ORMAT TECHNOLOGIES, INC. - Quarter Report: 2014 March (Form 10-Q)

ora20140331_10q.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, 2014

	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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer☐	Accelerated filer ☑	Non-accelerated filer ☐	Smaller reporting company ☐
		(Do not check if a smaller reporting company)

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

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, 2014, the number of outstanding shares of common stock, par value $0.001 per share, was 45,478,717.

ORMAT TECHNOLOGIES, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2014

PART I — FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS	1

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	24

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	50

ITEM 4.	CONTROLS AND PROCEDURES	50

PART II — OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	51

ITEM 1A.	RISK FACTORS	51

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	51

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	51

ITEM 4.	MINE SAFETY DISCLOSURES	51

ITEM 5.	OTHER INFORMATION	51

ITEM 6.	EXHIBITS	51

SIGNATURES		52

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.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,		December 31,
	2014		2013
	(Dollars in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	47,927	$	57,354
Restricted cash and cash equivalents (all related to variable interest entities ("VIEs"))		74,406		51,065
Receivables:
Trade		55,676		95,365
Related entity		442		442
Other		28,756		11,049
Due from Parent		534		382
Inventories		22,671		22,289
Costs and estimated earnings in excess of billings on uncompleted contracts		27,789		21,217
Deferred income taxes		684		523
Prepaid expenses and other		33,728		29,654

Total current assets		292,613		289,340
Unconsolidated investments		7,510		7,076
Deposits and other		24,743		22,114
Deferred income taxes		—		891
Deferred charges		35,881		36,738
Property, plant and equipment, net ($1,394,424 and $1,381,083 related to VIEs, respectively)		1,463,574		1,452,336
Construction-in-process ($54,535 and $136,947 related to VIEs, respectively)		249,777		288,827
Deferred financing and lease costs, net		29,127		30,178
Intangible assets, net		31,122		31,933
Total assets	$	2,134,347	$	2,159,433
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	93,820	$	98,047
Short-term revolving credit lines with banks (full recourse)		34,733		—
Billings in excess of costs and estimated earnings on uncompleted contracts		3,817		7,903
Current portion of long-term debt:
Limited and non-recourse (all related to VIEs):
Senior secured notes		29,337		31,137
Other loans		21,127		20,377
Full recourse:		28,994		28,875

Total current liabilities		211,828		186,339
Long-term debt, net of current portion:
Limited and non-recourse (all related to VIEs):
Senior secured notes		256,366		270,310
Other loans		305,762		311,078
Full recourse:
Senior unsecured bonds (plus unamortized premium based upon 7% of $1,051)		250,520		250,596
Other loans		49,887		53,467
Revolving credit lines with banks		62,467		112,017
Liability associated with sale of tax benefits		56,090		60,985
Deferred lease income		62,762		63,496
Deferred income taxes		59,322		55,035
Liability for unrecognized tax benefits		5,132		4,950
Liabilities for severance pay		24,182		23,841
Asset retirement obligation		19,053		18,679
Other long-term liabilities		5,282		3,529
Total liabilities		1,368,653		1,414,322

Commitments and contingencies (Note 10)

Equity:
The Company's stockholders' equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 45,478,717 and 45,460,653 shares issued and outstanding as of March 31, 2014 and December 31, 2013, respectively		46		46
Additional paid-in capital		736,735		735,295
Retained earnings (accumulated deficit)		15,737		(3,088	)
Accumulated other comprehensive income		451		487

		752,969		732,740
Noncontrolling interest		12,725		12,371

Total equity		765,694		745,111

Total liabilities and equity	$	2,134,347	$	2,159,433

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended March 31,
	2014			2013 As revised
	(Dollars in thousands, except per share data)
Revenues:
Electricity	$	94,817		$	68,298
Product		47,619			50,608
Total revenues		142,436			118,906
Cost of revenues:
Electricity		57,034			55,088
Product		31,943			37,041
Total cost of revenues		88,977			92,129
Gross margin		53,459			26,777
Operating expenses:
Research and development expenses, net		(87	)		1,000
Selling and marketing expenses		3,379			11,509
General and administrative expenses		7,596			6,584
Operating income		42,571			7,684
Other income (expense):
Interest income		111			41
Interest expense, net		(20,518	)		(15,863	)
Foreign currency translation and transaction gains (losses)		(638	)		1,682
Income attributable to sale of tax benefits		6,717			3,532
Other non-operating income, net		63			1,417
Income (loss) before income taxes and equity in losses of investees		28,306			(1,507	)
Income tax provision		(6,320	)		(4,047	)
Equity in losses of investees		(197	)		—
Income (loss) from continuing operations		21,789			(5,554	)
Discontinued operations:
Income from discontinued operations		—			827
Income tax provision		—			(222	)
Total income from discontinued operations		—			605

Net income (loss)		21,789			(4,949	)
Net income attributable to noncontrolling interest		(237	)		(85	)
Net income (loss) attributable to the Company's stockholders	$	21,552		$	(5,034	)
Comprehensive income (loss):
Net income (loss)		21,789			(4,949	)
Other comprehensive income (loss), net of related taxes:
Amortization of gains in respect of derivative instruments designated for cash flow hedge		(36	)		(42	)
Comprehensive income (loss)		21,753			(4,991	)
Comprehensive income attributable to noncontrolling interest		(237	)		(85	)
Comprehensive income (loss) attributable to the Company's stockholders	$	21,516		$	(5,076	)

Earnings (loss) per share attributable to the Company's stockholders - basic and diluted:
Income (loss) from continuing operations:	$	0.47		$	(0.12	)
Discontinued operations:		—			0.01
Net income (loss):	$	0.47		$	(0.11	)

Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company's stockholders:
Basic		45,479			45,431
Diluted		45,660			45,431

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

	The Company's Stockholders' Equity
							Retained			Accumulated
					Additional		Earnings			Other
	Common Stock				Paid-in		(Accumulated			Comprehensive						Noncontrolling			Total
	Shares		Amount		Capital		Deficit)			Income			Total			Interest			Equity
	(Dollars in thousands, except per share data)
Balance at December 31, 2012, as revised		45,431	$	46	$	732,140	$	(44,326	)	$	651		$	688,511		$	7,096		$	695,607
Stock-based compensation		—		—		1,543		—			—			1,543			—			1,543
Cash paid to noncontrolling interest		—		—		—		—			—			—			(189	)		(189	)
Increase in noncontrolling interest in ORTP LLC		—		—		—		—			—			—			4,906			4,906
Net income (loss)		—		—		—		(5,034	)		—			(5,034	)		85			(4,949	)
Other comprehensive income (loss), net of related taxes:
Amortization of gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $28)		—		—		—		—			(42	)		(42	)		—			(42	)
Balance at March 31, 2013, as revised		45,431	$	46	$	733,683	$	(49,360	)	$	609		$	684,978		$	11,898		$	696,876

Balance at December 31, 2013		45,461	$	46	$	735,295	$	(3,088	)	$	487		$	732,740		$	12,371		$	745,111
Stock-based compensation		—		—		1,440		—			—			1,440			—			1,440
Exercise of options by employees and directors		18		—		—		—			—			—			—			—
Cash paid to noncontrolling interest		—		—		—		—			—			—			(140	)		(140	)
Increase in noncontrolling interest in ORTP LLC		—		—		—		—			—			—			257			257
Cash dividend paid, $0.06 per share		—		—		—		(2,727	)		—			(2,727	)		—			(2,727	)
Net income		—		—		—		21,552			—			21,552			237			21,789
Other comprehensive income (loss), net of related taxes:
Amortization of gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $22)		—		—		—		—			(36	)		(36	)		—			(36	)
Balance at March 31, 2014		45,479	$	46	$	736,735	$	15,737		$	451		$	752,969		$	12,725		$	765,694

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2014			2013 As revised
	(Dollars in thousands)
Cash flows from operating activities:
Net income (loss)	$	21,789		$	(4,949	)
Adjustments to reconcile net income or loss to net cash provided by operating activities:
Depreciation and amortization		23,417			23,137
Amortization of premium from senior unsecured bonds		(77	)		(77	)
Accretion of asset retirement obligation		374			376
Stock-based compensation		1,440			1,543
Amortization of deferred lease income		(671	)		(671	)
Income attributable to sale of tax benefits, net of interest expense		(4,472	)		(1,133	)
Equity in losses of investees		197			—
Mark-to-market of derivative instruments		224			5,760
Gain (loss) on severance pay fund asset		17			(372	)
Deferred income tax provision		5,896			3,720
Liability for unrecognized tax benefits		182			515
Deferred lease revenues		(63	)		(31	)
Other		(181	)		(819	)
Changes in operating assets and liabilities, net of amounts acquired:
Receivables		43,118			10,571
Costs and estimated earnings in excess of billings on uncompleted contracts		(6,572	)		(522	)
Inventories		(382	)		2,411
Prepaid expenses and other		(4,074	)		(144	)
Deposits and other		(1,229	)		(2,981	)
Accounts payable and accrued expenses		(7,725	)		(14,765	)
Due from/to related entities, net		—			(24	)
Billings in excess of costs and estimated earnings on uncompleted contracts		(4,086	)		(3,659	)
Liabilities for severance pay		341			614
Other long-term liabilities		765			(231	)
Due from/to Parent		(152	)		(53	)
Net cash provided by operating activities		68,076			18,216
Cash flows from investing activities:
Return of investment in unconsolidated investments		—			(5	)
Net change in restricted cash and cash equivalents		(23,341	)		(48,350	)
Cash received from sale of property, plant and equipment		15,000			—
Capital expenditures		(48,330	)		(49,561	)
Cash grant received from the U.S. Treasury under Section 1603 of the ARRA		21,811			—
Investment in unconsolidated companies		(631	)		(198	)
Increase (decrease) in severance pay fund asset, net of payments made to retired employees		168			(130	)
Net cash used in investing activities		(35,323	)		(98,244	)
Cash flows from financing activities:
Proceeds from long-term loans		—			45,000
Proceeds from the sale of limited liability company interest in ORTP LLC		—			32,197
Purchase of OFC Senior Secured Notes		(12,860	)		(11,888	)
Proceeds from revolving credit lines with banks		887,583			597,193
Repayment of revolving credit lines with banks		(902,400	)		(582,450	)
Repayments of long-term debt		(10,528	)		(5,195	)
Cash paid to noncontrolling interest		(3,091	)		(3,783	)
Cash received from non-controlling interest		2,234			—
Deferred debt issuance costs		(391	)		(47	)
Cash dividends paid		(2,727	)		—
Net cash provided by (used in) financing activities		(42,180	)		71,027
Net change in cash and cash equivalents		(9,427	)		(9,001	)
Cash and cash equivalents at beginning of period		57,354			66,628
Cash and cash equivalents at end of period	$	47,927		$	57,627
Supplemental non-cash investing and financing activities:
Decrease in accounts payable related to purchases of property, plant and equipment	$	(5,641	)	$	(4,950	)

The accompanying notes are an integral part of these condensed 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, 2014, the consolidated results of operations and comprehensive income (loss) for the three-month periods ended March 31, 2014 and 2013 and the consolidated cash flows for the three-month periods ended March 31, 2014 and 2013.

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, 2014 are not necessarily indicative of the results to be expected for the year ending December 31, 2014.

These condensed 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, 2013. The condensed consolidated balance sheet data as of December 31, 2013 was derived from the audited consolidated financial statements for the year ended December 31, 2013, 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.

Revision of previously issued financial statements

The Company identified an error in the second quarter of 2013 related to the calculation and presentation of income tax provision and the related deferred tax asset for the year ended December 31, 2012 and the three months ended March 31, 2013, which was a direct result of the deferred tax effects of the non-cash asset impairment charge recorded in the fourth quarter of 2012. The Company understated the valuation allowance against the U.S. deferred tax assets by $32.7 million and an additional $3.1 million at December 31, 2012 and March 31, 2013, respectively. As a result, for the year ended December 31, 2012 the Company revised the valuation allowance by $32.7 million, of which $26.1 million was recorded against property, plant and equipment where the Company recognized the deferred tax effects of grants received during 2012 and the remaining $6.6 million was recorded against the income tax provision. For the three months ended March 31, 2013, the Company revised the valuation allowance by an additional $3.1 million which also increased the tax provision for the period by the same amount.

The Company assessed the materiality of this error in accordance with the SEC’s Staff Accounting Bulletin 99 and concluded that the previously issued financial statements were not materially misstated. However, if the entire correction of the error was recorded during the second quarter of fiscal 2013, the impact would be significant to the quarter ended June 30, 2013. In accordance with the SEC’s Staff Accounting Bulletin 108, the Company corrected these errors by revising the affected financial statements previously included in the Company’s 2012 Annual Report on Form 10-K and its Quarterly Report on Form 10-Q for the three months ended March 31, 2013.

This revision had no impact on the Company’s revenues, gross margin, operating income (loss), income (loss) before taxes and equity income (loss) of investees. There was also no impact on the Company’s consolidated net operating, investing or financing cash flows; however, the revisions impacted line items within the balance sheet at December 31, 2012 and March 31, 2013 and cash flows from operating activities for the year ended December 31, 2012 and the three months ended March 31, 2013. The revision impacted the Company income tax benefit (provision), net income (loss) from continuing operations, net income (loss) attributable to the Company’s stockholders, comprehensive income (loss) and earnings (loss) per share (“EPS”) in the consolidated statements of operations and comprehensive income (loss) for the year ended December 31, 2012 and the three months ended March 31, 2013.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The consolidated statement of operations and comprehensive income (loss), consolidated balance sheet, and consolidated statement of cash flows for the year ended December 31, 2012 were revised to correct the errors described above in the Company’s 2013 Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q for the three months ended March 31, 2014.

The effect of the revision on the line items within the Company’s consolidated balance sheet as of December 31, 2012 is as follows:

	As of December 31, 2012
	As reported			Adjustment			As revised
	(Dollars in thousands)
Deferred income taxes	$	53,989		$	(32,706	)	$	21,283
Property, plant and equipment, net		1,226,758			26,115			1,252,873
Total assets		2,094,114			(6,591	)		2,087,523
Accumulated deficit		(37,735	)		(6,591	)		(44,326	)
Total equity		702,189			(6,591	)		695,607
Total liabilities and equity		2,094,114			(6,591	)		2,087,523

The effect of the revision on the line items within the Company’s consolidated statements of operations and comprehensive income (loss) for the year ended December 31, 2012 is as follows:

	Year Ended December 31, 2012
	As reported			Adjustment			As revised
	(Dollars in thousands, except per share data)
Income tax benefit (provision)	$	3,500		$	(6,591	)	$	(3,091	)
Loss from continuing operations		(206,016	)		(6,591	)		(212,607	)

Net loss		(206,016	)		(6,591	)		(212,607	)
Net loss attributable to the Company's stockholders	$	(206,430	)	$	(6,591	)	$	(213,021	)
Comprehensive loss		(205,960	)		(6,591	)		(212,551	)
Comprehensive loss attributable to the Company's stockholders	$	(206,374	)	$	(6,591	)	$	(212,965	)
Loss per share attributable to the Company's stockholders:
Basic and diluted	$	(4.54	)	$	(0.15	)	$	(4.69	)

The effect of the revision on the line items within the Company’s consolidated statements of cash flows for the year ended December 31, 2012 is as follows:

	Year Ended December 31, 2012
	As reported			Adjustment			As revised
	(Dollars in thousands)
Cash flows from operating activities:
Net loss	$	(206,016	)	$	(6,591	)	$	(212,607	)
Deferred income tax provision (benefit)		(11,327	)		6,591			(4,736	)
Net cash provided by operating activities	$	89,471		$	-		$	89,471

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The effect of the revision on the line items within the Company’s consolidated balance sheet as of March 31, 2013 is as follows:

	As of March 31, 2013
	As reported			Adjustment			As revised
	(Dollars in thousands)
Deferred income taxes	$	52,939		$	(35,758	)	$	17,181
Property, plant and equipment, net		1,207,410			26,115			1,233,525
Total assets		2,143,568			(9,643	)		2,133,925
Accumulated deficit		(39,717	)		(9,643	)		(49,360	)
Total equity		706,519			(9,643	)		696,876
Total liabilities and equity		2,143,568			(9,643	)		2,133,925

The effect of the revision on the line items within the Company’s consolidated statements of operations and comprehensive income (loss) for the three months ended March 31, 2013 is as follows:

	Three Months Ended March 31, 2013
	As reported			Adjustment			As revised *
	(Dollars in thousands)
Income tax benefit (provision)	$	(1,217	)	$	(3,052	)	$	(4,269	)
Loss from continuing operations		(1,897	)		(3,052	)		(4,949	)

Net loss		(1,897	)		(3,052	)		(4,949	)
Net loss attributable to the Company's stockholders	$	(1,982	)	$	(3,052	)	$	(5,034	)
Comprehensive loss:
Net loss		(1,897	)		(3,052	)		(4,949	)
Comprehensive loss		(1,939	)		(3,052	)		(4,991	)
Comprehensive loss attributable to the Company's stockholders	$	2,024		$	(3,052	)	$	(5,076	)
Loss per share attributable to the Company's stockholders:
Basic and diluted	$	(0.04	)	$	(0.07	)	$	(0.11	)

* These numbers are revised for the correction of the error but prior to the impact of discontinued operations.

The effect of the revision on the line items within the Company’s consolidated statements of cash flows for the three months ended March 31, 2013 is as follows:

	Three Months Ended March 31, 2013
	As reported			Adjustment			As revised
	(Dollars in thousands)
Cash flows from operating activities:
Net loss	$	(1,897	)	$	(3,052	)	$	(4,949	)
Deferred income tax provision		668			3,052			3,720
Net cash provided by operating activities	$	18,216		$	-		$	18,216

Other comprehensive income

For the three months ended March 31, 2014 and 2013, the Company reclassified $36,000 and $42,000, respectively, from accumulated other comprehensive income, of which $58,000 and $70,000, respectively, were recorded to reduce interest expense and $22,000 and $28,000, respectively, were recorded against the income tax provision, in the condensed consolidated statements of operations and comprehensive income.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Termination fee

On March 15, 2013, the Company finalized the agreement with Southern California Edison Company (“Southern California Edison”), by which the current G1 and G3 Standard Offer #4 power purchase agreements (“PPAs”) were terminated and a termination fee of $9.0 million was recorded in selling and marketing expenses in the quarter ended March 31, 2013. Under the agreement, the Company will continue to sell power from G2, the third plant of the Mammoth complex, under its existing PPA with Southern California Edison, with the term of the contract extended by an additional six years until early 2027.

Solar project sale

On March 26, 2014, the Company signed an agreement with RET Holdings, LLC to sell the Heber Solar project in Imperial County, California for $35.25 million. The Company received the first payment of $15.0 million with the remainder expected to be paid in the second quarter of 2014. Due to certain contingencies in the sale agreement, the Company deferred the pre-tax gain of approximately $7.5 million until resolution of such contingencies (which is expected in the second quarter of 2014).

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, 2014 and December 31, 2013, the Company had deposits totaling $11,476,000 and $13,805,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At March 31, 2014 and December 31, 2013, the Company’s deposits in foreign countries amounted to approximately $49,438,000 and $56,133,000, respectively.

At March 31, 2014 and December 31, 2013, accounts receivable related to operations in foreign countries amounted to approximately $27,075,000 and $32,231,000, respectively. At March 31, 2014 and December 31, 2013, accounts receivable from the Company’s primary customers amounted to approximately 68.3% and 35.0%, respectively, of the Company’s accounts receivable.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 15.3% and 15.5% of the Company’s total revenues for the three months ended March 31, 2014 and 2013, respectively.

Southern California Edison accounted for 12.1% and 11.7% of the Company’s total revenues for the three months ended March 31, 2014 and 2013, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 14.3% and 8.4% of the Company’s total revenues for the three months ended March 31, 2014 and 2013, respectively.

The Company performs ongoing credit evaluations of its customers’ financial condition. The Company has historically been able to collect on all of its receivable balances, and accordingly, no provision for doubtful accounts has been made.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements effective in the three-month period ended March 31, 2014

Reporting Discontinued Operations and Disclosures

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendment, required to be applied prospectively for reporting periods beginning after December 15, 2014, limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have, or will have, a major effect on operations and financial results. The amendment requires expanded disclosures for discontinued operations and also requires additional disclosures regarding disposals of individually significant components that do not qualify as discontinued operations. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. This amendment has no impact on our current disclosures, but will in the future if we dispose of any individually significant components of the Company.

Presentation of Unrecognized Tax Benefits

In July 2013, the FASB clarified the accounting guidance on presentation of the unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The guidance states that an unrecognized tax benefit (or a portion thereof) should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except for certain exceptions specified in the guidance. The exceptions include when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to reduce any income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and not be combined with deferred tax assets. The assessment of whether a deferred tax asset is available is based on the unrecognized tax benefit and deferred tax asset that exist at the reporting date and is to be made assuming the disallowance of the tax position at the reporting date. This accounting update is effective for fiscal periods after December 15, 2013. The provision was applied prospectively to all unrecognized tax benefits that exist on January 1, 2014. The adoption of this guidance did have a material impact on the condensed consolidated financial statements.

NOTE 3 — INVENTORIES

Inventories consist of the following:

	March 31, 2014		December 31, 2013
	(Dollars in thousands)
Raw materials and purchased parts for assembly	$	6,557	$	6,326
Self-manufactured assembly parts and finished products		16,114		15,963
Total	$	22,671	$	22,289

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

NOTE 4 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments, mainly in power plants, consist of the following:

March 31,

2014

December 31,

2013

(Dollars in thousands)

Sarulla

7,510

7,076

The Sarulla Project

The Company (through a subsidiary) is a 12.75% equity stake member of a consortium (the “Sarulla” Consortium”) which is in the process of developing the Sarulla geothermal power project in Indonesia with 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, 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 is expected to supply its Ormat Energy Converters (“OECs”) to the power plant. The supply contract was signed on October 2013.

The consortium has started preliminary testing and development activities at the site and signed an engineering procurement and construction agreement (“EPC”) with an unrelated third party. The project will be constructed in three phases of 110 MW each, utilizing both steam and brine extracted from the geothermal field to increase the power plant’s efficiency.

On March 28, 2014, the consortium signed financing agreements in an aggregate amount of $1.17 billion to finance 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 to obtain construction and term loan under limited-recourse financing package backed by political risk guarantee from JBIC.

Upon financing closing, the consortium is expected to begin full scope of construction with the first phase of operations expected to commence in 2016. The remaining two phases of operations are scheduled to commence within 18 months thereafter. The Company will supply its Ormat Energy Converters to the power plant and will add the $254.0 million supply contract to its product segment backlog once the Notice to Proceed is issued, upon closing of the financing. According to the current project plan we expect to recognize revenue from the project over the course of the next three to four years starting in the third quarter of 2014.

During the first quarter of 2014, the Company made additional investment contributions of $0.6 million to the Sarulla project, consistent with its pro rata share in the consortium.

The Company’s share in the results of operations of the Sarulla project was not significant for each of the periods presented in these condensed consolidated financial statements.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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, 2014 and December 31, 2013 for financial assets and liabilities measured at fair value by level within the fair value hierarchy, as well as carrying value. 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.

	Carrying Value			March 31, 2014
	at March 31,			Fair Value
	2014			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	62,946		$	62,946		$	62,946	$	-		$	-
Derivatives:
Swap transaction on oil price ⁽¹⁾		663			663			-		663			-
Swap transaction on natural gas price ⁽²⁾		223			223			-		223			-
Currency forward contracts ⁽³⁾		1,113			1,113			-		1,113			-
Liabilities:
Current liabilities:
Derivatives:
Swap transaction on natural gas price⁽²⁾		(3,941	)		(3,941	)		-		(3,941	)		-
	$	61,004		$	61,004		$	62,946	$	(1,942	)	$	-

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

	Carrying Value			December 31, 2013
	at December 31,			Fair Value
	2013			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	40,015		$	40,015		$	40,015	$	-		$	-
Derivatives:
Currency forward contracts ⁽³⁾		2,290			2,290			-		2,290			-
Liabilities:
Current liabilities:
Derivatives:
Swap transaction on oil price ⁽¹⁾		(2,490	)		(2,490	)		-		(2,490	)		-
Swap transaction on natural gas price⁽²⁾		(341	)		(341	)		-		(341	)		-
	$	39,474		$	39,474		$	40,015	$	(541	)	$	-

(1)	This amount relates to derivatives which represent swap contracts on oil prices, valued primarily based on observable inputs, including forward and spot prices for related commodity indices, and are included within "prepaid expenses and other" and "accounts payable and accrued expenses" in the condensed consolidated balance sheet with the corresponding gain or loss being recognized within "electricity revenues" in the condensed consolidated statement of operations and comprehensive income (loss).

(2)	This amount relates to derivatives which represent swap contracts on natural gas prices, valued primarily based on observable inputs, including forward and spot prices for related commodity indices, and are included within "prepaid expenses and other" and "accounts payable and accrued expenses" in the condensed consolidated balance sheet with the corresponding gain or loss being recognized within "electricity revenues" in the condensed consolidated statement of operations and comprehensive income (loss).

(3)	This amount relates to derivatives which represent currency forward contracts, valued primarily based on observable inputs, including forward and spot prices for currencies, netted against contracted rates and then multiplied against notational amounts, and are included within "prepaid expenses and other" in the condensed consolidated balance sheet with the corresponding gain or loss being recognized within "foreign currency translation and transaction gains (losses)" in the condensed consolidated statement of operations and comprehensive income (loss).

The amounts set forth in the tables above include investments in debt instruments, money market funds (which are included in cash equivalents) and short-term bank deposits. 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.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table presents the amounts of gain (loss) recognized in the condensed consolidated statements of operations and comprehensive income (loss) 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)	2014			2013
		(Dollars in thousands)

Put options on oil price	Electricity revenues	$	—		$	(927	)
Swap transaction on oil price	Electricity revenues		907			(295	)
Swap transaction on natural gas price	Electricity revenues		(3,276	)		(3,390	)
Currency forward contracts	Foreign currency translation and transaction gains (losses)		(231	)		2,035
		$	(2,600	)	$	(2,577	)

On September 3, 2013, the Company entered into an NGI swap contract with a bank for notional volume of approximately 4.4 million MMbtus for settlement effective January 1, 2014 until December 31, 2014, in order to reduce its exposure to NGI below $4.035 per MMbtu under its PPAs with Southern California Edison. The contract did not have up-front costs. Under the terms of this contract, the Company makes floating rate payments to the bank and receives fixed rate payments from the bank on each settlement date. The swap contract has monthly settlement whereby the difference between the fixed price of $4.035 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (January 1, 2014 to December 1, 2014) is being settled on a cash basis.

On October 16, 2013, the Company entered into an NGI swap contract with a bank for notional volume of approximately 4.2 million MMbtus for settlement effective January 1, 2014 until December 31, 2014, in order to reduce its exposure to NGI below $4.103 per MMbtu under its PPAs with Southern California Edison. The contract did not have any up-front costs. Under the terms of this contract, the Company makes floating rate payments to the bank and receives fixed rate payments from the bank on each settlement date. The swap contract has monthly settlements whereby the difference between the fixed price of $4.103 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (January 1, 2014 to December 1, 2014) is being settled on a cash basis.

On October 16, 2013, the Company entered into a New York Harbor ULSD swap contract with a bank for notional volume of 275,000 BBL effective from January 1, 2014 until December 31, 2014 to reduce the Company’s exposure to fluctuations in the energy rate caused by fluctuations in oil prices under the 25 MW PPA for the Puna complex. The Company entered into this contract because the swap had a high correlation with the avoided costs (which are incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others) that HELCO uses to calculate the energy rate. The contract did not have any up-front costs. Under the term of this contract, the Company will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date ($125.15 per BBL). The swap contract has monthly settlements whereby the difference between the fixed price and the monthly average market price will be settled on a cash basis.

On March 6, 2014, the Company entered into an NGI swap contract with a bank for notional volume of approximately 2.2 million MMbtus for settlement effective January 1, 2015 until March 31, 2015, in order to reduce its exposure to NGI below $4.95 per MMbtu under its PPAs with Southern California Edison. The contract did not have any up-front costs. Under the terms of this contract, the Company will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date. The swap contract has monthly settlements whereby the difference between the fixed price of $4.95 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (January 1, 2015 to March 1, 2015) will be settled on a cash basis.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The foregoing swap transactions have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “electricity revenues” in the condensed consolidated statements of operations and comprehensive income (loss). The Company recognized a net loss from these transactions of $2.4 million and $4.6 million in the three months ended March 31, 2014 and March 31, 2013, respectively.

There were no transfers of assets or liabilities between Level 1 and Level 2 during the three months ended March 31, 2014.

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

	Fair Value				Carrying Amount
	March 31, 2014		December 31, 2013		March 31, 2014		December 31, 2013
	(Dollars in millions)				(Dollars in millions)
Olkaria III Loan - DEG	$	40.7	$	40.3	$	39.5	$	39.5
Olkaria III Loan - OPIC		280.6		279.6		296.1		299.9
Amatitlan Loan		33.7		34.8		30.8		31.5
Senior Secured Notes:
Ormat Funding LLC ("OFC")		74.9		83.5		77.6		90.8
OrCal Geothermal LLC ("OrCal")		67.1		65.8		66.2		66.2
OFC 2 LLC ("OFC 2")		119.1		119.0		141.9		144.4
Senior Unsecured Bonds		265.9		270.6		250.5		250.6
Loans from institutional investors		18.2		20.1		17.7		19.5

The fair value of OFC Senior Secured Notes is determined using observable market prices as these securities are traded. The fair value of 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, 2014:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III Loan - DEG	$	—	$	—	$	40.7	$	40.7
Olkaria III Loan - OPIC		—		—		280.6		280.6
Amatitlan Loan		—		—		33.7		33.7
Senior Secured Notes:
OFC		—		74.9		—		74.9
OrCal		—		—		67.1		67.1
OFC 2		—		—		119.1		119.1
Senior unsecured bonds		—		—		265.9		265.9
Loan from institutional investors		—		—		18.2		18.2
Other long-term debt		—		21.7		—		21.7
Revolving credit lines with banks		—		97.2		—		97.2
Deposits		21.1		—		—		21.1

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table presents the fair value of financial instruments as of December 31, 2013:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III Loan - DEG	$	—	$	—	$	40.3	$	40.3
Olkaria III Loan - OPIC		—		—		279.6		279.6
Amatitlan Loan		—		—		34.8		34.8
Senior Secured Notes:
OFC		—		83.5		—		83.5
OrCal		—		—		65.8		65.8
OFC 2		—		—		119.0		119.0
Senior unsecured bonds		—		—		270.6		270.6
Loan from institutional investors		—		—		20.1		20.1
Other long-term debt		—		23.3		—		23.3
Revolving credit lines with banks		—		112.0		—		112.0
Deposits		21.3		—		—		21.3

NOTE 6 — STOCK-BASED COMPENSATION

The 2004 Incentive Compensation Plan

In 2004, the Company’s Board of Directors adopted the 2004 Incentive Compensation Plan (“2004 Incentive Plan”), which provides 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 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 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 date of grant. The shares of common stock will be issued upon exercise of options or SARs from the Company’s authorized share capital. The 2004 Incentive Plan expired in May 2012 upon adoption of the 2012 Incentive Plan, except as to share based awards outstanding on that date.

The 2012 Incentive Compensation Plan

In May 2012, the Company’s shareholders adopted the 2012 Incentive Compensation Plan (“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 date of grant. The shares of common stock will be issued upon exercise of options or SARs from the Company’s authorized share capital.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The 2012 Incentive Plan empowers the Company's Board of Directors, in its discretion, to amend the 2012 Incentive Plan in certain respects. Consistent with its authority to amend the Incentive Plan, in February 2014 the Board adopted and approved certain amendments to the 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. This amendment will become void if not adopted by the Company's stockholders by May 31, 2014; and

Acceleration of vesting: Section 15(l) of the 2012 Incentive Plan was amended to clarify the Company 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).

On February 11, 2014 the Company granted its Chief Financial Officer stock options to purchase 32,500 shares of common stock under the 2012 Incentive Plan. The exercise price of each option is $24.57, which represented the fair market value of the Company’s common stock on the grant date. Such options will expire five years from the date of grant and will vest in equal annual installments over a period of three years from the grant date, subject to acceleration upon a change of control.

The fair value of each SAR on the grant date was $5.78. The Company calculated the fair value of each SAR on the date of grant using the Black-Scholes valuation model based on the following assumptions:

Risk-free interest rates			0.81%
Expected term (in years)			3.375
Dividend yield			0.80%
Expected volatility			33.50%

NOTE 7 — INTEREST EXPENSE, NET

The components of interest expense, net, are as follows:

	Three Months Ended March 31,
	2014			2013
	(Dollars in thousands)
Interest related to sale of tax benefits	$	2,579		$	2,717
Other		18,391			15,843
Less — amount capitalized		(452	)		(2,697	)
	$	20,518		$	15,863

NOTE 8 — EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per share attributable to the Company’s stockholders (“earnings (loss) per share”) 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.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

	Three Months Ended March 31,
	2014		2013
	(In thousands)
Weighted average number of shares used in computation of basic earnings (loss) per share		45,479		45,431
Add:
Additional shares from the assumed exercise of employee stock-based awards		181		—
Weighted average number of shares used in computation of diluted earnings (loss) per share		45,660		45,431

For the three months ended March 31, 2013, the employee stock-based awards were anti-dilutive because of the Company’s net loss, and therefore they have been excluded from the diluted earnings (loss) per share calculation.

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 (loss) per share because to do so would have been anti-dilutive was 3,349,877 and 5,161,802 for the three months ended March 31, 2014 and 2013, respectively.

NOTE 9 — BUSINESS SEGMENTS

The Company has two reporting segments: Electricity and Product Segments. 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, 2014:
Net revenues from external customers	$	94,817		$	47,619	$	142,436
Intersegment revenues		—			20,594		20,594
Operating income		30,918			11,653		42,571
Segment assets at period end *		2,003,991			130,356		2,134,347
* Including unconsolidated investments		7,510			—		7,510
Three Months Ended March 31, 2013, as revised:
Net revenues from external customers	$	68,298		$	50,608	$	118,906
Intersegment revenues		—			6,581		6,581
Operating income (loss)		(1,278	)		8,962		7,684
Segment assets at period end *		2,046,817			96,751		2,143,568
* Including unconsolidated investments		2,789			—		2,789

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

	Three Months Ended March 31,
	2014			2013, As revised
	(Dollars in thousands)
Operating income	$	42,571		$	7,684
Interest income		111			41
Interest expense, net		(20,518	)		(15,863	)
Foreign currency translation and transaction gains (losses)		(638	)		1,682
Income attributable to sale of equity interest		6,717			3,532
Other non-operating (expense), net		63			1,417
Total income (loss), before income taxes and equity in losses of investees	$	28,306		$	(1,507	)

NOTE 10 — COMMITMENTS AND CONTINGENCIES

In December 2012, Laborers’ International Union of North America Local Union No. 783 (“LiUNA”), an organized labor union, filed a petition in Mono County Superior Court, naming Mono County, California and the Company as defendant and real party in interest, respectively. The petitioners brought this action to challenge the November 13, 2012 decision of the Mono County Board of Supervisors in adopting Resolutions No. 12-78, denying petitioners’ administrative appeal of the Planning Commission’s approval of Conditional Use Permit (“CUP”), adoption of findings under the California Environmental Quality Act (“CEQA”) and adoption of the final environmental impact report (“EIR”) for the Mammoth Pacific enhancement. The petition asked the court to set aside the approval of the CUP and adoption of the EIR and cause a new EIR to be prepared and circulated.

The Company believes that the petition is without merit and intends to respond and take necessary legal action to dismiss the proceedings. The Company responded to LiUNA’s petition. Filing of the petition in and of itself does not have any immediate adverse implications for the Mammoth enhancement.

In January 2014, the Company learned that two former employees alleged in a “qui tam” complaint filed in the United States District Court for the Southern District of California that the Company submitted fraudulent applications and certifications to obtain grants. While the United States Department of Justice has declined to intervene, the former employees may proceed on their own. In April 2014, the Company was served and does not believe that the allegations of the lawsuit have any merit and will defend itself vigorously.

In addition, from time to time, the Company is named as a party in various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of its 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, 2014 and 2013 was 22.3% and 268.5%, respectively. The effective tax rate differs from the federal statutory rate of 35% for the three months ended March 31, 2014 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) lower tax rates in Israel; 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, 2014 and March 31, 2013 was $1,019,000 and $951,000, respectively.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

At December 31, 2013, the Company had U.S. federal NOL carryforwards of approximately $235.4 million and state NOL carryforwards of approximately $218.1 available to reduce future taxable income, which expire between 2021 and 2032 for federal NOLs and between 2014 and 2032 for state NOLs. Investment tax credits in the amount of $0.7 million at December 31, 2013 are available for a 20-year period and expire between 2022 and 2024. Production tax credits in the amount of $71.3 million at December 31, 2013 are available for a 20-year period and expire between 2026 and 2032.

Realization of the deferred tax assets is dependent on generating sufficient taxable income in appropriate jurisdictions prior to expiration of the NOL carryforwards and tax credits. The scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies were considered in determining the amount of valuation allowance. A full valuation allowance was recorded against the U.S. deferred tax assets as of December 31, 2013 and March 31, 2014, as at these points in time, it was more likely than not that the deferred tax assets will not be realized. If sufficient evidence of the Company’s ability to generate taxable income is established in the future, the Company may be required to reduce this valuation allowance, resulting in income tax benefits in its condensed consolidated statement of operations and comprehensive income (loss).

The Company believes that based on its plans to increase the 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.. In addition, the Company’s U.S. sources of cash and liquidity are sufficient to meet its needs in the U.S. and, accordingly, the Company does not currently plan to repatriate the funds it has designated as being permanently invested outside the U.S.. If the Company changes its plans, it may be required to accrue and pay U.S. taxes to repatriate these funds.

The Company’s subsidiary, Ormat Systems Ltd. (“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. As a Benefited Enterprise, Ormat Systems was exempt from Israeli income taxes with respect to income derived from the first benefited investment for a period of two years beginning in 2004, and thereafter such income was subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years until 2010. Ormat Systems was also exempt from Israeli income taxes with respect to income derived from the second benefited investment for a period of two years beginning in 2007. Thereafter, such income is subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years until 2013. These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and its affiliates are done on an arm’s length basis, and that the management of Ormat Systems will be located in, and the control will be conducted from, Israel during the entire period of the tax benefits. A change in control of Ormat Systems would need to be reported to the Israel Tax Authority in order for Ormat Systems to maintain the tax benefits. 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. According to the amendment, the uniform tax rate applicable to the zone where the production facilities of Ormat Systems are located would be 15% in 2011 and 2012, 12.5% in 2013 and 2014, and 12% in 2015 and thereafter. Under the transitory provisions of the new legislation, Ormat Systems had the option either to irrevocably comply with the new law while waiving benefits provided under the previous law or to continue to comply with the previous law during a transition period with the option to move from the previous law to the new law at any stage. Ormat Systems decided to irrevocably comply with the new law starting in 2011.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

	Three Months Ended March 31,
	2014		2013
	(Dollars in thousands)
Balance at beginning of period	$	4,950	$	7,280
Additions based on tax positions taken in prior years		76		104
Additions based on tax positions taken in current year		106		411
Balance at end of period	$	5,132	$	7,795

NOTE 12 — TAX MONETIZATION TRANSACTION

OPC TRANSACTION

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

The first closing under the agreements occurred in 2007 and covered the Company’s 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 production tax credits and taxable income or loss (together, the “Economic Benefits”). Once Ormat Nevada recovered the capital that it has invested in the power plants, which occurred in the fourth quarter of 2010, the investors receive both the distributable cash flow and the Economic Benefits. The investors’ return is limited by the term of the transaction. 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 buy out the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the power plants.

The Class B membership units are provided with a 5% residual economic interest in OPC. The 5% residual interest commences on achievement by the investors of a contractually stipulated return that triggers the OPC Flip Date. The actual OPC Flip Date is not known with certainty and is determined by the operating results of OPC. This residual 5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. Cash is distributed each period in accordance with the cash allocation percentages stipulated in the agreements. Until the fourth quarter of 2010, Ormat Nevada was allocated the cash earnings in OPC and therefore, the amount allocated to the 5% residual interest represented the noncash loss of OPC which principally represented depreciation on the property, plant and equipment. As from the fourth quarter of 2010, the distributable cash is allocated to the Class B membership units. As a result of the acquisition by Ormat Nevada, on October 30, 2009, of all of the Class B membership units of OPC held by Lehman-OPC LLC (see below), the residual interest decreased to 3.5%. Such residual interest increased to 5% on February 3, 2011 when Ormat Nevada sold its Class B membership units to JPM Capital Corporation (“JPM”) (see below).

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The Company’s voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada, the Company owns all of the Class A membership units, which represent 75% of the voting rights in OPC. The investors own all of the Class B membership units, which represent 25% of the voting rights in OPC. In the period from October 30, 2009 to February 3, 2011, the Company owned, through Ormat Nevada, all of the Class A membership units, which represented 75% of the voting rights in OPC, and 30% of the Class B membership units, which represented 7.5% of the voting rights of OPC. In total the Company had 82.5% of the voting rights in OPC as of December 31, 2010. In that period, the investors owned 70% of the Class B membership units, which represented 17.5% of the voting rights of OPC. Other than in respect of customary protective rights, all operational decisions in 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 investor’s voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the OPC Flip Date and therefore consolidates OPC.

On October 30, 2009, Ormat Nevada acquired from Lehman-OPC LLC all of the Class B membership units of OPC held by Lehman-OPC pursuant to a right of first offer for a price of $18.5 million. A substantial portion of the initial sale of the Class B membership units by Ormat Nevada was accounted for as a financing transaction. As a result, the repurchase of these interests at a discount resulted in a pre-tax gain of $13.3 million in the year ended December 31, 2009. In addition, an amount of approximately $1.1 million has been reclassified from noncontrolling interest to additional paid-in capital representing the 1.5% residual interest of Lehman-OPC’s Class B membership units.

On February 3, 2011, Ormat Nevada sold to JPM all of the Class B membership units of OPC that it had acquired on October 30, 2010 for a total sale price of $24.9 million in cash. The Company did not record any gain from the sale of its Class B membership interests in OPC to JPM. A substantial portion of the Class B membership units are accounted for as a financing transaction. As a result, the majority of these proceeds were recorded as a liability. In addition, $2.3 million has been reclassified from additional paid-in capital to noncontrolling interest representing the 1.5% residual interest of JPM’s Class B membership units.

ORTP TRANSACTION

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

Under the terms of the transaction, Ormat Nevada transferred the Heber complex, the Mammoth complex, the Ormesa complex, and 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 are expected to be made until December 31, 2016 up to a maximum amount of $11.0 million of which we received $2.2 million in the first quarter of 2014.

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 PTCs and the taxable income or loss (together, 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% 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 buy out 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.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The Class B membership units entitle the holder to 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 interest commences on achievement by JPM of a contractually stipulated return that triggers the ORTP Flip Date. The actual ORTP Flip Date is not known with certainty. This residual 5.0% and 2.5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments.

The Company’s voting rights in ORTP are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada the Company owns all of the Class A membership units, which represent 75% of the voting rights in ORTP. JPM owns all of the Class B membership units, which represent 25% 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.

NOTE 13 — DISCONTINUED OPERATIONS

On May 30, 2013, the Company’s wholly owned subsidiary, Ormat Holding Corp., sold the Momotombo Power Company (“MPC”), which operates the Momotombo power plant located in Nicaragua, to a third party for $7,751,000 approximately one year before the scheduled termination of the concession arrangement with the Nicaraguan owner. The Company recorded an after-tax gain on sale of approximately $3.6 million in June 2013.

In conjunction with the sale, the Company’s wholly owned subsidiary and the buyer signed a technical support agreement, whereby the subsidiary will provide technical consulting services, which can be terminated by either party with 60 days advance notice. The Company is of the opinion that the expected continuing cash flows from this agreement are insignificant and that there is no significant continuing involvement by the Company, including its subsidiaries, in the operations of the MPC after the sale. Therefore, the related income from operations prior to the date of the sale and the gain on the sale of the MPC have been included as discontinued operations in the condensed consolidated statements of operations and comprehensive income (loss) for all comparative periods presented.

The summarized financial information related to the discontinued operations is as follows:

	Three Months Ended March 30,
	2013
	(Dollars in thousands)
Revenues - electricity	$	2,804
Cost of revenues - electricity		1,849
Gross margin		955
Operating expenses:
Selling and marketing expenses		67
General and administrative expenses		66
Operating income		827

Income from discontinued operations before income taxes		827
Income tax provision		(222	)
Total income from discontinued operations	$	605

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The net assets of the MPC as of May 30, 2013 were as follows:

	(Dollars in thousands)

Cash and cash equivalents	$	52
Accounts receivable		2,274
Prepaid expenses and other		167
Property, plant and equipment		3,935
Accounts payable and accrued expenses		(493	)
Deferred income taxes		(442	)
Accrued severance pay		(313	)
Other liabilities		(590	)
Net assets	$	4,590

NOTE 14 — SUBSEQUENT EVENTS

On April 2, 2014, the Company granted its Chief Executive Officer appointee stock options to purchase up to an aggregate of 400,000 shares of common stock under the 2012 Incentive Plan. The exercise price of each stock option was $29.52 per share, which represented the fair market value of the Company’s common stock on the date of the grant. Of the 400,000 stock options, options to purchase 300,000 shares of common stock will expire six years following the date of grant and will vest in equal annual installments over four years from the grant date, subject to acceleration associated with a change of control. The remaining options to purchase 100,000 shares of common stock will vest on March 31, 2021, subject to acceleration associated with a change of control, and will expire on September 30, 2021.

On May 8, 2014, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.3 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on May 21, 2014, payable on May 30, 2014.

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:

●

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

●

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

●

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

●

financial market conditions and the results of financing efforts;

●

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

●

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;

●

construction or other project delays or cancellations;

●

political, legal, regulatory, governmental, administrative and economic conditions and developments in the United States and other countries in which we operate;

●

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

●

contract counterparty risk;

●

weather and other natural phenomena including earthquakes, drought and other nature disasters;

●

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;

●

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;

●

current and future litigation;

●

our ability to successfully identify, integrate and complete acquisitions;

●

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

●

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

●

the direct or indirect impact on our company’s business resulting from various forms of hostilities such as the threat or occurrence of 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;

●

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

●

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;

●

the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2013 and any update contained herein and other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission; and

●

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, 2013 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 engaged primarily in the geothermal and recovered energy power business. We design, develop, build, sell, own, and operate clean, environmentally friendly geothermal and recovered energy-based power plants, in most cases 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 all of our recovered energy-based plants have been constructed by us. We conduct our business activities in two business segments:

●

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; and

●

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

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

For the three months ended March 31, 2014, our total revenues increased by 19.8% (from $118.9 million to $142.4 million) over the corresponding period in 2013.

For the three months ended March 31, 2014, Electricity Segment revenues were $94.8 million, compared to $68.3 million for the three months ended March 31, 2013, an increase of 38.8%, while Product Segment revenues for the three months ended March 31, 2014 were $47.6 million, compared to $50.6 million during the three months ended March 31, 2013, a decrease of 5.9%.

During the three months ended March 31, 2014 and 2013, our consolidated power plants generated 1,201,141 megawatt hours (MWh) and 1,040,044 MWh, respectively, an increase of 15.5%, with the majority due to new power plants that came on line in the past year.

For the three months ended March 31, 2014, our Electricity Segment represented approximately 66.6% of our total revenues, while our Product Segment represented approximately 33.4% of our total revenues. For the three months ended March 31, 2013, our Electricity Segment represented approximately 57.4% of our total revenues, while our Product Segment represented approximately 42.6% of our total revenues.

For the three months ended March 31, 2014, approximately 72.3% 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:

●

The energy rates under the PPAs in California for each of the Ormesa complex, the Heber 1 and Heber 2 power plants in the Heber complex and the G2 power plant in the Mammoth complex (the California SO#4 PPAs) change based primarily on fluctuations in natural gas prices; and

●

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

We have reduced our exposure to fluctuations in the price of oil until December 31, 2014 and in the price of natural gas until March 31, 2015, by entering into derivatives transactions. In the first quarter of 2014, we recorded a $2.4 million loss in electricity revenues related to these transactions.

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, and 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 to us of all available and unrestricted cash flows generated by their assets.

Electricity Segment revenues are also subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under “Seasonality”. In addition, the revenues we report in our financial statements may show more variation due to our increased use of derivatives in connection with our variable price PPAs and the accounting principles associated with our use of those derivatives.

Revenues attributable to our Product Segment are based on the sale of equipment and the provision of various services to our customers. These revenues may vary from period to period because of the timing of our receipt of purchase orders and the progress of our execution of each project.

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

Recent Developments

The most significant developments in our company and business since January 1, 2014 are described below:

●

On March 28, 2014, we announced that members of the Sarulla Consortium of which Ormat (through our subsidiary, Ormat International, Inc.) is a 12.75% equity stake member, signed project financing agreements in the aggregate amount of $1.17 billion to finance the development and construction of the 330-megawatt (MW) Sarulla geothermal project in Tapanuli Utara, North Sumatra in Indonesia. Closing is expected in the second quarter of 2014 subject to fulfillment of certain conditions. These financing agreements were signed with the Japan Bank for International Cooperation (JIBC), the Asian Development Bank and six commercial banks. The Sarulla project will obtain construction and term loans under a limited recourse financing package backed by political risk guarantees from JBIC.

Upon closing, the consortium is expected to begin full scope construction with the first phase of operations expected to commence in 2016. The remaining two phases of operations are scheduled to commence within 18 months thereafter. We will supply our Ormat Energy Converters to the power plant and will add the $254.0 million supply contract to our Product Segment backlog once the Notice to Proceed is issued upon closing of the financing. According to the current project plan we expect to recognize revenue from the project over the course of the next three to four years starting in the third quarter of 2014.

	●	On March 26, 2014, we signed an agreement with RET Holdings, LLC to sell the Heber Solar project in Imperial County, California for $35.25 million. We received the first payment of $15.0 million with the remainder expected to be paid in the second quarter of 2014, subject to fulfillment of certain conditions subsequent. Due to certain contingencies in the sale agreement, the Company deferred the pre-tax gain of approximately $7.5 million until resolution of such contingencies (which is expected in the second quarter of 2014).

●

On February 11, 2014, our Board of Directors appointed Mr. Isaac Angel as CEO. Mr. Angel joined Ormat on April 1, 2014 and will assume the CEO position effective July 1, 2014. He will succeed Mrs. Yehudit (Dita) Bronicki, who announced her retirement in November 2013. Mrs. Bronicki will continue to serve as a Director of Ormat in a non-executive capacity. We further announced that Mr. Gillon Beck will step down from his position of Chairman of the Board of Directors of the company effective June 30, 2014 and the Board of Directors has elected and appointed Mr. Yoram Bronicki as the succeeding Chairman, with such appointment being also effective June 30, 2014. Mr. Beck will continue to serve as a director of the company after he steps down from his position as Chairman. Upon assuming the position of the Chairman of the board, Mr. Yoram Bronicki will relinquish his position as President and Chief Operating Officer of the company.

●

On February 4, 2014, we announced that we successfully completed construction and reached commercial operation of Plant 3 in the Olkaria III geothermal power plant complex in Kenya, almost three months ahead of schedule. With Plant 3 online, the complex's total generation capacity has increased to 110 MW. The power generated by the Olkaria III complex is sold under a 20-year PPA with KPLC. On November 25, 2013, we announced that we drew down the remaining $45.0 million comprising Tranche III of the previously announced $310 million project finance facility with OPIC.

●

On January 23, 2014, we announced that we successfully completed the scope of work needed to bring the Mammoth G1 geothermal power plant in Mono County, California to full capacity. The 6 MW plant reached commercial operation under the new PPA with Pacific, Gas and Electric (PG&E) that allows for hourly energy deliveries of up to 7.5 MW and, as of December 26, 2013, it received the full commercial rate defined in the PPA.

●

On January 22, 2014, we announced that our wholly owned subsidiary signed an amendment to the PPA with INDE for the Zunil geothermal power plant in Guatemala, which extends the term of the PPA from 2019 to 2034. The amendment also transfers operation and management responsibilities of the Zunil geothermal field from INDE to Ormat for the term of the amended PPA in exchange for a tariff increase. Additionally, INDE exercised its right under the PPA to become a partner in the Zunil power plant and to acquire a three percent equity interest therein.

●

On January 6, 2014, we announced that we completed the construction of the Don A. Campbell geothermal power plant in Mineral County, Nevada. The plant is currently producing at full generating capacity of 16 MW and performing as expected. The Don A. Campbell facility, formerly Wild Rose, receives a full rate of $99.0 per MWh with no annual escalation under the terms of the PPA, signed in April 2013, with Southern California Public Power Authority (SCPPA). SCPPA resells the power from the Don A. Campbell geothermal power plant to the Los Angeles Department of Water and Power (LADWP) and Burbank Water and Power through NV Energy Inc.’s transmission system.

Trends and Uncertainties

The geothermal industry in the United States has historically experienced significant growth followed by a consolidation of owners and operators of geothermal power plants. During the 1990s, growth and development in the geothermal industry occurred primarily in foreign markets and only minimal growth and development occurred in the United States. Since 2001, there has been increased demand for energy generated from geothermal resources in the United States as costs for electricity generated from geothermal resources have become more competitive recently, much of this is attributable to legislative and regulatory requirements and incentives, such as state renewable portfolio standards and federal tax credits. The American Recovery and Reinvestment Act of 2009 (ARRA) further encourages the use of geothermal energy through production tax credits (PTCs) or investment tax credits (ITCs) as well as cash grants (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits” below). In response, the geothermal industry in the United States has seen a wave of new entrants and, over the last several years, consolidation involving smaller developers. We believe that the future demand for energy generated from geothermal and other renewable resources in the United States will be driven by further commitment and implementation of renewable portfolio standards as well as the introduction of additional tax incentives. The trends that from time to time impact our operations are subject to market cycles.

Although other trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee, 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:

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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 and in the Solar PV sector.

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Our focus continues to be organic growth through exploration, development, construction of new projects and enhancements of existing power plants along with increasing operational efficiency of our operating portfolio. We expect that our investment in organic growth will increase our total generating capacity, consolidated revenues and operating income attributable to our Electricity Segment from year to year. In addition, we routinely look at acquisition opportunities.

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The continued awareness of climate change may result in significant changes in the business and regulatory environments, which may create business opportunities for us. In 2011, the first phase of the Environmental Protection Agency (EPA) “Tailoring Rule” took effect. The Tailoring Rule sets thresholds addressing the applicability of the permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs to certain major sources of GHG emissions. Federal legislation or additional federal regulations addressing climate change are possible. In June 2013 President Barack Obama announced a new national climate action plan, directing the EPA to complete new carbon dioxide pollution standards for both new and existing power plants. In addition, several states and regions are already addressing legislation to reduce GHG emissions. For example, California’s state climate change law, AB 32, which was signed into law in September 2006, regulates most sources of GHG emissions and aims to reduce GHG emissions to 1990 levels by 2020. On October 20, 2011 the CARB adopted cap-and-trade regulations to reduce California’s greenhouse gas emissions under AB 32. In addition to California, twenty U.S. states have set GHG emissions reduction targets and two states have reduction goals. Regional initiatives, such as the Western Climate Initiative (which includes California and four Canadian provinces) and the Midwest GHG Reduction Accord (which includes six U.S. states and one Canadian province), are also being developed to reduce GHG emissions and develop trading systems for renewable energy credits. In the United States, approximately 40 states have adopted RPS, renewable portfolio goals, or similar laws requiring or encouraging electric utilities in such states to generate or buy a certain percentage of their electricity from renewable energy sources or recovered heat sources. On April 12, 2011, the California Senate Bill X1-2 (SBX1-2) was signed into law, and increased California’s RPS to 33% by December 31, 2020 and instituted a tradable REC program. SBX1-2 is expected to foster a liquid tradable REC market and lead to more creative off-take arrangements. Although we cannot predict at this time whether the tradable REC program under SBX1-2 and its implementing regulations will have a significant impact on our operations or revenue, it may facilitate additional options when negotiating PPAs and selling electricity from our projects.

In June 2013, the Nevada state legislature passed three bills that were signed by Nevada’s Governor and are expected to support renewable energy development in the state. Senate Bill (SB) No. 123 calls for the retirement or elimination of not less than 800 MW of coal-fired electric generating capacity on or before December 31, 2019 and the construction or acquisition of, or contracting for, 350 MW of electric generating capacity from renewable energy facilities. Senate Bill 252 revises provisions relating to the renewable portfolio standard by removing energy efficiency, solar multipliers, and station usage from generating portfolio energy credits Finally, Assembly Bill (AB) No.239 Revised Statutes 701A.340 defines geothermal energy as renewable energy for purposes of tax abatements and makes geothermal projects eligible for partial sales and property tax abatements, with property tax abatements for a period of twenty years and local sales and use tax abatements for three years.

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For projects outside of the United States, in November 2012 the U.S., Brunei, and Indonesia formed the Asia-Pacific comprehensive partnership and President Obama announced the allocation of $6.0 billion for green energy development in Asia. Also, on June 30, 2013, President Obama announced the “Power Africa” initiative pursuant to which the United States will invest $7.0 billion in Sub-Saharan Africa over the following five years, with the aim of doubling access to power. The Sub-Sahara Africa includes three countries (Ethiopia, Kenya and Tanzania) that have large geothermal potential as well as operating geothermal power plants. We accelerated our efforts to expand business development activities in those areas by, among other things, participating in new applicable bids. In addition, we expect that a variety of 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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In the Electricity Segment, we expect competition from the wind and solar power generation industry to continue. While we believe the expected demand for renewable energy will be large enough to accommodate increased competition, any such increase and the amount of renewable energy under contract may contribute to a reduction in electricity prices. Despite increased competition from the wind and solar power generation industry, 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 resource. Also, geothermal power plants positively impact electrical grid stability and provide valuable ancillary services because of their base load nature while the intermittent renewables create integration costs. The reduced level of competition has contributed to a decrease in lease costs.

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In the Product Segment, we expect 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 a reduction in the prices that we are able to charge for our binary equipment, which in turn may impact our profitability.

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The changing natural gas landscape, the resulting effect on natural gas pricing (in either direction) and the corresponding implications for electric utilities and other producers of electricity in terms of planning for and choosing a source of fuel, will affect the pricing under our PPAs that have short run avoided cost (SRAC) pricing, as described below.

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The 38 MW Puna complex has three PPAs, of which the 25 MW PPA has a monthly variable energy rate based on the local utility’s avoided costs. A change in the price of oil will result in a change 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 price we recently signed a fixed rate PPAs for the rest of the complex and we are currently negotiating a fixed price for the 25 MW PPA as well. In the meantime, we have entered into put and swap contracts to reduce our exposure to fluctuations in the energy rate caused by fluctuations in oil prices through December 31, 2014. Our use of derivative instruments for this purpose has increased, and likely will continue to be used to manage volatility in revenues, net profit and certain other line items in our financial statements.

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We had PPAs for the Ormesa Mammoth and Heber complexes for a total of 161 MW that were fixed until May 1, 2012. Thereafter, the energy price component under these PPAs changed from a fixed rate to a variable rate based on SRAC pricing that is impacted by fluctuations in natural gas prices. In 2013, we signed new fixed rate PPAs that reduced our current exposure to SRAC by 18 MW and by additional 44 MW in 2016. We have entered into derivative transactions at a fixed price of $4.07 per MMbtu for the year 2014 to reduce further our exposure to fluctuations in natural gas prices through December 31, 2014 and $4.95 per MMbtu for the period from January 1, 2015 until March 31, 2015. Our use of derivative instruments for this purpose has increased, and likely will continue to be used to manage volatility in revenues, net profit and certain other line items in our financial statements.

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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 of the date of this report, those risks include the partial privatization of the electricity sector in Guatemala and the political uncertainty currently prevailing in some of the countries in which we operate. Although we maintain 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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FERC is allowed under PURPA to terminate, upon the request of a utility, the obligation of electric utilities 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. The legislation does not affect existing PPAs. We do not expect this change in law to affect our U.S. power plants significantly, as all of our current PPAs are long-term. 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.

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 72.3% of our Electricity revenues for the three months ended March 31, 2014 were derived from PPAs with fixed price components, we have variable price PPAs in California and Hawaii. Our 143MW California SO#4 PPAs 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 are impacted by the price of oil. Accordingly, our revenues from those power plants may fluctuate. In 2013 and 2014, we entered into derivative transactions in an attempt to reduce our exposure to fluctuations in the prices of oil from Puna’s PPAs until December 31, 2014 and natural gas and from the California SO#4 PPAs until March 31, 2015.

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 and the status and timing of such orders. Larger customer orders for our products are typically the result of our participating in, and winning, tenders or requests for proposals issued by potential customers in connection with projects they are developing. 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:

	Revenues (dollars in thousands)				% of Revenues for Period Indicated
	Three Months Ended March 31,				Three Months Ended March 31,
	2014		2013		2014			2013
Revenues:
Electricity	$	94,817	$	68,298		66.6	%		57.4	%
Product		47,619		50,608		33.4			42.6
Total	$	142,436	$	118,906		100.0	%		100.0	%

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

	Revenues (dollars in thousands)				% of Revenues for Period Indicated
	Three Months Ended March 31,				Three Months Ended March 31,
	2014		2013		2014			2013
Electricity Segment:

United States	$	67,222	$	52,068		70.9	%		76.2	%
Foreign		27,595		16,230		29.1			23.8
Total	$	94,817	$	68,298		100.0	%		100.0	%

Product Segment:
United States	$	16,892	$	14,433		35.5	%		28.5	%
Foreign		30,727		36,175		64.5			71.5
Total	$	47,619	$	50,608		100.0	%		100.0	%

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 1 and 2 power plants 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 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 our energy revenues. However, the higher payments payable by Southern California Edison and Pacific Gas & Electric Company in the summer months have a more significant impact on our revenues than that of the higher energy revenues generally generated in winter due to increased efficiency. As a result, our electricity revenues are generally higher in the summer than in the winter.

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. 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 4.6% and 4.0% of Electricity Segment revenues for the three months ended March 31, 2014 and March 31, 2013, 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, Cash Equivalents, Marketable Securities and Short-Term Bank Deposit

Our cash and cash equivalents, as of March 31, 2014 decreased to $47.9 million from $57.4 million as of December 31, 2013. This decrease was principally due to: (i) our use of $48.3 million to fund capital expenditures; (ii) a net change in restricted cash, cash equivalents and marketable securities of $23.3 million; (iii) net repayment of $14.8 million from borrowers under our revolving credit lines with commercial banks; (iv) $12.9 million of cash used to repurchase Ormat Funding LLC (OFC) Senior Secured Notes: (v) repayment of $10.5 million of long-term debt; and (vi) $2.7 million cash dividend paid. This decrease was partially offset by: (i) $68.1 million derived from operating activities during the three months ended March 31, 2014; (ii) cash grant of $21.8 million received from the U.S. Treasury under Section 1603 of the ARRA in the third quarter of 2013 relating to our Don A. Campbell geothermal power plant; and (iii) $15.0 million cash received as part of the Herber Solar sale transaction. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of March 31, 2014 was $522.6 million, as described below in “Liquidity and Capital Resources”, of which we have utilized $314.5 million (including $214.9 million of letters of credit) as of March 31 2014.

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, 2013.

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,
	2014			2013 As revised
	(Dollars in thousands, except per share data)
Statements of Operations Historical Data:
Revenues:
Electricity	$	94,817		$	68,298
Product		47,619			50,608
		142,436			118,906
Cost of revenues:
Electricity		57,034			55,088
Product		31,943			37,041
		88,977			92,129
Gross margin:
Electricity		37,783			13,210
Product		15,676			13,567
		53,459			26,777
Operating expenses:
Research and development expenses, net		(87	)		1,000
Selling and marketing expenses		3,379			11,509
General and administrative expenses		7,596			6,584
Write-off of unsuccessful exploration activities		—			—
Operating income		42,571			7,684
Other income (expense):
Interest income		111			41
Interest expense, net		(20,518	)		(15,863	)
Foreign currency translation and transaction gains (losses)		(638	)		1,682
Income attributable to sale of tax benefits		6,717			3,532
Other non-operating expense, net		63			1,417
Income (loss), before income taxes and equity in losses of investees		28,306			(1,507	)
Income tax provision		(6,320	)		(4,047	)
Equity in losses of investees		(197	)		—
Income from continuing operations		21,789			(5,554	)
Discontinued operations:
Income from discontinued operations		—			827
Income tax provision		—			(222	)
Total income from discontinued operations		—			605

Net income (loss)		21,789			(4,949	)
Net income attributable to noncontrolling interest		(237	)		(85	)
Net income (loss) attributable to the Company's stockholders	$	21,552		$	(5,034	)
Earnings (loss) per share attributable to the Company's stockholders - basic and diluted:
Income (loss) from continuing operations:	$	0.47		$	(0.12	)
Discontinued operations:		—			0.01
Net income (loss)	$	0.47		$	(0.11	)
Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company's stockholders:
Basic		45,479			45,431
Diluted		45,660			45,431

	Three Months Ended March 31,
	2014			2013 As revised
Statements of Operations Percentage Data:
Revenues:
Electricity		66.6	%		57.4	%
Product		33.4			42.6
		100.0			100.0
Cost of revenues:
Electricity		60.2			80.7
Product		67.1			73.2
		62.5			77.5
Gross margin:
Electricity		39.8			19.3
Product		32.9			26.8
		37.5			22.5
Operating expenses:
Research and development expenses, net		(0.1	)		0.8
Selling and marketing expenses		2.4			9.7
General and administrative expenses		5.3			5.5
Operating income		29.9			6.5
Other income (expense):
Interest income		0.1			0.0
Interest expense, net		(14.4	)		(13.3	)
Foreign currency translation and transaction gains (losses)		(0.4	)		1.4
Income attributable to sale of tax benefits		4.7			3.0
Other non-operating expense, net		0.0			1.2
Income (loss), before income taxes and equity in losses of investees	19.9				(1.3	)
Income tax provision		(4.4	)		(3.4	)
Equity in losses of investees		(0.1	)		0.0
Income from continuing operations		15.3			(4.7	)
Discontinued operations:
Income from discontinued operations		0.0			0.7
Income tax provision		0.0			(0.2	)
Total income from discontined operations		0.0			0.5

Net income (loss)		15.3			(4.2	)
Net income attributable to noncontrolling interest		(0.2	)		(0.1	)
Net income (loss) attributable to the Company's stockholders		15.1	%		(4.3	)%

Comparison of the Three Months Ended March 31, 2014 and the Three Months Ended March 31, 2013

Total Revenues

Total revenues for the three months ended March 31, 2014 were $142.4 million, compared to $118.9 million for the three months ended March 31, 2013, which represented a 19.8% increase. This increase was attributable to our Electricity Segment, in which revenues increased by 38.8% compared to the corresponding period in 2013. The increase was partially offset by a decrease of 5.9% in revenues from our Product Segment over the corresponding period in 2013.

Electricity Segment

Revenues attributable to our Electricity Segment for the three months ended March 31, 2014 were $94.8 million, compared to $68.3 million for the three months ended March 31, 2013, which represented a 38.8% increase in such revenues. This increase was primarily due to: (i) the commencement of operations of our Plant 2 and 3 at the Olkaria III complex in Kenya, which commenced commercial operation in May 2013 and January 2014, respectively, and our Don A. Campbell power plant in Nevada, which commenced commercial operation in December 2013; (ii) higher energy rates under the SO#4 contracts; and (iii) a reduction in net loss on derivative contracts on oil and natural gas prices from $4.6 million in the first quarter of 2013 to $2.4 million in the corresponding period in 2014.

Power generation in our power plants increased by 15.5% from 1,040,275 MWh in the three months ended March 31, 2013 to 1,201,141 MWh in the three months ended March 31, 2014 mainly due to the commercial operation of Plants 2 and 3 in the Olkaria III complex and the Don A Campbell power plant.

Product Segment

Revenues attributable to our Product Segment for the three months ended March 31, 2014 were $47.6 million, compared to $50.6 million for the three months ended March 31, 2013, which represented a 5.9% decrease. The decrease in our Product Segment revenues was primarily due to the decrease in new customer orders and timing of revenue recognition.

Total Cost of Revenues

Total cost of revenues for the three months ended March 31, 2014 was $89.0 million, compared to $92.1 million for the three months ended March 31, 2013. As a percentage of total revenues, our total cost of revenues for the three months ended March 31, 2014, decreased to 62.5%, from 77.5% for the three months ended March 31, 2013. This decrease was attributable primarily to a decrease in cost of revenues in our Product Segment, as further explained below.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the three months ended March 31, 2014 was $57.0 million, compared to $55.1 million, for the three months ended March 31, 2013. This increase was primarily due to additional cost of revenues from the new power plants that commenced commercial operation in 2013 and 2014, as discussed above. The increase in our electricity cost of revenues was offset by lower maintenance costs in most of our power plants are partially due to efficiency and partially to timing. As a percentage of total electricity revenues, our total cost of revenues attributable to our Electricity Segment for the three months ended March 31, 2014, was 60.2% compared to 80.7%, for the three months ended March 31, 2013. This decrease was mainly due to the increase in Electricity revenues, as discussed above.

Product Segment

Total cost of revenues attributable to our Product Segment for the three months ended March 31, 2014 was $31.9 million, compared to $37.0 million, for the three months ended March 31, 2013, which represented a 13.8% decrease. This decrease was primarily due to the decrease 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, 2014, decreased to 67.1% from 73.2%, for the three months ended March 31, 2013.

Research and Development Expenses, net

Research and development expenses excluding grants from the U.S. Department of Energy were $0.4 million for the three months ended March 31, 2014 compared to $1.3 million for the three months ended March 31, 2013. Research and development expenses (income) are net of grants from the U.S. Department of Energy in the amount of $0.5 million and $0.3 million for the three months ended March 31, 2014 and 2013, respectively, related to the Enhanced Geothermal System project. Research and development income for the three months ended March 31, 2014 were $0.1 million, compared to expenses of $1.0 million for the three months ended March 31, 2013.

Selling and Marketing Expenses

Selling and marketing expenses for the three months ended March 31, 2014 were $3.4 million, compared to $11.5 million for the three months ended March 31, 2013. The decrease was primarily due to a one-time early termination fee in the amount of $9.0 million we paid to SCE in the first quarter of 2013 to terminate the PPAs for the G1 and G3 power plants in the Mammoth complex. Excluding the one-time termination fee, selling and marketing expenses for the three months ended March 31, 2014 constituted 2.4% of total revenues for such period, compared to 9.7% for the three months ended March 31, 2013.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2014 were $7.6 million, compared to $6.6 million for the three months ended March 31, 2013. General and administrative expenses for the three months ended March 31, 2014 constituted 5.3% of total revenues for such period, compared to 5.5% for the three months ended March 31, 2013.

Operating Income

Operating income for the three months ended March 31, 2014 was $42.6 million, compared to $7.7 million for the three months ended March 31, 2013. The increase in operating income was principally attributable to: (i) the increase in our gross margin in our Electricity Segment; and (ii) a one-time early termination fee of $9.0 million recorded in the three months ended March 31, 2013, both as discussed above. Operating income attributable to our Electricity Segment for the three months ended March 31, 2014 was $30.9 million, compared to an operating loss of $1.3 million for the three months ended March 31, 2013. Operating income attributable to our Product Segment for the three months ended March 31, 2014 was $11.7 million, compared to $9.0 million for the three months ended March 31, 2013.

Interest Expense, Net

Interest expense, net for the three months ended March 31, 2014 was $20.5 million, compared to $15.9 million for the three months ended March 31, 2013. This increase was primarily due to (i) an increase in interest expense related to new loans received from OPIC in February 2013 and November 2013 each in the amount of $45.0 million; (ii) the conversion in July 2013 of OPIC interest loans from floating interest rate to fixed interest rate; and (iii) a $2.2 million decrease related to interest capitalized to projects.

Foreign Currency Translation and Transaction Gains (losses)

Foreign currency translation and transaction losses for the three months ended March 31, 2014 were $0.6 million, compared to gains of $1.7 million for the three months ended March 31, 2013. Foreign currency translation and transaction gains for the three months ended March 31, 2013 was attributable primarily to gains on 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 in “OPC Transaction” and “ORTP Transaction”, each below) for the three months ended March 31, 2014 was $6.7 million, compared to $3.5 million for the three months ended March 31, 2013. This income represents the value of PTCs and taxable income or loss generated by OPC and ORTP and allocated to the investors in the amount of $1.8 million and $4.9 million, respectively, in the three months ended March 31, 2014, compared to $1.4 million and $2.1 million, respectively in the three months ended March 31, 2013. This increase was primarily attributable to additional payments in the amount of $2.2 million related to the ORTP transaction which represented 25% of the value of PTC’s generated by the portfolio over time, compared to the original forecast, received in the three months ended March 31, 2014.

Income Taxes

Income tax provision for the three months ended March 31, 2014 was $6.3 million, compared to $4.0 million for the three months ended March 31, 2013. Our effective tax rate for the three months ended March 31, 2014 and 2013 was 22.3% and 268.5%, respectively. The effective tax rate differs from the statutory rate of 35% for the three months ended March 31, 2014, primarily due to unbenefited losses in the U.S. and certain foreign jurisdictions.

Income (Loss) from Continuing Operations

Income from continuing operations for the three months ended March 31, 2014 was $21.8 million, compared to a loss from continuing operations of $5.5 million for the three months ended March 31, 2013. The increase in income from continuing operations of $27.3 million was principally attributable to the increase in operating income in the amount of $34.9 million, as discussed above.

Discontinued Operations

In June 2013, our wholly-owned subsidiary sold its interest in MPC, the operator of the Momotombo geothermal power plant in Nicaragua, to a private company for $7.8 million, approximately one year before the scheduled termination of the concession agreement with the Nicaraguan owner. The operations of the MPC for the three months ended March 31, 2013 have been included in discontinued operations. Discontinued operations for the three months ended March 31, 2013 include revenues of $2.8 million of the MPC.

Net Income (Loss)

Net income for the three months ended March 31, 2014 was $21.8 million, compared to a net loss of $4.9 million for the three months ended March 31, 2013, which represents an increase of $26.7 million. The increase in net income was principally attributable to the increase in income from continuing operations, as discussed above.

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 financing, tax monetization, short term borrowing under our lines of credit and cash grants we received under the ARRA. We have utilized this cash to develop and construct power generation plants, fund our acquisitions, and meet our other cash and liquidity needs.

As of March 31, 2014, we had access to (i) $47.9 million in cash and cash equivalents of which $36.9 million is related to foreign jurisdictions; and (ii) $208.1 million of unused corporate borrowing capacity under existing lines of credit with various commercial banks.

Our estimated capital needs for the remainder of 2014 include approximately $190.0 million for capital expenditures required for new projects under development or construction, exploration activity, operating projects, and machinery and equipment purchases, as well as $68.1 million for debt repayment.

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.

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; (iii) future project financing and refinancing (including construction loans); and (iv) cash grants available to us under the ARRA in respect of the refurbishment of G1 power plant in the Mammoth complex. Management believes that these sources will address our anticipated liquidity, capital expenditures, and other investment requirements.

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 in semi-annual payments. 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 (DSCR) 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 DSCR 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, 2013, (the last measurement date of the covenants) the actual historical 12-month DSCR was 1.29 and the pro-forma 12-month DSCR was 2.25. There were $77.6 million and $90.8 million of OFC Senior Secured Notes outstanding as of March 31, 2014 and December 31, 2013, respectively.

In January 2014, we acquired from OFC noteholders OFC Senior Secured Notes with an outstanding aggregate principal amount of $13.2 million. We recognized a gain of approximately $0.3 million in the first quarter of 2014. In February 2013, we acquired from OFC noteholders OFC Senior Secured Notes with an outstanding aggregate principal amount of $12.8 million and we recognized a gain of $0.8 million in the year ended December 31, 2013.

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 in semi-annual payments. 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 DSCR 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 DSCR 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, 2013, (the last measurement date of the covenants) the actual historical 12-month DSCR was 1.3. There were $66.2 million of OrCal Senior Secured Notes outstanding as of March 31, 2014 and December 31, 2013.

OFC 2 Senior Secured Notes — Limited Recourse during Construction and Non-Recourse Thereafter

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 OFC 2 Noteholder Trust, as purchaser, John Hancock, as administrative agent, and the 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 due December 31, 2034.

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 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 in 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 $147.4 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.

Issuance of the Series B Notes is dependent on the Jersey Valley power plant reaching certain operational targets in addition to the other conditions precedent noted above. If issued, the aggregate principal amount of the Series B Notes will not exceed $28.0 million, and such proceeds would be used to finance a portion of the construction costs of Phase I of the Jersey Valley power plant.

The OFC 2 Issuers have sole discretion regarding whether to commence construction of Phase II of any of the Jersey Valley, McGinness Hills and Tuscarora power plants. If Phase II construction is undertaken for any of the power plants, the OFC 2 Issuers may issue Phase II tranches of Notes, comprised of one or more of Series C Notes, Series D Notes, Series E Notes and Series F Notes, to finance a portion of the construction costs of such Phase II of any facility. The aggregate principal amount of all Phase II Notes may not exceed $170.0 million. The aggregate principal amount of each series of Notes comprising a Phase II tranche will be determined by the OFC 2 Issuers in their sole discretion provided that certain financial ratios are satisfied pursuant to the terms of the Note Purchase Agreement and subject to the aggregate limit noted above.

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 and projected quarterly DSCR requirement of at least 1.2 (on a blended basis for all of the OFC 2 power plants) and 1.5 on a pro forma basis (giving effect to the distributions). We are required to measure these covenants on a quarterly basis and as of March 31, 2014, the last measurement date of the covenants, the actual DSCR was 2.30 and the pro-forma 12-month DSCR was 2.26. There were $141.9 million and $144.4 million of OFC 2 Senior Secured Notes outstanding as of March 31, 2014 and December 31, 2013, respectively.

We provided a guarantee in connection with the issuance of the Series A Notes, and will provide a guarantee in connection with the issuance of each other Series of OFC 2 Senior Secured Notes, which will be available to be drawn upon if certain trigger events occur. One trigger event is the failure of any facility financed by the relevant series of OFC 2 Senior Secured Notes to reach completion and meet certain operational performance levels (the non-performance trigger) which gives rise to a prepayment obligation on the OFC 2 Senior Secured Notes. The other trigger event is a payment default on the OFC 2 Senior Secured Notes or the occurrence of certain fundamental defaults that result in the acceleration of the OFC 2 Senior Secured Notes, in each case that occurs prior to the date that the relevant facility financed by such OFC 2 Senior Secured Notes reaches completion and meets certain operational performance levels. A demand on our guarantee based on the non-performance trigger is limited to an amount equal to the prepayment amount on the OFC 2 Senior Secured Notes necessary to bring the OFC 2 Issuers into compliance with certain coverage ratios. A demand on our guarantee based on the other trigger event is not so limited.

Olkaria III Finance Agreement with OPIC — Limited Recourse during Construction and Non-Recourse Thereafter

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, 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 Debt”. The remainder of Tranche I proceeds was used for reimbursement of prior capital costs and other corporate purposes.

● Tranche II in an aggregate principal amount of $180.0 million 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 distributed under this Tranche II.

● Tranche III in an aggregate principal amount of $45.0 million 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.

In July 2013, we completed the conversion of the interest rate applicable to both Tranche I and Tranche II from a floating interest rate to a fixed interest rate. The average fixed interest rate for Tranche I, which has an outstanding balance of $79.1 million and matures on December 15, 2030 and Tranche II, which has an outstanding balance of $172.0 million and matures on June 15, 2030, is 6.31%. In November 2013, we fixed the interest rate applicable to Tranche III. The fixed interest rate for Tranche III, which has an outstanding balance of $45.0 million and matures on December 15, 2030, is 6.12%.

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 $39.5 million as of March 31, 2014, 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 DSCR 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 DSCR 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 will become effective on December 15, 2014.

There were $296.1 million and $299.9 million of the OPIC Loan outstanding as of March 31, 2014 and December 31, 2013, respectively.

Amatitlan Loan — Non-Recourse

In May 2009, Ortitlan, one of our subsidiaries, entered into a note purchase agreement in an aggregate principal amount of $42.0 million which refinanced its investment in the 20 MW geothermal power plant located in Amatitlan, Guatemala. The loan was provided by TCW Global Project Fund II, Ltd. (TCW). The loan bears interest at a rate of 9.83%, will mature on June 15, 2016, and is payable in quarterly installments. There are various restrictive covenants under the loan, which include (i) a projected 12-month DSCR of not less than 1.2 and (ii) a long-term debt to equity ratio not to exceed 4.0 (both of which are measured quarterly). If Ortitlan fails to comply with these financial ratios it will be prohibited from making distributions to its shareholders. In addition, subject to certain cure rights, such failure will constitute an event of default. As of March 31, 2014, the projected 12-month DSCR was 1.62 and the debt to equity ratio was 1.93, and $30.8 million of this loan was outstanding.

Full-Recourse Third-Party Debt

Union Bank. In February 2012, Ormat Nevada, our wholly owned subsidiary entered into an amended and restated credit agreement with Union Bank. Under the amended and restated agreement, the credit termination date was extended from February 15, 2012 to February 7, 2014 (which was subsequently extended to May 15, 2014, pursuant to Amendment No. 3 to the amended and restated agreement). The aggregate amount available under the credit agreement was increased from $39.0 million to $50.0 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 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) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of March 31, 2014: (i) the actual 12-month debt to EBITDA ratio was 2.22; (ii) the 12-month DSCR was 2.78; and (iii) the distribution leverage ratio was 1.30. 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, 2014, letters of credit in the aggregate amount of $47.1 million remain issued and outstanding under this credit agreement.

HSBC. In May 2013, Ormat Nevada, our wholly owned subsidiary, entered into a credit agreement with HSBC Bank USA, N.A for one year with annual renewals. The aggregate amount available under the credit agreement is $25.0 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.

As of March 31, 2014, letters of credit in the aggregate amount of $16.1 million remain issued and outstanding under this committed credit agreement.

Credit Agreements. We also have committed credit agreements with five other commercial banks for an aggregate amount of $447.6 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 $308.0 million and (ii) the issuance of one or more letters of credit in the amount of up to $139.6 million. The credit agreements mature end of April 2014 and November 2016. 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, 2014, loans in the total amount of $97.2 million were outstanding, and letters of credit with an aggregate stated amount of $151.8 million were issued and outstanding under these credit agreements. The $97.2 million in loans are for terms of three months or less and bear interest at a weighted average rate of 2.74%.

Term Loans. We have a $20.0 million term loan with a group of institutional investors, which matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010, and bears interest at a rate of 6.5%. As of March 31, 2014, $5.7 million was outstanding under this loan.

We have a $20.0 million term loan with a group of institutional investors, which matures on August 1, 2017, 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, 2014, $11.7 million was outstanding under this loan.

We have a $20.0 million term loan with a group of institutional investors, which matures on November 16, 2016, is payable in ten semi-annual installments commencing May 16, 2012, and bears interest of 5.75%. As of March 31, 2014, $12.0 million was outstanding under this loan.

We have a $50.0 million term loan with a commercial bank, which matures on November 10, 2014, is payable in ten semi-annual installments commencing May 10, 2010, and bears interest at 6-month LIBOR plus 3.25%. As of March 31, 2014, $10.0 million was outstanding under this loan.

Senior Unsecured Bonds. We have an aggregate principal amount of approximately $250.0 million of Senior Unsecured Bonds issued and outstanding. We issued approximately $142.0 million of these bonds in August 2010 and an additional $107.5 million in February 2011. Subject to early redemption, the principal of the bonds is repayable in a single bullet payment upon the final maturity of the bonds on August 1, 2017. The bonds bear 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 of 6.75%.

Loan Agreement with DEG (The Olkaria III Complex). OrPower 4 entered into a project financing 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%. Currently, $39.5 million is outstanding under the DEG Loan (out of which $27.1 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 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”). As part of the amendment we prepaid in full two loans under the DEG facility 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 our 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 and (iii) the elimination of most of the affirmative and negative covenants under the DEG Loan Agreement and certain other conforming provisions as a result of OrPower 4’s execution of the OPIC Finance Agreement and its obligations thereunder.

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 million and in no event less than 30% of total assets; (ii) 12-month debt, net of cash, cash equivalents, and short-term bank deposits to Adjusted EBITDA ratio not to exceed 7.0; and (iii) dividend distributions not to exceed 35% of net income in any calendar year. As of March 31, 2014: (i) total equity was $765.7 million and the actual equity to total assets ratio was 35.9% and (ii) the 12-month debt, net of cash and cash equivalents, to Adjusted EBITDA ratio was 3.93. 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.

Letters of Credit

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, 2014, committed letters of credit in the aggregate amount of $241.8 million remained issued and outstanding, out of which $214.9 million were issued under the credit agreements with Union Bank, HSBC and five of the commercial banks as described under “Full-Recourse Third Party Debt”. In addition $26.9 million were issued under non-committed lines of credit.

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 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.

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 in 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 investor’s voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the OPC Flip Date and therefore consolidates OPC.

The Class B membership units are provided with 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.

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 PTCs and the taxable income or loss (together, 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 interest commences on achievement by JPM of a contractually stipulated return that triggers the ORTP Flip Date. The actual ORTP Flip Date is not known with certainty. This residual 5.0% and 2.5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments.

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.

For the three months ended March 31, 2014 and March 31, 2013, the impact of the ORTP transaction was a net gain of $3.4 million and $1.1 million, respectively, on our condensed consolidated statements of operations and comprehensive income (loss). For the three months ended March 31, 2014 and March 31, 2013, revenues of $4.9 million and $2.2 million, respectively, were recognized in income attributable to the sale of tax benefits and a $1.5 million and $1.1 million finance charge was recognized in interest expense, respectively.

Liquidity Impact of Uncertain Tax Positions

As discussed in Note 11 to our condensed consolidated financial statements set forth in Item 1 of this quarterly report, we have a liability associated with unrecognized tax benefits and related interest and penalties in the amount of approximately $5.1 million as of March 31, 2014. 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, 2012:

	Dividend Amount
Date Declared	per Share		Record Date	Payment Date
May 8, 2012	$	0.04	May 21, 2012	May 30, 2012
August 1, 2012	$	0.04	August 14, 2012	August 23, 2012
August 6, 2013	$	0.04	August 19, 2013	August 29, 2013
November 6, 2013	$	0.04	November 20, 2013	December 4, 2013

Historical Cash Flows

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

	Three Months Ended March 31,
	2014			2013
	(Dollars in thousands)
Net cash provided by operating activities	$	68,076		$	18,216
Net cash used in investing activities		(35,323	)		(98,244	)
Net cash provided by (used in) financing activities		(42,180	)		71,027
Net change in cash and cash equivalents		(9,427	)		(9,001	)

For the Three Months Ended March 31, 2014

Net cash provided by operating activities for the three months ended March 31, 2014 was $68.1 million, compared to $18.2 million for the three months ended March 31, 2013. The net increase of $49.9 million resulted primarily from (i) a decrease in receivables of $43.1 million in the three months ended March 31, 2014, compared to $10.6 million in the three months ended March 31, 2013, as a result of timing of collection from our customers; and (ii) the increase in cash inflow from higher net income of $26.7 million, from a net loss of $4.9 million for the three months ended March 31, 2013 to a net income of $21.8 million for the three months ended March 31, 2014 as described above.

Net cash used in investing activities for the three months ended March 31, 2014 was $35.3 million, compared to $98.2 million for the three months ended March 31, 2013. The principal factors that affected our net cash used in investing activities during the three months ended March 31, 2014 were (i) capital expenditures of $48.3 million, primarily for our facilities under construction and (ii) a net increase of $23.3 million in restricted cash, and cash equivalents due to timing of debt repayments, reduced by (i) cash grant of $21.8 million received from the U.S. Treasury under Section 1603 of the ARRA in the first quarter of 2014 relating to our Don A. Campbell geothermal power plant and (ii) $15.0 million cash received as part of the Heber Solar sale transaction. The principal factors that affected our net cash used in investing activities during the three months ended March 31, 2013 were capital expenditures of $49.6 million, primarily for our facilities under construction and a net increase of $48.4 million in restricted cash, cash equivalents.

Net cash used in financing activities for the three months ended March 31, 2014 was $42.2 million, compared to $71.0 million provided by for the three months ended March 31, 2013. The principal factors that affected the net cash used in financing activities during the three months ended March 31, 2014 were; (i) a net decrease of $14.8 million against our revolving lines of credit with commercial banks; (ii) $12.9 million of cash paid to repurchase our OFC Senior Secured Notes; (iii) the repayment of long-term debt in the amount of $10.5 million; and (iv) $2.7 million cash dividend paid. The principal factors that affected our net cash provided by financing activities during the three months ended March 31, 2013 were: (i) $45.0 million of net proceeds from the disbursement from Tranche II of the OPIC Loan; (ii) ) $32.2 million of net proceeds from the ORTP Transaction (see “ORTP Transaction” above); and (iii) a net increase of $14.7 million against our revolving lines of credit with commercial banks reduced by (i) the repayment of long-term debt in the amount of $5.2 million; and (ii) cash paid to non-controlling interest in the amount of $3.8 million.

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, excluding impairment of long-lived assets and a one-time termination fee. EBITDA and Adjusted EBITDA are not measurements of financial performance or liquidity under GAAP and should not be considered as alternatives to cash flow from operating activities or as measures of liquidity or alternatives to net earnings as indicators of our operating performance or any other measures of performance derived in accordance with 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. This information should not be considered in isolation or as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP or other non-GAAP financial measures.

Adjusted EBITDA for the three months ended March 31, 2014 was $70.6 million, compared to $45.7 million for the three months ended March 31, 2013.

The following table reconciles net cash provided by operating activities to EBITDA and Adjusted EBITDA for the three-month periods ended March 31, 2014 and 2013:

	Three Months Ended March 31,
	2014			2013 As revised
	(Dollars in thousands)
Net cash provided by operating activities	$	68,076		$	18,216
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		19,176			14,336
Interest income		(111	)		(41	)
Income tax provision		6,320			4,269
Adjustments to reconcile net income or loss to net cash provided by operating activities (excluding depreciation and amortization)		(22,870	)		(28	)
EBITDA		70,591			36,752
Termination fee		—			8,979
Adjusted EBITDA	$	70,591		$	45,731
Net cash used in investing activities	$	(35,323	)	$	(98,244	)
Net cash provided by (used in) financing activities	$	(42,180	)	$	71,027

Capital Expenditures

Our capital expenditures primarily relate to two principal components: (i) the enhancement of our existing power plants and (ii) the development and construction of new power plants.

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

McGinness Hills Phase 2. We are currently developing the 30 MW McGinness Hills phase 2 project located in Lander County, Nevada. Field development is in process. We signed an amendment to the McGinness 20-year PPA with NV Energy to include the 30 MW phase 2. The new power plant is expected to come online in the first half of -2015.

Mammoth Complex. We are currently in the process of a refurbishment program for G3 plant at the Mammoth complex located in Mammoth Lakes, California. We plan to replace the old units of the G3 plant with new Ormat-manufactured equipment. We expect the replacement of the equipment to optimize the operation of the complex. We expect to complete the refurbishment in 2015.

Heber 1Power Plant. We are currently in the process of enhancing the Heber complex located in Imperial Valley, California, by adding new wells, decommissioning old wells and replacing part of the old equipment with new equipment. The replacement work is in process and expected to be completed in the second quarter of 2014 and will require a total plant outage of approximately eight weeks until May 15, 2014.

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

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. Permitting delays prevented substantial progress on the project site until late last year and have had a significant impact on the development plan and the economics of the project. As a result, in December 2011, we terminated the project’s PPA and the joint operating agreement with Nevada Power Company. We are not planning to invest material capital expenditures in this project in 2014.

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 SCE Wholesale Distribution Access Tariff Transition Cluster Generator Interconnection Process to deliver energy into the Southern California Edison system at the Casa Diablo Substation. We are not planning to invest material capital expenditures in this project in 2014.

We have estimated approximately $154.0 million in capital expenditures for the projects listed above, and for enhancement of our existing power plants, of which we have invested approximately $43.0 million as of March 31, 2014. We expect to invest $97.0 million of such total during the remainder of 2014 and the remaining $14.0 million thereafter.

In addition, we estimate approximately $93.0 million in additional capital expenditures in the remainder of 2014 to be allocated as follows: (i) $43.0 million in development of new projects; (ii) $20.0 million for maintenance capital expenditure of our operating power plants; (iii) $27.0 million in exploration activities in various leases for geothermal resources in which we have started the exploration activity; and (iv) $3.0 million in enhancement of our production facilities. In the aggregate, we estimate our total capital expenditures for the remainder of 2014 will be approximately $190.0 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.

One market risk to which power plants are typically exposed is the volatility of electricity prices. Our exposure to such market risk is currently limited because many of our long-term PPAs (except for the 25 MW PPA for the Puna complex and the PPAs of the Heber 1 and 2 power plants 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. Beginning in May 2012, the energy payments under the PPAs of the Heber 1 and 2 power plants 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 SRAC. A decline in the price of natural gas will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from natural gas, which in turn will reduce the variable energy rate that we may charge under the relevant PPA for these power plants. In October 2013 and March 2014, we entered into derivative transactions to reduce our exposure to the price of natural gas, under these PPAs, until March 31, 2015. 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 Hawaii Electric Light Company’s (HELCO) avoided costs. Likewise, in October 2013, we entered into derivative transaction to reduce our exposure to the price of oil, under the 25 MW PPA of the Puna complex, until December 31, 2014.

As of March 31, 2014, 87.4% of our consolidated long-term debt comprised a fixed rate debt and therefore was not subject to interest rate volatility risk. As of such date, 12.6% of our long-term debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. As of March 31, 2014, $131.3 million of our long-term debt remained subject to some floating 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 market risk due to changes in interest rates. Fixed rate securities may have their market value adversely impacted due to a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. Due in part to these factors, our future investment income may fall short of expectation due to changes in interest rates or we may suffer losses in principal if we are forced to sell securities that decline in market value due to changes in interest rates. However, because we classify our debt securities as “available-for-sale”, no gains or losses are recognized due to changes in interest rates unless such securities are sold prior to maturity or declines in fair value are determined to be other-than-temporary.

Another market risk to which we are exposed is potential adverse changes in foreign currency exchange rates, in particular the fluctuation of the U.S. dollar versus the NIS. 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. 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 sale 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 swap contracts on oil prices, put options on natural gas prices, long-term debt obligations, and foreign currency exchange forward contracts. The swap contracts on oil prices, 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, 2014 and December 31, 2013 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of March 31, 2014 and December 31, 2013 are presented below:

	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
Risk	March 31, 2014			December 31, 2013			March 31, 2014		December 31, 2013		Change in the Fair Value of
	(Dollars in thousands)
NGI Price	$	(7,773	)	$	(3,522	)	$	337	$	3,522	NGI Swap
NYMEX Heating Oil Price		(1,849	)		(3,442	)		3,174		3,442	NYMEX HO2 Swap
Foreign Currency		(2,346	)		(3,381	)		1,919		4,133	Foreign currency forward contracts
Interest Rate		(2,007	)		(2,562	)		2,094		2,690	OFC
Interest Rate		(1,201	)		(1,298	)		1,237		1,339	OrCal
Interest Rate		(5,366	)		(5,519	)		5,779		5,962	OFC 2
Interest Rate		(345	)		(379	)		353		388	Loan from DEG
Interest Rate		(11,433	)		(11,836	)		12,217		12,683	Loan from OPIC
Interest Rate		(291	)		(328	)		295		333	Loan from TCW
Interest Rate		(4,025	)		(4,349	)		4,101		4,438	Senior unsecured bonds

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 mitigating factors against any inflation risk.

In connection with the Electricity Segment, inflation may directly impact an expense incurred for the operation of our projects, hence increasing the overall operating cost to us. 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 plant, 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 determined 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, hence increasing our operating costs in that segment. In this segment, it is more likely that we will be able to offset part or all of the inflationary impact through our project pricing. With respect to power plants that we construct 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 Edison, HELCO, KPLC and 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.

Sierra Pacific Power Company and Nevada Power Company accounted for 15.3% and 15.5% of our total revenues for the three months ended March 31, 2014 and 2013, respectively.

KPLC accounted for 14.3% and 8.4% of our total revenues for the three months ended March 31, 2014 and 2013, respectively.

Southern California Edison accounted for 12.1% and 11.7% of our total revenues for the three months ended March 31, 2014 and 2013, respectively. Southern California Edison is also the power purchaser and revenue source for our Mammoth project, which we accounted for separately under the equity method of accounting through August 1, 2010.

HELCO accounted for 9.1% and 9.3% of our total revenues for the three months ended March 31, 2014 and 2013, 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, 2013, 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 the first quarter of 2014 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. Companies that placed qualifying renewable energy facilities in service during 2009, 2010 or 2011 or that began construction of qualifying renewable energy facilities during 2009, 2010 or 2011 and placed them in service by December 31, 2013, may choose to apply for a cash grant from the U.S. Treasury in an amount equal to the ITC. Likewise, the tax basis for depreciation will be reduced by 50% of the cash grant received. Under the ARRA, the U.S. Treasury is instructed to pay the cash grant within 60 days of the application or the date on which the qualifying facility is placed in service.

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. As a Benefited Enterprise, Ormat Systems was exempt from Israeli income taxes with respect to income derived from the first benefited investment for a period of two years that started in 2004, and thereafter such income was subject to reduced Israeli income tax rates, which could not exceed 25% for an additional five years until 2010. Ormat Systems was also exempt from Israeli income taxes with respect to income derived from the second benefited investment for a period of two years that started in 2007. Thereafter, such income is subject to reduced Israeli income tax rates which cannot exceed 25% for an additional five years until 2013 (see also below). These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and its affiliates are done on an arm’s length basis and that the management of Ormat Systems will be located in, and the control will be conducted from, Israel during the entire period of the tax benefits. A change in control of Ormat Systems would need to be reported to the Israel Tax Authority in order for Ormat Systems to maintain the tax benefits. 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. According to the amendment, the uniform tax rate applicable to the zone where the production facilities of Ormat Systems are located would be 15% in 2011 and 2012, 12.5% in 2013 and 16% in 2014 and thereafter. Under the transitory provisions of the new legislation, Ormat Systems had the option either to irrevocably comply with the new law while waiving benefits provided under the previous law or to continue to comply with the previous law during the transition period, with an option to move from the previous law to the new law at any stage. Ormat Systems decided to irrevocably comply with the new law starting in 2011.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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, 2014, 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 2014 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

In December 2012, Laborers’ International Union of North America Local Union No. 783 (“LiUNA”), an organized labor union, filed a petition in Mono County Superior Court, naming Mono County, California and the Company as defendant and real party in interest, respectively. The petitioners' brought this action to challenge the November 13, 2012 decision of the Mono County Board of Supervisors in adopting Resolutions No. 12-78, denying petitioners’ administrative appeal of the Planning Commission's approval of Conditional Use Permit (“CUP”), adoption of findings under the California Environmental Quality Act (“CEQA”) and adoption of the final environmental impact report (“EIR”) for the Mammoth enhancement. The petition asks the court to set aside the approval of the CUP and adoption of the EIR and cause a new EIR to be prepared and circulated.

In January 2014, the Company learned that two former employees alleged in a “qui tam” complaint filed in the United States District Court for the Southern District of California that the Company submitted fraudulent applications and certifications to obtain grants. While the United States Department of Justice has declined to intervene, the former employees may proceed on their own. The Company does not believe that the allegations of the lawsuit have any merit and will defend itself vigorously if served.

ITEM 1A. RISK FACTORS

A comprehensive discussion of our risk factors is included in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2013 filed with the SEC on February 28, 2014.

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

There were no unregistered sales of equity securities of the Company during the first quarter of 2014.

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, 2014

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. Registration Statement on Form S-1 (File No. 333-117527) to 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. Current Report on Form 8-K to 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. Current Report on Form 8-K to the Securities and Exchange Commission on January 30, 2013.

4.1	Form of Common Share Stock Certificate, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to 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. Registration Statement on Form S-1 (File No. 333-117527) to 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. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to 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. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to 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. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to 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 Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Current Report on Form 8-K to 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 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. Current Report on Form 8-K to 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. Quarterly Report on Form 10-Q to 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. Quarterly Report on Form 10-Q to 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. Current Report on Form 8-K to the Securities and Exchange Commission on December 1, 2011.

10.2	Employment Agreement, dated as of February 11, 2014, between Ormat Technologies, Inc. and Isaac Angel, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 11, 2014.

10.3	Amended and Restated Ormat Technologies, Inc. 2012 Incentive Compensation Plan, incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 11, 2014.

10.4	Form of Stock Option Agreement to Amended and Restated Ormat Technologies, Inc. 2012 Incentive Compensation Plan, incorporated by reference to Exhibit 10.31.2 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 28, 2014.

10.5	Form of Freestanding Stock Appreciation Right Agreement to Amended and Restated Ormat Technologies, Inc. 2012 Incentive Compensation Plan, incorporated by reference to Exhibit 10.31.3 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 28, 2014.

10.6	Membership Interest Purchase and Sale Agreement, dated March 26, 2014, between RET Holdings, LLC and Ormat Nevada Inc., incorporated by reference to Exhibit 10 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on March 31, 2014.

10.7	JBIC Facility Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., OrSarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited, Japan Bank for International Cooperation and Mizuho Bank, Ltd., filed herewith.

10.8	Common Terms Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., OrSarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited, Japan Bank for International Cooperation, Asian Development Bank, The Bank of Tokyo-Mitsubishi UFJ, Ltd., ING Bank N.V., Tokyo Branch, National Australia Bank Limited, Mizuho Bank, Ltd., Mizuho Bank (USA), Pt. Bank Mizuho Indonesia, Société Générale, Société Générale Tokyo Branch, and Sumitomo Mitsui Banking Corporation, filed herewith.

10.9	Covered Lenders Facility Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., Orsarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited, The Bank of Tokyo-Mitsubishi UFJ, Ltd., ING Bank N.V., Tokyo Branch, National Australia Bank Limited, Société Générale, Tokyo Branch, and Sumitomo Mitsui Banking Corporation, filed herewith.

10.10	ADB Facility Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., OrSarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited and Asian Development Bank, filed herewith.

10.11	Ormat Equity Support Deed, dated March 28, 2014, by and among Ormat International, Inc., Ormat Holding Corp., OrPower 11 Inc., OrSarulla Inc., Sarulla Operations Ltd, Mizuho Bank, Ltd. and Mizuho Bank (USA), filed herewith.

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.