	Common Stock				Paid-in		(Accumulated			Income						Noncontrolling			Total
	Shares		Amount		Capital		Deficit)			(Loss)			Total			Interest			Equity

	(Dollars in thousands, except per share data)

Balance at December 31, 2015		49,107	$	49	$	849,223	$	148,396		$	(7,667	)	$	990,001		$	93,873		$	1,083,874

Stock-based compensation		—		—		842		—			—			842			—			842
Exercise of options by employees and directors		213		—		4,195		—			—			4,195			—			4,195
Cash paid to non controlling interest		—		—		—		—			—			—			(2,869	)		(2,869	)
Cash dividend declared, $0.31 per share		—		—		—		(15,472	)		—			(15,472	)		—			(15,472	)
Net income		—		—		—		29,271			—			29,271			1,674			30,945
Other comprehensive income (loss), net of related taxes:
cash flow hedge (net of related tax of $12)		—		—		—		—			21			21			—			21
Change in unrealized gains or losses in respect of the Company's share in derivative instruments of unconsolidated investment (net of related tax of $0)		—		—		—		—			(3,179	)		(3,179	)		—			(3,179	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $14)		—		—		—		—			(24	)		(24	)		—			(24	)

Balance at March 31, 2016		49,320	$	49	$	854,260	$	162,195		$	(10,849	)	$	1,005,655		$	92,678		$	1,098,333

Balance at December 31, 2016		49,667	$	50	$	869,463	$	216,644		$	(7,732	)	$	1,078,425		$	91,582		$	1,170,007

Stock-based compensation		—		—		1,713		—			—			1,713			—			1,713
Exercise of options by employees and directors		39		—		—		—			—			—			—			—
Cash paid to noncontrolling interest		—		—		—		—			—			—			(6,807	)		(6,807	)
Cash dividend declared, $0.17 per share		—		—		—		(8,448	)		—			(8,448	)		—			(8,448	)
Net income		—		—		—		35,312			—			35,312			4,079			39,391
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		—		—		—		—			89			89			(11	)		78
Loss in respect of derivative instruments designated for cash flow hedge (net of related tax of $12)		—		—		—		—			22			22			—			22
Change in unrealized gains or losses in respect of the Company's share in derivative instruments of unconsolidated investment (net of related tax of $0)		—		—		—		—			569			569			—			569
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $14)		—		—		—		—			(24	)		(24	)		—			(24	)

Balance at March 31, 2017		49,706	$	50	$	871,176	$	243,508		$	(7,076	)	$	1,107,658		$	88,843		$	1,196,501

The accompanying notes are an integral part of the consolidated financial statements.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended March 31,
	2017			2016
	(Dollars in thousands)
Cash flows from operating activities:
Net income	$	39,735		$	30,945
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		27,059			26,181
Amortization of premium from senior unsecured bonds		—			(77	)
Accretion of asset retirement obligation		455			406
Stock-based compensation		1,713			842
Amortization of deferred lease income		(671	)		(671	)
Income attributable to sale of tax benefits, net of interest expense		(4,335	)		(3,475	)
Equity in losses of investees		1,600			937
Mark-to-market of derivative instruments		(1,519	)		(162	)
Write-off of unsuccessful exploration activities		—			557
Gain on severance pay fund asset		(947	)		(564	)
Deferred income tax provision		6,612			6,643
Liability for unrecognized tax benefits		574			254
Deferred lease revenues		(92	)		88
Changes in operating assets and liabilities, net of amounts acquired:
Receivables		19,092			(21,925	)
Costs and estimated earnings in excess of billings on uncompleted contracts		(4,352	)		(4,777	)
Inventories		(5,800	)		1,279
Prepaid expenses and other		6,873			(1,808	)
Deposits and other		(557	)		80
Accounts payable and accrued expenses		681			(4,846	)
Billings in excess of costs and estimated earnings on uncompleted contracts		(14,035	)		(2,975	)
Liabilities for severance pay		930			(205	)
Other long-term liabilities		(1,553	)		317
Net cash provided by operating activities		71,463			27,044
Cash flows from investing activities:
Net change in restricted cash, cash equivalents and marketable securities		(25,617	)		(14,626	)
Capital expenditures		(52,885	)		(31,031	)
Investment in unconsolidated companies		(14,918	)		—
Cash paid for acquisition of controlling interest in a subsidiary, net of cash acquired		(35,300	)		—
Decrease (increase) in severance pay fund asset, net of payments made to retired employees		(18	)		1,037
Net cash used in investing activities		(128,738	)		(44,620	)
Cash flows from financing activities:
Proceeds from exercise of options by employees		—			4,195
Proceeds from revolving credit lines with banks		50,000			49,700
Repayment of revolving credit lines with banks		(20,000	)		(40,700	)
Cash received from noncontrolling interest		1,411			1,972
Repayments of long-term debt		(13,405	)		(11,631	)
Cash paid to noncontrolling interest		(6,807	)		(6,317	)
Payments of capital leases		(408	)		—
Deferred debt issuance costs		(1,144	)		(1,592	)
Cash dividends paid		(8,448	)		(15,472	)
Net cash provided by (used in) financing activities		1,199			(19,845	)
Net change in cash and cash equivalents		(56,076	)		(37,421	)
Cash and cash equivalents at beginning of period		230,214			185,919
Cash and cash equivalents at end of period	$	174,138		$	148,498
Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	1,801		$	(5,296	)
Accrued liabilities related to financing activities	$	—		$	3,768

The accompanying notes are an integral part of the consolidated financial statements.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — GENERAL AND BASIS OF PRESENTATION

These unaudited condensed consolidated interim financial statements of Ormat Technologies, Inc. and its subsidiaries (collectively, the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial statements. Accordingly, they do not contain all information and notes required by U.S. GAAP for annual financial statements. In the opinion of management, these unaudited condensed consolidated interim financial statements reflect all adjustments, which include normal recurring adjustments, necessary for a fair statement of the Company’s consolidated financial position as of March 31, 2017, the consolidated results of operations and comprehensive income (loss) for the three-month periods ended March 31, 2017 and 2016 and the consolidated cash flows for the three-month periods ended March 31, 2017 and 2016.

The financial data and other information disclosed in the notes to the condensed consolidated financial statements related to these periods are unaudited. The results for the three-month period ended March 31, 2017 are not necessarily indicative of the results to be expected for the year ending December 31, 2017.

These condensed unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2016. The condensed consolidated balance sheet data as of December 31, 2016 was derived from the Company’s audited consolidated financial statements for the year ended December 31, 2016, but does not include all disclosures required by U.S. GAAP.

Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest $1,000.

Viridity transaction

On March 15, 2017, the Company completed the acquisition of substantially all of the business and assets of Viridity Energy, Inc. (“VEI”), a privately held Philadelphia-based company engaged in the provision of demand response, energy management and energy storage services. Pursuant to the Asset Purchase Agreement dated as of December 29, 2016, Viridity Energy Solutions Inc. (“Viridity”), a wholly owned subsidiary of the Company paid initial consideration of $35.3 million at closing. Additional contingent consideration with an estimated fair value of $ 12.8 million will be payable in two installments upon the achievement of certain performance milestones measured at the end of fiscal years 2017 and 2020. The acquired business and assets are operated by Viridity.

Using proprietary software and solutions, Viridity serves primarily retail energy providers, utilities, and large commercial and industrial customers. Viridity’s offerings enable its customers to optimize and monetize their energy management, demand response and storage facilities potential by interacting on their behalf with regional transmission organizations and independent system operators.

The Company accounted for the transaction in accordance with Accounting Standard Codification 805, Business Combinations, and consequently recorded intangible assets of $35.0 million primarily relating to Viridity’s storage and non-storage activities with a weighted-average amortization period of 17 years, approximately $0.3 million of working capital and fixed assets, and $13.5 million of goodwill. Following the transaction, the Company consolidated Viridity, in accordance with Accounting Standard Codification 810, Consolidation.

The revenues of Viridity for the period from March 15, 2017 to March 31, 2017 were included in the Company’s consolidated statements of operations and comprehensive income for the three months ended March 31, 2017.

Accounting guidance provides that the allocation of the purchase price may be modified for up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.

Other comprehensive income

For the three months ended March 31, 2017 and 2016, the Company classified $2 thousand and $3 thousand, respectively, related to derivative instruments designated as cash flow hedges, from accumulated other comprehensive income, of which $3 thousand and $4 thousand, respectively, was recorded to reduce interest expense and $1 thousand, in both periods, was recorded against the income tax provision, in the condensed consolidated statements of operations and comprehensive income. The accumulated net loss included in Other comprehensive income as of March 31, 2017, is $0.6 million

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Write-offs of unsuccessful exploration activities

Write-offs of unsuccessful exploration activities for the three months ended March 31, 2017 and 2016 were $0.0 million and $0.6 million, respectively. The write-off of exploration costs in 2016 was related to the Company’s exploration activities in Nevada, which the Company determined would not support commercial operations.

Concentration of credit risk

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of temporary cash investments and accounts receivable.

The Company places its temporary cash investments with high credit quality financial institutions located in the United States (“U.S.”) and in foreign countries. At March 31, 2017 and December 31, 2016, the Company had deposits totaling $52.5 million and $72.5 million, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At March 31, 2017 and December 31, 2016, the Company’s deposits in foreign countries amounted to approximately $137.4 million and $166.2 million, respectively.

At March 31, 2017 and December 31, 2016, accounts receivable related to operations in foreign countries amounted to approximately $42.2 million and $53.3 million, respectively. At March 31, 2017 and December 31, 2016, accounts receivable from the Company’s primary customers amounted to approximately 60% of the Company’s accounts receivable.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 18.8% and 23.2% of the Company’s total revenues for the three months ended March 31, 2017 and 2016, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 14.3% and 17.4% of the Company’s total revenues for the three months ended March 31, 2017 and 2016, respectively.

Southern California Public Power Authority accounted for 9.0% and 12.1% of the Company’s total revenues for the three months ended March 31, 2017 and 2016, respectively.

Hyundai (Sarulla geothermal power project) accounted for 6.0% and 9.0% of the Company’s total revenues for the three months ended March 31, 2017 and 2016, respectively.

The Company has historically been able to collect on all of its receivable balances, and accordingly, no provision for doubtful accounts has been made.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements effective in the three-month period ended March 31, 2017

Improvement to Employee Share-Based Payment Accounting

In March 2016, the FASB issued ASU 2016-09, Improvement to Employee Share-Based Payment Accounting, an update to the guidance on stock-based compensation. Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in the income statement as they occur. This will replace the current guidance, which requires tax benefits that exceed compensation cost (windfalls) to be recognized in equity. It will also eliminate the need to maintain a “windfall pool,” and will remove the requirement to delay recognizing a windfall until it reduces current taxes payable. The new guidance will also change the cash flow presentation of excess tax benefits, classifying them as operating inflows, consistent with other cash flows related to income taxes. Today, windfalls are classified as financing activities. Also, this guidance will affect the dilutive effects in earnings per share, as there will no longer be excess tax benefits recognized in additional paid in capital. Today those excess tax benefits are included in assumed proceeds from applying the treasury stock method when computing diluted EPS. Under the amended guidance, companies will be able to make an accounting policy election to either (1) continue to estimate forfeitures or (2) account for forfeitures as they occur. This updated guidance is effective for annual and interim periods beginning after December 15, 2016. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

Interests Held through Related Parties that are under Common Control

In October 2016, the FASB issued ASU 2016-17, Consolidation (Topic 810): Interests held through Related Parties that are under Common Control. The amendments in this update require that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory, Topic 330. The update contains no amendments to disclosure requirements, but replaces the concept of ‘lower of cost or market’ with that of ‘lower of cost and net realizable value’. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those reporting periods. The amendments should be applied prospectively with early adoption permitted. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

New accounting pronouncements effective in future periods

Business Combinations

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805). The update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this update primarily provide a screen to determine when a set of assets and activities is not a business and by that reduces the number of transactions that need to be further evaluated. The amendments in this update should be applied prospectively and are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Statement of Cash Flows

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) – Restricted Cash. The amendments in this update require that a statement of cash flows explain the changes during the period in total cash, cash equivalents, and the amounts generally described as restricted cash or cash equivalents. Therefore, amounts of restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Intra-Entity Transfers of Assets Other than Inventory

In October 2016, the FASB issued ASU 2016-16, Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory. The amendments in this update require that the entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The new guidance does not apply to intra-entity transfers on inventory. The amendments in this update should be applied for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The modified retrospective approach will be required for transition to the new guidance, with cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. Early adoption is permitted in the first quarter of 2017. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Revenues from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenues from Contracts with Customers, Topic 606, which was a joint project of the FASB and the International Accounting Standards Board to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The update provides that an entity should recognize revenue in connection with the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Specifically, an entity is required to apply each of the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contracts; (3) determine the transaction price; (4) allocate the transaction price to the performance obligation in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also prescribes additional financial presentations and disclosures. The amendments in this update are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. Early adoption is permitted no earlier than 2017 for calendar fiscal year entities. The Company expects the adoption of this standard to have an immaterial impact, if any, on its Electricity segment as it accounts for its PPA’s under ASC 840, Leases. The Company still evaluates the potential impact of the adoption of the standard on its Product segment, however, it believes that such impact, if any, will be immaterial.

In March 2016, the FASB issued ASU 2016-08, Principal versus Agent Considerations. This update does not change the core principles of the guidance and is intended to clarify the implementation guidance on principal versus agent considerations. When another entity is involved in providing goods or services to a customer, an entity is required to determine if the nature of its promise is to provide the specific good or service itself (that is, the entity is a principal) or to arrange for that good or service to be provided by the other party (that is, the entity is an agent). The guidance includes indicators to assist an entity in determining whether it acts as a principal or agent in a specified transaction. The amendments in this update are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. Early adoption is permitted no earlier than 2017 for calendar fiscal year entities. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements, however, it believes that any such impact, if any, will be immaterial.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases, Topic 842. This update introduces a number of changes and simplifies previous guidance, primarily the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The update retains the distinction between finance leases and operating leases and the classification criteria between the two types remains substantially similar. Also, lessor accounting remains largely unchanged from previous guidance. However, key aspects of the update were aligned with the revenue recognition guidance in Topic 606. Additionally, the update defines a lease as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (a) the right to obtain substantially all of the economic benefits from the use of the asset and (b) the right to direct the use of the asset. The amendments in this update are effective for annual reporting periods beginning after December 15, 2018, including interim periods within those reporting periods. Early adoption is permitted. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. The update primarily requires that an entity present separately, in other comprehensive income, the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk if the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The application of this update should be by means of cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted as of the beginning of the fiscal year of adoption. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

NOTE 3 — INVENTORIES

Inventories consist of the following:

	March 31,		December 31,
	2017		2016
	(Dollars in thousands)
Raw materials and purchased parts for assembly	$	10,333	$	5,429
Self-manufactured assembly parts and finished products		7,471		6,571
Total	$	17,804	$	12,000

NOTE 4 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments consist of the following:

	March 31,		December 31,
	2017		2016
	(Dollars in thousands)
Sarulla	$	2,806	$	(11,081	)

The Sarulla Project

The Company holds a 12.75% equity interest in a consortium which is in the process of developing the Sarulla geothermal power project in Indonesia with an expected generating capacity of approximately 330 megawatts (“MW”). The Sarulla project is located in Tapanuli Utara, North Sumatra, Indonesia and will be owned and operated by the consortium members under the framework of a Joint Operating Contract (“JOC”) and Energy Sales Contract (“ESC”) that were signed on April 4, 2013. Under the JOC, PT Pertamina Geothermal Energy (“PGE”), the concession holder for the project, has provided the consortium with the right to use the geothermal field, and under the ESC, PT PLN, the state electric utility, will be the off-taker at Sarulla for a period of 30 years. In addition to its equity holdings in the consortium, the Company designed the Sarulla plant and will supply its Ormat Energy Converters (“OECs”) to the power plant, as further described below.

The project is being constructed in three phases of approximately 110 MW each, utilizing both steam and brine extracted from the geothermal field to increase the power plant’s efficiency. The first phase of the power plant commenced commercial operation on March 17, 2017. For the second phase of the power plant, engineering and procurement has been substantially completed, site construction is in progress and all of the major generating units, including those to be supplied by Ormat, were delivered. For the third phase of the power plant, engineering, procurement and construction work at the site are in progress and manufacturing of equipment to be supplied by Ormat is underway as planned. Ormat sent the first shipment of equipment manufactured by Ormat during the first quarter of 2017. Drilling for the second and third phases of the power plant is ongoing and the project has achieved to date, based on preliminary estimates, 100% of the required injection capacity and approximately 65% of the required production capacity.

On May 16, 2014, the consortium closed $1.17 billion in financing for the development of the Sarulla project with a consortium of lenders comprised of Japan Bank for International Cooperation (“JBIC”), the Asian Development Bank and six commercial banks and obtained construction and term loans on a limited recourse basis backed by a political risk guarantee from JBIC. Of the $1.17 billion, $0.1 billion (which was drawn down by the Sarulla project company on May 23, 2014) bears a fixed interest rate and $1.07 billion bears interest at a rate linked to LIBOR. The project has missed a few milestones under the loan documents, but has received waivers from the lenders and is currently in compliance with the lenders’ requirements. The project experienced delays in field development and cost overruns resulting from delays and excess drilling costs. Due to the cost overruns in drilling, the lenders requested that the sponsors commit to provide additional equity. The sponsors have agreed and the project’s financing documents were revised to reflect this request. Ormat, in its capacity as a supplier of equipment to the project, has achieved all contractual milestones under the supply agreement.

The Sarulla consortium entered into interest rate swap agreements with various international banks in order to fix the interest linked to LIBOR rate on up to $0.96 billion of the $1.07 billion credit facility at 3.4565%. The interest rate swap became effective as of June 4, 2014 along with the second draw-down by the project company of $50.0 million.

The Sarulla project company accounted for the interest rate swap as a cash flow hedge upon which changes in the fair value of the hedging instrument, relative to the effective portion, will be recorded in other comprehensive income. As such, during the three months ended March 31, 2017 and 2016, the project recorded a gain of $4.5 million and a net loss of $24.9 million, respectively, net of deferred tax, of which the Company's share was $0.6 million and $3.2 million, respectively, which were recorded in other comprehensive income. The related accumulated loss recorded by the Company in Other comprehensive income (loss) as of March 31, 2017 is $5.3 million.

Pursuant to a supply agreement that was signed in October 2013, the Company is supplying its OECs to the power plant and has added the $255.6 million supply contract to its Product Segment backlog. The Company started to recognize revenue from the project during the third quarter of 2014 and will continue to recognize revenue over the course of the year. The Company has eliminated the related intercompany profit of $13.7 million against Equity in loss of investees.

During the three months ended March 31, 2017, the Company made an additional cash equity investment in the Sarulla project of approximately $14.9 million and $26.9 million in total.

NOTE 5— FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received upon selling an asset or paid upon transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the fair value measurement guidance are described below:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities;

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability;

Level 3 — Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (supported by little or no market activity).

The following table sets forth certain fair value information at March 31, 2017 and December 31, 2016 for financial assets and liabilities measured at fair value by level within the fair value hierarchy, as well as cost or amortized cost. As required by the fair value measurement guidance, assets and liabilities are classified in their entirety based on the lowest level of inputs that is significant to the fair value measurement.

				March 31, 2017
				Fair Value
	Carrying Value at March 31, 2017			Total			Level 1		Level 2		Level 3
	(Dollars in thousands)
Assets:
Current assets:
Cash equivalents (including restricted cash accounts)	$	19,276		$	19,276		$	19,276	$	—	$	—
Derivatives:
Put options on gas price ⁽³⁾		298			298			—		298		—
Contingent receivable ⁽¹⁾		1,472			1,472			—		—		1,472
Currency forward contracts ⁽²⁾		1,517			1,517			—		1,517		—
Liabilities:
Current liabilities:
Derivatives:
Contingent payables ⁽¹⁾		(24,662	)		(24,662	)		—		—		(24,662	)
Warrants ⁽¹⁾		(3,507	)		(3,507	)						(3,507	)

	$	(5,606	)	$	(5,606	)	$	19,276	$	1,815	$	(26,697	)

				December 31, 2016
				Fair Value
	Carrying Value at December 31, 2016			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	14,922		$	14,922		$	14,922	$	—		$	—
Derivatives:
Contingent receivable ⁽¹⁾		1,443			1,443			—		—			1,443
Liabilities:
Current liabilities:
Derivatives:
Contingent payables ⁽¹⁾		(11,581	)		(11,581	)		—		—			(11,581	)
Warrants ⁽¹⁾		(3,429	)		(3,429	)		—		—			(3,429	)
Currency forward contracts ⁽²⁾		(481	)		(481	)		—		(481	)		—
	$	874		$	874		$	14,922	$	(481	)	$	(13,567	)

⁽¹⁾	These amounts relate to contingent receivables and payables pertaining to the Viridity and Guadeloupe transactions, valued primarily based on unobservable inputs, and are included within "Prepaid expenses and other", "Accounts payable and accrued expenses" and "Other long-term liabilities" on March 31, 2017 and within "Prepaid expenses and other" and "Other long-term liabilities" on December 31, 2016 in the consolidated balance sheets with the corresponding gain or loss being recognized within "Derivatives and foreign currency transaction gains (losses)" in the consolidated statement of operations and comprehensive income.

⁽²⁾	These amounts relate to currency forward contracts valued primarily based on observable inputs, including forward and spot prices for currencies, netted against contracted rates and then multiplied against notional amounts, and are included within “Prepaid expenses and other” and “Accounts payable and accrued expenses” on March 31, 2017 and December 31, 2016, in the consolidated balance sheet with the corresponding gain or loss being recognized within “Derivatives and foreign currency transaction gains (losses)” in the consolidated statement of operations and comprehensive income.

⁽³⁾

These amounts relate to put option transactions on natural gas prices, valued primarily based on observable inputs, including spot prices for related commodity indices, and are included within "Prepaid expenses and other" on March 31, 2017 in the consolidated balance sheets with the corresponding gain or loss being recognized within “Derivatives and foreign currency transaction gains (losses)” in the consolidated statement of operations and comprehensive income.

The amounts set forth in the tables above include investments in debt instruments and money market funds (which are included in cash equivalents). Those securities and deposits are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.

The following table presents the amounts of gain (loss) recognized in the consolidated statements of operations and comprehensive income on derivative instruments not designated as hedges:

		Amount of recognized gain (loss)
		Three Months Ended March 31,
Derivatives not designated as hedging instruments	Location of recognized gain (loss)	2017			2016

Put options on natural gas price	Derivatives and foreign currency transaction gains (losses)		(193	)		—
Call options on natural gas price	Derivatives and foreign currency transaction gains (losses)		—			518
Call and put options on oil price	Derivatives and foreign currency transaction gains (losses)		—			(643	)
Contingent considerations	Derivative and foreign currency transaction gains (losses)		(50	)
Currency forward contracts	Derivative and foreign currency transaction gains (losses)		2,262			1,814
		$	2,019		$	1,689

In January, 2017, the Company entered into Henry Hub Natural Gas Future contracts under which it has bought a number of put options covering a notional quantity of approximately 4.1 million British Thermal Units ("MMbtu") with exercise prices of $3 and expiration dates ranging from January 26, 2017 until November 27, 2017 in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison. The Company paid an aggregate amount of approximately $0.7 million for these put options. The put option contracts have monthly expiration dates at which the options can be called and the transaction would be settled on a net cash basis.

On February 2, 2016, the Company entered into Henry Hub Natural Gas Future contracts under which it has written a number of call options covering a notional quantity of approximately 4.1 MMbtu with exercise prices of $2 and expiration dates ranging from February 24, 2016 until December 27, 2016 in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison. The Company received an aggregate premium of approximately $1.9 million from these call options. The call option contracts have monthly expiration dates on which the options can be called and the Company would have to settle its liability on a cash basis.

On February 24, 2016, the Company entered into Brent Oil Future contracts under which it has written a number of call options covering a notional quantity of approximately 185,000 barrels (“BBL”) of Brent with exercise prices of $32.80 to $35.50 and expiration dates ranging from March 24, 2016 until December 22, 2016 in order to reduce its exposure to fluctuations in Brent prices under its PPA with HELCO. The Company received an aggregate premium of approximately $1.1 million from these call options. The call option contracts have monthly expiration dates on which the options can be called and the Company would have to settle its liability on a cash basis. Moreover, during March 2016, the Company rolled 2 existing call options covering a total notional quantity of 31,800 BBL of Brent in order to limit its exposure to $41 to $42.50 instead of $32.80 to $33.50. In addition, the Company entered into short risk reversal transactions (sell call and buy put options) by rolling existing call options covering notional quantities of 16,500 BBL and 17,000 BBL in order to limit its exposure from the outstanding call options originally entered into in February 2016 to between $28.50 and $37.50 and $28 and $38.50, respectively.

The foregoing future and forward transactions were not designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “Derivatives and foreign currency transaction gains (losses).

There were no transfers of assets or liabilities between Level 1, Level 2 and Level 3 during the three months ended March 31, 2017.

The fair value of the Company’s long-term debt approximates its carrying amount, except for the following:

	Fair Value				Carrying Amount
	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
	(Dollars in millions)				(Dollars in millions)
Olkaria III Loan - DEG	$	16.2	$	16.3	$	15.8	$	15.8
Olkaria III Loan - OPIC		248.9		253.4		242.1		246.6
Olkaria IV Loan - DEG 2		51.6		50.9		50.0		50.0
Amatitlan Loan		36.2		37.3		35.9		36.8
Senior Secured Notes:
Ormat Funding Corp. ("OFC")		17.0		17.0		17.0		17.0
OrCal Geothermal Inc. ("OrCal")		37.7		37.4		35.2		35.2
OFC 2 LLC ("OFC 2")		244.6		249.0		242.7		247.2
Don A. Campbell 1 ("DAC1")		87.4		88.9		90.8		92.4
Senior Unsecured Bonds		198.9		200.1		204.3		204.3
Other long-term debt		8.6		10.4		9.5		11.2

The fair value of the OFC Senior Secured Notes is determined using observable market prices as these securities are traded. The fair value of all the other long-term debt is determined by a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current borrowing rates. The fair value of revolving lines of credit is determined using a comparison of market-based price sources that are reflective of similar credit ratings to those of the Company.

The carrying value of other financial instruments, such as revolving lines of credit, deposits, and other long-term debt approximates fair value.

The following table presents the fair value of financial instruments as of March 31, 2017:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III - DEG	$	—	$	—	$	16.2	$	16.2
Olkaria III - OPIC		—		—		248.9		248.9
Olkaria IV - DEG 2		—		—		51.6		51.6
Amatitlan loan		—		36.2		—		36.2
Senior Secured Notes:
OFC		—		17.0		—		17.0
OrCal		—		—		37.7		37.7
OFC 2		—		—		244.6		244.6
Don A. Campbell 1 ("DAC1")		—		—		87.4		87.4
Senior unsecured bonds		—		—		198.9		198.9
Other long-term debt		—		1.7		6.9		8.6
Revolving lines of credit		—		30.0		—		30.0
Deposits		15.2		—		—		15.2

The following table presents the fair value of financial instruments as of December 31, 2016:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III Loan - DEG	$	—	$	—	$	16.3	$	16.3
Olkaria III Loan - OPIC		—		—		253.4		253.4
Olkaria IV - DEG 2		—		—		50.9		50.9
Amatitlan Loan		—		37.3		—		37.3
Senior Secured Notes:
OFC		—		17.0		—		17.0
OrCal		—		—		37.4		37.4
OFC 2		—		—		249.0		249.0
Don A. Campbell 1 ("DAC1")		—		—		88.9		88.9
Senior unsecured bonds		—		—		200.1		200.1
Other long-term debt		—		3.3		7.1		10.4
Deposits		14.4		—		—		14.4

NOTE 6 — STOCK-BASED COMPENSATION

The 2004 Incentive Compensation Plan

In 2004, the Company’s Board of Directors (the “Board”) adopted the 2004 Incentive Compensation Plan (“2004 Incentive Plan”), which provided for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, stock appreciation rights (“SARs”), stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2004 Incentive Plan, a total of 3,750,000 shares of the Company’s common stock were reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the 2004 Incentive Plan cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. Options granted to non-employee directors under the 2004 Incentive Plan cliff vest and are exercisable one year after the grant date. Vested stock-based awards may be exercised for up to ten years from the grant date. The shares of common stock issued in respect of awards under the 2004 Incentive Plan are issued from the Company’s authorized share capital upon exercise of options or SARs. The 2004 Incentive Plan expired in May 2012 upon adoption of the 2012 Incentive Compensation Plan (“2012 Incentive Plan”), except as to stock-based awards outstanding under the 2004 Incentive Plan on that date.

The 2012 Incentive Compensation Plan

In May 2012, the Company’s shareholders adopted the 2012 Incentive Plan, which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, SARs, stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2012 Incentive Plan, a total of 4,000,000 shares of the Company’s common stock have been reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the 2012 Incentive Plan typically vest and become exercisable as follows: 25% vest 24 months after the grant date, an additional 25% vest 36 months after the grant date, and the remaining 50% vest 48 months after the grant date. Options granted to non-employee directors under the 2012 Incentive Plan will vest and become exercisable one year after the grant date. The term of stock-based awards typically ranges from six to ten years from the grant date. The shares of common stock issued in respect of awards under the 2012 Incentive Plan are issued from the Company’s authorized share capital upon exercise of options or SARs.

The 2012 Incentive Plan empowers the Board, in its discretion, to amend the 2012 Incentive Plan in certain respects. Consistent with this authority, in February 2014 the Board adopted and approved certain amendments to the 2012 Incentive Plan. The key amendments are as follows:

● Increase of per grant limit: Section 15(a) of the 2012 Incentive Plan was amended to allow the grant of up to 400,000 shares of the Company’s common stock with respect to the initial grant of an equity award to newly hired executive officers in any calendar year; and

● Acceleration of vesting: Section 15(l) of the 2012 Incentive Plan was amended to clarify the Company’s ability to provide in the applicable award agreement that part and/or all of the award will be accelerated upon the occurrence of certain predetermined events and/or conditions, such as a "change in control" (as defined in the 2012 Incentive Plan, as amended).

NOTE 7 — INTEREST EXPENSE, NET

The components of interest expense are as follows:

	Three Months Ended March 31,
	2017			2016

Interest related to sale of tax benefits	$	2,012		$	858
Interest expense		14,175			15,625
Less — amount capitalized		(1,264	)		(460	)
	$	14,923		$	16,023

NOTE 8 — EARNINGS PER SHARE

Basic earnings per share attributable to the Company’s stockholders is computed by dividing net income or loss attributable to the Company’s stockholders by the weighted average number of shares of common stock outstanding for the period. The Company does not have any equity instruments that are dilutive, except for employee stock-based awards.

The table below shows the reconciliation of the number of shares used in the computation of basic and diluted earnings per share:

	Three Months Ended March 31,
	2017		2016

Weighted average number of shares used in computation of basic earnings per share		49,680		49,173
Add:
Additional shares from the assumed exercise of employee stock options		811		609

Weighted average number of shares used in computation of diluted earnings per share		50,491		49,782

The number of stock-based awards that could potentially dilute future earnings per share and that were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was 11,491 and 177,978 for the three months ended March 31, 2017 and 2016, respectively.

NOTE 9 — BUSINESS SEGMENTS

The Company has two reporting segments: the Electricity segment and the Product segment. These segments are managed and reported separately as each offers different products and serves different markets. The Electricity segment is engaged in the sale of electricity from the Company’s power plants pursuant to PPAs. The Product segment is engaged in the manufacture, including design and development, of turbines and power units for the supply of electrical energy and in the associated construction of power plants utilizing the power units manufactured by the Company to supply energy from geothermal fields and other alternative energy sources. Transfer prices between the operating segments are determined based on current market values or cost plus markup of the seller’s business segment.

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:

	Electricity		Product		Consolidated
	(Dollars in thousands)
Three Months Ended March 31, 2017:
Net revenues from external customers	$	115,776	$	74,122	$	189,898
Intersegment revenues		—		16,213		16,213
Operating income		40,898		18,598		59,496
Segment assets at period end		2,282,837		217,051		2,499,888

Three Months Ended March 31, 2016:
Net revenues from external customers	$	107,868	$	43,726	$	151,594
Intersegment revenues		—		1,941		1,941
Operating income		34,785		15,758		50,543
Segment assets at period end		2,048,471		211,663		2,260,134

Reconciling information between reportable segments and the Company’s consolidated totals is shown in the following table:

	Three Months Ended March 31,
	2017			2016


Revenue:
Total segment revenue	$	189,898		$	151,594
Intersegment revenue		16,213			1,941
Elimination of intersegment revenue		(16,213	)		(1,941	)
Total consolidated revenue	$	189,898		$	151,594

Operating income:
Operating income	$	59,496		$	50,543
Interest income		244			320
Interest expense, net		(14,923	)		(16,023	)
Derivatives and foreign currency transaction gains (losses)		1,338			1,962
Income attributable to sale of tax benefits		6,157			4,398
Other non-operating income (expense), net		(92	)		191
Total consolidated income before income taxes and equity in income of investees	$	52,220		$	41,391

NOTE 10 — COMMITMENTS AND CONTINGENCIES

●

Jon Olson and Hilary Wilt, together with Puna Pono Alliance filed a complaint on February 17, 2015 in the Third Circuit Court for the State of Hawaii, requesting declaratory and injunctive relief requiring that PGV comply with an ordinance that the plaintiffs allege will prohibit PGV from engaging in night drilling operations at its KS-16 well site. On May 17, 2015, the original complaint was amended to add the county of Hawaii and the State of Hawaii Department of Land and Natural Resources as defendants to the case. On October 10, 2016, the court issued its decision in response to each of the plaintiffs’ and defendants’ motions for summary judgment, denying plaintiffs’ motion and granting defendant PGV's and the County of Hawaii’s cross motions for summary judgment, effectively rendering the plaintiffs’ action moot. On January 23, 2017, the plaintiffs filed a motion requesting that the Intermediate Court of Appeals address appellate jurisdiction, which was denied by the court on April 20, 2017 as premature. The Company believes that it has valid defenses under law and intends to defend itself vigorously.

●

On July 8, 2014, Global Community Monitor, LiUNA, and two residents of Bishop, California filed a complaint in the U.S. District Court for the Eastern District of California alleging that Mammoth Pacific, L.P., the Company and Ormat Nevada are operating three geothermal generating plants in Mammoth Lakes, California (MP-1, MP-II and PLES-I) in violation of the federal Clean Air Act and Great Basin Unified Air Pollution Control District rules. On June 26, 2015, in response to a motion by the defendants, the court dismissed all but one of the plaintiffs’ causes of action. On January 6, 2017, the court issued its order regarding several pending motions, including plaintiffs’ motion for partial summary judgment, defendants' motion for summary judgment, defendants' motion to exclude and defendants' motion for leave to file a sur-reply. The impact of the court’s January 6 order is to deny the plaintiffs’ sole remaining cause of action. No appeal by the plaintiffs is expected and the Company considers this case to be effectively closed.

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On March 29, 2016, a former local sales representative in Chile, Aquavant, S.A., filed a claim against Ormat’s subsidiaries in the 27th Civil Court of Santiago, Chile on the basis of unjust enrichment. The claim requests that the court order Ormat to pay Aquavant $4.6 million in connection with its activities in Chile, including the EPC contract for the Cerro Pabellon project and various geothermal concessions, plus 3.75% of Ormat geothermal products sales in Chile over the next 10 years. Pursuant to various petitions submitted by the defendants, including a motion describing preliminary procedural defenses, on August 18, 2016, and then on October 10, 2016, the 27th Civil Court issued a number of decisions, which include removal of the case to the 11th Civil Court of Santiago, thereby delaying a determination on the larger issues of jurisdiction and competency of the Chilean courts as a substantive (and not procedural) defense. The Company believes that it has valid defenses under law and intends to defend itself vigorously.

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On August 5, 2016, George Douvris, Stephanie Douvris, Michael Hale, Cheryl Cacocci, Hillary E. Wilt and Christina Bryan, acting for themselves and on behalf of all other similarly situated residents of the lower Puna District, filed a complaint in the Third Circuit Court for the State of Hawaii seeking certification of a class action for preliminary and permanent injunctive relief, consequential and punitive damages, attorney’s fees and statutory interest against PGV and other presently unknown defendants. On December 12, 2016, the federal district court granted plaintiffs’ motion for joinder of HELCO as a co-defendant, and the case, which had previously been removed to the U.S. District Court for the District of Hawaii, was remanded back to the Third Circuit Court. The amended complaint alleges that injuries and other damages in an undisclosed amount were caused to the plaintiffs as a result of an alleged toxic release by PGV in the wake of Hurricane Iselle in August 2014. On March 25, 2017, HELCO filed a motion to dismiss the first amended complaint in the Third Circuit Court against itself, on several grounds. Following briefing and oral arguments, the HELCO motion to dismiss is under consideration by the court. The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

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On June 20, 2016, Nadia Garcia, individually and as successor in interest to Thomas Garcia Valenzuela, and as guardian ad litem to Emerie Garcia, Khamilla Garcia and Reyene Adam, filed a complaint against Ormat Technologies, Ormat Nevada and Ormesa LLC in the Superior Court of Imperial County seeking unspecified monetary damages. The complaint alleges that the Ormat defendants caused the wrongful death, personal injury and other harm to Thomas Garcia when he was employed by Martin Hydroblasting Services, Inc. and suffered injuries leading to his death while performing work at the Ormesa plant site on or around March 31, 2016. At the end of April, 2017, an out of court settlement was agreed between the plaintiffs and the deceased's employer’s insurer, which is being presented to the court for its approval.

In addition, from time to time, the Company is named as a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, the Company accrues reserves when a loss is probable and the amount of such loss can be reasonably estimated. It is the opinion of the Company’s management that the outcome of these proceedings, individually and collectively, will not be material to the Company’s consolidated financial statements as a whole.

NOTE 11 — INCOME TAXES

The Company’s effective tax rate for the three months ended March 31, 2017 and 2016 was 20.8% and 23.0%, respectively. The effective rate differs from the federal statutory rate of 35% for the three months ended March 31, 2017 due to: (i) a full valuation allowance against the Company’s U.S. deferred tax assets in respect of net operating loss (“NOL”) carryforwards and unutilized tax credits (see below), (ii) a lower tax rate in Israel of 16%, partially offset by a tax rate in Kenya of 37.5%; and (iii) a tax credit and tax exemption related to the Company’s subsidiaries in Guatemala. The effect of the tax credit and tax exemption for the three months ended March 31, 2017 and 2016 was $0.9 million and $1.1 million, respectively.

The Company is currently in a net deferred tax asset position with a full valuation allowance. As of December 31, 2016, the Company had U.S. federal NOL carryforwards of approximately $299.6 million, which expire between 2029 and 2036, and state NOL carryforwards of approximately $244.7 million, which expire between 2018 and 2036, which are available to reduce future taxable income. The Company's investment tax credits (“ITCs”) in the amount of $1.3 million at December 31, 2016 are available for a 20-year period and expire between 2022 and 2024. The Company's production tax credits (“PTCs”) in the amount of $82.5 million at December 31, 2016 are available for a 20-year period and expire between 2026 and 2036. The Company also has offsetting deferred tax liabilities in the U.S.

Realization of the deferred tax assets and tax credits is dependent on generating sufficient taxable income in appropriate jurisdictions prior to expiration of the NOL carryforwards and tax credits. Based upon available evidence of the Company’s ability to generate additional taxable income in the future and historical losses in prior years, a full valuation allowance is recorded against the U.S. deferred tax assets, as it is more likely than not that the deferred tax assets will not be utilized.

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $367 million at December 31, 2016. It is the Company’s intention to reinvest undistributed earnings of its foreign subsidiaries and thereby indefinitely postpone their remittance. Accordingly, no provision has been made for foreign withholding taxes or U.S. income taxes which may become payable if undistributed earnings of foreign subsidiaries were paid as dividends to the Company. The additional taxes on that portion of undistributed earnings which is available for dividends are not practicably determinable.

The Company believes that based on its plans to increase operations outside of the U.S., the cash generated from the Company’s operations outside of the U.S. will be reinvested outside of the U.S. and, accordingly, we do not currently plan to repatriate the funds we have designated as being permanently invested outside of the U.S. If we change our plans, we may be required to accrue and pay U.S. taxes to repatriate these funds.

The Company is subject to income taxes in the U.S. (federal and state) and numerous foreign jurisdictions. Significant judgment is required in evaluating tax positions and determining the position for income taxes. Reserves are established to tax-related uncertainties based on estimates of whether, and the extent to which additional taxes will be due. As of March 31, 2017, the Company is unaware of any potentially significant uncertain tax positions for which a reserve has not been established.

As previously reported by the Company, the Kenya Revenue Authority (“KRA”) conducted an audit related to the Company’s operations in Kenya for fiscal years 2012 and 2013. In January 2017, KRA concluded its audit for the subject period and issued a demand letter to the Company for additional tax payments of approximately $16.1 million, including interest and penalties. On February 8, 2017, the Company submitted a notice of objection to the KRA demand letter in which it presented its tax positions. On March 29, 2017, the KRA submitted a response to the objection letter, primarily indicating that it accepted our position relating to the mining activity claim, as previously described in the Company’s annaul report on Form 10-K for the year ended December 31, 2016, and removed this claim from their tax assessment. As a result, the KRA reduced its demand for additional tax payment to approximately $10.0 million, including interest and penalties. On April 28, 2017, the Company submitted a Notice of Appeal to the KRA, noting that it intends to appeal to the Tax Tribunal on parts of the KRA assessment. The Company has recorded a provision based on its assessment of its reasonably expected potential exposure.

NOTE 12 — SUBSEQUENT EVENTS

Cash dividend

On May 8, 2017, the Board declared, approved and authorized payment of a quarterly dividend of $4.0 million ($0.08 per share) to all holders of the Company’s issued and outstanding shares of common stock on May 22, 2017, payable on May 31, 2017.

ORIX transaction

On May 4, 2017, we announced that ORIX Corporation ("ORIX") will acquire an approximately 22% ownership stake in the Company by purchasing approximately 11 million shares of the Company's common stock from FIMI ENRG Limited Partnership, FIMI ENRG, L.P. (collectively, "FIMI"), Bronicki Investments, Ltd. ("Bronicki"), and senior members of management. The per share sale price to be paid by ORIX at closing (subject to satisfaction of customary conditions, including regulatory approvals) is $57, which was the prevailing market price at the time that ORIX, FIMI and Bronicki reached agreement on the commercial terms of their transaction.

Under related agreements, ORIX will have the right to designate three persons to our board of directors, which will be expanded to nine directors, and also propose a fourth person to be mutually agreed by us and ORIX to serve as a new independent director on our board. In addition, for so long as ORIX is entitled to board representation, ORIX will be subject to certain customary standstill restrictions, including an effective 25% cap on its voting rights. ORIX will also have certain customary registration rights with respect to the shares of our common stock that it will own.

Under terms of a new Commercial Cooperation Agreement between us and ORIX, we will have exclusive rights to develop, own, operate and provide equipment for ORIX geothermal energy projects in all markets outside of Japan. In addition, we will have certain rights to serve as technical partner and co-invest in ORIX geothermal energy projects in Japan. Also, ORIX will assist us in obtaining project financing for our geothermal energy projects from a variety of leading providers of renewable energy debt financing with which ORIX has relationships in Asia and around the world.

We entered into the agreements with ORIX following the unanimous recommendation of a Special Committee of our board of directors that was formed to evaluate and negotiate the shareholder arrangements proposed by ORIX, with independent legal advice from Davis Polk & Wardwell LLP, and following the unanimous approval by our board of directors.

We expect closing under the various agreements described above to occur in the third quarter of 2017.

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

Cautionary Note Regarding Forward-Looking Statements

This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this quarterly report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as our projections of annual revenues, expenses and debt service coverage with respect to our debt securities, future capital expenditures, business strategy, competitive strengths, goals, development or operation of generation assets, market and industry developments and the growth of our business and operations, are forward-looking statements. When used in this quarterly report on Form 10-Q, the words “may”, “will”, “could”, “should”, “expects”, “plans”, “anticipates”, “believes”, “estimates”, “predicts”, “projects”, “potential”, or “contemplate” or the negative of these terms or other comparable terminology are intended to identify forward-looking statements, although not all forward-looking statements contain such words or expressions. The forward-looking statements in this quarterly report are primarily located in the material set forth under the headings “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Risk Factors”, and “Notes to Condensed Consolidated Financial Statements”, but are found in other locations as well. These forward-looking statements generally relate to our plans, objectives and expectations for future operations and are based upon management’s current estimates and projections of future results or trends. Although we believe that our plans and objectives reflected in or suggested by these forward-looking statements are reasonable, we may not achieve these plans or objectives. You should read this quarterly report on Form 10-Q completely and with the understanding that actual future results and developments may be materially different from what we expect due to a number of risks and uncertainties, many of which are beyond our control.

Specific factors that might cause actual results to differ from our expectations include, but are not limited to:

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significant considerations, risks and uncertainties discussed in this quarterly report;

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geothermal resource risk (such as the heat content, useful life and geological formation of the reservoir);

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operating risks, including equipment failures and the amounts and timing of revenues and expenses;

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financial market conditions and the results of financing efforts;

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the impact of fluctuations in oil and natural gas prices and renewable power market penetration on the energy price component under certain of our power purchase agreements (“PPAs”);

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risks and uncertainties with respect to our ability to implement strategic goals or initiatives in segments of the clean energy industry or new or additional geographic focus areas;

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environmental constraints on operations and environmental liabilities arising out of past or present operations, including the risk that we may not have, and in the future may be unable to procure, any necessary permits or other environmental authorizations;

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construction or other project delays or cancellations;

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political, legal, regulatory, governmental, administrative and economic conditions and developments in the United States and other countries in which we operate and, in particular, the impact of recent and future federal, state and local regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, public policies and government incentives that support renewable energy and enhance the economic feasibility of our projects at the federal and state level in the United States and elsewhere, and carbon-related legislation;

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the enforceability of long-term PPAs for our power plants;

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contract counterparty risk;

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weather and other natural phenomena including earthquakes, volcanic eruption, drought and other natural disasters;

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changes in environmental and other laws and regulations to which our company is subject, as well as changes in the application of existing laws and regulations;

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current and future litigation;

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our ability to successfully identify, integrate and complete acquisitions;

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competition from other geothermal energy projects and new geothermal energy projects developed in the future, and from alternative electricity producing technologies;

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market or business conditions and fluctuations in demand for energy or capacity in the markets in which we operate;

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the direct or indirect impact on our company’s business of various forms of hostilities including the threat or occurrence of war, terrorist incidents or cyber-attacks or responses to such threatened or actual incidents or attacks, including the effect on the availability of and premiums on insurance;

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our new strategic plan to expand our geographic markets, customer base and product and service offerings may not be implemented as currently planned or may not achieve our goals as and when implemented;

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development and construction of solar photovoltaic (“Solar PV”) and energy storage projects, if any, may not materialize as planned;

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the effect of and changes in current and future land use and zoning regulations, residential, commercial and industrial development and urbanization in the areas in which we operate;

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the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2016 and any update contained herein and other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (“SEC”); and

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other uncertainties which are difficult to predict or beyond our control and the risk that we may incorrectly analyze these risks and forces or that the strategies we develop to address them may be unsuccessful.

Investors are cautioned that these forward-looking statements are inherently uncertain. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results or outcomes may vary materially from those described herein. Other than as required by law, we undertake no obligation to update forward-looking statements even though our situation may change in the future. Given these risks and uncertainties, readers are cautioned not to place undue reliance on such forward-looking statements.

The following discussion and analysis of our financial condition and results of operations should be read together with our condensed consolidated financial statements and related notes included elsewhere in this report and the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2016 and any updates contained herein as well as those set forth in our reports and other filings made with the SEC.

General

Overview

We are a leading vertically integrated company that is currently primarily engaged in the geothermal and recovered energy power business. With the objective of becoming a leading global provider of renewable energy, we focus on several key initiatives under our new strategic plan, as described below.

We design, develop, build, sell, own, and operate clean, environmentally friendly geothermal and recovered energy-based power plants, usually using equipment that we design and manufacture.

Our geothermal power plants include both power plants that we have built and power plants that we have acquired, while we have built all of our recovered energy-based plants. We currently conduct our business activities in two business segments:

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The Electricity segment — in this segment, we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world, and sell the electricity they generate; as well as conduct activity in the demand response and storage markets as described below; and

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The Product segment — in this segment we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation, and remote power units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy-based power plants and in the future, other power generating units such as Solar PV and energy storage.

We recently expanded our operations to include the provision of services in the demand response, energy management and energy storage markets. On March 15, 2017, we completed the acquisition of substantially all of the business and assets of Viridity Energy, Inc. (“VEI”), a Philadelphia-based company with nearly a decade of expertise and leadership in demand response, energy management and storage. The acquired business and assets are owned and operated by our wholly owned subsidiary Viridity Energy Solutions Inc. (“Viridity”). The acquisition enabled us to enter the growing energy storage and demand response markets. We intend to use Viridity to accelerate long-term growth, expand our market presence, and further develop our demand response VPower™ software platform and energy storage services. We plan to continue to provide services and products to existing customers of the acquired business, while expanding into new geographies and targeting a broader potential customer base.

Both our Electricity segment and Product segment operations are conducted in the United States and the rest of the world. Our current generating portfolio includes geothermal power plants in the United States, Guatemala, Kenya and Guadeloupe, as well as recovered energy generation power plants in the United States.

For the three months ended March 31, 2017, our total revenues increased by 25.3% (from $151.6 million to $189.9 million) over the corresponding period in 2016.

For the three months ended March 31, 2017, Electricity segment revenues were $115.8 million, compared to $107.9 million for the three months ended March 31, 2016, an increase of 7.3% from the prior year period. Product segment revenues for the three months ended March 31, 2017 were $74.1 million, compared to $43.7 million during the three months ended March 31, 2016, an increase of 69.5% from the prior year period.

During the three months ended March 31, 2017 and 2016, our consolidated power plants generated 1,427,704 megawatt hours (“MWh”) and 1,396,868 MWh, respectively, an increase of 2.2%.

For the three months ended March 31, 2017, our Electricity segment generated approximately 61.0% of our total revenues, while our Product segment generated approximately 39.0% of our total revenues. For the three months ended March 31, 2016, our Electricity segment generated approximately 71.2% of our total revenues, while our Product segment generated approximately 28.8% of our total revenues.

For the three months ended March 31, 2017, approximately 87.4% of our Electricity segment revenues were derived from PPAs with fixed energy rates which are not affected by fluctuations in energy commodity prices. We have variable price PPAs in California and Hawaii, which provide for payments based on the local utilities’ avoided cost, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others, as follows:

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the energy rates under the PPAs in California for each of the Ormesa complex, Heber 2 power plant in the Heber complex and the G2 power plant in the Mammoth complex, a total of approximately 90 MW, change primarily based on fluctuations in natural gas prices; and

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the prices paid for electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii change primarily due to variations in the price of oil as well as other commodities.

We recently reduced our economic exposure to fluctuations in the price of oil and natural gas from February 2017 until December 2017, and before that we reduced our economic exposure to fluctuations in the price of natural gas from March 31, 2015 and from June 1, 2015 until December 31, 2015 and from February 3, 2016 until December 29, 2016 by entering into derivatives transactions. For the three months ended March 31, 2017, we recorded a net loss of $0.2 million under Derivatives and foreign currency transaction gains.

To comply with obligations under their respective PPAs, certain of our project subsidiaries are structured as special purpose, bankruptcy remote entities and their assets and liabilities are ring-fenced. Such assets are not generally available to pay our debt, other than debt at the respective project subsidiary level. However, these project subsidiaries are allowed to pay dividends and make distributions of cash flows generated by their assets to us, subject in some cases to restrictions in debt instruments, as described below.

Electricity segment revenues are also subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under “Seasonality”.

Revenues attributable to our Product segment are based on the sale of equipment, engineering, procurement and construction (“EPC”) contracts and the provision of various services to our customers. Product segment revenues may vary from period to period because of the timing of our receipt of purchase orders and the progress of our equipment manufacturing and execution of the relevant project.

Our management assesses the performance of our two operating segments differently. In the case of our Electricity segment, when making decisions about potential acquisitions or the development of new projects, management typically focuses on the internal rate of return of the relevant investment, technical and geological matters and other business considerations. Management evaluates our operating power plants based on revenues, expenses, and EBITDA, and our projects that are under development based on costs attributable to each such project. Management evaluates the performance of our Product segment based on the timely delivery of our products, performance quality of our products, revenues and costs actually incurred to complete customer orders compared to the costs originally budgeted for such orders.

Recent Developments

The most significant developments in our company and business since January 1, 2017 are described below:

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We expect closing under the various agreements described above to occur in the third quarter of 2017.

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On March 15, 2017, we announced that we completed the acquisition of substantially all of the business and assets of VEI, a Philadelphia-based company with nearly a decade of expertise and leadership in demand response, energy management and storage. Pursuant to the Asset Purchase Agreement dated as of December 29, 2016, Viridity paid initial consideration of $35.3 million at closing. Additional contingent consideration will be payable in two installments upon the achievement of certain performance milestones measured at the end of fiscal years 2017 and 2020. The acquired business and assets are owned and operated by Viridity. This transaction marks our entry into the growing energy storage and demand response markets, with an established North American presence.

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On March 21, 2017, we announced that the first unit of the Sarulla geothermal power plant, one of the world's largest geothermal power plants, located in Indonesia's North Sumatra, commenced commercial operation. The approximately 110 MW power plant, which combines flash and binary technologies to provide a high efficiency power plant and 100% reinjection of the exploited geothermal fluid, is operated by Sarulla Operations Ltd. We provided the conceptual design of the geothermal combined cycle unit power plant and supplied our Ormat Energy Converter, while Toshiba supplied the geothermal steam turbines and generators for the flash systems.

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In February 2017, we began construction to expand the Olkaria III complex in Kenya by an additional 10 MW and increase the complex's generating capacity to up to 150 MW during 2018.

Trends and Uncertainties

Different trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee. However, we believe that our results of operations and financial condition for the foreseeable future will be primarily affected by the following trends, factors and uncertainties that are from time to time also subject to market cycles:

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There has been increased demand for energy generated from geothermal and other renewable resources in the U.S. as costs for electricity generated from renewable resources have become more competitive. Much of this is attributable to legislative and regulatory requirements and incentives, such as state renewable portfolio standards (“RPS”) and federal tax credits such as production tax credits (“PTCs”) or investment tax credits (“ITCs”) (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits” below). We believe that future demand for energy generated from geothermal and other renewable resources in the U.S. will be driven mainly by further commitment and implementation of state RPS and greenhouse gas initiatives.

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We accelerated our efforts to expand business development activities in developing countries where geothermal is considered a local resource that can provide a stable and cost effective solution to increase access to power. We expect that a variety of local governmental initiatives will create new opportunities for the development of new projects, as well as create additional markets for our products. These initiatives include the award of long-term contracts to independent power generators, the creation of competitive wholesale markets for selling and trading energy, capacity and related energy products and the adoption of programs designed to encourage “clean” renewable and sustainable energy sources.

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We expect to continue to generate the majority of our revenues from our Electricity segment through the sale of electricity from our power plants. All of our current revenues from the sale of electricity are derived from payments under long-term PPAs related to fully-contracted power plants. We also intend to continue to pursue opportunities, as they arise in our recovered energy business, in the Solar PV sector, in the energy storage market and in other forms of clean energy. In addition, pursuant to our strategic plan, we acquired a business that operates in the demand response and energy storage markets and that generates revenues mainly from software license fees and the provision of services. We are also pursuing PPAs with enterprises that will increase our potential customer base.

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We have adopted a new strategic plan for the growth of our company, in terms of geographic scope, customer base, and technology platforms covered by our product and service offerings, with a focus on increasing net income from operations. Under this plan, we will continue to focus on organic growth and increasing operational efficiency of our existing business lines. In addition, we are actively pursuing acquisition opportunities, both in our existing business lines and the solar power generation and energy storage businesses targeted as part of the plan. Recent acquisitions include our acquisition of the Bouillante geothermal power plant on Guadeloupe Island and our recent acquisition of substantially all of the business and assets of VEI, which we have begun to operate in the demand response and storage markets. We will face a number of challenges and uncertainties in implementing this plan, including integration of recently acquired assets, and we may revise elements of the plan in response to market conditions or other factors as we move forward with the plan.

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In the Electricity segment, we expect intense domestic competition from the solar and wind power generation industries to continue and increase. While we believe the expected demand for renewable energy will be large enough to accommodate increased competition, any such increase in competition, including increasing amounts of renewable energy under contract as well as any further decline in natural gas prices due to increased production which can affect the market price for electricity may contribute to a reduction in electricity prices. However, despite increased competition from the solar and wind power generation industries, we believe that base load electricity, such as geothermal-based energy, will continue to be an important source of renewable energy in areas with commercially viable geothermal resources. Also, we believe that geothermal power plants can positively impact electrical grid stability and provide valuable ancillary services because of their base load nature. In the geothermal industry, due to reduced competition for geothermal leases, we have experienced a decrease in the upfront fee required to secure geothermal leases.

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In the Product segment, we have experienced increased competition from binary power plant equipment suppliers including the major steam turbine manufacturers. While we believe that we have a distinct competitive advantage based on our accumulated experience and current worldwide share of installed binary generation capacity, an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to further reduction in the prices that we are able to charge for our binary equipment, which in turn may reduce our profitability.

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The 38 MW Puna complex has three PPAs, one of which (the 25 MW PPA) has a monthly variable energy rate based on the local utility’s avoided costs. A decrease in the price of oil as well as in other commodities will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from oil, which will result in a reduction of the energy rate that we may charge under this PPA. In order to reduce our exposure to oil we signed fixed rate PPAs for the remaining 13 MW.

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The pricing under our PPAs for the Ormesa, Mammoth and Heber complexes for a total of 161 MW were variable rate based on short run avoided cost (“SRAC”) pricing that is impacted by natural gas prices. However, in 2013 and December 2015, we signed new fixed rate PPAs that reduced our current exposure to SRAC by 18 MW and 53 MW, respectively. We also recently we signed a fixed rate PPA that will reduce our exposure beginning in November 2017 by an additional 40 MW. In addition, to further reduce our exposure to natural gas prices, we enter, from time to time, into derivative transactions. In February 2016, we sold call options for total proceeds of $1.9 million at a fixed price of $2.00 per MMbtu to reduce our exposure to SRAC in the period from February 3, 2016 until December 29, 2016. In January 2017 we acquired put options at a strike price of $3 to hedge our exposure to decreasing natural gas prices to below $3 per MMbtu.

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The amounts that we are paid under our PPAs for electricity, capacity and other energy attributes vary for a number of reasons, including:

market conditions when the PPA is signed;

the competitive environment in the power market where the plant is located and the power and other energy attributes are sold; and

in the case of contracts described in the prior bullets with variable pricing components, current oil and natural gas prices.

		This means, among other things, that the average price per MWh, which is one of the metrics some investors may use to evaluate power plant revenues can fluctuate from period to period. Based on total Electricity segment revenues, we earned, on average, $81.1 and $77.2 per MWh in the three months ended March 31, 2017 and 2016, respectively. Oil and natural gas prices, together with other factors that affect our Electricity segment revenues, could cause changes in our average rate per MWh in the future.

	●	The viability of a geothermal resource depends on various factors such as the resource temperature, the permeability of the resource (i.e., the ability to get geothermal fluids to the surface) and operational factors relating to the extraction and injection of the geothermal fluids. Such factors, together with the possibility that we may fail to find commercially viable geothermal resources in the future, represent significant uncertainties that we face in connection with our growth expectations.

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As our power plants (including their respective well fields) age, they may require increased maintenance with a resulting decrease in their availability, potentially leading to the imposition of penalties if we are not able to meet the requirements under our PPAs as a result of any decrease in availability.

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Our foreign operations are subject to significant political, economic and financial risks which vary by country as well as hostilities that may arise in the countries we operate. As of the date of this report, those risks include security conditions in Israel, the partial privatization of the electricity sector in Guatemala and the political uncertainty currently prevailing in some of the countries in which we operate as further described in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2016. Although we maintain among other things political risk insurance for most of our investments in foreign power plants to mitigate these risks, insurance does not provide complete coverage with respect to all such risks.

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The 330 MW Sarulla project was released for construction, and we began to recognize our first Product segment revenues under the supply contract we signed with the EPC contractor in the quarter ended September 30, 2014. In addition, due to the recent commencement of operation of the first phase of the project, we expect to generate income from our 12.75% equity investment in the Sarulla consortium. The Sarulla project’s future operations may be impacted by the status of development, various factors which we do not control given our minority position in the consortium, as well as other factors described in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2016.

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While we do not see any immediate impact from the failed coup in Turkey and the recent vote for the constitutional amendment bill on our business and operations, we are monitoring any change in the political environment that may affect our future business and operations in the country. As a major equipment supplier in the Turkish geothermal market, we are involved in a number of projects that are currently under construction and plan to continue our marketing efforts to secure new contracts. Our revenue exposure to the Turkish market is increasing and we expect higher exposure in 2017, as we signed a significant number of new contracts in Turkey.

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A Turkish sub-contractor provides us with certain local equipment for renewable energy based generating facilities to help us meet our obligations under certain supply agreements in Turkey. The use of local equipment in renewable energy based generating facilities in Turkey entitles such facilities to certain benefits under Turkish law, provided such facilities have obtained an RER Certificate from EMRA, which requires the issuance of a local certificate. If we do not obtain the local certificate, then some of our customers under the relevant supply agreements in Turkey may not be issued an RER Certificate based on the equipment we supply to them, and we will be required to make a payment to such customers equal to the amount of the expected lost benefit. In order to assure these benefits and maintain our competetive advantage, we own an assembly shop to meet the Turkish requirements.

●

FERC is allowed under PURPA to terminate, upon the request of a utility, the obligation of the utility to purchase the output of a Qualifying Facility if FERC finds that there is an accessible competitive market for energy and capacity from the Qualifying Facility. FERC has granted the California investor owned utilities a waiver of the mandatory purchase obligations from Qualifying Facilities above 20 MW. If the utilities in the regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from us upon termination of the existing PPA, which could have an adverse effect on our revenues.

●

The current administration has expressed skepticism regarding climate change. The final outcome of this administration’s policies and efforts regarding climate change and resulting effects to the geothermal industry remain uncertain.

Revenues

We generate our revenues from the sale of electricity from our geothermal and recovered energy-based power plants; the design, manufacture and sale of equipment for electricity generation; and the construction, installation and engineering of power plant equipment.

Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 87.4% of our Electricity revenues for the three months ended March 31, 2017 were derived from PPAs with fixed price components, we have variable price PPAs in California and Hawaii. Our SO#4 PPAs totaling approximately 90 MWs in California are subject to the impact of fluctuations in natural gas prices whereas the prices paid for electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii is impacted by the price of oil as well as other commodities. Accordingly, our revenues from those power plants may fluctuate.

Our Electricity segment revenues are also subject to seasonal variations, as more fully described in “Seasonality” below.

Our PPAs generally provide for energy payments alone, or energy and capacity payments. Generally, capacity payments are payments calculated based on the amount of time that our power plants are available to generate electricity. Some of our PPAs provide for bonus payments in the event that we are able to exceed certain target capacity levels and the potential forfeiture of payments if we fail to meet certain minimum target capacity levels. Energy payments, on the other hand, are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser’s avoided costs. Our more recent PPAs generally provide for energy payments alone with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.

Revenues attributable to our Product segment fluctuate between periods, mainly based on our ability to receive customer orders, the status and timing of such orders, delivery of raw materials and the completion of manufacturing. Larger customer orders for our products are typically the result of our sales efforts, our participation in, and winning of, tenders or requests for proposals issued by potential customers in connection with projects they are developing as well as returning customers. Such projects often take a significant amount of time to design and develop and are subject to various contingencies, such as the customer’s ability to raise the necessary financing for a project. Consequently, we are generally unable to predict the timing of such orders for our products and may not be able to replace existing orders that we have completed with new ones. As a result, revenues from our Product segment fluctuate (sometimes, extensively) from period to period.

The following table sets forth a breakdown of our revenues for the periods indicated:

	Revenue (dollars in thousands)				% of Revenue for Period Indicated
	Three Months Ended March 31,				Three Months Ended March 31,
	2017		2016		2017			2016
Revenues:
Electricity	$	115,776	$	107,868		61.0	%		71.2	%
Product		74,122		43,726		39.0			28.8
Total	$	189,898	$	151,594		100	%		100	%

The following table sets forth the geographic breakdown of the revenues attributable to our Electricity and Product segments for the periods indicated:

	Revenue (dollars in thousands)				% of Revenue for Period Indicated
	Three Months Ended March 31,				Three Months Ended March 31,
	2017		2016		2017			2016
Electricity Segment:
United States	$	75,896	$	73,807		65.6	%		68.4	%
Foreign		39,880		34,061		34.4			31.6
Total	$	115,776	$	107,868		100	%		100	%

Product Segment:
United States	$	675	$	5,815		0.9	%		13.3	%
Foreign		73,447		37,911		99.1			86.7
Total	$	74,122	$	43,726		100	%		100	%

The contribution of our domestic and foreign operations within our Electricity segment and Product segment to combined pre-tax income differ in a number of ways.

Electricity Segment. Our Electricity segment domestic revenues were approximately 90% and 117% higher than our Electricity segment foreign revenues for the three months ended March 31, 2017 and 2016, respectively. However, domestic operations in our Electricity segment have higher costs of revenues and expenses than the foreign operations in our Electricity segment. Our foreign power plants are located in lower-cost regions, like Kenya, Guatemala and Guadeloupe, which favorably impact payroll and maintenance expenses among other items. They are also newer than most of our domestic power plants and therefore tend to have lower maintenance costs and higher availability factors than our domestic power plants.

Product Segment. Our Product segment foreign revenues were approximately 99% and 87% of our total Product segment revenues for the three months ended March 31, 2017 and 2016. Our Product segment foreign activity also benefits from lower costs of revenues and expenses than Product segment domestic activity such as labor and transportation costs. Accordingly, our Product segment foreign activity contributes more than our Product segment domestic activity to our pre-tax income from operations.

Relative Contributions. While our combined (domestic and foreign) Electricity segment revenues exceeded our combined Product segment revenues by approximately $42 million and $64 million, respectively, for the three months ended March 31, 2017 and 2016 (primarily foreign) Product segment revenues resulted in higher pre-tax income from foreign operations for both of those periods.

Seasonality

The prices paid for the electricity generated by some of our domestic power plants pursuant to our PPAs are subject to seasonal variations. The prices (mainly for capacity) paid for electricity under the PPAs with Southern California Edison and Pacific Gas & Electric in California for the Heber 2 power plant in the Heber complex, the Mammoth complex, the Ormesa complex, and the North Brawley power plant are higher in the months of June through September. As a result, we receive, and expect to continue to receive in the future, higher revenues from these power plants and complexes during such months. In the winter, our power plants produce more energy principally due to the lower ambient temperature, which has a favorable impact on the energy component of our Electricity revenues. The higher payments payable by Southern California Edison and Pacific Gas & Electric Company in the summer months offset the negative impact on our revenues from lower generation in the summer due to the higher ambient temperature.

Breakdown of Cost of Revenues

Electricity Segment

The principal cost of revenues attributable to our operating power plants includes operation and maintenance expenses comprised of salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes, insurance and, for some of our projects, purchases of make-up water for use in our cooling towers and also depreciation and amortization. In our California power plants, our principal cost of revenues also includes transmission charges and scheduling charges. In some of our Nevada power plants, we also incur transmission and wheeling charges. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual power plants from quarter to quarter. Payments made to government agencies and private entities on account of site leases where plants are located are included in cost of revenues. Royalty payments, included in cost of revenues, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenues derived from the associated geothermal rights. Royalties constituted approximately 3.9% and 4.3% of Electricity segment revenues for the three months ended March 31, 2017 and March 31, 2016, respectively.

Product Segment

The principal cost of revenues attributable to our Product segment includes materials, salaries and related employee benefits, expenses related to subcontracting activities, and transportation expenses. Sales commissions to sales representatives are included in selling and marketing expenses. Some of the principal expenses attributable to our Product segment, such as a portion of the costs related to labor, utilities and other support services are fixed, while others, such as materials, construction, transportation and sales commissions, are variable and may fluctuate significantly depending on market conditions. As a result, the cost of revenues attributable to our Product segment, expressed as a percentage of total revenues, fluctuates. Another reason for such fluctuation is that in responding to bids for our products, we price our products and services in relation to existing competition and other prevailing market conditions, which may vary substantially from order to order.

Cash and Cash Equivalents

Our cash and cash equivalents decreased to $174.1 million as of March 31, 2017 from $230.2 million as of December 31, 2016. This decrease was principally due to: (i) our use of $52.9 million to fund capital expenditures; (ii) $35.3 million net cash paid for the acquisition of substantially all the business and assets of VEI; (iii) a net change in in restricted cash and cash equivalents of $25.6 million; (iv) an unconsolidated investment in Sarulla of $14.9 million; (v) net repayment of $13.4 million of long-term debt; (vi) $6.8 million cash paid to non-controlling interests; and (vii) a $8.4 million cash dividend paid. This decrease was partially offset by: (i) $71.5 million derived from operating activities during the three months ended March 31, 2017; and (ii) net proceeds of $30.0 million from our revolving credit lines with commercial banks. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of March 31, 2017 was $524.8 million, as described below in “Liquidity and Capital Resources”. As of March 31, 2017, we have utilized $350.6 million of our corporate borrowing capacity.

Critical Accounting Estimates and Assumptions

A comprehensive discussion of our critical accounting estimates and assumptions is included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our Annual Report on Form 10-K for the year ended December 31, 2016.

New Accounting Pronouncements

See Note 2 to our condensed consolidated financial statements set forth in Item 1 of this quarterly report for information regarding new accounting pronouncements.

Results of Operations

Our historical operating results in dollars and as a percentage of total revenues are presented below. A comparison of the different periods described below may be of limited utility primarily as a result of (i) our recent construction or disposition of new power plants and enhancement of acquired power plants; and (ii) fluctuation in revenues from our Product segment.

	Three Months Ended March 31,
	2017			2016
	(Dollars in thousands, except per share data)
Statements of Operations Historical Data:
Revenues:
Electricity	$	115,776		$	107,868
Product		74,122			43,726
		189,898			151,594
Cost of revenues:
Electricity		66,036			63,686
Product		49,452			24,035
		115,488			87,721
Gross profit
Electricity		49,740			44,182
Product		24,670			19,691
		74,410			63,873
Operating expenses:
Research and development expenses		602			349
Selling and marketing expenses		4,363			3,675
General and administrative expenses		9,949			8,749
Write-off of unsuccessful exploration activities		—			557
Operating income		59,496			50,543
Other income (expense):
Interest income		244			320
Interest expense, net		(14,923	)		(16,023	)
Derivatives and foreign currency transaction gains (losses)		1,338			1,962
Income attributable to sale of tax benefits		6,157			4,398
Other non-operating income (expense), net		(92	)		191
Income from continuing operations before income taxes and equity in losses of investees		52,220			41,391
Income tax (provision) benefit		(10,886	)		(9,509	)
Equity in losses of investees, net		(1,599	)		(937	)
Net income		39,735			30,945
Net income attributable to noncontrolling interest		(4,423	)		(1,674	)
Net income attributable to the Company's stockholders	$	35,312		$	29,271
Earnings per share attributable to the Company's stockholders:
Basic:
Net income	$	0.71		$	0.60
Diluted:
Net income	$	0.70		$	0.59
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic		49,680			49,173
Diluted		50,491			49,782

	Three Months Ended March 31,
	2017			2016
Statements of Operations Data:
Revenues:
Electricity		61.0	%		71.2	%
Product		39.0			28.8
		100.0			100.0
Cost of revenues:
Electricity		57.0			59.0
Product		66.7			55.0
		60.8			57.9
Gross profit
Electricity		43.0			41.0
Product		33.3			45.0
		39.2			42.1
Operating expenses:
Research and development expenses		0.3			0.2
Selling and marketing expenses		2.3			2.4
General and administrative expenses		5.2			5.8
Write-off of unsuccessful exploration activities		0.0			0.4
Operating income		31.3			33.3
Other income (expense):
Interest income		0.1			0.2
Interest expense, net		(7.9	)		(10.6	)
Derivatives and foreign currency transaction gains (losses)		0.7			1.3
Income attributable to sale of tax benefits		3.2			2.9
Other non-operating income (expense), net		(0.0	)		0.1

and equity in losses of investees		27.5			27.3
Income tax provision		(5.7	)		(6.3	)
Equity in losses of investees, net		(0.8	)		(0.6	)
Net income	20.9			20.4
Net income attributable to noncontrolling interest		(2.3	)		(1.1	)
Net income attributable to the Company's stockholders		18.6	%		19.3	%

Comparison of the Three Months Ended March 31, 2017 and the Three Months Ended March 31, 2016

Total Revenues

Total revenues for the three months ended March 31, 2017 were $189.9 million, compared to $151.6 million for the three months ended March 31, 2016, which represented a 25.3% increase from the prior year period. This increase was attributable to both our Electricity and Product segments, in which revenues increased by 7.3% and 69.5%, respectively, compared to the corresponding period in 2016.

Electricity Segment

Revenues attributable to our Electricity segment for the three months ended March 31, 2017 were $115.8 million, compared to $107.9 million for the three months ended March 31, 2016, representing a 7.3% increase from the prior period. This increase was primarily attributable to: (i) the consolidation of our Bouillante power plant in Guadeloupe, effective July 5, 2016, with revenues of $5.4 million for the three months ended March 31, 2017; and (ii) an increase in generation at our Puna power plant due to successful improvement of the resource performance.

Power generation in our power plants increased by 2.2% from 1,396,868 MWh in the three months ended March 31, 2016 to 1,427,704 MWh in the three months ended March 31, 2017 mainly due to the increase in generation at our Puna power plant due to higher performance and the consolidation of our Bouillante power plant, effective July 5, 2016, as discussed above.

Product Segment

Revenues attributable to our Product segment for the three months ended March 31, 2017 were $74.1 million, compared to $43.7 million for the three months ended March 31, 2016, which represented a 69.5% increase. The increase in our Product segment revenues was primarily due to the start of revenue recognition from two new geothermal projects in New Zealand and China that we started to construct in the first quarter of 2017. We recognized approximately $14.2 million and $21.5 million in revenues, respectively, from these projects in the three months ended March 31, 2017. The total contract prices for the projects are $36.6 million and $23.3 million, respectively, and they are scheduled to be completed by mid-2017 and the end of 2017, respectively. The increase in our Product segment revenues was also attributable to the start of approximately $17.0 million in revenue recognition from our new projects in Turkey, partially offset by other projects in Turkey, which were completed in the year ended December 31, 2016. The increase was also partially offset by a decrease in revenues from our geothermal project in Chile, which is close to completion, and due to timing of revenue recognition and a different product mix.

Total Cost of Revenues

Total cost of revenues for the three months ended March 31, 2017 was $115.5 million, compared to $87.7 million for the three months ended March 31, 2016, which represented a 31.7% increase. This increase was due to an increase in cost of revenues from both our Electricity and Product segments. As a percentage of total revenues, our total cost of revenues for the three months ended March 31, 2017 increased to 60.8% from 57.9% for the three months ended March 31, 2016. This increase was attributable to an increase in cost of revenues as a percentage of total revenues in our Product segment.

Electricity Segment

Total cost of revenues attributable to our Electricity segment for the three months ended March 31, 2017 was $66.0 million, compared to $63.7 million for the three months ended March 31, 2016, which represented a 3.7% increase from the prior period. This slight increase was primarily due to additional cost of revenues from the consolidation of our Bouillante power plant, effective July 5, 2016. As a percentage of total Electricity revenues, our total cost of revenues attributable to our Electricity segment for the three months ended March 31, 2017 was 57.0%, compared to 59.0% for the three months ended March 31, 2016. This decrease was primarily due to higher efficiency in some of our operating power plants.

Product Segment

Total cost of revenues attributable to our Product segment for the three months ended March 31, 2017 was $49.5 million, compared to $24.0 million for the three months ended March 31, 2016, which represented a 105.7% increase. This increase was primarily attributable to the increase in Product segment revenues, as discussed above. As a percentage of total Product segment revenues, our total cost of revenues attributable to our Product segment for the three months ended March 31, 2017 was 66.7%, compared to 55.0% for the three months ended March 31, 2016. This increase was mainly attributable to additional costs associated with our project in Chile, as well as a different product mix and different margins in the various sales contracts we entered into for the Product segment during these periods.

Research and Development Expenses, Net

Research and development expenses for the three months ended March 31, 2017 were $0.6 million, compared to $0.3 million for the three months ended March 31, 2016.

Selling and Marketing Expenses

Selling and marketing expenses for the three months ended March 31, 2017 were $4.4 million compared to $3.7 million for the three months ended March 31, 2016. This increase was primarily attributable to an increase in sales commissions related to our Product segment. Selling and marketing expenses for the three months ended March 31, 2017 constituted 2.3% of total revenues for such period, compared to 2.4% for the three months ended March 31, 2016.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2017 were $9.9 million, compared to $8.7 million for the three months ended March 31, 2016. The increase was mainly due to costs associated with our acquisition activities. General and administrative expenses for the three months ended March 31, 2017, constituted 5.2% of total revenues for such period, compared to 5.8% for the three months ended March 31, 2016.

Operating Income

Operating income for the three months ended March 31, 2017 was $59.5 million, compared to $50.5 million for the three months ended March 31, 2016, which represented a 17.7% increase. The increase in operating income was principally attributable to the increase in our gross margin in both our Electricity and Product segments primarily due to the increase in revenues, as discussed above. Operating income attributable to our Electricity segment for the three months ended March 31, 2017 was $40.9 million, compared to $34.8 million for the three months ended March 31, 2016. Operating income attributable to our Product segment for the three months ended March 31, 2017 was $18.6 million, compared to $15.8 million for the three months ended March 31, 2016.

Interest Expense, Net

Interest expense, net for the three months ended March 31, 2017 was $14.9 million, compared to $16.0 million for the three months ended March 31, 2016. This decrease was primarily due to: (i) the repayment, in September 2016, of $250 million of our senior unsecured bonds which bore interest at a fixed rate of 7% per annum, through the issuance of $67 million and $137 million, respectively, of two new series of senior unsecured bonds, which bear interest at an interest rate of 3.7% and 4.45%, respectively; (ii) lower interest expense as a result of principal payments of long term debt and revolving credit lines with banks; and (iii) a $0.8 million increase related to interest capitalized to projects, partially offset by an increase in interest related to the sale of tax benefits in connection with the Opal transaction described below.

Derivatives and foreign Currency Transaction gains

Derivatives and foreign currency transaction gains for the three months ended March 31, 2017 were $1.3 million, compared to $2.0 million for the three months ended March 31, 2016. Derivatives and foreign currency transaction gains for the three months ended March 31, 2017 and 2016 were attributable primarily to gains from foreign currency forward contracts which were not accounted for as hedge transactions.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits to institutional equity investors (as described below under “OPC Transaction”, “ORTP Transaction” and “Opal Transaction”) for the three months ended March 31, 2017 was $6.2 million, compared to $4.4 million for the three months ended March 31, 2016. This income primarily represents the value of PTCs and taxable income or loss generated by Opal Geo (as defined below) and ORTP and allocated to the investors in the three months ended March 31, 2017 compared to the value of PTCs and taxable income or loss generated by ORTP and OPC and allocated to the investors in the three months ended March 31, 2016.

Income Taxes

Income tax provision for the three months ended March 31, 2017 was $10.9 million, compared to $9.5 million for the three months ended March 31, 2016. Our effective tax rate for the three months ended March 31, 2017 and March 31, 2016, was 20.8% and 23%, respectively. Our effective tax rate is principally based upon the composition of our income in different countries and changes related to valuation allowances for certain countries. Our aggregate effective tax rate for the three months ended March 31, 2017 is lower than the 35% U.S. federal statutory tax rate as a substantial portion of our income is derived in Israel and taxed at the corporate tax rate of 16%, partially offset by taxes on earnings in Kenya which are taxed at a statutory rate of 37.5%. There is no impact on the Company’s income tax expense (benefit) related to U.S. earnings (losses) due to the offsetting impact on the provision related to the change in the valuation allowance on the Company’s U.S. net deferred tax asset position.

Equity in losses of investees, net

Equity in losses of investees, net for the three months ended March 31, 2017 was $1.6 million, compared to $0.9 million for the three months ended March 31, 2016. Equity in losses of investees, net are derived from our 12.75% share in the losses of the Sarulla project and from profits elimination.

Net Income

Net income for the three months ended March 31, 2017 was $39.7 million, compared to $30.9 million for the three months ended March 31, 2016, which represents an increase of $8.8 million. This increase in net income was principally attributable to the increase in operating income of $8.9 million, an increase of $1.8 million in income attributable to the sale of tax benefits, and a $1.1 million decrease in interest expense, net, all as discussed above.

Net Income attributable to the Company’s Stockholders

Net income attributable to the Company’s stockholders for the three months ended March 31, 2017 was $35.3 million, compared to $29.3 million for the three months ended March 31, 2016, which represents an increase of $6.0 million. This increase in net income attributable to the Company’s stockholders was principally attributable to the increase in net income of $8.8 million as discussed above, partially offset by an increase of $2.7 million in net income attributable to noncontrolling interest mainly due to the closing of a follow-up sale of a 36.75% equity interest in the second phase of the Don A. Campbell power plant to Northleaf Geothermal Holdings, LLC ("Northleaf") in November 2016.

Liquidity and Capital Resources

Our principal sources of liquidity have been derived from cash flows from operations, proceeds from third party debt in the form of borrowings under credit facilities and private offerings, issuances of notes, project financings, tax monetization transactions, short term borrowing under our lines of credit, and sales of membership interests in one or more of our projects. We have utilized this cash to develop and construct power plants, fund our acquisitions, pay down existing outstanding indebtedness, and meet our other cash and liquidity needs.

As of March 31, 2017, we had access to (i) $174.1 million in cash and cash equivalents of which $158.1 million is held by our foreign subsidiaries; and (ii) $132.6 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.

Our estimated capital needs for the remainder of 2017 include approximately $212.0 million for capital expenditures on new projects under development or construction, exploration activity, and operating projects, as well as $52.6 million for debt repayment.

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; and (iii) future project financings and refinancings (including construction loans). Management believes that, based on the current stage of implementation of the new strategic plan, the sources of liquidity and capital resources described above will address our anticipated liquidity, capital expenditures, and other investment requirements.

We believe that, based on our plans to increase our operations outside of the U.S., the cash generated from our operations outside of the U.S. will be reinvested outside of the U.S. In addition, our U.S. sources of cash and liquidity are sufficient to meet our needs in the U.S. and, accordingly, we do not currently plan to repatriate the funds we have designated as being permanently invested outside the U.S. If we change our plans, we may be required to accrue and pay U.S. taxes to repatriate these funds.

Third-Party Debt

Our third-party debt is composed of two principal categories. The first category consists of project finance debt or acquisition financing that we or our subsidiaries have incurred for the purpose of developing and constructing, refinancing or acquiring our various projects, which are described below under “Non-Recourse and Limited-Recourse Third-Party Debt”. The second category consists of debt incurred by us or our subsidiaries for general corporate purposes, which are described below under “Full-Recourse Third-Party Debt.”

Non-Recourse and Limited-Recourse Third-Party Debt

OFC Senior Secured Notes — Non-Recourse

In February 2004, OFC, one of our subsidiaries, issued $190.0 million of OFC Senior Secured Notes for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1, 1A, 2 and 3 power plants, and the financing of the acquisition cost of 50% of the Mammoth complex. The OFC Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OFC Senior Secured Notes are payable semi-annually. The OFC Senior Secured Notes are collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness of OFC and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC. In addition, there are restrictions on the ability of OFC to make distributions to its shareholders, which include a required historical and projected 12-month debt service coverage ratio of not less than 1.25 (measured semi-annually as of June 30 and December 31 of each year). If OFC fails to comply with the debt service coverage ratio, it will be prohibited from making distributions to its shareholders. We are only required to measure these covenants on a semi-annual basis and as of December 31, 2016 (the last measurement date of the covenants) the actual historical 12-month debt service coverage ratio was 1.25 and the pro-forma 12-month debt service coverage ratio was 1.38 (on a semi-annual basis and as of December 31, 2016). There was $17.0 million aggregate principal amount of OFC Senior Secured Notes outstanding as of March 31, 2017.

OrCal Geothermal Senior Secured Notes — Non-Recourse

In December 2005, OrCal, one of our subsidiaries, issued $165.0 million of OrCal Senior Secured Notes for the purpose of refinancing the acquisition cost of the Heber complex. The OrCal Senior Secured Notes have been rated BBB- by Fitch Ratings. The OrCal Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OrCal Senior Secured Notes are payable semi-annually. The OrCal Senior Secured Notes are collateralized by substantially all of the assets of OrCal and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OrCal. There are various restrictive covenants under the OrCal Senior Secured Notes which include limitations on additional indebtedness of OrCal and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OrCal. In addition, there are restrictions on the ability of OrCal to make distributions to its shareholders, which include a required historical and projected 12-month debt service coverage ratio of not less than 1.25 (measured semi-annually as of June 30 and December 31 of each year). If OrCal fails to comply with the debt service coverage ratio it will be prohibited from making distributions to its shareholders. We are only required to measure these covenants on a semi-annual basis and as of December 31, 2016, (the last measurement date of the covenants) the actual historical 12-month debt service coverage ratio was 1.77, and the pro-forma 12-month debt service coverage ratio was 2.57. There was $35.2 million aggregate principal amount of OrCal Senior Secured Notes outstanding as of March 31, 2017.

OFC 2 Senior Secured Notes — Limited Recourse

In September 2011, OFC 2, one of our subsidiaries, and its wholly owned project subsidiaries (collectively, the "OFC 2 Issuers") entered into a note purchase agreement (the "Note Purchase Agreement") with the OFC 2 Noteholder Trust, as purchaser, John Hancock, as administrative agent, and the Department of Energy (DOE), as guarantor, in connection with the offer and sale of up to $350.0 million aggregate principal amount of OFC 2 Senior Secured Notes.

Subject to the fulfillment of customary and other specified conditions precedent, the OFC 2 Senior Secured Notes may be issued in up to six distinct series associated with the phased construction (Phase I and Phase II) of the Jersey Valley, McGinness Hills and Tuscarora geothermal power plants, which are owned by the OFC 2 Issuers. The OFC 2 Senior Secured Notes will mature on December 31, 2034 and the principal amount of the OFC 2 Senior Secured Notes will be payable in equal quarterly installments and in any event not later than December 31, 2034. Each series of notes will bear interest at a rate calculated based on a spread over the U.S. Treasury yield curve that will be set at least ten business days prior to the issuance of such series of notes. Interest will be payable quarterly in arrears. The DOE guarantees payment of 80% of principal and interest on the OFC 2 Senior Secured Notes pursuant to Section 1705 of Title XVII of the Energy Policy Act of 2005, as amended. The conditions precedent to the issuance of the OFC 2 Senior Secured Notes include certain specified conditions required by the DOE in connection with its guarantee of the OFC 2 Senior Secured Notes.

In October 2011, the OFC 2 Issuers completed the sale of $151.7 million aggregate principal amount of 4.687% Series A Notes due 2032 (the Series A Notes). The net proceeds from the sale of the Series A Notes, after deducting transaction fees and expenses, were approximately $141.1 million, and were used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora power plants and to fund certain reserves. Principal and interest on the Series A Notes are payable quarterly in arrears on the last day of March, June, September and December of each year.

On June 20, 2014, Phase I of the Tuscarora facility achieved project completion under the Note Purchase Agreement. In accordance with the terms of the Note Purchase Agreement, we recalibrated the original financing assumptions and as a result the loan amount was adjusted through a principal payment of $4.3 million.

On August 29, 2014, OFC 2 received a $140.0 million loan under the OFC 2 Senior Secured Notes to finance the construction of phase II of the McGinness Hills project. This draw is the last tranche (the "Series C Notes") under the Note Purchase Agreement with John Hancock Life Insurance Company (USA), and is guaranteed by the U.S Department of Energy Loan Programs Office in accordance with and subject to the Department’s Loan Guarantee Program under section 1705 of Title XVII of the Energy Policy Act of 2005. The $140.0 million loan, which matures in December 2032, carries a 4.61% coupon with principal to be repaid on a quarterly basis. The OFC 2 Senior Secured Notes, which include loans for the Tuscarora, Jersey Valley and McGinness Hills complexes, are rated “BBB” by Standard & Poor’s.

In connection with the August 13, 2014 drawdown, we entered into an on-the-run interest lock agreement with a financial institution with a termination date of August 15, 2014. This on-the-run interest lock agreement had a notional amount of $140.0 million and was designated by us to as a cash flow hedge. The objective of this cash flow hedge was to eliminate the variability in the change in the 10-year U.S. Treasury rate as that is one of the components in the annual interest rate of the OFC 2 loan that was forecasted to be fixed on August 15, 2014. As such, we hedged the variability in total proceeds attributable to changes in the 10-year U.S. Treasury rate for the forecasted issuance of fixed rate OFC 2 loan. On the settlement date of August 18, 2014, we paid $1.5 million to the counterparty to the on-the-run interest rate lock agreement. The OFC 2 Senior Secured Notes are collateralized by substantially all of the assets of OFC 2 and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC 2. There are various restrictive covenants under the OFC 2 Senior Secured Notes, which include limitations on additional indebtedness of OFC 2 and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC 2. In addition, there are restrictions on the ability of OFC 2 to make distributions to its shareholders.

Among other things, the distribution restrictions include a historical debt service coverage ratio requirement of at least 1.2 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two six-months periods comprised of distinct consecutive fiscal quarters immediately preceding the proposed distribution, and a projected future debt service coverage ratio requirement of at least 1.5 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two six-months periods comprised of distinct consecutive fiscal quarters immediately following such proposed distribution. As of March 31, 2017, our historical debt service coverage ratio was 2.54 and 2.27, respectively for each of the two six-month periods, and our projected future debt service coverage ratio was 1.88 and 2.14, respectively for each of the two six-month periods.

There was $242.7 million aggregate principal amount of OFC 2 Senior Secured Notes outstanding as of March 31, 2017.

We provided a guarantee in connection with the issuance of the Series A and C Notes, which will be available to be drawn upon if certain trigger events occur. The trigger events include any loss, liability, damage, expense or cost to the Jersey Valley facility caused by the interconnection under the various interconnection related agreements of the Dixie Meadows project that we may develop in the future.

Olkaria III Finance Agreement with OPIC — Limited Recourse

In August 2012, OrPower 4, one of our subsidiaries, entered into a finance agreement with OPIC, an agency of the United States government, to provide limited-recourse senior secured debt financing in an aggregate principal amount of up to $310.0 million (the "OPIC Loan") for the refinancing and financing of our Olkaria III geothermal power complex in Kenya. The finance agreement was amended on November 9, 2012.

The OPIC Loan is comprised of three tranches:

●

Tranche I in an aggregate principal amount of $85.0 million and a fixed interest rate of 6.34%, which was drawn in November 2012, was used to prepay approximately $20.5 million (plus associated prepayment penalty and breakage costs of $1.5 million) of the DEG Loan, as described below under “Full Recourse Third Party Debt”. The remainder of Tranche I proceeds was used for reimbursement of prior capital costs and other corporate purposes. As of March 31, 2017, Tranche I has an outstanding balance of $64.9 million and matures on December 15, 2030.

●

Tranche II in an aggregate principal amount of $180.0 million and a fixed interest rate of 6.29%, was used to fund the construction and well field drilling for Plant 2 of the Olkaria III geothermal power complex. In November 2012, an amount of $135.0 million was disbursed under this Tranche II, and in February 2013 the remaining $45.0 million was disbursed under this Tranche II. As of March 31, 2017, Tranche II has an outstanding balance of $140.3 million and matures on June 15, 2030.

●

Tranche III in an aggregate principal amount of $45.0 million and a fixed interest rate of 6.12%, was used to fund the construction of Plant 3 of the Olkaria III geothermal power complex and was drawn down in full in November 2013. As of March 31, 2017, Tranche III has an outstanding balance of $36.9 million and matures on December 15, 2030.

OrPower 4 has a right to make voluntary prepayments of all or a portion of the OPIC Loan subject to prior notice, minimum prepayment amounts, and a prepayment premium of 2.0% in the first two years after the Plant 2 commercial operation date, declining to 1% in the third year after the Plant 2 commercial operation date, and without premium thereafter, plus a redemption premium. In addition, the OPIC Loan is subject to customary mandatory prepayment in the event of certain reductions in generation capacity of the power plants, unless such reductions will not cause the projected ratio of cash flow to debt service to fall below 1.7.

The OPIC Loan is secured by substantially all of OrPower 4’s assets and by a pledge of all of the equity interests in OrPower 4.

The finance agreement includes customary events of default, including failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations and warranties, non-payment or acceleration of other debt of OrPower 4, bankruptcy of OrPower 4 or certain of its affiliates, judgments rendered against OrPower 4, expropriation, change of control, and revocation or early termination of security documents or certain project-related agreements, subject to various exceptions and notice, cure and grace periods.

The repayment of the remaining outstanding DEG Loan (see “Full-Recourse Third-Party Debt” below) in the amount of approximately $15.8 million as of March 31, 2017, has been subordinated to the OPIC Loan.

There are various restrictive covenants under the OPIC Loan, which include a required historical and projected 12-month debt service coverage ratio of not less than 1.4 (measured as of March 15, June 15, September 15 and December 15 of each year). If OrPower 4 fails to comply with these financial ratios it will be prohibited from making distributions to its shareholders. In addition, if the debt service coverage ratio falls below 1.1, subject to certain cure rights; such failure will constitute an event of default by OrPower 4. This covenant in respect of Tranche I became effective on December 15, 2014. As of March 31, 2017, the actual historical and projected 12-month debt service coverage ratio was 2.14 and 2.99, respectively.

As of March 31, 2017, $242.1 million of the OPIC Loan was outstanding.

Amatitlan financing — Limited Recourse

On July 31, 2015, one of our indirect wholly-owned subsidiaries, Ortitlản, Limitada, obtained a 12-year secured term loan in the principal amount of $42.0 million for the 20 MW Amatitlàn power plant in Guatemala. Under the credit agreement with Banco Industrial S.A. and Westrust Bank (International) Limited, we can expand the Amatitlàn power plant with financing to be provided either via equity, additional debt from Banco Industrial S.A. or from other lenders, subject to certain limitations on expansion financing in the credit agreement.

The loan is payable in 48 quarterly payments commencing September 30, 2015. The loan bears interest at a rate per annum equal to of the sum of the LIBO Rate (which cannot be lower than 1.25%) plus a margin of (i) 4.35%, as long as the Company’s guaranty of the loan (as described below) is outstanding or (ii) 4.75% otherwise. Interest is payable quarterly, on March 30, June 30, September 30 and December 30 of each year, on the stated maturity date of the loan and on any prepayment or payment of the loan. The loan must be prepaid upon the occurrence of certain events, such as casualty, condemnation, certain asset sales and expansion financing not provided by the lenders under the credit agreement, among others. The loan may be voluntarily prepaid if certain conditions are satisfied, including payment of a premium (ranging from 100-50 basis points) if prepayment occurs prior to the eighth anniversary of the loan.

There are various restrictive covenants under the Amatitlàn credit agreement. These include, among others, (i) a financial covenant to maintain a Debt Service Coverage Ratio (as defined in the credit agreement) of not less than 1.15 to 1.00 as of the last day of any fiscal quarter and (ii) limitations on Restricted Payments (as defined in the credit agreement) that, among other things, would limit dividends that could be paid to us unless the historical and projected Debt Service Coverage Ratio is not less than 1.25 to 1.00 for the four fiscal quarterly periods (calculated as a single accounting period). As of March 31, 2017, the actual historical and projected 12-month Debt Service Coverage Ratio was 1.35 and 1.85, respectively. The credit agreement includes various events of default that would permit acceleration of the loan (subject in some cases to grace and cure periods). These include, among others, a Change of Control (as defined in the credit agreement) and failure to maintain certain required balances in debt service and maintenance reserve accounts. The credit agreement includes certain equity cure rights for failure to maintain the Debt Service Coverage Ratio and the minimum amounts required in the debt service and maintenance reserve accounts.

The loan is secured by substantially all the assets of the borrower and a pledge of all of the membership interests of the borrower.

The Company has guaranteed payment of all obligations under the credit agreement and related financing documents. The guaranty is limited and the Company is only required to pay the guaranteed obligations if a “trigger event” occurs. A trigger event is the occurrence and continuation of a default by Instituto Nacional de Electricidad (“INDE”) in its payment obligations under the PPA for the Amatitlàn power plant or a refusal by INDE to receive capacity and energy sold under that PPA. Our obligations under the guaranty may be terminated prior to payment in full of the guaranteed obligations under certain circumstances described in the guaranty. If our guaranty is terminated early, the interest rate payable on the loan would increase as described above.

As of March 31, 2017, $35.9 million of this loan is outstanding.

Don A. Campbell Senior Secured Notes — Non-Recourse

On November 29, 2016, ORNI 47 LLC (“ORNI 47”) entered into a note purchase agreement (the “ORNI 47 Note Purchase Agreement”) with MUFG Union Bank, N.A., as collateral agent, Munich Reinsurance America, Inc. and Munich American Reassurance Company (the “Purchasers”) pursuant to which ORNI 47 issued and sold to the Purchasers $92.5 million aggregate principal amount of its 4.03% Senior Secured Notes due September 27, 2033 (the “Notes”) in a private placement exempt from the registration requirements of the Securities Act of 1933, as amended. ORNI 47 is the owner of the Don A. Campbell Phase I (“DAC 1”) geothermal power plant, and part of ORPD.

The net proceeds to ORNI 47 from the sale of the Notes, after deducting certain transaction expenses and the funding of a debt service reserve account, were approximately $87.1 million. ORNI 47 used the proceeds from the sale of the Notes to refinance the development and construction costs of the DAC 1 geothermal power plant, which were originally financed using equity.

ORNI 47 will pay a scheduled amount of principal of the Notes beginning on December 27, 2016 and then quarterly, on the 27th day of each March, June, September and December, until the Notes mature.

The Notes constitute senior secured obligations of ORNI 47 and are secured by all of the assets of ORNI 47. Under the ORNI 47 Note Purchase Agreement, ORNI 47 may prepay at any time all, or from time to time any part of, the Notes in an amount equal to at least $2 million or such lesser amount as may remain outstanding under the Notes at 100% of the principal amount to be prepaid plus the applicable make-whole amount determined for the prepayment date with respect to such principal amount. Upon the occurrence of a Change of Control (as defined in the ORNI 47 Note Purchase Agreement), ORNI 47 must make an offer to each holder of Notes to repurchase all of the holder’s Notes at 101% of the aggregate principal amount of Notes to be repurchased plus accrued and unpaid interest, if any, on the Notes to be repurchased to, but not including, the date of repurchase. Each holder of Notes may accept such offer in whole or in part. In certain events, including certain asset sales outside the ordinary course of business, ORNI 47 must make mandatory prepayments of the Notes at 100% of the principal amount to be prepaid. The ORNI 47 Note Purchase Agreement requires ORNI 47 to comply with certain covenants, including, among others, restrictions on the incurrence of indebtedness or liens, amendment or modification of material project documents, the ability of ORNI 47 to merge or consolidate with another entity. The ORNI 47 Note Purchase Agreement also contains customary events of default. In addition, there are restrictions on the ability of ORNI 47 to make distributions to its shareholders, which include a required historical and projected Debt Service Coverage Ratio not less than 1.20 for the four fiscal quarterly periods. As of March 31, 2017, the projected Debt Service Coverage Ratio was 1.84.

As of March 31, 2017, $90.8 million is outstanding under the DAC 1 Loan.

Full-Recourse Third-Party Debt

Credit Agreements

Union Bank. In February 2012, Ormat Nevada, our wholly owned subsidiary, entered into an amended and restated credit agreement with Union Bank. Under the credit agreement as amended and restated through the date of this report, the credit termination date is June 30, 2017. On December 31, 2016, the aggregate amount available under the credit agreement was increased by $10 million to $60.0 million. The facility is limited to the issuance, extension, modification or amendment of letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured.

There are various restrictive covenants under the credit agreement, including a requirement for Ormat Nevada to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) a 12-month debt service coverage ratio of not less than 1.35; and (iii) a distribution leverage ratio not to exceed 2.0. As of March 31, 2017: (i) the actual 12-month debt to EBITDA ratio was 2.85; (ii) the 12-month debt service coverage ratio was 2.51; and (iii) the distribution leverage ratio was 0.86. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of Union Bank.

As of March 31, 2017, letters of credit in the aggregate amount of $32.6 million remain issued and outstanding under this committed credit agreement with Union Bank.

HSBC. In May 2013, Ormat Nevada entered into a credit agreement with HSBC Bank USA, N.A for one year with annual renewals. The current expiration date of the facility under this credit agreement is December 31, 2017. The aggregate amount available under the credit agreement was increased by $10 million to $35.0 million. This credit line is limited to the issuance, extension, modification or amendment of letters of credit and $10.0 million out of this credit line is available to be drawn for working capital needs. HSBC is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured.

There are various restrictive covenants under the credit agreement, including a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) a 12-month debt service coverage ratio of not less than 1.35; and (iii) a distribution leverage ratio not to exceed 2.0. As of March 31, 2017: (i) the actual 12-month debt to EBITDA ratio was 2.85; (ii) the 12-month debt service coverage ratio was 2.51; and (iii) the distribution leverage ratio was 0.86. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of HSBC.

As of March 31, 2017, letters of credit in the aggregate amount of $23.2 million remain issued and outstanding under this committed credit agreement.

Other Banks. We also have committed credit agreements with five other commercial banks for an aggregate amount of $429.8 million. Under the terms of these credit agreements, we or our Israeli subsidiary, Ormat Systems, can request (i) extensions of credit in the form of loans and/or the issuance of one or more letters of credit in the amount of up to $215.0 million and (ii) the issuance of one or more letters of credit in the amount of up to $214.8 million. The credit agreements mature at the end of March 2017 and July 2019. Loans and draws under the credit agreements or under any letters of credit will bear interest at the respective bank’s cost of funds plus a margin. As of March 31, 2017, loan balance of $30 million was outstanding under these credit agreements.

As of March 31, 2017, letters of credit with an aggregate stated amount of $263.7 million were issued and outstanding under these credit agreements.

Letters of Credits under the Credit Agreements

Some of our customers require our project subsidiaries to post letters of credit in order to guarantee their respective performance under relevant contracts. We are also required to post letters of credit to secure our obligations under various leases and licenses and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. In addition, our subsidiary Ormat Systems is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products.

As of March 31, 2017, committed letters of credit in the aggregate amount of $319.6 million remained issued and outstanding under the credit agreements with Union Bank, HSBC and five of the commercial banks as described under “Credit Agreements”.

Term Loans. We have a $20.0 million term loan with a group of institutional investors, which matures on August 1, 2017, that is payable in 12 semi-annual installments commencing February 1, 2012, and bears interest at 6-month LIBOR plus 5.0%. As of March 31, 2017, $1.7 million was outstanding under this loan.

Senior Unsecured Bonds. We had an aggregate principal amount of approximately $250.0 million of senior unsecured bonds issued and outstanding. We issued approximately $142.0 million aggregate principal amount of these bonds in August 2010 and an additional $107.5 million aggregate principal amount in February 2011. Subject to early redemption, the principal of the bonds was repayable in a single bullet payment upon the final maturity of the bonds on August 1, 2017. The bonds bore interest at a fixed rate of 7.00%, payable semi-annually. The bonds that we issued in February 2011 were issued at a premium which reflects an effective fixed interest rate of 6.75%.

On September 8, 2016, the Company concluded an auction tender and accepted subscriptions for $204 million aggregate principal amount of two tranches of senior unsecured bonds (approximately $67 million aggregate principal amount of “Series 2 Bonds” and approximately $137 million aggregate principal amount of “Series 3 Bonds”). The proceeds from the Series 2 Bonds and Series 3 Bonds were used on September 29, 2016 to prepay the Company’s $250 million senior unsecured bonds that were payable on August 1, 2017.

The Series 2 Bonds will mature in September 2020 and bear interest at a fixed rate of 3.7% per annum, payable semi-annually. The Series 3 Bonds will mature in September 2022 and bear interest at a fixed rate of 4.45% per annum, payable semi-annually. The Series 2 Bonds and Series 3 Bonds will be repaid at maturity in a single bullet payment, unless earlier prepaid by Ormat pursuant to the terms and conditions of the trust instrument that governs such bonds. Both tranches received a rating of ilA+ from Maloot S&P in Israel with a stable outlook.

Loan Agreement with DEG (The Olkaria III Complex). OrPower 4 entered into a project financing loan (the “DEG Loan”) to refinance its investment in Plant 1 of the Olkaria III complex located in Kenya with a group of European development finance institutions arranged by Deutsche Investitions-und Entwicklungsgesellschaft mbH (DEG). The DEG Loan will mature on December 15, 2018, and is payable in 19 equal semi-annual installments. Interest on the loan is variable based on 6-month LIBOR plus 4.0%. We fixed the interest rate on most of the loan at 6.90%. As of March 31, 2017, $15.8 million is outstanding under the DEG Loan (out of which $10.8 million bears interest at a fixed rate).

In October 2012, OrPower 4, DEG and the other parties thereto amended and restated the DEG loan agreement (the “DEG Loan Agreement”). The amendment became effective on November 9, 2012 upon the execution by OrPower 4 of the Tranche I and Tranche II notes under the OPIC Loan and the related disbursements of the proceeds thereof under the OPIC finance agreement (as described above under the heading “Non-Recourse and Limited–Recourse Third-Party Debt”). In connection with the amendment, we prepaid in full two loans under the DEG Loan Agreement in the total principal amount of approximately $20.5 million. The amended and restated DEG Loan Agreement provides for (i) the release and discharge of all collateral security previously provided by OrPower 4 to the secured parties under the DEG Loan Agreement and the substitution of the Company’s guarantee of OrPower 4’s payment and certain other performance obligations in lieu thereof; (ii) the establishment of a LIBOR floor of 1.25% in respect of one of the loans under the DEG Loan Agreement, (iii) the elimination of most of the affirmative and negative covenants under the DEG Loan Agreement and (iv) certain other conforming provisions as a result of OrPower 4’s execution of the OPIC finance agreement and its obligations thereunder.

On October 20, 2016, OrPower 4 entered into a new $50 million subordinated facility agreement with DEG (the “DEG 2 Loan Agreement”) and on December 21, 2016, OrPower 4 completed a drawdown of the full loan commitment amount of $50 million, which bears interest at a fixed interest rate of 6.28% for the duration of the loan (the “DEG 2 Loan”). The DEG 2 Loan, which matures on June 21, 2028, will be repaid in 20 equal semi-annual principal installments commencing December 21, 2018. Proceeds of the DEG 2 Loan were used by OrPower 4 to refinance Plant 4 of the Olkaria III Complex, which was originally financed using equity. The DEG 2 Loan is subordinated to the senior loan provided by OPIC for Plants 1-3 of the Olkaria III Complex. The DEG 2 Loan is guaranteed by the Company.

Under the DEG 2 Loan Agreement, OrPower 4 may prepay at any time all, or from time to time any part of the DEG 2 Loan in an amount equal to at least $5 million or such lesser amount as may remain outstanding under the DEG 2 Loan at 100% of the principal amount to be prepaid plus the applicable make-whole amount and certain prepayment premium amount determined for the prepayment date with respect to such principal amount. In certain events, OrPower 4 must make mandatory prepayments of the DEG 2 Loan at 100% of the principal amount to be prepaid plus the applicable make-whole amount and certain prepayment premium amount determined for the prepayment date with respect to such principal amount. The DEG 2 Loan Agreement requires OrPower 4 to comply with certain covenants, including, among others, restrictions on the incurrence of indebtedness or liens. The DEG 2 Loan Agreement also contains customary events of default.

As of March 31, 2017, $50.0 million is outstanding under the DEG 2 Loan.

Restrictive covenants

Our obligations under the credit agreements, the loan agreements, and the trust instrument governing the bonds, described above, are unsecured, but we are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets, or a change of control in our ownership structure. Some of the credit agreements, the term loan agreements, and the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, we have agreed to maintain certain financial ratios, which are measured quarterly, such as: (i) equity of at least $600.0 million and in no event less than 25% of total assets; (ii) 12-month debt, net of cash, cash equivalents, and short-term bank deposits to Adjusted EBITDA ratio not to exceed 6.0; and (iii) dividend distributions not to exceed 35% of net income in any calendar year. As of March 31, 2017: (i) total equity was $1,196.5 million and the actual equity to total assets ratio was 48.0% and (ii) the 12-month debt, net of cash and cash equivalents, to Adjusted EBITDA ratio was 2.46. During the three months ended March 31, 2017, we distributed interim dividends in an aggregate amount of $8.4 million. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.

As described above, we are currently in compliance with our covenants with respect to the credit agreements, the loan agreements and the trust instrument, and believe that the restrictive covenants, financial ratios and other terms of any of our (or Ormat Systems’) full-recourse bank credit agreements will not materially impact our business plan or operations.

Future minimum payments

As of March 31, 2017, future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks and lease payments under the Puna lease transaction described below, are as follows:

	(Dollars in thousands)


Year ending December 31:
2017	$	52,570
2018		64,813
2019		59,146
2020		126,870
2021		46,579
Thereafter		593,276
Total	$	943,254

Puna Power Plant Lease Transactions

In May 2005, Puna Geothermal Venture (“PGV”), our Hawaiian subsidiary, entered into a transaction involving the original geothermal power plant of the Puna complex located on the Big Island (the “Puna Power Plant”).

Pursuant to a 31-year head lease (the "Head Lease"), PGV leased the Puna Power Plant to an unrelated lessor (the “Puna Lessor”) in return for prepaid lease payments in the total amount of $83.0 million. The carrying value of the leased assets as of March 31, 2017 amounted to $27.3 million, net of accumulated depreciation of $33.5 million. The Puna Lessor simultaneously leased back the Puna Power Plant to PGV under a 23-year lease (the Project Lease). PGV’s rent obligations under the Project Lease will be paid solely from revenues generated by the Puna Power Plant under a PPA that PGV has with HELCO. The Head Lease and the Project Lease are non-recourse lease obligations. PGV’s rights in the geothermal resource and the related PPA have not been leased to the Puna Lessor as part of the Head Lease but are part of the Puna Lessor’s security package.

The transaction was concluded with financing parties by means of a leveraged lease transaction. A secondary stage of the lease transaction relating to two new geothermal wells that PGV drilled in the second half of 2005 (for production and injection) was completed on December 30, 2005. Pursuant to a 31-year head lease, PGV leased its geothermal power plant to the abovementioned financing parties in return for payments of $83.0 million by such financing parties to PGV, which are accounted for as deferred lease income.

There are various restrictive covenants under the lease agreement, including a requirement to have certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve funds amounted to $6.3 million and $2.9 million as of March 31, 2017 and December 31, 2016, respectively, and were included in restricted cash accounts in the consolidated balance sheets and were classified as current as they were used for current payments.

Opal Transaction

On December 16, 2016, Ormat Nevada entered into an equity contribution agreement (the “Equity Contribution Agreement”) with OrLeaf LLC (“OrLeaf”) and JPM Capital Corporation (“JPM”) with respect to Opal Geo LLC (“Opal Geo”). Also on December 16, 2016, OrLeaf, a newly formed limited liability company formed by Ormat Nevada and ORPD LLC, entered into an amended and restated limited liability company agreement of Opal Geo (the “LLC Agreement”) with JPM. The transactions contemplated by the Equity Contribution Agreement and LLC Agreement will allow the Company to monetize PTCs and certain other tax benefits relating to the operation of five geothermal power plants located in Nevada.

In connection with the transactions contemplated by the Equity Contribution Agreement and the LLC Agreement, Ormat Nevada transferred its indirect ownership interest in the McGinness Hills (Phase I and Phase II), Tuscarora, Jersey Valley and Don A. Campbell Phase 2 (“DAC 2”) geothermal power plants to Opal Geo. Prior to such transfer, Ormat Nevada held an approximately 63.25% indirect ownership interest in DAC 2 through ORPD LLC, a joint venture between Ormat Nevada and Northleaf, and held, directly or indirectly, a 100% ownership interest in the remaining geothermal power plants that were transferred to Opal Geo.

Pursuant to the Equity Contribution Agreement, JPM contributed approximately $62.1 million to Opal Geo in exchange for 100% of the Class B Membership Interests of Opal Geo. JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the DAC 2 and McGinness Hills Phase II power plants which are eligible for the PTC. The Company expects the aggregate amount of JPM’s deferred capital contributions to equal approximately $21 million and to be paid over time covering the period through December 31, 2022.

Under the LLC Agreement, until December 31, 2022, OrLeaf will receive distributions of 97.5% of any distributable cash generated by operation of the power plants while JPM will receive distributions of 2.5% of any distributable cash generated by operation of the power plants. Unless JPM has already achieved its target internal rate of return on its investment in Opal Geo, from December 31, 2022 until JPM has achieved its target internal rate of return, JPM will receive 100% of any distributable cash generated by operation of the power plants. Thereafter, OrLeaf will receive distributions of 97.5%, and JPM will receive 2.5%, of any distributable cash generated by operation of the power plants.

Under the LLC Agreement, all items of Opal Geo income and loss, gain, deduction and credit (including the federal PTCs relating to the operation of the two PTC eligible power plants) will be allocated, until JPM has achieved its target internal rate of return on its investment in Opal Geo (and for so long as the two PTC eligible power plants are generating PTCs), 99% to JPM and 1% to OrLeaf, or 5% to JPM and 95% to OrLeaf if PTCs are no longer available to either of the two PTC eligible power plants. Once JPM achieves its target internal rate of return, all items of Opal Geo income and loss, gain, deduction and credit will be allocated 5% to JPM and 95% to OrLeaf.

Under the LLC Agreement, OrLeaf, which owns 100% of the Class A Membership Interests in Opal Geo, will serve as the managing member of Opal Geo and control the day-to-day management of Opal Geo and its portfolio of five power plants. However, in certain limited circumstances (such as bankruptcy of Orleaf, fraud or gross negligence by OrLeaf) JPM may remove OrLeaf as the managing member of Opal Geo. JPM, as the Class B Member of Opal Geo, has consent and approval rights with respect to certain items that are designated as major decisions for Opal Geo and the five power plants. In addition, by virtue of certain provisions in OrLeaf’s own limited liability company agreement, and consistent with the ORPD LLC formation documents, Northleaf has similar consent and approval rights with respect to OrLeaf’s determination of major decisions pertaining to the DAC 2 power plant. In both cases, these major decisions are generally equivalent to customary minority protection rights. As a result, the Company’s wholly owned subsidiary, Ormat Nevada, which serves as the managing member of OrLeaf and as the managing member of ORPD LLC, will effectively retain the day-to-day control and management of Opal Geo and its portfolio of five power plants.

The LLC Agreement contains certain customary restrictions on transfer applicable to both OrLeaf and JPM with respect to their respective Membership Interests in Opal Geo, and also provides OrLeaf with a right of first offer in the event JPM desires to transfer any of its Class B Membership Interests, pursuant to which OrLeaf may purchase such Class B Membership Interests. The LLC Agreement also provides OrLeaf with the option to purchase all of the Class B Membership Interests on either December 31, 2022 or the date that is 9 years after the closing date under the Equity Contribution Agreement at a price equal to the greater of (i) the fair market value of the Class B Membership Interests as of the date of purchase (subject to certain adjustments) and (ii) $3 million.

Pursuant to the Equity Contribution Agreement, the Company has provided a guaranty for the benefit of JPM of certain of OrLeaf’s indemnification obligations to JPM under the LLC Agreement. In addition, Ormat Nevada also provided a guaranty for the benefit of JPM of all present and future payment and performance obligations of OrLeaf under the LLC Agreement and each ancillary document to which OrLeaf is a party.

JPM’s contribution of approximately $62.1 million to Opal Geo in exchange for 100% of the Class B Membership Interests of Opal Geo was recorded as a $3.7 million allocation to noncontrolling interests and a $58.5 million allocation to liabilities associated with the sale of tax benefits.

OPC Transaction

In June 2007, Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC and Lehman-OPC LLC, respectively), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC, entitling the investors to certain tax benefits (such as PTCs and accelerated depreciation) and distributable cash associated with four geothermal power plants in Nevada.

The first closing under the agreements occurred in 2007 and covered our Desert Peak 2, Steamboat Hills, and Galena 2 power plants. The investors paid $71.8 million at the first closing. The second closing under the agreements occurred in 2008 and covered the Galena 3 power plant. The investors paid $63.0 million at the second closing.

Ormat Nevada continues to operate and maintain the power plants. Under the agreements, Ormat Nevada initially received all of the distributable cash flow generated by the power plants, while the investors received substantially all of the PTCs and the taxable income or loss (together, the "Economic Benefits"). Once Ormat Nevada recovered the capital that it invested in the power plants, which occurred in the fourth quarter of 2010, the investors began receiving both the distributable cash flow and the Economic Benefits. Once the investors reach a target after-tax yield on their investment in OPC (the “OPC Flip Date”), Ormat Nevada will receive 95% of both distributable cash and taxable income, on a going forward basis. Following the OPC Flip Date, Ormat Nevada also has the option to purchase the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. If Ormat Nevada were to exercise this purchase option, it would become the sole owner of the power plants again.

Our voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada, we own all of the Class A membership units, which represent 75% of the voting rights in OPC, and the investors (as described below) own all of the Class B membership units, which represent 25% of the voting rights of OPC. Other than in respect of customary protective rights, all operational decisions at OPC are decided by the vote of a majority of the membership units. Following the OPC Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investors’ voting rights will decrease to 5%. Ormat Nevada has, and after the OPC Flip Date will retain, the controlling voting interest in OPC and therefore consolidates OPC. We expect the OPC Flip Date to occur in the second quarter of 2017.

The Class B membership units have a 5% residual economic interest in OPC, which commences as of the OPC Flip Date. This residual 5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. The Class B membership units are currently held by Morgan Stanley Geothermal LLC and JPM. On October 30, 2009, Ormat Nevada acquired from Lehman-OPC LLC all of the Class B membership units of OPC held by Lehman-OPC LLC pursuant to a right of first offer for a purchase price of $18.5 million in cash and on February 3, 2011, Ormat Nevada sold to JPM all of the Class B membership units of OPC that it had acquired for a sale price of $24.9 million in cash.

ORTP Transaction

On January 24, 2013, Ormat Nevada entered into agreements with JPM under which JPM purchased interests in a newly formed subsidiary of Ormat Nevada, ORTP, entitling JPM to certain tax benefits (such as PTCs and accelerated depreciation) associated with certain geothermal power plants in California and Nevada.

In connection with the transaction, Ormat Nevada transferred the Heber complex, the Mammoth complex, the Ormesa complex, the Steamboat 2 and 3, Burdette (Galena 1) and Brady power plants to ORTP, and sold class B membership units in ORTP to JPM. In connection with the closing, JPM paid approximately $35.7 million to Ormat Nevada and will make additional payments to Ormat Nevada of 25% of the value of PTCs generated by the portfolio over time. The additional payments were expected to be made until December 31, 2016 and total up to a maximum amount of $11.0 million, of which we received $1.4 million, $2.0 million, $1.7 million and $2.2 million in the first quarters of 2017, 2016, 2015 and 2014, respectively.

Ormat Nevada will continue to operate and maintain the power plants. Under the agreements, Ormat Nevada will initially receive all of the distributable cash flow generated by the power plants, while JPM will receive substantially all of the Economic Benefits. JPM’s return is limited by the terms of the transaction. Once JPM reaches a target after-tax yield on its investment in ORTP (the “ORTP Flip Date”), Ormat Nevada will receive 97.5% of the distributable cash and 95.0% of the taxable income, on a going forward basis. At any time during the twelve-month period after the end of the fiscal year in which the ORTP Flip Date occurs (but no earlier than the expiration of five years following the date that the last of the power plants was placed in service for purposes of federal income taxes), Ormat Nevada also has the option to purchase JPM’s remaining interest in ORTP at the then-current fair market value. If Ormat Nevada were to exercise this purchase option, it would become the sole owner of the power plants again.

The Class B membership units entitle the holder to a 5.0% (allocation of income and loss) and 2.5% (allocation of cash) residual economic interest in ORTP. The 5.0% and 2.5% residual interests commence on achievement by JPM of a contractually stipulated return that triggers the ORTP Flip Date. The actual ORTP Flip Date occurred on March 31, 2017. This residual 5.0% and 2.5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. We expect to negotiate a buyout from JPM of their Class B membership units during the second quarter of 2017.

Our voting rights in ORTP are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada, we own all of the Class A membership units, which represent 75.0% of the voting rights in ORTP. JPM owns all of the Class B membership units, which represent 25.0% of the voting rights of ORTP. Other than in respect of customary protective rights, all operational decisions in ORTP are decided by the vote of a majority of the membership units. Ormat Nevada retains the controlling voting interest in ORTP both before and after the ORTP Flip Date and therefore will continue to consolidate ORTP.

Liquidity Impact of Uncertain Tax Positions

The Company has a liability associated with unrecognized tax benefits and related interest and penalties in the amount of approximately $6.3 million as of March 31, 2017. This liability is included in long-term liabilities in our condensed consolidated balance sheet because we generally do not anticipate that settlement of the liability will require payment of cash within the next twelve months. We are not able to reasonably estimate when we will make any cash payments required to settle this liability.

Dividends

The following are the dividends declared by us since March 31, 2015:

Date Declared	Dividend Amount per Share		Record Date	Payment Date
May 6, 2015	$	0.06	May 19, 2015	May 27, 2015
August 3, 2015	$	0.06	August 18, 2015	September 2, 2015
November 3, 2015	$	0.06	November 18, 2015	December 2, 2015
February 23, 2016	$	0.31	March 15, 2016	March 29, 2016
May 4, 2016	$	0.07	May 18, 2016	May 24, 2016
August 2, 2016	$	0.07	August 16, 2016	August 30, 2016
November 7, 2016	$	0.07	November 21, 2016	December 6, 2016
February 28, 2017	$	0.17	March 15, 2017	March 29, 2017
May 8, 2017	$	0.08	May 22, 2017	May 31, 2017

Historical Cash Flows

The following table sets forth the components of our cash flows for the periods indicated:

	Three Months Ended March 31,
	2017			2016
	(Dollars in thousands)
Net cash provided by operating activities	$	71,463		$	27,044
Net cash used in investing activities		(128,738	)		(44,620	)
Net cash provided by (used in) financing activities		1,199			(19,845	)
Net change in cash and cash equivalents		(56,076	)		(37,421	)

For the Three Months Ended March 31, 2017

Net cash provided by operating activities for the three months ended March 31, 2017 was $71.5 million, compared to $27.0 million for the three months ended March 31, 2016. The net increase of $44.5 million resulted primarily from: (i) a decrease in receivables of $19.1 million in the three months ended March 31, 2017, compared to an increase of $21.9 million in the three months ended March 31, 2016, as a result of timing of collection from our customers; and (ii) an increase in accounts payable and accrued expenses of $0.7 million in the three months ended March 31, 2017, compared to a decrease of $4.8 million in the three months ended March 31, 2016, as a result of timing in payments of our payables. The increase was partially offset by a decrease in billing in excess of costs and estimated earnings on uncompleted contracts, net of $18.4 million in our Product segment in the three months ended March 31, 2017, compared to $7.8 million in the three months ended March 31, 2016, as a result of timing in billing of our customers.

Net cash used in investing activities for the three months ended March 31, 2017 was $128.7 million, compared to $44.6 million for the three months ended March 31, 2016. The principal factors that affected our net cash used in investing activities during the three months ended March 31, 2017 were: (i) capital expenditures of $52.9 million, primarily for our facilities under construction; (ii) $35.3 million net cash paid for the acquisition of substantially all of the business and assets of VEI; (iii) a net increase of $25.6 million in restricted cash and cash equivalents due to the timing of debt repayments; and (iv) an investment in an unconsolidated company of $14.9 million. The principal factors that affected our net cash used in investing activities during the three months ended March 31, 2016 were capital expenditures of $31.0 million, primarily for our facilities under construction and a net increase of $14.6 million in restricted cash and cash equivalents, due to the timing of debt repayments.

Net cash provided by financing activities for the three months ended March 31, 2017 was $1.2 million, compared to $19.8 million of net cash used in financing activities for the three months ended March 31, 2016. The principal factors that affected the net cash used in financing activities during the three months ended March 31, 2017 were: (i) the repayment of long-term debt in the amount of $13.4 million; (ii) an $8.4 million cash dividend paid; (iii) $6.8 million cash paid to non-controlling interests; and (iv) a net increase of $30.0 million against our revolving lines of credit with commercial banks. The principal factors that affected our net cash used in financing activities during the three months ended March 31, 2016 were: (i) the repayment of long-term debt in the amount of $11.6 million; (ii) a $15.5 million cash dividend paid; and (iii) $6.3 million cash paid to non-controlling interest, reduced by a net increase of $9.0 million against our revolving lines of credit with commercial banks.

EBITDA and Adjusted EBITDA

We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate Adjusted EBITDA as net income before interest, taxes, depreciation and amortization, adjusted for (i) termination fees, (ii) impairment of long-lived assets, (iii) write-off of unsuccessful exploration activities, (iv) any mark-to-market gains or losses from accounting for derivatives, (v) merger and acquisition transaction costs (vi) stock-based compensation, (vii) gains or losses from extinguishment of liability, and (viii) gains or losses on sales of subsidiaries and property, plant and equipment. EBITDA and Adjusted EBITDA are not measurements of financial performance or liquidity under accounting principles generally accepted in the United States of America (“U.S. GAAP”) and should not be considered as an alternative to cash flow from operating activities or as a measure of liquidity or an alternative to net earnings as indicators of our operating performance or any other measures of performance derived in accordance with U.S. GAAP. EBITDA and Adjusted EBITDA are presented because we believe they are frequently used by securities analysts, investors and other interested parties in the evaluation of a company’s ability to service and/or incur debt. However, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than we do.

Adjusted EBITDA for the three months ended March 31, 2017 was $91.8 million, compared to $80.2 million for the three months ended March 31, 2016.

The following table reconciles net cash provided by operating activities to EBITDA and Adjusted EBITDA for the three-month periods ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017			2016


Net cash provided by operating activities	$	71,463		$	27,044
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		13,405			14,127
Interest income		(244	)		(320	)
Income tax provision		10,886			9,509
Minority interest in earnings of subsidiaries		-			-
Adjustments to reconcile net income to net cash provided by operating activities (excluding depreciation and amortization)		(4,669	)		30,082

EBITDA		90,841			80,442
Mark-to-market gains or losses from accounting for derivatives		(1,523	)		(1,746	)
Stock-based compensation		1,713			842
Gain on sale of subsidiary and property, plant and equipment		-			-
Termination fee		-			-
Impairment of long-lived assets		-			-
Loss from extinguishment of liability		-
Merger and aquisition transaction costs		800			147
Settlement expenses		-			-
Write-off of unsuccessful exploration activities		-			557

Adjusted EBITDA	$	91,831		$	80,242
Net cash used in investing activities	$	(128,738	)	$	(44,620	)

Net cash provided by (used in) financing activities	$	1,199		$	(19,845	)

The following table reconciles Net income to EBITDA for the three-month periods ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017			2016


Net income	$	39,735		$	30,945
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		13,405			14,127
Interest income		(244	)		(320	)
Income tax provision		10,886			9,509
Depreciation and amortization		27,059			26,181
EBITDA	$	90,841		$	80,442

Capital Expenditures

Our capital expenditures primarily relate to: (i) the development and construction of new power plants, (ii) the enhancement of our existing power plants; and (iii) investment in activities under our new strategic plan .

The following is an overview of projects that are fully released for construction:

Sarulla (Indonesia). The project is being constructed in three phases of approximately 110 MW each, utilizing both steam and brine extracted from the geothermal field to increase the power plant’s efficiency. The first phase of the power plant commenced commercial operation on March 17, 2017. For the second phase of the power plant, engineering and procurement has been substantially completed, site construction is in progress and all of the major generating units, including those to be supplied by Ormat, were delivered. For the third phase of the power plant, engineering, procurement and construction work at the site are in progress and manufacturing of equipment to be supplied by Ormat is underway as planned. Ormat sent the first shipment of equipment to be manufactured by Ormat during the first quarter of 2017. Drilling for the second and third phases of the power plant is ongoing and the project has achieved to date, based on preliminary estimates, 100% of the required injection capacity and approximately 65% of the required production capacity. The project has missed a few milestones under the loan documents, but has received waivers from the lenders and is currently in compliance with the lenders’ requirements. The project experienced delays in field development and cost overruns resulting from delays and excess drilling costs. Due to the cost overruns in drilling, the lenders requested that the sponsors commit to provide additional equity. The sponsors have agreed and the project’s financing documents were revised to reflect this request. Ormat, in its capacity as a supplier of equipment to the project, has achieved all contractual milestones under the supply agreement.

The Sarulla project will be owned and operated by the consortium members under the framework of a Joint Operating Contract (“JOC”) and Energy Sales Contract (“ESC’). Under the JOC, PT Pertamina Geothermal Energy (“PGE”), the concession holder for the project, has provided the consortium with the right to use the geothermal field, and under the ESC, PT PLN, the state electric utility, will be the off-taker at Sarulla for a period of 30 years.

Ormat holds a 12.75% equity interest in the project, corresponding to a commitment to invest approximately $60 million of equity based on the current project plan.

Heber 1 Power Plant (California). We are currently in the process of enhancing the Heber 1 power plant of the Heber complex located in Imperial Valley, California. We are planning to convert artesian wells to pumped wells, add a new water cooling unit and replace one of the Ormat Energy Converters (“OECs”), following which we expect the capacity of the complex to reach 92 MW. Engineering and procurement is ongoing and completion of the enhancement is expected at the end of 2017. In December 2015, we started to sell power generated by the Heber 1 power plant under a new fixed price PPA with SCPPA.

Platanares Project (Honduras). We are currently developing the Geotermica Platanares geothermal project in Honduras. Construction and drilling activities are ongoing and certain of the equipment is already on site. In December 2015, we concluded the drilling activity as well as extensive testing that support the decision to construct a 35 MW project, which is larger than initially estimated. We hold the assets, including the project’s wells, land, permits and PPA, under a Build, Operate, Transfer (“BOT”) structure for 15 years from the date of commercial operation. Commercial operation is expected before the end of 2017.

Tungsten Mountain (Nevada). We are currently developing the 24 MW Tungsten Mountain geothermal power plant in Churchill County, Nevada. Field development has been completed, while site construction is ongoing. We have also secured the interconnection agreement . The project is expected to be on-line by the end of 2017.

Olkaria III Plant 1 Repowering (Kenya). We are currently repowering plant 1 of the 139MW Olkaria complex in Kenya. We plan to add additional OEC unit to the existing power plant that will add approximately 10MW to the complex. The generated electricity from the new unit will be sold under Plant 1 PPA.

Brady Power Plant (Nevada). We are currently in the process of enhancing the Brady power plant located in Churchill County, Nevada. We are planning to replace its equipment with new OECs, following which we expect the capacity of the complex to increase to approximately 12 MW. Engineering and manufacturing is ongoing and construction has started. We expect the enhancement to be completed during 2018.

Rabitt Hill (Texas). We are currently jointly developing the Rabitt Hill energy storage project located in Georgetown, Texas with Alevo Group SA. (“Alevo”). We will own and fund the majority of the costs associated with the 10 MW Rabbit Hill energy storage project and, under the terms of the agreement, will provide engineering and construction services and balance of plant equipment. Alevo will provide its innovative GridBank™ inorganic lithium ion energy storage system in conjunction with the power conversion systems. The project will consist of three GridBank™ enclosures and will provide FRRS as an open market participant in the ERCOT, an independent system operator that manages the flow of electric power to Texas customers. Construction of the project is ongoing. Progress and completion is pending the supply of batteries by Alevo.

The following is an overview of projects that are in initial stages of construction:

Dixie Meadows (Nevada). We are currently developing the 15-20 MW Dixie Meadows geothermal power plant in Churchill County, Nevada. Drilling is ongoing. The project is expected to be on-line by the end of 2018.

Carson Lake Project. We plan to develop the 20 MW Carson Lake project on Bureau of Land Management (BLM) leases located in Churchill County, Nevada. We drilled one well in 2016 that did not meet our commercial criteria. However, this well provided us with more data on the resource. We are currently evaluating the next development steps for the project.

CD 4 Project. We plan to develop 30 MW of new capacity at the Mammoth complex on land which is comprised mainly of BLM leases. We have commenced field development and drilled one production well and one injection well. Continued drilling is subject to receipt of additional permits. As part of the process to secure a transmission line, we are participating in the Southern California Edison Wholesale Distribution Access Tariff Transition Cluster Generator Interconnection Process (the “WDAT LGIA”) to deliver energy into the Southern California Edison system at the Casa Diablo Substation. Southern California Edison completed phase I and phase II cluster studies and the WDAT LGIA is being reviewed while re-evaluation of the system upgrades is being completed due to changes in the participants in the cluster study. We are not planning to make material capital expenditures on this project in 2017.

We have estimated approximately $418.0 million in capital expenditures for construction of new projects and enhancements to our existing power plants, of which we have invested approximately $187.0 million as of March 31, 2017. We expect to invest approximately $125.0 million of such total during the remainder of 2017 and the remaining approximately $106.0 million thereafter.

In addition, we estimate approximately $72.0 million in additional capital expenditures in the remainder of 2017 to be allocated as follows: (i) $25.0 million for development of new projects; (ii) $30.0 million for maintenance capital expenditures to our operating power plants; (iii) $14.0 million for continued exploration activity under various leases for geothermal resources where we have already started exploration activity; and (iv) $3.0 million for enhancements to our production facilities. In the aggregate, we estimate our total capital expenditures for the remainder of 2017 will be approximately $197.0 million.

Exposure to Market Risks

Based on current conditions, we believe that we have sufficient financial resources to fund our activities and execute our business plans. However, the cost of obtaining financing for our project needs may increase significantly or such financing may be difficult to obtain.

We, like other power plant operators, are exposed to electricity price volatility risk. Our exposure to such market risk is currently limited because many of oulong-term PPAs (except for the 25 MW PPA for the Puna complex and the aggregate 90 MW PPAs for the Heber 2 power plant in the Heber complex, the Ormesa complex and the G2 power plant in the Mammoth complex) have fixed or escalating rate provisions that limit our exposure to changes in electricity prices.

The energy payments under the PPAs of the Heber 2 power plant in the Heber complex, the Ormesa complex and the G2 power plant in Mammoth complex are determined by reference to the relevant power purchaser’s short run avoided costs, or SRAC. A decline in the price of natural gas or an increase in the amount of renewable power sold to relevant power purchaser or competitive market will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from natural gas, or by reducing the price of purchasing its electrical energy needs from natural gas power plants, which in turn will reduce the energy rates that we may charge under the relevant PPA for these power plants. In March 2014, May 2015 and February 2016, we entered into derivative transactions to reduce our exposure to the price of natural gas under these PPAs, until December 29, 2016. The Puna complex is currently benefiting from energy prices which are higher than the floor under the 25 MW PPA for the Puna complex as a result of the high fuel costs that impact HELCO’s avoided costs.

As of March 31, 2017, 91.9% of our consolidated long-term debt was fixed rate debt and therefore was not subject to interest rate volatility risk. As of such date, 8.1% of our long-term debt was floating rate debt, exposing us to interest rate risk in connection therewith. As of March 31, 2017, $79.0 million of our long-term debt remained subject to some interest rate risk.

We currently maintain our surplus cash in short-term, interest-bearing bank deposits, money market securities and commercial paper (with a minimum investment grade rating of AA by Standard & Poor’s Ratings Services.)

Our cash equivalents are subject to interest rate risk. Fixed rate securities may have their market value adversely impacted by a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. As a result of these factors, our future investment income may fall short of expectations because of changes in interest rates or we may suffer losses in principal if we are forced to sell securities that decline in market value because of changes in interest rates.

We are also exposed to foreign currency exchange risk, in particular the fluctuation of the U.S. dollar versus the NIS and Euro. Risks attributable to fluctuations in currency exchange rates can arise when we or any of our foreign subsidiaries borrow funds or incur operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary, or increase such subsidiary’s overall expenses. Risks attributable to fluctuations in foreign currency exchange rates can also arise when the currency denomination of a particular contract is not the U.S. dollar. Substantially all of our PPAs in the international markets are either U.S. dollar-denominated or linked to the U.S. dollar except for our operation in the Island of Guadeloupe , where we own and operate the Boulliante power plant which sells its power under a Euro-denominated PPA with Électricité de France S.A. ("EDF") . Our construction contracts from time to time contemplate costs which are incurred in local currencies. The way we often mitigate such risk is to receive part of the proceeds from the contract in the currency in which the expenses are incurred. Currently, we have forward contracts in place to reduce our foreign currency exposure, and expect to continue to use currency exchange and other derivative instruments to the extent we deem such instruments to be the appropriate tool for managing such exposure. We do not believe that our exchange rate exposure has or will have a material adverse effect on our financial condition, results of operations or cash flows.

We performed a sensitivity analysis on the fair values of our put options on natural gas prices, long-term debt obligations, and foreign currency exchange forward contracts. The put options on natural gas prices and foreign currency exchange forward contracts listed below principally relate to trading activities. The sensitivity analysis involved increasing and decreasing forward rates at March 31, 2017 and December 31, 2016 by a hypothetical 10% and calculating the resulting change in the fair values.

At this time, the development of our new strategic plan has not exposed us to any additional market risk. However, as the implementation of the plan progresses, we may be exposed to additional or different market risks.

The results of the sensitivity analysis calculations as of March 31, 2017 and December 31, 2016 are presented below:

	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
Risk	March 31, 2017			December 31, 2016			March 31, 2017			December 31, 2016			Change in the Fair Value of
	(Dollars in thousands)
Put options on natural gas price	$	(158	)	$	-		$	344		$	-		NGI futures
Foreign Currency		(4,419	)		(4,665	)		5,402			4,632		Foreign currency forward contracts
Interest Rate		(270	)		(254	)		257			260		Ormat Funding Corp. (“OFC”)
Interest Rate		(256	)		(281	)		259			284		Orcal Geothermal Inc. (“OrCal”)
Interest Rate		(6,973	)		(7,714	)		7,281			7,496		OFC 2 LLC (“OFC 2”)
Interest Rate		(65	)		(64	)		65			65		Loan from DEG
Interest Rate		(7,417	)		(7,667	)		7,770			8,039		Loan from OPIC
Interest Rate		(4,134	)		(4,351	)		4,223			4,472		Senior unsecured bonds
Interest Rate		(1,521	)		(1,568	)		1,589			1,639		New DEG (“DEG 2”) loan
Interest Rate		(2,684	)		(2,749	)		2,820			2,890		Don A. Campble (“DAC I”) Senior Secured Notes
Interest Rate		-	⁽¹⁾		-	⁽¹⁾		-	⁽¹⁾		-	⁽¹⁾	Amatitlan Loan
Interest Rate		(161	)		(161	)		167			167		Other long-term loans

(1)

The application of a 10% increase and decrease to the interest rate, did not exceed the minimum rate as set in the loan agreement.

Effect of Inflation

We do not expect that inflation will be a significant risk in the near term, given the current global economic conditions, however, that could change in the future. To address rising inflation, some of our contracts include certain provisions that mitigate inflation risk.

In connection with the Electricity segment, inflation may directly impact an expense we incur for the operation of our projects, thereby increasing our overall operating costs. The negative impact of inflation may be partially offset by price adjustments built into some of our PPAs that could be triggered upon such occurrences. The energy payments pursuant to the PPAs for the Brady power plant, the Steamboat 2 and 3 power plants, the Steamboat Hills power plant, and the Burdette power plant increase every year through the end of the relevant terms of such agreements, though such increases are not directly linked to the CPI or any other inflationary index. Lease payments are generally fixed, while royalty payments are generally calculated as a percentage of revenues and therefore are not significantly impacted by inflation. In our Product segment, inflation may directly impact fixed and variable costs incurred in the construction of our power plants, thereby increasing our operating costs in the Product segment. We are more likely to be able to offset all or part of this inflationary impact through our project pricing. With respect to power plants that we build for our own electricity production, inflationary pricing may impact our operating costs which may be partially offset in the pricing of the new long-term PPAs that we negotiate.

Concentration of Credit Risk

Our credit risk is currently concentrated with the following major customers: Southern California Public Power Authority, KPLC, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy). If any of these electric utilities fails to make payments under its PPAs with us, such failure would have a material adverse impact on our financial condition. Also, by implementing our new multi-year strategic plan we may be exposed, by expanding our customer base, to different credit profile customers than our current customers.

Sierra Pacific Power Company and Nevada Power Company accounted for 18.8% and 23.2% of our total revenues for the three months ended March 31, 2017 and 2016, respectively.

Southern California Public Power Authority accounted for 9.0% and 12.1% of our total revenues for the three months ended March 31, 2017 and 2016, respectively.

KPLC accounted for 14.3% and 17.4% of our total revenues for the three months ended March 31, 2017 and 2016, respectively.

Hyundai (Sarulla geothermal power project) accounted for 6% and 9% of the Company’s total revenues for the three months ended March 31, 2017 and 2016, respectively.

Government Grants and Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies. If we started construction of a new geothermal power plant in the U.S. by December 31, 2016, we are permitted to claim a tax credit against our U.S. federal income taxes equal to 30% of certain eligible costs when the project is placed in service. If we fail to meet the start of construction deadline for such a project, then the 30% credit is reduced to 10%. In lieu of the 30% tax credit (if the project qualifies), we are permitted to claim a tax credit based on the power produced from a geothermal power plant. These production-based credits, which in 2015 were 2.3 cents per kWh, are adjusted annually for inflation and may be claimed for ten years on the electricity produced by the project and sold to third parties after the project is placed in service. The owner of the power plant may not claim both the 30% tax credit and the production-based tax credit. Under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward. If we claim the ITC, our “tax basis” in the plant that we can recover through depreciation must be reduced by half of the ITC. If we claim the PTC, there is no reduction in the tax basis for depreciation. New solar projects that are under construction by December 2019 will qualify for a 30% investment tax credit. The credit will fall to 26% for projects starting construction in 2020 and 22% for projects starting construction in 2021. Projects that are under construction before these deadlines must be placed in service by December 2023 to qualify. The investment credit will revert to its permanent 10% level after that.

We are also permitted to depreciate, or write off, most of the cost of the plant. In those cases where we claimed the one-time 30% (or 10%) tax credit or received the Treasury cash grant, our tax basis in the plant that we can recover through depreciation is reduced by one-half of the tax credit or cash grant; if in the future we claim other tax credits, there is no reduction in the tax basis for depreciation. For projects that are placed into service after December 31, 2011 and before January 1, 2017, a depreciation “bonus” will permit us to write off 50% of the cost of that equipment in the year the power plant is placed into service. New equipment put in service in 2018 would qualify for a 40% bonus. Equipment put in service in 2019 would qualify for a 30% bonus. After applying any depreciation bonus that is available, we can write off the remainder of our tax basis in the plant, if any, over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period.

Ormat Systems received “Benefited Enterprise” status under Israel’s Law for Encouragement of Capital Investments, 1959 (the Investment Law), with respect to two of its investment programs through 2011. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax will apply to all qualified income of certain industrial companies, as opposed to the previous law’s incentives that are limited to income from a “Benefited Enterprise” during their benefits period. As a result, we now pay a uniform corporate tax rate of 16% with respect to that qualified income.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information appearing under the headings “Exposure to Market Risks” and “Concentration of Credit Risk” in Part I, Item 2 of this quarterly report on Form 10-Q is hereby incorporated by reference.

ITEM 4. CONTROLS AND PROCEDURES

a. Evaluation of disclosure controls and procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures to ensure that the information required to be disclosed in our filings pursuant to Rule 13a-15 under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, as of March 31, 2017, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective.

b. Changes in internal controls over financial reporting

There were no changes in our internal controls over financial reporting in the first quarter of 2017 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

There were no material developments in any legal proceedings to which the Company is a party during the first quarter of 2017, other than as described below.

●

Jon Olson and Hilary Wilt, together with Puna Pono Alliance filed a complaint on February 17, 2015 in the Third Circuit Court for the State of Hawaii, requesting declaratory and injunctive relief requiring that PGV comply with an ordinance that the plaintiffs allege will prohibit PGV from engaging in night drilling operations at its KS-16 well site. On May 17, 2015, the original complaint was amended to add the county of Hawaii and the State of Hawaii Department of Land and Natural Resources as defendants to the case. On October 10, 2016, the court issued its decision in response to each of the plaintiffs’ and defendants’ motions for summary judgment, denying plaintiffs’ motion and granting defendant PGV's and the County of Hawaii’s cross motions for summary judgment, effectively rendering the plaintiffs’ action moot. On January 23, 2017, the plaintiffs filed a motion requesting that the Intermediate Court of Appeals to address appellate jurisdiction, which was denied by the court on April 20, 2017 as premature. The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

●

On July 8, 2014, Global Community Monitor, LiUNA, and two residents of Bishop, California filed a complaint in the U.S. District Court for the Eastern District of California, alleging that Mammoth Pacific, L.P., the Company and Ormat Nevada are operating three geothermal generating plants in Mammoth Lakes, California (MP-1, MP-II and PLES-I) in violation of the federal Clean Air Act and Great Basin Unified Air Pollution Control District rules. On June 26, 2015, in response to a motion by the defendants, the court dismissed all but one of the plaintiffs’ causes of action. On January 6, 2017, the court issued its order regarding several pending motions, including plaintiffs’ motion for partial summary judgment, defendants' motion for summary judgment, defendants' motion to exclude and defendants' motion for leave to file a sur-reply. The impact of the court’s January 6 order is to deny the plaintiffs’ sole remaining cause of action. No appeal by the plaintiffs is expected and the company considers this case to be effectively closed.

●

On March 29, 2016, a former local sales representative in Chile, Aquavant, S.A., filed a claim against Ormat’s subsidiaries in the 27th Civil Court of Satiago, Chile on the basis of unjust enrichment. The claim requests that the court order Ormat to pay Aquavant $4.6 million in connection with its activities in Chile, including the EPC contract for the Cerro Pabellon project and various geothermal concessions, plus 3.75% of Ormat geothermal products sales in Chile over the next 10 years. Pursuant to various petitions submitted the defendants, including a motion describing preliminary procedural defenses, on August 18, 2016, and then on October 10, 2016, the 27th Civil Court issued a number of decisions, which include removal of the case to the 11th Civil Court of Santiago, thereby delaying a determination on the larger issues of jurisdiction and competency of the Chilean courts as a substantive (and not procedural) defense. The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

●

On August 5, 2016, George Douvris, Stephanie Douvris, Michael Hale, Cheryl Cacocci, Hillary E. Wilt and Christina Bryan, acting for themselves and on behalf of all other similarly situated residents of the lower Puna District, filed a complaint in the Third Circuit Court for the State of Hawaii seeking certification of a class action for preliminary and permanent injunctive relief, consequential and punitive damages, attorney’s fees and statutory interest against PGV and other presently unknown defendants. On December 12, 2016, the federal district court granted plaintiffs’ motion for joinder of HELCO as a co-defendant, and the case, which had previously been removed to the U.S. District Court for the District of Hawaii, was remanded back to the Third Circuit Court. The amended complaint alleged that injuries and other damages in an undisclosed amount were caused to the plaintiffs as a result of an alleged toxic release by PGV in the wake of Hurricane Iselle in August 2014. On March 25, 2017, HELCO filed a motion to dismiss the first amended complaint in the Third Circuit Court, on several grounds. Following briefing and oral arguments, the HELCO motion to dismiss is under consideration by the court. The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

●

On June 20, 2016, Nadia Garcia, individually and as successor in interest to Thomas Garcia Valenzuela, and as guardian ad litem to Emerie Garcia, Khamilla Garcia and Reyene Adam, filed a complaint against Ormat Technologies, Ormat Nevada and Ormesa LLC in the Superior Court of Imperial County seeking unspecified monetary damages. The complaint alleges that the Ormat defendants caused the wrongful death, personal injury and other harm to Thomas Garcia when he was employed by Martin Hydroblasting Services, Inc. and suffered injuries leading to his death while performing work at the Ormesa plant site on or around March 31, 2016. At the end of April 2017, an out of court settlement was agreed between the plaintiffs and the deceased's employer’s insurer, which is being presented to the court for its approval.

ITEM 1A. RISK FACTORS

A comprehensive discussion of our other risk factors is included in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2016 which was filed with the SEC on March 1, 2017.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable

ITEM 5. OTHER INFORMATION

Not applicable.

ITEM 6. EXHIBITS

We hereby file, as exhibits to this quarterly report, those exhibits listed on the Exhibit Index immediately following the signature page hereto.

SIGNATURES

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.

	ORMAT TECHNOLOGIES, INC.

	By:	/s/ Doron Blachar
		Name: Doron Blachar
		Title: Chief Financial Officer

Date: May 9, 2017

EXHIBIT INDEX

Exhibit No.	Document

3.1	Second Amended and Restated Certificate of Incorporation, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 20, 2004.

3.2	Fourth Amended and Restated By-laws, incorporated by reference to Exhibit 3.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on January 2, 2013.

3.3	Amended and Restated Limited Liability Company Agreement of OPC LLC dated June 7, 2007, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC, and Lehman-OPC LLC, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on June 13, 2007.

3.4	Limited Liability Company Agreement of ORTP, LLC dated as of January 24, 2013, between Ormat Nevada, Inc., a wholly-owned subsidiary of Ormat Technologies, Inc., and JPM Capital Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on January 30, 2013.

3.5	Amended and Restated Limited Liability Company Agreement of ORPD LLC, dated as of April 30, 2015, by and among Ormat Nevada Inc., Northleaf Geothermal Holdings LLC and ORPD Holdings LLC, incorporated by reference to Exhibit 3.5 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 filed with the Securities and Exchange Commission on May 7, 2015.

4.1	Form of Common Share Stock Certificate, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 20, 2004.

4.2	Form of Preferred Share Stock Certificate, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 20, 2004.

4.3	Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust Company, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on October 22, 2004.

4.4	Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) filed with the Securities and Exchange Commission on January 26, 2006.

4.5	Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) filed with the Securities and Exchange Commission on January 26, 2006.

4.6	Deed of Trust, dated as of August 3, 2010, between Ormat Technologies, Inc. and Mishmeret Trust Company Limited (Formerly Ziv Haft Trust Company Ltd.), as trustee, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 2, 2011.

4.7	Addendum, dated as of January 27, 2011, to the Deed of Trust, dated as of August 3, 2010, between Ormat Technologies, Inc. and Mishmeret — Trusts Services Company Ltd (Formerly Ziv Haft Trust Company Ltd.), as trustee, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.

4.8	Form of Bond issued pursuant to the Deed of Trust, dated as of August 3, 2010 (as amended or supplemented), between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 2, 2011.

4.9	Second Addendum, dated as of February 11, 2011, to the Deed of Trust, dated as of August 3, 2010 (as amended or supplemented), between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.7 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 6, 2011.

4.10	Indenture of Trust and Security Agreement, dated September 23, 2011, among OFC 2 LLC, ORNI 15 LLC, ORNI 39 LLC, ORNI 42 LLC, HSS II, LLC, and Wilmington Trust Company, as Trustee and Depository, incorporated by reference to Exhibit 4.8 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 4, 2011..

4.11	Third Addendum, dated as of December 1, 2011, to a Deed of Trust, dated as of August 3, 2010 as amended on January 31, 2011 (effective as of January 27, 2011) and on February 13, 2011, between Ormat Technologies, Inc. and Mishmeret — Trusts Services Company Ltd. (formerly Ziv Haft Trust Company Ltd.), as trustee, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on December 1, 2011.

31.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

31.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, furnished herewith.

32.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, furnished herewith.

101.IN*	XBRL Instance Document.
101.SC*	XBRL Taxonomy Extension Schema Document.
101.CA*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DE*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LA*	XBRL Taxonomy Extension Label Linkbase Document.
101.PR*	XBRL Taxonomy Extension Presentation Linkbase Document.

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