Edgar Filing: ORMAT TECHNOLOGIES, INC.

Large accelerated filer ¨

Accelerated filer þ

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2013

¨	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 þ 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 þ 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):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ 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 9, 2013, the number of outstanding shares of common stock, par value $0.001 per share, was 45,430,886.

ORMAT TECHNOLOGIES, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2013



PART I — FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	4
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	20
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	49
ITEM 4.	CONTROLS AND PROCEDURES	49

PART II — OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	50
ITEM 1A.	RISK FACTORS	50
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	50
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	51
ITEM 4.	MINE SAFETY DISCLOSURES	51
ITEM 5.	OTHER INFORMATION	51
ITEM 6.	EXHIBITS	52
SIGNATURES		53

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 FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2013			December 31, 2012
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	57,627		$	66,628
Short-term bank deposit		3,015			3,010
Restricted cash, cash equivalents and marketable securities (all related to variable interest entities (“VIEs”))		124,887			76,537
Receivables:
Trade		42,779			55,680
Related entity		397			373
Other		10,962			8,632
Due from Parent		364			311
Inventories		18,258			20,669
Costs and estimated earnings in excess of billings on uncompleted contracts		10,135			9,613
Deferred income taxes		1,238			637
Prepaid expenses and other		30,151			34,144

Total current assets		299,813			276,234
Unconsolidated investments		2,789			2,591
Deposits and other		39,670			36,187
Deferred income taxes		52,939			53,989
Deferred charges		35,217			35,351
Property, plant and equipment, net ($1,144,289 and $1,162,606 related to VIEs, respectively)		1,207,410			1,226,758
Construction-in-process ($282,075 and $253,775 related to VIEs, respectively)		439,301			396,141
Deferred financing and lease costs, net		31,748			31,371
Intangible assets, net		34,681			35,492

Total assets	$	2,143,568		$	2,094,114

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	78,406		$	98,001
Deferred income taxes		20,392			20,392
Billings in excess of costs and estimated earnings on uncompleted contracts		21,749			25,408
Current portion of long-term debt:
Limited and non-recourse (all related to VIEs):
Senior secured notes		29,408			28,231
Other loans		15,494			11,453
Full recourse:		28,760			28,649

Total current liabilities		194,209			212,134
Long-term debt, net of current portion:
Limited and non-recourse (all related to VIEs):
Senior secured notes		298,944			312,926
Other loans		281,930			242,815
Full recourse:
Senior unsecured bonds (plus unamortized premium based upon 7% of $1,359)		250,827			250,904
Other loans		78,882			82,344
Revolving credit lines with banks		88,349			73,606
Liability associated with sale of tax benefits		77,216			51,126
Deferred lease income		65,696			66,398
Deferred income taxes		45,118			45,059
Liability for unrecognized tax benefits		7,795			7,280
Liabilities for severance pay		23,501			22,887
Asset retirement obligation		19,665			19,289
Other long-term liabilities		4,917			5,148

Total liabilities		1,437,049			1,391,916

Commitments and contingencies
Equity:
The Company’s stockholders’ equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 45,430,886 shares issued and outstanding as of March 31, 2013 and December 31, 2012		46			46
Additional paid-in capital		733,683			732,140
Accumulated deficit		(39,717	)		(37,735	)
Accumulated other comprehensive income		609			651

		694,621			695,102
Noncontrolling interest		11,898			7,096

Total equity		706,519			702,198

Total liabilities and equity	$	2,143,568		$	2,094,114

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,
	2013			2012
	(In thousands, except per share data)
Revenues:
Electricity	$	71,102		$	82,247
Product		50,608			50,105

Total revenues		121,710			132,352

Cost of revenues:
Electricity		56,937			57,931
Product		37,041			34,627

Total cost of revenues		93,978			92,558

Gross margin		27,732			39,794
Operating expenses:
Research and development expenses		1,000			1,048
Selling and marketing expenses		11,571			4,922
General and administrative expenses		6,650			7,314
Write-off of unsuccessful exploration activities		—			768

Operating income		8,511			25,742
Other income (expense):
Interest income		41			388
Interest expense, net		(15,863	)		(14,878	)
Foreign currency translation and transaction gains		1,682			14
Income attributable to sale of tax benefits		3,532			2,517
Other non-operating income (expense), net		1,417			(161	)

Income (loss), before income taxes and equity in losses of investees		(680	)		13,622
Income tax provision		(1,217	)		(5,457	)
Equity in losses of investees		—			(140	)

Net income (loss)		(1,897	)		8,025
Net income attributable to noncontrolling interest		(85	)		(130	)

Net income (loss) attributable to the Company’s stockholders	$	(1,982	)	$	7,895

Comprehensive income (loss):
Net income (loss)		(1,897	)		8,025
Other comprehensive income (loss), net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(42	)		(47	)
Change in unrealized gains or losses on marketable securities available-for-sale		—			(30	)

Comprehensive income (loss)		(1,939	)		7,948
Comprehensive income attributable to noncontrolling interest		(85	)		(130	)

Comprehensive income (loss) attributable to the Company’s stockholders	$	(2,024	)	$	7,818

Earnings (loss) per share attributable to the Company’s stockholders — basic and diluted	$	(0.04	)	$	0.17

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

Diluted		45,431			45,437

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
	Common Stock				Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income			Total			Noncontrolling Interest			Total Equity
	Shares		Amount		Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income			Total			Noncontrolling Interest			Total Equity
	(In thousands, except per share data)
Balance at December 31, 2011		45,431	$	46	$	725,746	$	172,331		$	595		$	898,718		$	7,926		$	906,644
Stock-based compensation		—		—		1,657		—			—			1,657			—			1,657
Cash paid to noncontrolling interest		—		—		—		—			—			—			(212	)		(212	)
Net income		—		—		—		7,895			—			7,895			130			8,025
Other comprehensive income (loss), net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $29)		—		—		—		—			(47	)		(47	)		—			(47	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $0)		—		—		—		—			(30	)		(30	)		—			(30	)

Balance at March 31, 2012		45,431	$	46	$	727,403	$	180,226		$	518		$	908,193		$	7,844		$	916,037


Balance at December 31, 2012		45,431	$	46	$	732,140	$	(37,735	)	$	651		$	695,102		$	7,096		$	702,198
Stock-based compensation		—		—		1,543		—			—			1,543			—			1,543
Cash paid to noncontrolling interest		—		—		—		—			—			—			(189	)		(189	)
Increase in noncontrolling interest due to sale of equity interest in ORTP LLC		—		—		—		—			—			—			4,906			4,906
Net (loss) income		—		—		—		(1,982	)		—			(1,982	)		85			(1,897	)
Other comprehensive income (loss), net of related taxes:
Amortization of unrealized 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		45,431	$	46	$	733,683	$	(39,717	)	$	609		$	694,621		$	11,898		$	706,519

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,
	2013			2012
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	(1,897	)	$	8,025
Adjustments to reconcile net income or loss to net cash provided by operating activities:
Depreciation and amortization		23,137			24,744
Amortization of premium from senior unsecured bonds		(77	)		(78	)
Accretion of asset retirement obligation		376			413
Stock-based compensation		1,543			1,657
Amortization of deferred lease income		(671	)		(671	)
Income attributable to sale of tax benefits, net of interest expense		(1,133	)		(869	)
Equity in losses of investees		—			140
Mark-to-market of derivative instruments		5,760			—
Write-off of unsuccessful exploration activities		—			768
Loss on severance pay fund asset		(372	)		(641	)
Deferred income tax provision		668			4,460
Liability for unrecognized tax benefits		515			534
Deferred lease revenues		(31	)		37
Other		(819	)		—
Changes in operating assets and liabilities, net of amounts acquired:
Receivables		10,571			9,086
Costs and estimated earnings in excess of billings on uncompleted contracts		(522	)		(4,652	)
Inventories		2,411			(4,659	)
Prepaid expenses and other		(144	)		(1,191	)
Deposits and other		(2,981	)		(169	)
Accounts payable and accrued expenses		(14,765	)		4,877
Due from/to related entities, net		(24	)		(20	)
Billings in excess of costs and estimated earnings on uncompleted contracts		(3,659	)		(949	)
Liabilities for severance pay		614			1,127
Other long-term liabilities		(231	)		(232	)
Due from/to Parent		(53	)		137

Net cash provided by operating activities		18,216			41,874

Cash flows from investing activities:
Return of investment in unconsolidated investments		(5	)		—
Marketable securities, net		—			2,772
Net change in restricted cash, cash equivalents and marketable securities		(48,350	)		376
Capital expenditures		(49,561	)		(65,430	)
Investment in unconsolidated companies		(198	)		(115	)
Increase in severance pay fund asset, net of payments made to retired employees		(130	)		64

Net cash used in investing activities		(98,244	)		(62,333	)

Cash flows from financing activities:
Proceeds from long-term loans		45,000			—
Proceeds from the sale of limited liability company interest in ORTP, LLC, net of transaction costs		32,197			—
Purchase of OFC Senior Secured Notes		(11,888	)		—
Proceeds from revolving credit lines with banks		597,193			182,641
Repayment of revolving credit lines with banks		(582,450	)		(169,048	)
Repayments of long-term debt		(5,195	)		(3,845	)
Cash paid to noncontrolling interest		(3,783	)		(4,229	)
Deferred debt issuance costs		(47	)		(366	)

Net cash provided by financing activities		71,027			5,153

Net change in cash and cash equivalents		(9,001	)		(15,306	)
Cash and cash equivalents at beginning of period		66,628			99,886

Cash and cash equivalents at end of period	$	57,627		$	84,580

Supplemental non-cash investing and financing activities:
Decrease in accounts payable related to purchases of property, plant and equipment	$	(4,950	)	$	(11,509	)

Accrued liabilities related to financing activities	$	—		$	513

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, 2013, the consolidated results of operations and comprehensive income (loss) for the three-month periods ended March 31, 2013 and 2012 and the consolidated cash flows for the three-month periods ended March 31, 2013 and 2012.

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, 2013 are not necessarily indicative of the results to be expected for the year ending December 31, 2013.

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, 2012. The condensed consolidated balance sheet data as of December 31, 2012 was derived from the audited consolidated financial statements for the year ended December 31, 2012, 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.

Other comprehensive income

As of March 31, 2013, the Company classified $42,000 from other comprehensive income, of which $70,000 was recorded to reduce interest expense and $28,000 was recorded against the income tax provision in the condensed consolidated statements of operations and comprehensive income (loss).

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 agreement (“PPAs”) were terminated and a termination fee of $9.0 million was recorded in this quarter in selling and marketing expenses. 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.

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, 2013 and December 31, 2012, the Company

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

had deposits totaling $33,435,000 and $41,231,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At March 31, 2013 and December 31, 2012, the Company’s deposits in foreign countries amounted to approximately $32,985,000 and $33,215,000, respectively.

At March 31, 2013 and December 31, 2012, accounts receivable related to operations in foreign countries amounted to approximately $14,692,000 and $17,606,000, respectively. At March 31, 2013 and December 31, 2012, accounts receivable from the Company’s primary customers amounted to approximately 65.9% and 45.0%, respectively, of the Company’s accounts receivable.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 21.1% and 12.9% of the Company’s total revenues for the three months ended March 31, 2013 and 2012, respectively.

Southern California Edison accounted for 11.4% and 19.7% of the Company’s total revenues for the three months ended March 31, 2013 and 2012, respectively.

Hawaii Electric Light Company accounted for 9.1% and 9.3% of the Company’s total revenues for the three months ended March 31, 2013 and 2012, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 8.2% and 7.3% of the Company’s total revenues for the three months ended March 31, 2013 and 2012, 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.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements effective in the three-month period ended March 31, 2013

Disclosures about Offsetting Assets and Liabilities

In December 2011, the Financial Accounting Standards Board (“FASB”) issued accounting guidance to amend the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve the comparability of balance sheets prepared under GAAP and those prepared under International Financial Reporting Standards. In January 2013, the FASB issued additional guidance on the scope of these disclosures. The revised disclosure guidance applies to derivative instruments and securities borrowing and lending transactions that are subject to an enforceable master netting arrangement or similar agreement. The revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning January 1, 2013. As this guidance only imposes additional disclosure requirements, its adoption did not have a material impact on the Company’s consolidated financial statements.

Amounts Reclassified Out of Accumulated Other Comprehensive Income

In February 2013, the FASB updated accounting guidance to add new disclosure requirements for items reclassified out of accumulated other comprehensive income. Although the update does not change the current requirements for reporting net income or other comprehensive income in financial statements, it does require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

presented or in the notes thereto, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount reclassified is required to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. The amendments included in this guidance are required to be applied on a retrospective basis for interim and annual periods beginning January 1, 2013. As this guidance only imposes additional disclosure requirements, its adoption did not have a material impact on the Company’s consolidated financial statements.

NOTE 3 — INVENTORIES

Inventories consist of the following:


	March 31, 2013		December 31, 2012
	(Dollars in thousands)
Raw materials and purchased parts for assembly	$	6,128	$	9,775
Self-manufactured assembly parts and finished products		12,130		10,894

Total	$	18,258	$	20,669

NOTE 4 — UNCONSOLIDATED INVESTMENTS

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


	March 31, 2013		December 31, 2012
	(Dollars in thousands)
Sarulla	$	2,789	$	2,591

The Sarulla Project

The Company is a 12.75% member of a 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 (“PGE”), the concession holder for the project has provided the consortium with the right to use the geothermal field, and under the ESC, PT PLN, the state electric utility will be the off-taker at Sarulla for a period of 30 years. In addition to its equity holdings in the consortium, the Company designed the Sarulla plant and will supply its Ormat Energy Converters (“OECs”) to the power plant.

The consortium has started preliminary testing and development activities at the site and recently 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. Construction is expected to begin after the consortium obtains financing, which is expected to take approximately one year from the signing of the JOC and ESC. The first phase is scheduled to commence in 2016, and the remaining two phases are scheduled to be completed in stages within 18 months thereafter.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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.

Watts & More Ltd.

In December 2012, the Company acquired additional shares in Watts & More Ltd. (“W&M”) and as a result holds 60% of W&M’s outstanding ordinary shares and W&M was consolidated as of December 31, 2012.

The Company’s investment in W&M prior to its consolidation was not significant for the related period presented in these consolidated financial statements.

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, 2013 and December 31, 2012 for financial assets and liabilities measured at fair value by level within the fair value hierarchy, as well as cost or amortized cost. As required by the fair value measurement guidance, assets and liabilities are classified in their entirety based on the lowest level of inputs that is significant to the fair value measurement.


	Cost or Amortized Cost at March 31, 2013		Fair Value at March 31, 2013
	Cost or Amortized Cost at March 31, 2013		Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	91,551	$	91,551		$	91,551	$	—		$	—
Derivatives:
Put options on oil price⁽¹⁾		—		845			—		845			—
Currency forward contracts⁽²⁾		—		2,712			—		2,712			—
Liabilities
Current liabilities:
Swap transaction on natural gas price⁽³⁾		—		(1,623	)		—		(1,623	)		—

	$	91,551	$	93,485		$	91,551	$	1,934		$	—

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Cost or Amortized Cost at December 31, 2012		Fair Value at December 31, 2012
	Cost or Amortized Cost at December 31, 2012		Total		Level 1		Level 2		Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	54,298	$	54,298	$	54,298	$	—	$	—
Derivatives:
Put options on oil price⁽¹⁾		—		1,842		—		1,842		—
Currency forward contracts⁽²⁾		—		1,675		—		1,675		—
Swap transaction on natural gas price⁽³⁾		—		2,804		—		2,804		—
Swap transaction on oil price⁽⁴⁾		—		336		—		336		—

	$	54,298	$	60,955	$	54,298	$	6,657	$	—

⁽¹⁾

This amount relates to derivatives which represent European put transactions 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” 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⁾

These amounts relate 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” in the condensed consolidated statement of operations and comprehensive income (loss).

⁽³⁾

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 “accounts payable and accrued expenses” and “prepaid expenses and other” in March 31, 2013 and December 31, 2012, respectively, 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).

⁽⁴⁾

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” 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).

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:


Derivatives not designated as hedging instruments	Location of gain (loss) recognized	Amount of gain (loss) recognized
		Three Months Ended March 31,
		2013			2012
		(Dollars in thousands)
Put options on oil price	Electricity revenues	$	(927	)	$	—
Swap transaction on oil price	Electricity revenues		(295	)		—
Swap transaction on natural gas price	Electricity revenues		(3,390	)		—
Currency forward contracts	Foreign currency translation and transaction gains		2,035			673

		$	(2,577	)	$	673

The Company’s financial assets measured at fair value (including restricted cash accounts) at March 31, 2013 and December 31, 2012 include short-term bank deposits and money market funds (which are included in cash equivalents). Those assets are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.

There were no transfers of assets or liabilities between Level 1 and Level 2 during the three months ended March 31, 2013.

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


	Fair Value				Carrying Amount
	March 31, 2013		December 31, 2012		March 31, 2013		December 31, 2012
	(Dollars in millions)				(Dollars in millions)
Olkaria III Loan - DEG	$	49.3	$	48.8	$	47.4	$	47.4
Amatitlan Loan		37.9		38.9		33.6		34.3
Senior Secured Notes:
Ormat Funding LLC (“OFC”)		93.2		105.0		101.3		114.1
OrCal Geothermal LLC (“OrCal”)		78.5		77.3		76.5		76.5
OFC 2 LLC (“OFC 2”)		131.2		131.2		150.5		150.5
Senior unsecured bonds		271.0		273.2		250.8		250.9
Loans from institutional investors		26.1		27.7		25.3		27.0

The fair value of OFC Senior Secured Notes is determined using observable market prices as these securities are traded. The fair value of other long-term debt is determined by a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of estimated current borrowing rates. The fair value of revolving lines of credit is determined using 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.

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 March 31, 2013:


	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III Loan - DEG	$	—	$	—	$	49.3	$	49.3
Amatitlan Loan		—		—		37.9		37.9
Senior Secured Notes:
OFC		—		93.2		—		93.2
OrCal		—		—		78.5		78.5
OFC 2		—		—		131.2		131.2
Senior unsecured bonds		—		—		271.0		271.0
Loan from institutional investors		—		—		26.1		26.1
Other long-term debt		—		35.0		—		35.0
Revolving credit lines with banks		—		88.3		—		88.3
Deposits		22.2		—		—		22.3

NOTE 6 — INTEREST EXPENSE, NET

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


	Three Months Ended March 31,
	2013			2012
	(Dollars in thousands)
Interest related to sale of tax benefits	$	2,717		$	1,837
Other		15,843			16,468
Less — amount capitalized		(2,697	)		(3,427	)

	$	15,863		$	14,878

NOTE 7 — 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.

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,
	2013		2012
	(In thousands)
Weighted average number of shares used in computation of basic earnings (loss) per share		45,431		45,431
Add:
Additional shares from the assumed exercise of employee stock-based awards		—		6

Weighted average number of shares used in computation of diluted earnings (loss) per share		45,431		45,437

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

In 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 5,161,802 and 5,134,381 for the three months ended March 31, 2013 and 2012, respectively.

NOTE 8 — 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, 2013:
Net revenues from external customers	$	71,102		$	50,608	$	121,710
Intersegment revenues		—			6,581		6,581
Operating income (loss)		(487	)		8,998		8,511
Segment assets at period end*		2,046,817			96,751		2,143,568
* Including unconsolidated investments		2,789			—		2,789
Three Months Ended March 31, 2012:
Net revenues from external customers	$	82,247		$	50,105	$	132,352
Intersegment revenues		—			12,966		12,966
Operating income		15,875			9,867		25,742
Segment assets at period end*		2,227,064			100,705		2,327,769
* Including unconsolidated investments		2,330			1,402		3,732

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


	Three Months Ended March 31,
	2013			2012
	(Dollars in thousands)
Operating income	$	8,511		$	25,742
Interest income		41			388
Interest expense, net		(15,863	)		(14,878	)
Foreign currency translation and transaction gains		1,682			14
Income attributable to sale of equity interest		3,532			2,517
Other non-operating (expense), net		1,417			(161	)

Total income (loss), before income taxes and equity in losses of investees	$	(680	)	$	13,622

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

NOTE 9 — COMMITMENTS AND CONTINGENCIES

On December 24, 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 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 I replacement project. 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.

On January 4, 2012, the California Unions for Reliable Energy (“CURE”) filed a petition in Alameda Superior Court, naming the California Energy Commission (“CEC”) and the Company as defendant and real party in interest, respectively. The petition asked the court to order the CEC to vacate its decision which denied, with prejudice, the complaint filed by CURE against the Company with the CEC. The CURE complaint alleged that the Company’s North Brawley Project and East Brawley Project both exceed the CEC’s 50 MW jurisdictional threshold and therefore are subject to the CEC licensing authority rather than Imperial County licensing authority. In addition, the CURE petition asks the court to investigate and halt any ongoing violation of the Warren Alquist Act by the Company, and to award CURE attorney’s fees and costs. As to North Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider provisions of the County permit for North Brawley, which CURE contends authorizes the Company to build a generating facility with a number of OECs capable of generating more than 50 MW. As to East Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider the conditional use permit application for East Brawley, which CURE contends shows that the Company requested authorization to build a facility with a number of OECs capable of generating more than 50 MW.

The court held two hearings and on November 15, 2012 CURE’s petition was denied. Any appeal of the court’s decision had to be filed by March 4, 2013, and no appeal was filed.

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 10 — INCOME TAXES

The Company’s effective tax rate for the three months ended March 31, 2013 and 2012 was 179.0% and 40.1%, respectively. The effective tax rate differs from the federal statutory rate of 35% for the three months ended March 31, 2013 primarily due to the $8.6 million increase in the 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), offset by (i) lower tax rates in Israel; and (ii) 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, 2013 and 2012 was $951,000 and $1,277,000, respectively ($0.02 and $0.03 per share of common stock, respectively).

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

At December 31, 2012, the Company had U.S. federal NOL carryforwards of approximately $267.6 million and state NOL carryforwards of approximately $193.4, net of valuation allowance of $129.7 million, available to reduce future taxable income, which expire between 2021 and 2032 for federal NOLs and between 2013 and 2032 for state NOLs. Investment tax credits in the amount of $2.0 million at December 31, 2012 are available for a 20-year period and expire between 2022 and 2024. Production tax credits (“PTCs”) in the amount of $69.0 million at December 31, 2012 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 valuation allowance in the amount of $80.9 million was recorded against the U.S. deferred tax assets as of December 31, 2012 as, at this point in time, it is more likely than not that the deferred tax assets will not be realized. Such valuation allowance was increased to $89.5 million as of March 31, 2013. 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 consolidated statement of operations and comprehensive income (loss).

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)

company) of the Benefited Enterprise. The number of new employees for these purposes will be determined in comparison to the number of employees employed by the Benefited Enterprise at the end of 2011. Such investment must be made over a period of five years commencing in the tax year in which the election is made. The amount of the required investment is determined pursuant to a formula set forth in the new legislation. A company that makes the election allowed under the new legislation cannot later undo its election. As of the date of this quarterly report Ormat Systems has not yet decided whether to make such election.

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


	Three Months Ended March 31,
	2013		2012
	(Dollars in thousands)
Balance at beginning of period	$	7,280	$	5,875
Additions based on tax positions taken in prior years		104		142
Additions based on tax positions taken in current year		411		392

Balance at end of period	$	7,795	$	6,409

NOTE 11 — ORTP TAX MONETIZATION TRANSACTION

On January 24, 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 ORTP 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 and total approximately $8.7 million.

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.

The Class B membership units entitle the holder to 5% (allocation of income and loss) and 2.5% (allocation of cash) residual economic interest in ORTP. The 5% and 2.5% residual interest commences on achievement by

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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% 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.

For the three months ended March 31, 2013, the impact of the ORTP transaction was a net gain of $1.1 million on the Company’s condensed consolidated statement of operations and comprehensive income (loss). Revenues of $2.2 million were recognized in income attributable to the sale of tax benefits and a $1.1 million finance charge was recognized in interest expense.

NOTE 12 — SUBSEQUENT EVENTS

On April 3, 2013, the Company granted its Chief Financial Officer stock options to purchase 120,000 shares of common stock under the Company’s 2012 Incentive Compensation Plan. The exercise price of each stock option was $20.54 per share, which represented the fair market value of the Company’s common stock on the date of the grant. Such stock options will expire six years from the date of grant and will vest from the grant date in equal annual installments over four years.

On April 29, 2013, the Company’s wholly owned subsidiary, ORNI 47, entered into a 20-year PPA with Southern California Public Power Authority to deliver electricity from its Wild Rose geothermal power plant in Mineral County, Nevada.

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 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 and other nature disasters;

•

the impact of recent and future federal and state 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 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 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, 2012 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, 2012 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. We have expanded our activities in the Electricity Segment to include the ownership and operation of power plants that produce electricity generated by Solar PV systems that we do not manufacture; 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, Kenya, and Nicaragua, as well as recovered energy generation plants in the United States.

For the three months ended March 31, 2013, our total revenues decreased by 8.0% (from $132.4 million to $121.7 million) over the corresponding period in 2012.

For the three months ended March 31, 2013, Electricity Segment revenues were $71.1 million, compared to $82.2 million for the three months ended March 31, 2012, a decrease of 13.6%, while Product Segment revenues for the three months ended March 31, 2013 were $50.6 million, compared to $50.1 million during the three months ended March 31, 2012, an increase of 1.0%.

During the three months ended March 31, 2013 and 2012, our consolidated power plants generated 1,083,618 megawatt hours (MWh) and 1,040,044 MWh, respectively.

For the three months ended March 31, 2013, our Electricity Segment represented approximately 58.4% of our total revenues, while our Product Segment represented approximately 41.6% of our total revenues. For the three months ended March 31, 2012, our Electricity Segment represented approximately 62.1% of our total revenues, while our Product Segment represented approximately 37.9% of our total revenues.

For the three months ended March 31, 2013, approximately 69.8% 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:

•

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 G2 power plant in the Mammoth complex (the California Standard Offer #4 (SO#4) PPAs), change based primarily on fluctuations in natural gas prices.

•

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 natural gas and oil until December 31, 2013 by entering into derivatives contracts. In the first quarter of 2013, we recorded a $4.6 million reduction in electricity revenues related to these contracts.

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 the timely delivery of our products, performance quality of our products, and costs actually incurred to complete customer orders compared to the costs originally budgeted for such orders.

Recent Developments

The most significant developments in our company and business since January 1, 2013 are described below:

•

On May 3, 2013, we reached commercial operation of Plant 2 in the Olkaria III complex in Naivasha, Kenya, increasing our total worldwide generating capacity by 36 MW to 611 MW. The power generated in the Olkaria III complex is sold under a 20-year PPA with Kenya Power and Lighting Company Limited (KPLC). We financed the new plant and the prior existing two phases of the complex, which have been operating at full capacity since they were completed in 2000 and 2009, respectively, with a $265 million debt facility, provided by the Overseas Private Investment Corporation, an agency of the United States government (OPIC).

•

On April 29, 2013, we entered into a 20-year PPA with Southern California Public Power Authority (SCPPA) to deliver electricity from our Wild Rose geothermal power plant in Mineral County, Nevada. We will sell the power to SCPPA at $99 per MWh with no annual escalation, and SCPPA will resell the power to the Los Angeles Department of Water and Power (LADWP) and Burbank Water and Power (BWP). Electricity from Wild Rose geothermal power plant will be transmitted to LADWP and BWP through NV Energy Inc.’s transmission system.

•

On April 4, 2013, Sarulla Operations Ltd. (SOL) signed a Joint Operating Contract (JOC) and Energy Sales Contract (ESC) for the 330 MW Sarulla geothermal power project in Tapanuli Utara, North Sumatra in Indonesia. We designed the plant and will supply our Ormat Energy Converters (OEC) to the power plant, as a result of which we expect to recognize revenues of approximately $254 million related to the equipment sales over the construction period. In addition, through our subsidiary Ormat International, Inc., we hold a 12.75% equity stake in SOL, which owns and operates the Sarulla project. Other members of the consortium include Medco Energi Internasional Tbk (Medco); Itochu Corporation (Itochu); and Kyushu Electric Power Co. Inc (Kyushu).

The consortium has started preliminary testing and development activities at the site and recently signed an engineering procurement and construction agreement (EPC) with an unrelated third party. Construction is expected to begin after the consortium obtains financing, which is expected to take approximately one year from the signing of the JOC and ESC. The first phase is scheduled to commence operation in 2016, with the remaining two phases scheduled to be completed in stages within 18 months thereafter.

The project is expected to obtain construction and term loans under a non-recourse or limited-recourse financing package of direct loans from the Japan Bank for International Cooperation (JBIC) and the Asian Development Bank (ADB), as well as loans to be provided by five commercial banks (the MLAs). The MLAs are expected to be backed by political risk guarantees from JBIC.

•

On April 1, 2013, we began to sell geothermal power from the G3 plant in the Mammoth Complex in California to Pacific Gas & Electric (PG&E) under a new 20-year PPA for up to 14 MW. Deliveries under a separate PPA for up to 7.5 MW of geothermal power from the G1 plant in the Mammoth complex are expected to start by the end of 2013. On March 15, 2013, we finalized the agreement with Southern California Edison (SCE), by which the current G1 and G3 SO#4 PPAs were terminated and, in connection therewith, we paid a termination fee of approximately $9.0 million. Under the agreement, we will continue to sell power from G2, the third plant of the Mammoth complex, under its existing PPA with SCE, with the term of the contract extended by an additional six years until early 2027.

•

On January 28, 2013, Ormat Nevada, our wholly owned subsidiary, and JP Morgan (JPM) entered into a tax equity partnership transaction involving certain geothermal power plants in California and Nevada. As part of the transaction, Ormat Nevada transferred the plants into ORTP, LLC (ORTP), a new wholly owned subsidiary, and sold an interest in ORTP to JPM. In connection with the closing, JPM paid to Ormat Nevada approximately $35.7 million and will make additional payments to ORTP based on the value of production tax credits (PTCs) generated by the portfolio over time that are expected to be made until December 31, 2016 and add up to approximately $8.7 million.

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 relative to fossil fuel generation. This has partly been due to increasing natural gas and oil prices during much of this period and, equally important, 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 PTC 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. The future demand for energy generated from geothermal and other renewable resources in the United States is driven by further commitment and implementation of the renewable portfolio standards as well as further introduction of tax incentives. Our operations and 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 affected by the following trends, factors and uncertainties:

•

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.

•

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 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.

•

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 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 addition, several states and regions are already addressing climate change. 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-two other U.S. states have set GHG emissions targets or 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. The CPUC authorized the utilities to procure 1,299 MW through the RAM program, a procurement mechanism for renewable distributed generation projects greater than 3 MW and up to 20 MW, by holding four auctions over two years. We expect that in future years the additional demand for renewable energy from utilities in California, driven by the impact of the increase in California’s RPS, will outpace a possible reduction in general demand for energy (if any) due to the effect of economic conditions.

•

Outside of the United States, 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.

•

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 baseload electricity, such as geothermal-based energy, will continue to be a leading source of renewable energy in areas with commercially viable geothermal resource. In the geothermal industry, we are experiencing a notable decrease in competition, specifically in the acquisition of geothermal leases. The reduced level of competition has contributed to a decrease in lease costs.

•

In the Product Segment, we expect increased competition from binary power plant equipment suppliers. While we believe that we have a distinct competitive advantage based on our accumulated experience and current worldwide share of installed binary generation capacity (which is in excess of 90%), 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.

•

North America is the largest and most developed natural gas market in the world. As recently as five years ago, the region was considered to be short on supply, with an expected need to import significant volumes of LNG from the international gas market to balance supply with expected demand. The rise of shale gas production over the last four years has significantly changed the natural gas market landscape in North America. The unexpected growth in supply at increasingly lower costs has come at a time when the U.S. economy has been facing constrained demand growth for natural gas. The current low natural gas price level has led some producers to shut-in wells and reduce output, which in turn may increase natural gas prices. Among other things, the natural gas supply growth has led to an increased interest in exporting natural gas from the U.S. in the form of LNG. Various natural gas companies and other project sponsors have recently applied and, in some cases, already received an export license to export LNG to countries with which the U.S. has a free trade agreement providing comity in trading natural gas (FTA-nations) and to other non-FTA nations. At the same time,

environmentalists, regulators, natural gas companies and the public have been focusing more attention on the potential environmental impacts associated with natural gas fracking, including possible chemical leakage, ground water contamination and other effects, which may slow development in some areas. 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.

•

Our 25 MW PPA for the Puna complex has a monthly variable energy rate based on the local utility’s avoided costs. A decrease in the price of oil will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from oil, which will result in a reduction of the energy rate that we may charge under this PPA and under any other variable energy rate in PPAs that we may enter into in the future. We have entered into put contracts to reduce our exposure to fluctuations in the energy rate caused by fluctuations in oil prices through December 31, 2013. Our use of derivative instruments for this purpose has increased, and likely will continue to increase volatility in revenues, net profit and certain other line items in our financial statements due to applicable accounting standards.

•

Our PPAs for the Ormesa complex, G2 power plant in the Mammoth complex and the Heber 1 and 2 power plants in the Heber complex 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. These PPAs may be impacted by fluctuations in natural gas prices. We have entered into swap transactions to reduce our exposure to fluctuations in natural gas prices through December 31, 2013. Our use of derivative instruments for this purpose has increased, and likely will continue to increase volatility in revenues, net profit and certain other line items in our financial statements due to applicable accounting standards.

•

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.

•

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.

•

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, labor unrest in Nicaragua 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 foreign power plants to mitigate these risks, insurance does not provide complete coverage with respect to all such risks.

•

The Energy Policy Act of 2005 authorizes the U.S. Federal Energy Regulatory Commission (FERC) 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 existing U.S. power plants significantly, as all of our current PPAs are long-term. FERC recently 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 69.8% of our Electricity revenues for the three months ended March 31, 2013 were derived from PPAs with fixed price components, we have variable price PPAs in California and Hawaii. Our 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 the year 2012, we entered into swap contracts and put transactions in an attempt to reduce our exposure to fluctuations in the prices of natural gas and oil from these PPAs until December 31, 2013.

Our Electricity Segment revenues are also subject to seasonal variations, as more fully described in “Seasonality” below, and may also be affected by higher-than-average ambient temperature, which could cause a decrease in the generating capacity of our power plants, and by unplanned major maintenance activities related to our power plants.

Our PPAs generally provide for the payment of 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. In each of the three months ended March 31, 2013 and 2012, we experienced a significant increase in our Product Segment customer orders, which has increased our Product Segment backlog. We expect that our Product Segment revenues will remain robust until the end of 2013 as a result of these new orders and increased backlog.

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


	Three Months Ended March 31,				Three Months Ended March 31,
	2013		2012		2013			2012
Revenues:
Electricity	$	71,102	$	82,247		58.4	%		62.1	%
Product		50,608		50,105		41.6			37.9

Total	$	121,710	$	132,352		100.0	%		100.0	%

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


	Three Months Ended March 31,				Three Months Ended March 31,
	2013		2012		2013			2012
United States	$	52,068	$	62,244		73.2	%		75.7	%
Foreign		19,034		20,003		26.8			24.3

Total	$	71,102	$	82,247		100.0	%		100.0	%

Product Segment:
United States	$	14,433	$	—		28.5	%		0.0	%
Foreign		36,175		50,105		71.5			100.0

Total	$	50,608	$	50,105		100.0	%		100.0	%

For the three months ended March 31, 2013, 71.5% of our revenues attributable to our Product Segment were generated outside of the United States.

Seasonality

In the Electricity Segment we have identified that 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 higher ambient temperature, and as a result have a favorable impact to energy revenues. However, the higher payments payable by Southern California Edison 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 (such as depreciation and amortization) 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, and insurance. In our California power plants our principal cost of revenues also includes transmission charges, scheduling charges and purchases of make-up water for use in our cooling towers. 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 4.0% and 4.5% of Electricity Segment revenues for the three months ended March 31, 2013 and 2012, 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, cash equivalents, marketable securities and a short-term bank deposit as of March 31, 2013 decreased to $60.6 million from $69.6 million as of December 31, 2012. This decrease is principally due to: (i) our use of $49.6 million to fund capital expenditures; (ii) a net change in restricted cash, cash equivalents and marketable securities of $48.4 million; (iii) repayment of $5.2 million of long-term debt; (iv) $3.8 million of cash paid to the Class B membership units of OPC (see “OPC Transaction” below); and (v) $11.9 million of cash used to repurchase Ormat Funding LLC (OFC) Senior Secured Notes. This decrease was partially offset by: (i) additional $45.0 million of net proceeds from the disbursement from Tranche II of the OPIC Loan, as described below under “Non-Recourse and Limited-Recourse Third-Party Debt”; (ii) $18.2 million derived from operating activities during the three months ended March 31, 2013; (iii) $32.2 million of net proceeds from the ORTP Transaction (see “ORTP Transaction” below); and (iv) net proceeds of $14.7 million from borrowers under our revolving credit lines with commercial banks Our corporate borrowing capacity under committed lines of credit with different commercial banks as of March 31, 2013 was $440.9 million, as described below in “Liquidity and Capital Resources”, of which we have utilized $288.0 million (including $196.1 million of letters of credit) as of March 31, 2013.

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, 2012.

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 as a result of: (i) our recent construction of new power plants and enhancement of acquired power plants; and (ii) fluctuation in revenues from our Product Segment.


	Three Months Ended March 31,
	2013			2012
	(In thousands, except per share data)
Statements of Operations Historical Data:
Revenues:
Electricity	$	71,102		$	82,247
Product		50,608			50,105

		121,710			132,352

Cost of revenues:
Electricity		56,937			57,931
Product		37,041			34,627

		93,978			92,558

Gross margin:
Electricity		14,165			24,316
Product		13,567			15,478

		27,732			39,794
Operating expenses:
Research and development expenses		1,000			1,048
Selling and marketing expenses		11,571			4,922
General and administrative expenses		6,650			7,314
Write-off of unsuccessful exploration activities		—			768

Operating income		8,511			25,742
Other income (expense):
Interest income		41			388
Interest expense, net		(15,863	)		(14,878	)
Foreign currency translation and transaction gains		1,682			14
Income attributable to sale of tax benefits		3,532			2,517
Other non-operating income (expense), net		1,417			(161	)

Income (loss), before income taxes and equity in losses of investees		(680	)		13,622
Income tax provision		(1,217	)		(5,457	)
Equity in losses of investees		—			(140	)

Net income (loss)		(1,897	)		8,025
Net income attributable to noncontrolling interest		(85	)		(130	)

Net income (loss) attributable to the Company’s stockholders	$	(1,982	)	$	7,895

Earnings (loss) per share attributable to the Company’s stockholders — basic and diluted	$	(0.04	)	$	0.17

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

Diluted		45,431			45,437


	Three Months Ended March 31,
	2013			2012
Statements of Operations Percentage Data:
Revenues:
Electricity		58.4	%		62.1	%
Product		41.6			37.9

		100.0			100.0

Cost of revenues:
Electricity		80.1			70.4
Product		73.2			69.1

		77.2			69.9

Gross margin:
Electricity		19.9			29.6
Product		26.8			30.9

		22.8			30.1
Operating expenses:
Research and development expenses		0.8			0.8
Selling and marketing expenses		9.5			3.7
General and administrative expenses		5.5			5.5
Write-off of unsuccessful exploration activities		0.0			0.6

Operating income		7.0			19.4
Other income (expense):
Interest income		0.0			0.3
Interest expense, net		(13.0	)		(11.2	)
Foreign currency translation and transaction gains		1.4			0.0
Income attributable to sale of tax benefits		2.9			1.9
Other non-operating income (expense), net		1.2			(0.1	)

Income (loss), before income taxes and equity in losses of investees		(0.6	)		10.3
Income tax provision		(1.0	)		(4.1	)
Equity in losses of investees		0.0			(0.1	)

Net income (loss)		(1.6	)		6.1
Net income attributable to noncontrolling interest		(0.1	)		(0.1	)

Net income (loss) attributable to the Company’s stockholders		(1.7	)%		6.0	%

Comparison of the Three Months Ended March 31, 2013 and the Three Months Ended March 31, 2012

Total Revenues

Total revenues for the three months ended March 31, 2013 were $121.7 million, compared to $132.4 million for the three months ended March 31, 2012, which represented an 8.0% decrease in total revenues. This decrease was principally attributable to our Electricity Segment, in which revenues decreased by 13.6%, over the corresponding period in 2012.

Electricity Segment

Revenues attributable to our Electricity Segment for the three months ended March 31, 2013 were $71.1 million, compared to $82.2 million for the three months ended March 31, 2012, which represented a 13.6% decrease in such revenues. This decrease was primarily due to: (i) a $9.3 million decrease resulting from the impact of low natural gas prices on the energy rates in our SO#4 PPAs in California, which at the beginning of

May 2012 changed from a fixed rate to a variable rate that is subject mainly to the fluctuations in natural gas prices; (ii) a $6.4 million net decrease due to reduced generation in some of our power plants and a reduction in energy rates in our Puna and Amatitlan power plants; and (iii) a net loss of $4.6 million on derivative contracts on oil and natural gas prices. This decrease was partially offset by an aggregate of $9.2 million in revenues from our McGinness Hills power plant, which commenced commercial operation in July 2012, and our Tuscarora power plant, which started to receive commercial rates in the second quarter of 2012. The generation of power in our power plants increased by 4.2% from 1,040,044 MWh in the three months ended March 31, 2012 to 1,083,618 MWh in the three months ended March 31, 2013.

Product Segment

Revenues attributable to our Product Segment for the three months ended March 31, 2013 were $50.6 million, compared to $50.1 million for the three months ended March 31, 2012, which represented a 1.0% increase.

Total Cost of Revenues

Total cost of revenues for the three months ended March 31, 2013 was $94.0 million, compared to $92.6 million for the three months ended March 31, 2012, which represented a 1.5% increase. This was primarily due to the increase in cost of revenues from our Product Segment. As a percentage of total revenues, our total cost of revenues for the three months ended March 31, 2013 was 77.2%, compared to 69.9% for the three months ended March 31, 2012. This increase was attributable to both our Electricity and Product Segments.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the three months ended March 31, 2013 was $56.9 million, compared to $57.9 million for the three months ended March 31, 2012, which represented a 1.7% decrease. Despite the additional cost of revenues from our new power plant, McGinness Hills which commenced commercial operations in July 2012, there has been a net decrease mainly due to a decrease in depreciation in: (i) our North Brawley power plant as a result of the impairment recorded in the fourth quarter of 2012 and (ii) our Mammoth complex, due to fully depreciating a portion of its equipment in previous quarters as a result of the planned repowering and purchase of new equipment. The cost per MWh for the three months ended March 31, 2013, decreased compared to the three months ended March 31, 2012. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the three months ended March 31, 2013 was 80.1%, compared to 70.4% for the three months ended March 31, 2012. This increase was attributable to the decrease in electricity revenues as discussed above.

Product Segment

Total cost of revenues attributable to our Product Segment for the three months ended March 31, 2013 was $37.0 million, compared to $34.6 million for the three months ended March 31, 2012, which represented a 7.0% increase. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the three months ended March 31, 2013 was 73.2%, compared to 69.1% for the three months ended March 31, 2012. This increase was mainly attributable to a different product mix and different margins in the various sales contracts.

Research and Development Expenses

Research and development expenses for each of the three months ended March 31, 2013 and 2012, were $1.0 million, respectively. The research and development expenses are net of grants from the U.S. Department of Energy in the amount of $0.3 million and $0.2 million for the three months ended March 31, 2013 and 2012, respectively, related to the Enhanced Geothermal System (EGS) project.

Selling and Marketing Expenses

Selling and marketing expenses for the three months ended March 31, 2013 were $11.6 million, compared to $4.9 million for the three months ended March 31, 2012. The increase was primarily due to a one-time early termination fee in the amount of $9.0 million we paid to SCE, relating to the termination of the G1 and G3 PPAs for the Mammoth complex, as described above. Excluding the one-time termination fee, selling and marketing expenses for the three months ended March 31, 2013 constituted 2.1% of total revenues for such period, compared to 3.7% for the three months ended March 31, 2012.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2013 were $6.7 million, compared to $7.3 million for the three months ended March 31, 2012, which represented a 9.1% decrease. The decrease was primarily due to a reduction in manpower. General and administrative expenses for the three months ended March 31, 2013, constituted 5.5% of total revenues for such three months, compared to 5.5% for the three months ended March 31, 2012.

Write-off of Unsuccessful Exploration Activities

There were no write-offs of unsuccessful exploration activities for the three months ended March 31, 2013. Write-off of unsuccessful exploration activities for the three months ended March 31, 2012 was $0.8 million, due to the write-off of exploration costs related to the Leach Hot Springs project in Nevada, which we determined in the first quarter of 2012 would not support commercial operations.

Operating Income

Operating income for the three months ended March 31, 2013 was $8.5 million, compared to $25.7 million for the three months ended March 31, 2012. The decrease in operating income was principally attributable to the decrease in our gross margins which was primarily associated with the decrease in electricity revenues (which contributed to lower operating income for this segment) and the one-time early termination fee included in selling and marketing expenses discussed above. Operating loss attributable to our Electricity Segment for the three months ended March 31, 2013 was $0.5 million, compared to operating income of $15.9 million for the three months ended March 31, 2012. Operating income attributable to our Product Segment for the three months ended March 31, 2013 was $9.0 million, compared to $9.9 million for the three months ended March 31, 2012.

Interest Expense, Net

Interest expense, net, for the three months ended March 31, 2013 was $15.9 million, compared to $14.9 million for the three months ended March 31, 2012, which represents a 6.6% increase. This increase was primarily due to an increase of $0.9 million in interest expense related to sale of tax benefits and a $0.7 million decrease related to interest capitalized to projects, partially offset due to lower interest related to our net debt.

Foreign Currency Translation and Transaction Gains

Foreign currency translation and transaction gains for the three months ended March 31, 2013 were $1.7 million, compared to $0.0 for the three months ended March 31, 2012. The increase was primarily due to gains on forward foreign exchange transactions for the three months ended March 31, 2013, 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” below) for the three months ended March 31, 2013 was $3.5 million,

compared to $2.5 million for the three months ended March 31, 2012. This income represents the value of PTCs and taxable income or loss generated by OPC and ORTP and allocated to the investors in the amounts of $1.4 million and $2.2 million, respectively, in the three months ended March 31, 2013, compared to PTCs and taxable income or loss generated by OPC and allocated to the investors in the three months ended March 31, 2012.

Income Taxes

Income tax provision for the three months ended March 31, 2013 was $1.2 million, compared to $5.5 million for the three months ended March 31, 2012. The decrease in income tax provision primarily resulted from the decrease in income before income taxes.

For each of the three months ended March 31, 2013 and 2012, we recorded a valuation allowance in the amount of approximately $8.6 million and $6.4 million, respectively, against our U.S. deferred tax assets in respect of net operating loss carryforwards and unutilized tax credits (PTCs and ITCs).

Net Income (Loss)

Net loss for the three months ended March 31, 2013 was $1.9 million, compared to a net income of $8.0 million for the three months ended March 31, 2012. The decrease in net income of $9.9 million was principally attributable to a $17.2 million decrease in operating income, offset partially by: (i) a $4.2 million decrease in income tax provision and (ii) a $1.7 million increase in foreign currency translation and transaction gains.

Liquidity and Capital Resources

Our principal sources of liquidity have been derived from cash flows from operations, the issuance of our common stock in public and private offerings, proceeds from third party debt in the form of borrowings under credit facilities and private offerings, issuance by OFC, OrCal Geothermal, LLC (OrCal) and OFC 2 LLC (OFC 2) of their respective Senior Secured Notes, project financing (including the Puna lease and the OPC and ORTP Transactions described below), and cash grants we received under the ARRA. We have utilized this cash to develop and construct power generation plants, to fund our acquisitions, and to meet our other cash and liquidity needs.

As of March 31, 2013, we had access to: (i) $60.6 million in cash, cash equivalents and a short-term bank deposit; and (ii) $152.9 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.

Our estimated capital needs for the remainder of 2013 include approximately $173.0 million for capital expenditures on new projects under development or construction, exploration activity, operating projects, and machinery and equipment, as well as $63.1 million for debt repayment.

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; (iii) future project financing and refinancing (including construction loans); and (iv) cash grants available to us under the ARRA in respect of new projects that will be placed in service before the end of 2013. Management believes that these sources will be sufficient to 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 believe that the transition to variable energy prices under the Ormesa and Mammoth PPAs and the impact of the currently low natural gas prices on the revenues under these PPAs may cause OFC to not meet the DSCR ratio requirements for making distributions, but we do not believe that there will be an event of default by OFC. We are only required to measure these covenants on a semi-annual basis and as of December 31, 2012, the last measurement date of the covenants, the actual historical 12-months DSCR was 1.28. There were $101.3 million and $114.1 million of OFC Senior Secured Notes outstanding as of March 31, 2013 and December 31, 2012, respectively.

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 first quarter of 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. The Company is only required to measure these covenants on a semi-annual basis and as of December 31, 2012, the last measurement date of the covenants, the actual historical 12-months DSCR was 1.36. There were $76.5 million of OrCal Senior Secured Notes outstanding as of March 31, 2013 and December 31, 2012, respectively.

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 will guarantee 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 December 31, 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, 2013, the last measurement date of the covenants, the historical actual DSCR was 2.52 and the pro-forma 12-month DSCR was 1.9. As of March 31, 2013, there were $150.5 million of OFC 2 Senior Secured Notes outstanding.

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 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 in November, 2012.

The OPIC Loan is comprised of up to 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 up to $180.0 million will be used to fund the construction and well field drilling for the expansion of the Olkaria III geothermal power complex (Plant 2). 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 is a stand-by tranche in an aggregate principal amount of up to $45.0 million, and will be made available to OrPower 4 in the event it elects, in its discretion, to construct a further expansion of the Olkaria III complex (Plant 3). Terms and conditions for Tranche III of the OPIC Loan will be agreed upon by OPIC and OrPower 4 in subsequent documentation.

The interest rate on both Tranche I and Tranche II is variable from the date of disbursement until a conversion date selected by OrPower 4, whereupon interest on each Tranche will convert to a fixed rate. The interest rate as of March 31, 2013 was 2.90%. Interest, whether floating or fixed, is payable quarterly in arrears on each March 15, June 15, September 15 and December 15, commencing with the first such date following the respective disbursement of a Tranche. OrPower 4 is required to select a conversion date that will be within 180 days of the commercial operation date of Plant 2.

The applicable Tranche interest rate will be determined at the time of the actual disbursement of loan proceeds based upon, and in connection with the issuance of certificates of participation in the OPIC Loan. The payment of principal and interest on the certificates of participation is fully guaranteed by OPIC, and is backed by the full faith and credit of the U.S. government.

The final maturity of Tranche I and Tranche II is approximately 18 years, i.e., December 15, 2030 and June 15, 2030, respectively.

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% 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 $51.3 million as of November 9, 2012, 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.

As of March 31, 2013, $263.8 million of the above loan was outstanding.

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, 2013, the projected 12-month DSCR was 1.59 and the debt to equity ratio was 2.23, and $33.6 million of this loan was outstanding.

Full-Recourse Third-Party Debt

Union Bank. In February 2012, Ormat Nevada 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 and 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, 2013: (i) the actual 12-month debt to EBITDA ratio was 3.65; (ii) the 12-month DSCR was 2.11; and (iii) the distribution leverage ratio was 1.15. 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, 2013, letters of credit in the aggregate amount of $50.0 million remain issued and outstanding under this credit agreement.

Credit Agreements. We also have credit agreements with five other commercial banks for an aggregate amount of $390.9 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 $260.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $130.9 million. The credit agreements mature between June 2013 and December 2014. 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, 2013, loans in the total amount of $88.3 were outstanding, and letters of credit with an aggregate stated amount of $145.8 million were issued and outstanding under these credit agreements. The $88.3 million in loans are for terms of three months or less and bear interest at a weighted average rate of 2.39%.

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, 2013, $9.3 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, 2013, $15.0 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 at a rate of 5.75%. As of March 31, 2013, $16.0 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, 2013, $20.0 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, $47.4 million is outstanding under the DEG Loan (out of which $32.5 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”). The amended and restated DEG Loan Agreement provides for: (i) the prepayment in full of two loans thereunder in the total principal amount of approximately $20.5 million; (ii) 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; (iii) the establishment of a LIBOR floor of 1.25% in respect of one of the loans under

the DEG Loan Agreement, and (iv) 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, marketable securities and short-term bank deposits to 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, 2013: (i) total equity was $706.5 million and the actual equity to total assets ratio was 33.0%; and (ii) the 12-month debt, net of cash, cash equivalents, marketable securities and short-term bank deposits to EBITDA ratio was 5.94. 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, 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, 2013, letters of credit in the aggregate amount of $225.5 million remained issued and outstanding, out of which $196.1 million were issued under the credit agreements with Union Bank and five of the commercial banks as described under “Full-Recourse Third Party Debt” and $29.4 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. In October, 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 in February, 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.

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. Pursuant to the term of the agreement, JPM paid approximately $35.7 million to Ormat Nevada and undertook to make additional payments to ORTP 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 and total approximately $8.7 million.

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 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% (allocation of income and loss) and 2.5% (allocation of cash) residual economic interest in ORTP. The 5% 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% 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% 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.

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

Liquidity Impact of Uncertain Tax Positions

As discussed in Note 10 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 $7.8 million as of March 31, 2013. 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 we have declared and paid during the past two years:


Date Declared	Dividend Amount per Share		Record Date	Payment Date
February 22, 2011	$	0.05	March 15, 2011	March 24, 2011
May 4, 2011	$	0.04	May 18, 2011	May 25, 2011
August 3, 2011	$	0.04	August 16, 2011	August 25, 2011
May 8, 2012	$	0.04	May 21, 2012	May 30, 2012
August 1, 2012	$	0.04	August 14, 2012	August 23, 2012

Historical Cash Flows

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


	Three Months Ended March 31,
	2013			2012
	(In thousands)
Net cash provided by operating activities	$	18,216		$	41,874
Net cash used in investing activities		(98,244	)		(62,333	)
Net cash provided by financing activities		71,027			5,153
Net change in cash and cash equivalents		(9,001	)		(15,306	)

For the Three months Ended March 31, 2013

Net cash provided by operating activities for the three months ended March 31, 2013 was $18.2 million, compared to $41.9 million for the three months ended March 31, 2012. The net decrease of $23.7 million resulted primarily from (i) the decrease in net income of $9.9 million, from a net income of $8.0 million for the three months ended March 31, 2012 to a net loss of $1.9 million for the three months ended March 31, 2013 described above and (ii) a decrease in accounts payable and accrued expenses of $14.8 million in the three months ended March 31, 2013, compared to an increase of $4.9 million in the three months ended March 31, 2013 as a result of timing of payments to our vendors. The decrease was partially offset due to mark-to-market loss of derivatives instruments of $5.8 million.

Net cash used in investing activities for the three months ended March 31, 2013 was $98.2 million, compared to $62.3 million for the three months ended March 31, 2012. The principal factors that affected our net cash used in investing activities during the three months ended March 31, 2013 were (i) capital expenditures of $49.6 million, primarily for our facilities under construction; and (ii) net increase of $48.4 million in restricted cash, cash equivalents, and marketable securities.

Net cash provided by financing activities for the three months ended March 31, 2013 was $71.0 million, compared to $5.2 million for the three months ended March 31, 2012. The principal factors that affected the 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, as described above under “Non-Recourse and Limited-Recourse Third-Party Debt”; (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. This increase was partially offset due to: (i) $11.9 million of cash paid to repurchase our OFC Senior Secured Notes (ii) the repayment of long-term debt in the amount of $5.2 million; and (iii) $3.8 million of cash paid to the Class B membership units of OPC (see “OPC Transaction”). The principal factors that affected our net cash provided by financing activities during the three months ended March 31, 2012 was a net increase of $13.6 million against our revolving lines of credit with commercial banks, offset by (i) the repayment of long-term debt in the amount of $3.8 million; and (ii) cash paid to non-controlling interest in the amount of $4.2 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, 2013 was $45.7 million, compared to $51.5 million for the three months ended March 31, 2012.

The following table reconciles net cash provided by operating activities to EBITDA and Adjusted EBITDA for the three-month periods ended March 31, 2013 and 2012:


	Three Months Ended March 31,
	2013			2012
	(In thousands)
Net cash provided by operating activities	$	18,216		$	41,874
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		14,336			13,647
Interest income		(41	)		(388	)
Income tax provision		1,217			5,457
Adjustments to reconcile net income or loss to net cash provided by operating activities (excluding depreciation and amortization)		3,024			(9,105	)

EBITDA		36,752			51,485
Termination fee		8,979			—

Adjusted EBITDA	$	45,731		$	51,485

Net cash used in investing activities	$	(98,244	)	$	(62,333	)

Net cash provided by financing activities	$	71,027		$	5,153

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:

Heber Solar PV Project. We are currently developing the 10 MW Heber Solar PV project located in Imperial County, California. We signed a 20-year PPA with the Imperial Irrigation District (IID). We expect to begin commercial operation by the end of 2013, subject to timely completion of the interconnection that is to be provided by IID.

Mammoth Complex. We are currently in the process of repowering the Mammoth complex located in Mammoth Lakes, California, by replacing part of the old units with new Ormat-manufactured equipment. We expect the replacement of the equipment to optimize the operation of the complex. We recently started the manufacturing of the equipment for the complex.

Olkaria III Plant 2 & 3. Development of the 36 MW Plant 2 and the 16 MW Plant 3 of the Olkaria III complex located in Naivasha, Kenya is in process. Plant 2 is currently at start-up phase and its commercial operation is expected in mid-2013. Plant 3 is in field development stage and expected to come online in 2014.

Wild Rose Project. We are currently developing the 16 MW Wild Rose project located in Mineral County, Nevada. Field development was completed; manufacturing of the power plant equipment is in advanced stage. We recently signed a 20-year PPA with the Southern California Power Public Authority at a rate of $99 per MWh. The new power plant is expected to come online by the end of 2013.

Heber 1 Power Plant. We plan to enhance the Heber complex located in Imperial Valley, California, by adding new wells and replacing part of the old equipment with new equipment. We expect the enhancement to optimize the operation of the Heber complex.

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 2013.

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 continued drilling is subject to receipt of additional permits. As part of the process to secure a transmission line, we are participating in the Southern California Edison Wholesale Distribution Access Tariff Transition Cluster Generator Interconnection Process to deliver energy into the Southern California Edison system at the Casa Diablo Substation.

We have estimated approximately $373.0 million in capital expenditures for the projects listed above, of which we have invested approximately $221.0 million as of March 31, 2013. We expect to invest $124.0 million of such total in the remainder of 2013 and the remaining $28 million thereafter.

In addition, we estimate approximately $49.0 million in additional capital expenditures in 2013 to be allocated as follows: (i) $15.0 million in development of new projects; (ii) $9.0 million for maintenance capital expenditure; (iii) $18.0 million in exploration activities in various leases for geothermal resources in which we have started the exploration activity; and (iv) $7.0 million in enhancement of our production facilities. In the aggregate, we estimate our total capital expenditures for the remainder of 2013 will be approximately $173.0 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 the 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 addition, in May and July 2012, we entered into put transactions, and in October 2012, we entered into swap contracts to reduce our exposure to the price of natural gas, under these PPAs, until December 31, 2013. 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 April 2012, we entered into swap contracts, and in September 2012, we entered into put transactions to reduce our exposure to the price of oil, under the 25 MW PPA of the Puna complex, until December 31, 2013.

As of March 31, 2013, 62.5% of our consolidated long-term debt bore a fixed rate and therefore was not subject to interest rate volatility risk. As of such date, 37.5% of our long-term debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith, and $402.1 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 and our portfolio of marketable securities 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 primarily related to 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 and option 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, 2013 and December 31, 2012 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of March 31, 2013 and December 31, 2012 are presented below:


	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
Risk	March 31, 2013			December 31, 2012			March 31, 2013		December 31, 2012		Change in the Fair Value of
	(In thousands)
NGI Price	$	(4,554	)	$	(484	)	$	1,181	$	6,097	NGI Swap
NYMEX Heating Oil Price		—			(439	)		—		1,037	NYMEX HO2 Swap
ICE Brent Price		—			(122	)		—		41	ICE Brent Swap
NYMEX Heating Oil Price		344			790			2,947		2,988	NYMEX HO2 Fixed Rate Put
ICE Brent Price		51			135			380		429	ICE Brent Fixed Rate Put
Foreign Currency		(250	)		(5,074	)		204		7,503	Foreign currency forward contracts
Interest Rate		(2,413	)		(3,388	)		2,517		3,557	OFC
Interest Rate		(1,495	)		(1,550	)		1,542		1,650	OrCal
Interest Rate		(5,788	)		(5,600	)		6,218		6,100	OFC 2
Interest Rate		(466	)		(540	)		478		560	Loan from DEG
Interest Rate		(450	)		(532	)		458		468	Loan from TCW
Interest Rate		(5,021	)		(5,477	)		5,136		5,623	Senior unsecured bonds
Interest Rate		(200	)		(401	)		203		99	Loan from institutional investors

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 21.1% and 12.9% of our total revenues for the three months ended March 31, 2013 and 2012, respectively.

Southern California Edison accounted for 11.4% and 19.7% of our total revenues for the three months ended March 31, 2013 and 2012, 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, 2013 and 2012, respectively.

KPLC accounted for 8.2% and 7.3% of our total revenues for the three months ended March 31, 2013 and 2012, respectively.

Government Grants and Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies. If we start 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 three months ended March 31, 2013 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 place 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 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 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.

In November 2012, new legislation amending the Investment Law was enacted. Under the new legislation, companies that have retained earnings as of December 31, 2011 from Benefited Enterprises may elect by November 11, 2013 to pay a reduced corporate tax rate set forth in the new legislation on such undistributed income and distribute a dividend from such income without being required to pay additional corporate tax with respect to such income. A company that makes this election will be required to make certain investments in its Benefited Enterprise by: (i) purchasing productive assets (other than buildings); (ii) investing in research and development in Israel; and/or (iii) paying salaries of new employees (other than directors and officers of the company) of the Benefited Enterprise. The number of new employees for these purposes will be determined in comparison to the number of employees employed by the Benefited Enterprise at the end of 2011. Such investment must be made over a period of five years commencing in the tax year in which the election is made. The amount of the required investment is determined pursuant to a formula set forth in the new legislation. A company that makes the election allowed under the new legislation cannot later undo its election. As of the date of this report Ormat Systems has not yet decided whether to make such election.

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, 2013, 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 2013 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PART II — OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

On December 24, 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 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 I replacement project. 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.

On January 4, 2012, the California Unions for Reliable Energy (“CURE”) filed a petition in Alameda Superior Court, naming the California Energy Commission (“CEC”) and the Company as defendant and real party in interest, respectively. The petition asked the court to order the CEC to vacate its decision which denied, with prejudice, the complaint filed by CURE against the Company with the CEC. The CURE complaint alleged that the Company’s North Brawley Project and East Brawley Project both exceed the CEC’s 50 MW jurisdictional threshold and therefore are subject to the CEC licensing authority rather than Imperial County licensing authority. In addition, the CURE petition asked the court to investigate and halt any ongoing violation of the Warren Alquist Act by the Company, and to award CURE attorney’s fees and costs. As to North Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider provisions of the County permit for North Brawley, which CURE contends authorizes the Company to build a generating facility with a number of Ormat Energy Converters (“OECs”) capable of generating more than 50 MW. As to East Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider the conditional use permit application for East Brawley, which CURE contends shows that the Company requested authorization to build a facility with a number of OECs capable of generating more than 50 MW.

The court held two hearings and on November 15, 2012 CURE’s petition was denied. Any appeal of the court’s decision had to be filed by March 4, 2013, and no appeal was filed.

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, 2012 filed with the SEC on March 11, 2013.

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 2013.

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 8, 2013

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.

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.


Exhibit No.		Document

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.

10.1		Equity Contribution Agreement with respect to ORTP, 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.

10.2		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.

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.

Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that the Company specifically incorporates such information by reference.