XNYS:ORA Ormat Technologies Inc Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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Table of Contents

 

 

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, 2012

or

 

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

For the transition period from             to            

Commission file number: 001-32347

ORMAT TECHNOLOGIES, INC.

(Exact name of registrant as specified in its charter)

 

DELAWARE   88-0326081

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

6225 Neil Road, Reno, Nevada 89511-1136

(Address of principal executive offices)

Registrant’s telephone number, including area code:

(775) 356-9029

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):

 

Large accelerated filer  ¨

  Accelerated filer  þ    Non-accelerated filer  ¨    Smaller reporting company  ¨
  (Do not check if a smaller reporting company)

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

As of the date of this filing, the number of outstanding shares of common stock of Ormat Technologies, Inc. is 45,430,886 par value of $0.001 per share.

 

 

 


Table of Contents

ORMAT TECHNOLOGIES, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2012

 

PART I — UNAUDITED FINANCIAL INFORMATION

  

    ITEM 1.

 

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     4   

    ITEM 2.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     21   

    ITEM 3.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     47   

    ITEM 4.

 

CONTROLS AND PROCEDURES

     47   

PART II — OTHER INFORMATION

  

    ITEM 1.

 

LEGAL PROCEEDINGS

     48   

    ITEM 1A.

 

RISK FACTORS

     50   

    ITEM 2.

 

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

     50   

    ITEM 3.

 

DEFAULTS UPON SENIOR SECURITIES

     50   

    ITEM 4.

 

MINE SAFETY DISCLOSURES

     50   

    ITEM 5.

 

OTHER INFORMATION

     50   

    ITEM 6.

 

EXHIBITS

     51   

SIGNATURES

     53   

 

2


Table of Contents

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.

 

3


Table of Contents

PART I — UNAUDITED FINANCIAL INFORMATION

 

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

     March 31,
2012
     December 31,
2011
 
     (In thousands)  
ASSETS      

Current assets:

     

Cash and cash equivalents

   $ 84,580      $ 99,886  

Marketable securities

     15,719        18,521  

Restricted cash, cash equivalents and marketable securities (all related to VIEs)

     75,145        75,521  

Receivables:

     

Trade

     43,545        51,274  

Related entity

     307        287  

Other

     8,058        9,415  

Due from Parent

     123        260  

Inventories

     17,200        12,541  

Costs and estimated earnings in excess of billings on uncompleted contracts

     8,618        3,966  

Deferred income taxes

     2,315        1,842  

Prepaid expenses and other

     19,863        18,672  
  

 

 

    

 

 

 

Total current assets

     275,473        292,185  

Unconsolidated investments

     3,732        3,757  

Deposits and other

     22,940        22,194  

Deferred charges

     40,066        40,236  

Property, plant and equipment, net ($1,438,586 and $1,477,580 related to VIEs, respectively)

     1,505,543        1,518,532  

Construction-in-process ($299,126 and $271,859 related to VIEs, respectively)

     413,998        370,551  

Deferred financing and lease costs, net

     28,054        28,482  

Intangible assets, net

     37,963        38,781  
  

 

 

    

 

 

 

Total assets

   $ 2,327,769      $ 2,314,718  
  

 

 

    

 

 

 
LIABILITIES AND EQUITY      

Current liabilities:

     

Accounts payable and accrued expenses

   $ 98,993      $ 105,112  

Billings in excess of costs and estimated earnings on uncompleted contracts

     32,155        33,104  

Current portion of long-term debt:

     

Limited and non-recourse (all related to VIEs):

     

Senior secured notes

     22,247        21,464  

Other loans

     13,612        13,547  

Full recourse

     20,647        20,543  
  

 

 

    

 

 

 

Total current liabilities

     187,654        193,770  

Long-term debt, net of current portion:

     

Limited and non-recourse (all related to VIEs:)

     

Senior secured notes

     340,374        341,157  

Other loans

     99,921        100,585  

Full recourse:

     

Senior unsecured bonds (plus unamortized premium based upon 7% of $1,667)

     249,964        250,042  

Other loans

     60,273        63,623  

Revolving credit lines with banks

     227,642        214,049  

Liability associated with sale of tax benefits

     64,383        69,269  

Deferred lease income

     68,321        68,955  

Deferred income taxes

     59,399        54,665  

Liability for unrecognized tax benefits

     6,409        5,875  

Liabilities for severance pay

     21,674        20,547  

Asset retirement obligation

     21,697        21,284  

Other long-term liabilities

     4,021        4,253  
  

 

 

    

 

 

 

Total liabilities

     1,411,732        1,408,074  
  

 

 

    

 

 

 

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

     46        46  

Additional paid-in capital

     727,403        725,746  

Retained earnings

     180,226        172,331  

Accumulated other comprehensive income

     518        595  
  

 

 

    

 

 

 
     908,193        898,718  

Noncontrolling interest

     7,844        7,926  
  

 

 

    

 

 

 

Total equity

     916,037        906,644  
  

 

 

    

 

 

 

Total liabilities and equity

   $ 2,327,769      $ 2,314,718  
  

 

 

    

 

 

 

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

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

     Three Months Ended
March 31,
 
           2012                 2011        
     (In thousands, except per
share data)
 

Revenues:

    

Electricity

   $ 82,247     $ 78,268  

Product

     50,105       19,552  
  

 

 

   

 

 

 

Total revenues

     132,352       97,820  
  

 

 

   

 

 

 

Cost of revenues:

    

Electricity

     57,931       65,937  

Product

     34,627       16,890  
  

 

 

   

 

 

 

Total cost of revenues

     92,558       82,827  
  

 

 

   

 

 

 

Gross margin

     39,794       14,993  

Operating expenses:

    

Research and development expenses

     1,048       2,207  

Selling and marketing expenses

     4,922       2,660  

General and administrative expenses

     7,314       7,007  

Write-off of unsuccessful exploration activities

     768         
  

 

 

   

 

 

 

Operating income

     25,742       3,119  

Other income (expense):

    

Interest income

     388       135  

Interest expense, net

     (14,878     (13,080

Foreign currency translation and transaction gains

     14       517  

Income attributable to sale of tax benefits

     2,517       2,139  

Other non-operating expense, net

     (161     (797
  

 

 

   

 

 

 

Income (loss), before income taxes and equity in losses of investees

     13,622       (7,967

Income tax provision

     (5,457     (586

Equity in losses of investees

     (140     (412
  

 

 

   

 

 

 

Net income (loss)

     8,025       (8,965

Net income attributable to noncontrolling interest

     (130     (10
  

 

 

   

 

 

 

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

   $ 7,895     $ (8,975
  

 

 

   

 

 

 

Comprehensive income (loss):

    

Net income (loss)

     8,025       (8,965

Other comprehensive income (loss), net of related taxes:

    

Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge

     (47     (53

Change in unrealized gains or losses on marketable securities available-for-sale

     (30     (23
  

 

 

   

 

 

 

Comprehensive income (loss)

     7,948       (9,041

Comprehensive income attributable to noncontrolling interest

     (130     (10
  

 

 

   

 

 

 

Comprehensive income (loss) attributable to the Company’s stockholders

   $ 7,818     $ (9,051
  

 

 

   

 

 

 

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

   $ 0.17     $ (0.20
  

 

 

   

 

 

 

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

     45,437       45,431  
  

 

 

   

 

 

 

Dividend per share declared

   $      $ 0.05  
  

 

 

   

 

 

 

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

 

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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
Other
Comprehensive
Income
    Total     Noncontrolling
Interest
    Total
Equity
 
    Shares     Amount              
    (In thousands, except per share data)  

Balance at December 31, 2010

    45,431     $ 46      $ 716,731      $ 221,311      $ 1,044      $ 939,132      $ 6,095      $ 945,227   

Stock-based compensation

                  1,727                     1,727              1,727  

Increase in noncontrolling interest due to sale of equity interest in OPC LLC

                  2,343                     2,343       2,070       4,413  

Cash dividend declared, $0.05 per share

                         (2,290            (2,290            (2,290

Net income (loss)

                         (8,975            (8,975     10       (8,965

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 $32)

                                (53     (53            (53

Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $14)

                                (23     (23            (23
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at March 31, 2011

    45,431     $ 46      $ 720,801      $ 210,046      $ 968      $ 931,861      $ 8,175      $ 940,036   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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 non-controlling 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   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

 

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Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Three Months Ended
March 31,
 
     2012     2011  
     (In thousands)  

Cash flows from operating activities:

    

Net income (loss)

   $ 8,025     $ (8,965

Adjustments to reconcile net income or loss to net cash provided by operating activities:

    

Depreciation and amortization

     24,744       23,370  

Amortization of premium from senior unsecured bonds

     (78       

Accretion of asset retirement obligation

     413       387  

Stock-based compensation

     1,657       1,727  

Amortization of deferred lease income

     (671     (671

Income attributable to sale of tax benefits, net of interest expense

     (869     (542

Equity in losses of investees

     140       412  

Impairment of auction rate securities

            207  

Write-off of unsuccessful exploration activities

     768         

Loss on severance pay fund asset

     (641     (614

Premium from issuance senior unsecured bonds

            1,975  

Deferred income tax provision

     4,460       145  

Liability for unrecognized tax benefits

     534       (1,137

Deferred lease revenues

     37       (269

Changes in operating assets and liabilities, net of amounts acquired:

    

Receivables

     9,086       (14,367

Costs and estimated earnings in excess of billings on uncompleted contracts

     (4,652     2,615  

Inventories

     (4,659     (2,016

Prepaid expenses and other

     (1,191     1,138  

Deposits and other

     (169     (132

Accounts payable and accrued expenses

     4,877       (3,184

Due from/to related entities, net

     (20     (29

Billings in excess of costs and estimated earnings on uncompleted contracts

     (949     12,223  

Liabilities for severance pay

     1,127       1,281  

Other long-term liabilities

     (232     (257

Due from/to Parent

     137       (231
  

 

 

   

 

 

 

Net cash provided by operating activities

     41,874       13,066  
  

 

 

   

 

 

 

Cash flows from investing activities:

    

Marketable securities, net

     2,772       (22,965

Net change in restricted cash, cash equivalents and marketable securities

     376       (29,920

Capital expenditures

     (65,430     (55,052

Investment in unconsolidated companies

     (115       

Increase in severance pay fund asset, net of payments made to retired employees

     64       13  
  

 

 

   

 

 

 

Net cash used in investing activities

     (62,333     (107,924
  

 

 

   

 

 

 

Cash flows from financing activities:

    

Proceeds from issuance of senior unsecured bonds

            107,447  

Proceeds from the sale of limited liability company interest in OPC LLC

            24,878  

Proceeds from revolving credit lines with banks

     182,641       79,334  

Repayment of revolving credit lines with banks

     (169,048     (150,300

Repayments of long-term debt

     (3,845     (2,434

Cash paid to non-controlling interest

     (4,229     (2,616

Deferred debt issuance costs

     (366     (1,301

Cash dividends paid

            (2,290
  

 

 

   

 

 

 

Net cash provided by financing activities

     5,153       52,718  
  

 

 

   

 

 

 

Net change in cash and cash equivalents

     (15,306     (42,140

Cash and cash equivalents at beginning of period

     99,886       82,815  
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 84,580     $ 40,675  
  

 

 

   

 

 

 

Supplemental non-cash investing and financing activities:

    

Decrease in accounts payable related to purchases of property, plant and equipment

   $ (11,509   $ (5,947
  

 

 

   

 

 

 

Accrued liabilities related to financing activities

   $ 513     $ 325  
  

 

 

   

 

 

 

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

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — GENERAL AND BASIS OF PRESENTATION

These unaudited condensed consolidated financial statements of Ormat Technologies, Inc. and its subsidiaries (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, the 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, 2012, the consolidated results of operations and comprehensive income (loss), and the consolidated cash flows for the three-month periods ended March 31, 2012 and 2011.

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, 2012 are not necessarily indicative of the results to be expected for the year ending December 31, 2012.

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, 2011. The condensed consolidated balance sheet data as of December 31, 2011 was derived from the audited consolidated financial statements for the year ended December 31, 2011, 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.

Concentration of credit risk

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of temporary cash investments, marketable securities 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, 2012 and December 31, 2011, the Company had deposits totaling $14,292,000 and $39,569,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At March 31, 2012 and December 31, 2011, the Company’s deposits in foreign countries amounted to approximately $62,367,000 and $57,838,000, respectively.

At March 31, 2012 and December 31, 2011, accounts receivable related to operations in foreign countries amounted to approximately $14,971,000 and $21,453,000, respectively. At March 31, 2012 and December 31, 2011, accounts receivable from the Company’s major customers that have generated 10% or more of its revenues amounted to approximately 51% and 58% of the Company’s accounts receivable, respectively.

Southern California Edison Company (“SCE”) accounted for 19.7% and 27.0% of the Company’s total revenues for the three months ended March 31, 2012 and 2011, respectively.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 12.9% and 16.2% of the Company’s total revenues for the three months ended March 31, 2012 and 2011, respectively.

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Hawaii Electric Light Company accounted for 9.3% and 10.6% of the Company’s total revenues for the three months ended March 31, 2012 and 2011, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 7.3% and 8.9% of the Company’s total revenues for the three months ended March 31, 2012 and 2011, 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, 2012

Accounting for Fair Value Measurement

In May 2011, the Financial Accounting Standards Board (“FASB”) issued additional authoritative guidance regarding fair value measurements and disclosures. Required disclosures are expanded under the new guidance, especially for fair value measurements that are categorized within Level 3 of the fair value hierarchy, for which quantitative information about the unobservable inputs, the valuation processes used by the entity, and the sensitivity of the measurement to the unobservable inputs are required. In addition, entities are required to disclose the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed. The adoption of this guidance by the Company on January 1, 2012 did not have a material impact on the Company’s consolidated financial statements.

Update on Presentation of Comprehensive Income in the Financial Statements

In June 2011, the FASB issued authoritative guidance requiring entities to present net income and other comprehensive income in a single continuous statement of comprehensive income or in two separate, but consecutive, statements. The new guidance does not change the components that are recognized in net income and the components that are recognized in other comprehensive income. The guidance originally required entities to present reclassifications between net income and other comprehensive income at the financial statement line item level; however, in December 2011, the FASB deferred this requirement. The adoption of this guidance by the Company on January 1, 2012 did not have a material impact on the Company’s consolidated financial statements.

New accounting pronouncements effective in future periods

Update on Disclosures about Offsetting Assets and Liabilities

In December 2011, the FASB issued new accounting guidance that revises the manner in which entities disclose the offsetting of assets and liabilities. The new guidance requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master netting arrangement. The amendment is applicable retrospectively effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013. The adoption of this amendment is not expected to have a material effect on the Company’s consolidated financial statements.

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

NOTE 3 — INVENTORIES

Inventories consist of the following:

 

     March 31,
2012
     December 31,
2011
 
     (Dollars in thousands)  

Raw materials and purchased parts for assembly

   $ 10,057      $ 6,058  

Self-manufactured assembly parts and finished products

     7,143        6,483  
  

 

 

    

 

 

 

Total

   $ 17,200      $ 12,541  
  

 

 

    

 

 

 

NOTE 4 — UNCONSOLIDATED INVESTMENTS

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

 

     March 31,
2012
     December 31,
2011
 
     (Dollars in thousands)  

Sarulla

   $ 2,330      $ 2,215  

Watts & More Ltd.

     1,402        1,542  
  

 

 

    

 

 

 
   $ 3,732      $ 3,757  
  

 

 

    

 

 

 

The Sarulla Project

The Company is a 12.75% member of a consortium which is in the process of developing a geothermal power project in Indonesia with expected generating capacity of approximately 330 MW. The 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 with PT Pertamina Geothermal Energy. The project will be constructed in three phases over five years, with each phase utilizing the Company’s 110 MW to 120 MW combined cycle geothermal plants in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power. The consortium is still negotiating certain contractual amendments for facilitation of project financing and for signing the resulting amended energy sales contract, and intends to proceed with the project after those amendments have become effective.

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 October 2010, the Company invested $2.0 million in Watts & More Ltd. (“W&M”), an early stage start-up company, engaged in the development of energy harvesting and system balancing solutions for electrical sources and, in particular, solar photovoltaic systems. The Company holds approximately 28.6% of W&M’s shares.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The Company’s share in the results of operations of W&M was not significant for each of the periods presented in these condensed 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 to sell an asset or paid to transfer 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. It 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, 2012 and December 31, 2011 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,
2012
     Fair Value at March 31, 2012  
        Total      Level 1      Level 2      Level 3  
     (Dollars in thousands)  

Assets

              

Current assets:

              

Cash equivalents (including restricted cash accounts)

   $ 43,371      $ 43,371      $ 43,371      $       $   

Marketable Securities

     15,453        15,719        15,719                  

Derivatives(1)

             296                296          
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
   $ 58,824      $ 59,386      $ 59,090      $ 296      $   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
              

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

     Cost or
Amortized
Cost at
December 31,
2011
     Fair Value at December 31, 2011  
        Total     Level 1      Level 2     Level 3  
     (Dollars in thousands)  

Assets

            

Current assets:

            

Cash equivalents (including restricted cash accounts)

   $ 61,649      $ 61,649     $ 61,649      $      $   

Marketable Securities

     18,284        18,521       18,521                 

Liabilities:

            

Current liabilities:

            

Derivatives(2)

             (890             (890       
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 
   $ 79,933      $ 79,280     $ 80,170      $ (890   $   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

 

 

(1)

Amounts relating to derivatives which represent currency forward contracts which are valued primarily based on observable inputs, including forward and spot prices for currencies which are netted against contracted rates and then multiplied against notational amounts, and are included within “receivables — others” in the balance sheet with the corresponding gain or loss being recognized within “foreign currency translation and transaction gains (losses)” in the condensed consolidated statement of operations and comprehensive income (loss).

 

(2)

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

The Company’s financial assets measured at fair value (including restricted cash accounts) at March 31, 2012 and December 31, 2011 include investments in debt instruments (which are included in marketable securities) and money market funds (which are included in cash equivalents). Those securities are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.

As of March 31, 2011, all of the Company’s auction rate securities are associated with failed auctions. Such securities have par values totaling $4.5 million, all of which have been in a loss position since the fourth quarter of 2007. The Company’s auction rate securities at December 31, 2010, were valued using Level 3 inputs. Historically, the carrying value of auction rate securities approximated fair value due to the frequent resetting of the interest rates. While the Company continued to earn interest on these investments at the contractual rates, the estimated market value of these auction rate securities no longer approximated par value. Due to the lack of observable market quotes on the Company’s illiquid auction rate securities, the Company utilized valuation models that relied exclusively on Level 3 inputs including, among other things: (i) the underlying structure of each security; (ii) the present value of future principal and interest payments discounted at rates considered to reflect the uncertainty of current market conditions; (iii) consideration of the probabilities of default, auction failure, or repurchase at par for each period; (iv) assessments of counterparty credit quality; (v) estimates of the recovery rates in the event of default for each security; and (vi) overall capital market liquidity. These estimated fair values were subject to uncertainties that were difficult to predict. Therefore, such auction rate securities were classified as of December 31, 2010 as Level 3 in the fair value hierarchy. In the first quarter of 2011, the

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Company identified a buyer outside of the auction process and, in April 2011, it sold the balance of the auction rate securities for consideration of $2,822,000. Therefore, such auction rate securities have been classified as of March 31, 2011 as Level 2 in the fair value hierarchy, based on the prices which were negotiated in March 2011.

The table below sets forth a summary of the changes in the fair value of the Company’s financial assets classified as Level 3 (i.e. illiquid auction rates securities) for the three months ended March 31, 2011:

 

     (Dollars in
thousands)
 

Balance at beginning of period

   $ 3,027  

Total unrealized losses:

  

Included in net income

     (205

Transferred to Level 2

     (2,822
  

 

 

 

Balance at end of period

   $   
  

 

 

 

There were no transfers of assets or liabilities between Level 1 and Level 2 during the three months ended March 31, 2012.

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

 

     Fair Value      Carrying Amount  
     March 31,
2012
     December 31,
2011
     March 31,
2012
     December 31,
2011
 
     (Dollars in millions)      (Dollars in millions)  

Olkaria III Loan

   $ 80.3      $ 79.2      $ 77.4      $ 77.4  

Amatitlan Loan

     36.6        37.2        36.2        36.8  

Senior Secured Notes:

           

Ormat Funding Corp. (“OFC”)

     118.7        114.8        125.0        125.0  

OrCal Geothermal Inc. (“OrCal”)

     85.8        84.4        85.9        85.9  

OFC 2 LLC (“OFC 2”)

     125.0        131.0        151.7        151.7  

Senior Unsecured Bonds

     238.7        252.8        248.3        248.3  

Loans from institutional investors

     32.5        34.2        32.6        34.2  

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.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The following table presents fair value of financial instruments as of March 31, 2012:

 

     Level 1      Level 2      Level 3      Total  
     (Dollars in millions)  

Olkaria III Loan

   $       $       $ 80.3      $ 80.3  

Amatitlan Loan

                     36.6        36.6  

Senior Secured Notes:

           

Ormat Funding Corp. (“OFC”)

             118.7                118.7  

OrCal Geothermal Inc. (“OrCal”)

                     85.8        85.8  

OFC 2 LLC (“OFC 2”)

                     125.0        125.0  

Senior Unsecured Bonds

                     238.7        238.7  

Loan from institutional investors

                     32.5        32.5  

Other long-term debt

                     50.0        50.0  

Deposits

     21.1                        21.1  

Revolving lines of credit

             227.6                227.6  

NOTE 6 — INTEREST EXPENSE, NET

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

 

     Three Months Ended
March 31,
 
     2012     2011  
     (Dollars in thousands)  

Interest related to sale of tax benefits

   $ 1,837     $ 1,710  

Loss on interest rate lock transactions*

            733  

Other

     16,468       12,918  

Less — amount capitalized

     (3,427     (2,281
  

 

 

   

 

 

 
   $ 14,878     $ 13,080  
  

 

 

   

 

 

 

 

*

The interest rate lock transactions are related to the OFC 2 Senior Secured Notes and were not accounted for using hedge accounting.

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.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

 

     Three Months Ended
March 31,
 
     2012      2011  
     (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

     45,437        45,431  
  

 

 

    

 

 

 

In the three months ended March 31, 2011, 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 5,134,381 and 3,025,249 for the three months ended March 31, 2012 and 2011, 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 power purchase agreements (“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, 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  

Three Months Ended March 31, 2011:

       

Net revenues from external customers

   $ 78,268      $ 19,552     $ 97,820  

Intersegment revenues

             13,362       13,362  

Operating income (loss)

     4,004        (885     3,119  

Segment assets at period end *

     2,005,182        88,765       2,093,947  

* Including unconsolidated investments

     1,980        1,852       3,832  

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

 

     Three Months Ended March 31,  
           2012                 2011        
     (Dollars in thousands)  

Operating income

   $ 25,742     $ 3,119  

Interest income

     388       135  

Interest expense, net

     (14,878     (13,080

Foreign currency translation and transaction gains

     14       517  

Income attributable to sale of equity interest

     2,517       2,139  

Other non-operating (expense), net

     (161     (797
  

 

 

   

 

 

 

Total income (loss), before income taxes and equity in losses of investees

   $ 13,622     $ (7,967
  

 

 

   

 

 

 

NOTE 9 — CONTINGENCIES

Securities Class Actions

Following the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs, three securities class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints assert claims against the Company and certain officers and directors for alleged violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”). One complaint also asserts claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act. All three complaints allege claims on behalf of a putative class of purchasers of Company common stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010. These three lawsuits were consolidated by the Court in an order issued on June 3, 2010 and the Court appointed three of the Company’s stockholders to serve as lead plaintiffs.

Lead plaintiffs filed a consolidated amended class action complaint (“CAC”) on July 9, 2010 that asserts claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of Company common stock between May 7, 2008 and February 24, 2010. The CAC alleges that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate certain of its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleges that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC seeks compensatory damages, expenses, and such further relief as the Court may deem proper.

Defendants filed a motion to dismiss the CAC on August 13, 2010. On March 3, 2011, the court granted in part and denied in part defendants’ motion to dismiss. The court dismissed plaintiffs’ allegations that the Company’s statements regarding the North Brawley project were false or misleading, but did not dismiss plaintiffs’ allegations regarding the 2008 restatement. Defendants answered the remaining allegations in the CAC regarding the restatement on April 8, 2011 and the case has now entered the discovery phase. On July 22, 2011, plaintiffs filed a motion to certify the case as a class action on behalf of a class of purchasers of Company common stock between February 25, 2009 and February 24, 2010, and defendants filed an opposition to the motion for class certification on October 4, 2011.

 

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(Unaudited)

 

Subsequently, the parties participated in a mediation where they reached an agreement in principle to settle the securities class action lawsuits. The parties thereafter filed a stipulation of settlement with the U.S. District Court for the District of Nevada on March 27, 2012 providing that the claims against the Company and its officers and directors will be dismissed with prejudice and plaintiffs will release the defendants from all claims in exchange for a cash payment of $3.1 million to be funded by the Company’s insurers. The stipulation of settlement received preliminary approval by the Court on March 30, 2012. It still remains subject to final approval by the Court following notice to members of the class.

The Company and the individual defendants have steadfastly maintained that the claims raised in the securities class action lawsuits were without merit, and have vigorously contested those claims. As part of the settlement, the Company and the individual defendants continue to deny any liability or wrongdoing under the securities laws or otherwise.

Stockholder Derivative Cases

Four stockholder derivative lawsuits have also been filed in connection with the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs. Two cases were filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe on March 16, 2010 and April 21, 2010 and two cases were filed in the United States District Court for the District of Nevada on March 29, 2010 and June 7, 2010. All four lawsuits assert claims brought derivatively on behalf of the Company against certain of its officers and directors for alleged breach of fiduciary duty and other claims, including waste of corporate assets and unjust enrichment.

The two stockholder derivative cases filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe were consolidated by the Court in an order dated May 27, 2010 and the plaintiffs filed a consolidated derivative complaint on September 7, 2010. In accordance with a stipulation between the parties, defendants filed a motion to dismiss on November 16, 2010. On April 18, 2011, the court stayed the state derivative case pending the resolution of the securities class action lawsuits. The Company cannot make an estimate of the reasonably possible loss or range of reasonably possible loss on the state derivative case.

The two stockholder derivative cases filed in the United States District Court for the District of Nevada were consolidated by the Court in an order dated August 31, 2010, and plaintiffs filed a consolidated derivative complaint on October 28, 2010. The Company filed a motion to dismiss on December 13, 2010. On March 7, 2011, the Court transferred the federal derivative case to the Court presiding over the securities class action, and on August 29, 2011, the Court stayed the federal derivative case pending the resolution of the securities class action lawsuits. The Company cannot make an estimate of the reasonably possible loss or range of reasonably possible loss on the federal derivative case.

The Company believes the allegations in these purported derivative actions are without merit and is defending the actions vigorously.

Other

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 asks 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

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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 the 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 Ormat Energy Converters 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 Ormat Energy Converters capable of generating more than 50 MW.

The Company believes that the petition is without merit and intends to respond and take necessary legal action to dismiss the proceedings. The Company was notified that CURE intends to file the administrative record from the underlying administrative proceeding in the Alameda County Superior Court proceeding. This notice extended the time for the Company to respond to CURE’s petition. Once the Company is served with a certified copy of the administrative record, the Company will have thirty days in which to respond to CURE’s petition, unless the Company agrees to a shorter time. Filing of the petition in and of itself does not have any immediate adverse implications for the North Brawley or East Brawley projects and the Company continues to operate the North Brawley project in the ordinary course of business and continues with its development work on the East Brawley project.

From time to time, the Company is named as a party in various 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 financial statements as a whole.

NOTE 10 — INCOME TAXES

The Company’s effective tax rate for the three months ended March 31, 2012 and 2011 was 40.1% and 7.4%, respectively. The effective tax rate differs from the federal statutory rate of 35% for the three months ended March 31, 2012 primarily due to the $6.4 million increase in the valuation allowance against our U.S. deferred tax assets in respect of net operating loss 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.

At December 31, 2011, the Company had U.S. federal net operating loss (“NOL”) carryforwards of approximately $349.5 million and state NOL carryforwards of approximately $159.0 million available to reduce future taxable income, which expire between 2021 and 2031 for federal NOLs and between 2015 and 2031 for state NOLs. Investment tax credits in the amount of $2.0 million at December 31, 2011 are available for a 20-year period and expire between 2022 and 2024. Production tax credits in the amount of $59.9 million at December 31, 2011 are available for a 20-year period and expire between 2026 and 2031.

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

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

amount of valuation allowance. A valuation allowance in the amount of $61.5 million was recorded against the U.S. deferred tax assets as of December 31, 2011 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 $67.9 million as of March 31, 2012. 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.

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. 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, and thereafter such income was subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax would apply to all qualified income of certain industrial companies, as opposed to the current 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. As a result, the deferred taxes as of December 31, 2010 have been reduced by $0.5 million. This amount reduced the tax provision for the three months ended March 31, 2012 by such amount.

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

 

     Three Months Ended March 31,  
           2012                  2011        
     (Dollars in thousands)  

Balance at beginning of period

   $ 5,875      $ 5,431  

Additions based on tax positions taken in prior years

     534        239  

Decrease for settlements with taxing authorities

             (1,376
  

 

 

    

 

 

 

Balance at end of period

   $ 6,409      $ 4,294  
  

 

 

    

 

 

 

NOTE 11 — SUBSEQUENT EVENTS

Stock-based Awards Grant

On April 2, 2012, the Company granted to employees 605,500 stock appreciation rights (“SARs”) under the Company’s 2004 Incentive Plan. The exercise price of each SAR is $20.13, which represented the fair market value of the Company’s common stock on the date of grant. Such SARs will expire seven years from the date of grant and will cliff vest and are exercisable from the grant date as follows: 25% after 24 months, an additional 25% after 36 months, and the remaining 50% after 48 months. Upon exercise, SARs entitle the recipient to receive shares of common stock equal to the increase in value of the award between the grant date and the exercise date.

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Swap Contracts on Oil Prices

On April 18, 2012, the Company entered into two swap contracts with a bank effective from May 1, 2012 until March 31, 2013 to reduce the Company’s exposure to fluctuations in the energy rate under the 25 MW PPA for the Puna complex as a result of fluctuations in oil prices. The Company decided to enter into a NYMEX Heating Oil swap contract (85%) and an ICE Brent swap contract (15%) as both swaps had a high correlation with the avoided costs that Hawaii Electric Light Company uses to calculate the energy rate. The current fuel prices are at historically high levels and the Company wanted to protect itself from a decrease in prices over the next twelve months. The contracts did not have up-front costs. Under these contracts the Company will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date. The swap contracts have monthly settlements whereby the difference between the fixed price and the monthly average price will be settled on a cash basis. These contracts will not be accounted for as hedge transactions and will be marked to market with the corresponding gains or losses which will be recognized within electricity revenues.

Cash Dividend

On May 8, 2012, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $1.8 million ($0.04 per share) to all holders of the Company’s issued and outstanding shares of common stock on May 21, 2012, payable on May 30, 2012.

 

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

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. We will not update forward-looking statements even though our situation may change in the future.

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;

 

   

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

 

   

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

 

   

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;

 

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weather and other natural phenomena;

 

   

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 and incentives for the production of renewable energy 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, as well as from alternative electricity producing technologies;

 

   

the effect of and changes in economic conditions in the areas in which we operate;

 

   

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 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;

 

   

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;

 

   

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

 

   

the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2011;

 

   

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

 

   

other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (SEC).

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. 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, 2011 and any updates contained herein as well as those set forth in our reports and other filings made with the SEC.

 

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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, which we refer to as our Electricity Segment and Product Segment. In our Electricity 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 photovoltaic (Solar PV) systems that we do not manufacture. In our Product 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 power plants in the United States, Guatemala, Kenya, and Nicaragua, as well as recovered energy generation (REG) plants in the United States.

For the three months ended March 31, 2012, our Electricity Segment revenues represented approximately 62.1% of our total revenues, while our Product Segment revenues represented approximately 37.9% of our total revenues. For the three months ended March 31, 2011, our Electricity Segment revenues represented approximately 80.0% of our total revenues, while our Product Segment revenues represented approximately 20.0% of our total revenues.

For the three months ended March 31, 2012, our total revenues increased by 35.3% (from $97.8 million to $132.4 million) over the same period last year.

For the three months ended March 31, 2012, total Electricity Segment revenues were $82.2 million, compared to $78.3 million for the three months ended March 31, 2011, an increase of 5.1%, while Product Segment revenues were $50.1 million for the three months ended March 31, 2012, compared to $19.6 million for the three months ended March 31, 2011, an increase of 156.3%.

Revenues from our Electricity Segment are derived from sales of electricity generated by our power plants pursuant to long-term PPAs. We have variable price PPAs in California, Hawaii and Guatemala. The energy rate under the PPAs in California for the Ormesa complex, the Mammoth complex, and the Heber 1 and Heber 2 power plants, converted, in the beginning of May 2012, from a fixed to a variable rate that is subject to the impact of fluctuations in natural gas prices. The prices paid for the electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii are variable and based on the local utility’s 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 prices, which are calculated on a monthly basis, are mainly impacted by the price of oil. However, we have hedged our exposure to fluctuations in the price of oil until March 31, 2013 (see further details under “Recent Developments” below). In the three months ended March 31, 2012, approximately 82.6% of our electricity revenues were derived from contracts with fixed energy rates, which are not affected by the fluctuations in energy commodity prices. However, electricity revenues are subject to seasonal variations and can be affected by higher-than average ambient temperatures, as described below under the heading “Seasonality”.

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.

 

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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, relevant technical and geological matters and other relevant 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

 

   

Since the beginning of 2012, we have entered into new leases for approximately 16,500 acres in Nevada.

 

   

On April 18, 2012, we entered into two swap contracts with a bank effective from May 1, 2012 until March 31, 2013 to reduce our exposure to fluctuations in the energy rate under our 25 MW PPA for the Puna complex as a result of fluctuations in oil prices. We decided to enter into a NYMEX Heating Oil swap contract (85%) and an ICE Brent swap contract (15%) as both swaps had a high correlation with the avoided costs that Hawaii Electric Light Company (HELCO) uses to calculate the energy rate. The current fuel prices are at historically high levels and we wanted to protect ourselves from a decrease in prices over the next twelve months. The contracts did not have up-front costs. Under these contracts we will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date. The swap contracts have monthly settlements whereby the difference between the fixed price and the monthly average price will be settled on a cash basis. These contracts will not be accounted for as hedge transactions and will be marked to market with the corresponding gains or losses which will be recognized within electricity revenues.

 

   

In April 2012, our wholly owned subsidiary, Ormat Nevada Inc. (Ormat Nevada) won a $61.2 million engineering, procurement and construction (EPC) contract. Under the expected EPC contract, which is currently under negotiation, we will provide two air-cooled Ormat Energy Converters at a geothermal power plant project in North America. The project is expected to be completed by the end of 2013. Until the signing of the full EPC contract, the parties have entered into an interim service agreement in the amount of approximately $9.0 million for a limited scope of work to ensure timely completion of the project.

 

   

In April 2012, we received from the U.S. Department of the Treasury (U.S. Treasury) $13.8 million in a cash grant for Specified Energy Property in Lieu of Tax Credits relating to our Puna geothermal complex under Section 1603 of the American Recovery and Reinvestment Act of 2009 (ARRA).

 

   

On February 16, 2012, Geothermal Development Company (GDC), a company owned by the Government of Kenya, awarded our subsidiary the first well head power plant project in the Menengai geothermal field in Kenya on a Build-Own-Transfer basis. The award was the result of an international tender for the design, manufacturing, procurement, construction and commissioning of a 6 MW geothermal well head power plant. GDC will supply the steam for conversion to electricity by Ormat’s power plant. The Menengai geothermal field is located on the outskirts of the town of Nakuru, about 110 miles west of Nairobi.

 

   

On January 30, 2012, the Public Utilities Commission of Nevada (PUCN) approved the 20-year PPA that we signed in February 2011 with NV Energy, Inc. (NV Energy) to sell 30 MW from the Dixie Meadows geothermal project that we are developing in Churchill County, Nevada.

 

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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 newly enacted legislative and regulatory requirements and incentives, such as state renewable portfolio standards and federal tax credits. The ARRA further encourages the use of geothermal energy through production 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”). In response, the geothermal industry in the U.S. has seen a wave of new entrants and, over the last several years, consolidation involving smaller developers. We see the increasing demand for energy generated from geothermal and other renewable resources in the United States and the further introduction of renewable portfolio standards as significant trends affecting our industry today and in the immediate future. Our operations and the trends that from time to time impact our operations are subject to market cycles.

We expect to continue to generate the majority of our revenues from our Electricity Segment through the sale of electricity from our power plants. Substantially 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.

In our Product Segment, we expect our increased backlog to have a positive impact on our revenues in that segment over the next couple of years.

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:

 

   

Our primary focus continues to be our organic growth through exploration, development, and construction of new projects and enhancements of existing power plants. We expect that this 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.

 

   

We expect that 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 U.S. Environmental Protection Agency’s (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 greenhouse gas (GHG) emissions. Federal legislation or additional federal regulations addressing climate change are possible. 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 California Air Resources Board (CARB) adopted cap-and-trade regulations to reduce California’s greenhouse gas emissions under AB 32. Compliance obligations under the cap-and-trade program are anticipated to commence in January 2013. However, implementation of this cap-and-trade program under AB 32 has been the subject of legal challenges that may hinder and/or ultimately thwart its implementation. In September of 2006, California also passed Senate Bill 1368, which prohibits the state’s utilities from entering into long-term financial commitments for base-load generation with power plants that fail to meet a CO2 emission performance standard established by the California Energy Commission and the California Public Utilities Commission. California’s long-term climate change goals

 

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are reflected in Executive Order S-3-05, which requires a reduction in GHGs to: (i) 2000 levels by 2010; (ii) 1990 levels by 2020; and (iii) 80% of 1990 levels by 2050. In addition to California, twenty-two other states have set GHG emissions targets or goals (Arizona, Colorado, Connecticut, Florida, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, Montana, New Hampshire, New Jersey, New Mexico, New York, Oregon, Rhode Island, Utah, Vermont, Virginia and Washington). 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 September 2008, the first-in-the-nation auction of CO2 allowances was held under the RGGI, a regional cap-and-trade system, which includes nine Northeast and Mid-Atlantic States. Under RGGI, the participating states plan to stabilize power section carbon emissions at their capped level, and then reduce the cap by a total of 10% at a rate of 2.5% each year between 2015 and 2018. In addition, twenty-nine states and the District of Columbia have adopted RPS and eight other states have adopted renewable portfolio goals. On April 12, 2011, Governor Jerry Brown signed California Senate Bill X1-2 (SBX1-2) which increased California’s RPS to 33% by December 31, 2020 and instituted a tradable REC program, according to which California utilities can purchase three products to comply with SBX1-2: (i) bundled electricity and RECs from electricity generators that interconnect with a California balancing authority, (ii) tradable RECs that are purchased either from out-of-state electricity generators or in-state electricity generators that do not interconnect with a California balancing authority, and (iii) firmed and shaped transactions with out-of-state electricity generators. Until December 31, 2013, unbundled tradable RECs may account for only 25% of a utility’s annual RPS, but this limit on unbundled RECs does not apply to municipal utilities and other small entities. The percentage will be reduced after 2013. 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. We expect that the additional demand for renewable energy from utilities in states with RPS will outpace a possible reduction in general demand for energy (if any) due to the effect of economic conditions. We see this increased demand expected principally after 2016 driven by the impact of the increase in California Renewable Portfolio Standards (RPS), as one of the most significant opportunities for us to expand existing power plants and develop new power plants.

 

   

Outside of the United States, we expect that a variety of government 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.

 

   

We expect competition from the wind and solar power generation industry to continue. While the expected demand for renewable energy is large to accommodate increased competition, the increase in competition 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 resources.

 

   

The business environment for obtaining new PPAs has become more difficult. Currently, at least one of the three main investor-owned utilities in California appears to have sufficient renewable energy under contract to satisfy its RPS goals over the next few years. However, we believe that this is a temporary market condition and remain confident in our ability to secure new long-term PPAs.

 

   

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

 

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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 liquefied natural gas (LNG) from the international gas market to balance supply with expected demand. The rise of shale gas production over the last three years has completely 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. Among other things, this 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, have already received an export license to export liquefied natural gas, 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 chemicals leakage, ground water contamination and other effects, which may slow development in some areas. The changing natural gas landscape, and 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, all combine to affect the pricing under our PPAs that have SRAC pricing or that are otherwise tied to natural gas prices. In addition, the current low natural gas price level is causing some producers to shut-in wells, which in turn may increase natural gas prices.

 

   

Our 25 MW PPA for the Puna complex has a monthly variable energy rate based on the local utility’s short run avoided costs, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. 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.

 

   

Our PPAs for the Ormesa complex, the Mammoth complex and the Heber 1 and 2 power plants were fixed until May 1, 2012. As of this date, the energy price component under these PPAs has changed from a fixed rate to a variable rate based on SRAC pricing, as required under a global settlement relating primarily to purchase and payment obligations of investor-owned utilities in California. These PPAs are impacted by fluctuations in natural gas prices.

 

   

We are experiencing a notable decrease in competition in the geothermal industry, specifically in the acquisition of geothermal leases. The reduced level of competition has contributed to a decrease in lease costs.

 

   

In the United States, we have noticed increased activity from union organizers to encourage employees to join unions that will act as bargaining representatives. We currently do not have employees represented by collective bargaining agreements. However, the International Brotherhood of Electrical Workers (IBEW) has recently filed a petition with the National Labor Relations Board (NLRB) in an attempt to organize our employees in our Puna complex in Hawaii.

 

   

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 age, they may require increased maintenance with a resulting decrease in their availability, potentially leading to the imposition of penalties if we are not able to meet the requirements under our PPAs as a result of any decrease in availability.

 

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Our foreign operations are subject to significant political, economic and financial risks, which vary by country. As of today, 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 Federal Energy Regulatory Commission (FERC) to revise the Public Utility Regulatory Policies Act (PURPA) so as to terminate the obligation of electric utilities to purchase the output of a Qualifying Facility if FERC finds that there is an accessible competitive market for energy and capacity from the Qualifying Facility. The legislation does not affect existing PPAs. We do not expect this change in law to affect our U.S. power plants significantly, as all except one of our current contracts 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. We have variable price PPAs in California, Hawaii and Amatitlan. Our California PPAs are subject to the impact of fluctuations in natural gas prices. The prices paid for electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii are impacted by the price of oil. The energy price under the Amatitlan PPA is fixed, but we have the option to sell the power with an advance notice to the spot market. Accordingly, our revenues from those power plants may fluctuate. In April 2012, we hedged our exposure to the price of oil, under the 25 MW PPA for the Puna complex, until March 31, 2013 (for further details please see discussion under “Recent Developments” above). Our Electricity Segment revenues are also subject to seasonal variations, as more fully described in the section entitled “Seasonality”, 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 short run avoided costs (the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others). 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 win 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 often subject to various contingencies, such as the customer’s ability to raise the necessary financing for a project. As a result, we are generally unable to predict the timing of such orders for our products

 

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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 (and at times, extensively) from period to period. In 2011, 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 increase over the next two years as a result of the 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,
 
         2012              2011              2012             2011      

Revenues:

          

Electricity

   $ 82,247       $ 78,268         62.1     80.0

Product

     50,105         19,552        37.9       20.0  
  

 

 

    

 

 

    

 

 

   

 

 

 

Total

   $ 132,352       $ 97,820         100.0     100.0
  

 

 

    

 

 

    

 

 

   

 

 

 

Geographical Breakdown of Revenues

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,
 
         2012              2011              2012             2011      

United States

   $ 62,244       $ 59,491         75.7     76.0

Foreign

     20,003        18,777        24.3       24.0  
  

 

 

    

 

 

    

 

 

   

 

 

 

Total

   $ 82,247       $ 78,268         100.0     100.0
  

 

 

    

 

 

    

 

 

   

 

 

 

For the three months ended March 31, 2012 and 2011, all of our revenues attributable to our Product Segment were generated outside of the United States.

Seasonality

The prices paid for the electricity generated by some of our domestic power plants pursuant to our PPAs are subject to seasonal variations. The prices paid for electricity under the PPAs with Southern California Edison Company (Southern California Edison) for the Heber 1 and 2 plants, the Mammoth complex, the Ormesa complex, and the North Brawley plant are higher in the months of June through September. As a result, we receive, and will receive in the future, higher revenues during such months. The prices paid for electricity pursuant to the PPAs of our power plants in Nevada have no significant changes during the year. In the winter, due principally to the lower ambient temperature, our power plants produce more energy and as a result we receive higher energy revenues. However, the higher capacity payments payable by Southern California Edison in California 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

 

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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 4.5% and 3.0%, respectively, for the three months ended March 31, 2012 and 2011, 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 and Marketable Securities

Our cash, cash equivalents and marketable securities as of March 31, 2012 decreased to $100.3 million from $118.4 million as of December 31, 2011. This decrease is principally due to: (i) our use of $65.4 million to fund capital expenditures; (ii) repayment of $3.8 million of long-term debt; and (iii) cash paid to non-controlling interest of $4.2 million. The decrease in our cash resources was partially offset by: (i) $41.9 million derived from operating activities during the three months ended March 31, 2012; and (ii) net proceeds of $13.6 million against our revolving credit lines with commercial banks. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of March 31, 2012 was $420.0 million, as described below in the section entitled “Liquidity and Capital Resources”, of which we utilized $367.4 million (including $149.7 million of letters of credit) as of March 31, 2012.

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, 2011.

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.

 

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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 each of the following: (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,  
             2012                     2011          
    

(In thousands, except

per share data)

 

Statements of Operations Historical Data:

    

Revenues:

    

Electricity

   $ 82,247     $ 78,268  

Product

     50,105       19,552  
  

 

 

   

 

 

 
     132,352       97,820  
  

 

 

   

 

 

 

Cost of revenues:

    

Electricity

     57,931       65,937  

Product

     34,627       16,890  
  

 

 

   

 

 

 
     92,558       82,827  
  

 

 

   

 

 

 

Gross margin:

    

Electricity

     24,316       12,331  

Product

     15,478       2,662  
  

 

 

   

 

 

 
     39,794       14,993  

Operating expenses:

    

Research and development expenses

     1,048       2,207  

Selling and marketing expenses

     4,922       2,660  

General and administrative expenses

     7,314       7,007  

Write-off of unsuccessful exploration activities

     768         
  

 

 

   

 

 

 

Operating income

     25,742       3,119  

Other income (expense):

    

Interest income

     388       135  

Interest expense, net

     (14,878     (13,080

Foreign currency translation and transaction gains

     14       517  

Income attributable to sale of tax benefits

     2,517       2,139  

Other non-operating expense, net

     (161     (797
  

 

 

   

 

 

 

Income (loss), before income taxes and equity in losses of investees

     13,622       (7,967

Income tax provision

     (5,457     (586

Equity in losses of investees

     (140     (412
  

 

 

   

 

 

 

Net income (loss)

     8,025       (8,965

Net income attributable to noncontrolling interest

     (130     (10
  

 

 

   

 

 

 

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

   $ 7,895     $ (8,975
  

 

 

   

 

 

 

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

   $ 0.17     $ (0.20
  

 

 

   

 

 

 

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

     45,437       45,431  
  

 

 

   

 

 

 

 

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     Three Months Ended March 31,  
             2012                     2011          

Statements of Operations Percentage Data:

    

Revenues:

    

Electricity

     62.1     80.0

Product

     37.9       20.0  
  

 

 

   

 

 

 
     100.0       100.0  
  

 

 

   

 

 

 

Cost of revenues:

    

Electricity

     70.4       84.2  

Product

     69.1       86.4  
  

 

 

   

 

 

 
     69.9       84.7  
  

 

 

   

 

 

 

Gross margin:

    

Electricity

     29.6       15.8  

Product

     30.9       13.6  
  

 

 

   

 

 

 
     30.1       15.3  

Operating expenses:

    

Research and development expenses

     0.8       2.3  

Selling and marketing expenses

     3.7       2.7  

General and administrative expenses

     5.5       7.2  

Write-off of unsuccessful exploration activities

     0.6       0.0  
  

 

 

   

 

 

 

Operating income

     19.4       3.2  

Other income (expense):

    

Interest income

     0.3       0.1  

Interest expense, net

     (11.2     (13.4

Foreign currency translation and transaction gains

     0.0       0.5  

Income attributable to sale of tax benefits

     1.9       2.2  

Other non-operating expense, net

     (0.1     (0.8
  

 

 

   

 

 

 

Income (loss), before income taxes and equity in losses of investees

     10.3       (8.1

Income tax provision

     (4.1     (0.6

Equity in losses of investees

     (0.1     (0.4
  

 

 

   

 

 

 

Net income (loss)

     6.1       (9.2

Net income attributable to noncontrolling interest

     (0.1     (0.0
  

 

 

   

 

 

 

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

     6.0     (9.2 )% 
  

 

 

   

 

 

 

Comparison of the Three Months Ended March 31, 2012 and the Three Months Ended March 31, 2011

Total Revenues

Total revenues for the three months ended March 31, 2012 were $132.4 million, compared to $97.8 million for the three months ended March 31, 2011, which represented a 35.3% increase in total revenues. This increase is attributable to both our Electricity and Product Segments, whose revenues increased by 5.1% and 156.3%, respectively, over the same period last year.

Electricity Segment

Revenues attributable to our Electricity Segment for the three months ended March 31, 2012 were $82.2 million, compared to $78.3 million for the three months ended March 31, 2011, which represented a 5.1% increase in such revenues. This result is due to an increase in the electricity rates in our Puna complex and

 

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Amatitlan power plant, whose energy payments are variable (see “Revenues” above). As a result, the average revenue rate of our electricity portfolio increased from $76 per MWh in the three months ended March 31, 2011 to $79 per MWh in the three months ended March 31, 2012. The generation in our power plants increased by 1.2% from 1,027,622 MWh in the three months ended March 31, 2011, to 1,040,044 MWh in the three months ended March 31, 2012. (We revised the calculation of the MWh for our Zunil power plant to reflect the change in the energy payment, which is based, since September 2011, on the actual generation of the power plant). The revenues from our North Brawley power plant in the first quarter of 2012 decreased to $3.2 million from $4.0 million during the same quarter in 2011.

Product Segment

Revenues attributable to our Product Segment for the three months ended March 31, 2012 were $50.1 million, compared to $19.6 million for the three months ended March 31, 2011, which represented a 156.3% increase in such revenues. The increase in our product revenues reflects the increase in new customer orders that we secured in 2011, and the recognition of $3.0 million of revenues, which represent the final proceeds upon completion of an LNG energy recovery unit in Spain.

Total Cost of Revenues

Total cost of revenues for the three months ended March 31, 2012 was $92.6 million, compared to $82.8 million for the three months ended March 31, 2011, which represented an increase of 11.7% in total cost of revenues, which increase reflects the significant increase in revenues attributable to our Product Segment. As a percentage of total revenues, our total cost of revenues for the three months ended March 31, 2012 was 69.9%, compared to 84.7% for the same period in 2011. The decrease in cost of revenues as a percentage of total revenues is attributable to the decrease in total cost of revenues attributable to our Electricity Segment and to the increase in revenues attributable to our Product Segment.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the three months ended March 31, 2012 was $57.9 million, compared to $65.9 million for the three months ended March 31, 2011, which represented a 12.1% decrease in total cost of revenues for such segment. We incurred lower costs associated with operating and maintaining the North Brawley power plant in the first quarter of 2012 ($7.2 million), compared to the first quarter of 2011 ($14.3 million). The cost per MWh in the current quarter was lower than in the first quarter of 2011, as a result of lower maintenance costs in most of our other power plants and specifically at North Brawley over the same quarter last year. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the three months ended March 31, 2012 was 70.4%, compared to 84.2% for the three months ended March 31, 2011.

Product Segment

Total cost of revenues attributable to our Product Segment for the three months ended March 31, 2012 was $34.6 million, compared to $16.9 million for the three months ended March 31, 2011, which represented a 105.0% increase in total cost of revenues related to such segment. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the three months ended March 31, 2012 was 69.1%, compared to 86.4% for the three months ended March 31, 2011. This decrease in product cost of revenues as a percentage of total product revenues is mainly attributable to: (i) higher revenues; (ii) a different product mix; and (iii) different margins in the various sales contracts.

 

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Research and Development Expenses

Research and development expenses for the three months ended March 31, 2012 were $1.0 million, compared to $2.2 million for the three months ended March 31, 2011, which represented a 52.5% decrease, which is primarily attributable to the costs incurred in the first quarter of 2011 in respect of an experimental LNG energy recovery unit which was completed in 2011. Our research and development activities during the three months ended March 31, 2012 included: (i) continued development of Enhanced Geothermal Systems (EGS); and (ii) activities intended to improve plant performance, reduce costs, and increase the breadth of product offerings. These activities include developing: (i) improvements to our Evaporative Cooling system; (ii) condensing equipment with improved performance and lower land usage; (iii) new turbine products; and (iv) specialized power units designed to reduce fuel consumption and associated costs during a project’s development phase.

Selling and Marketing Expenses

Selling and marketing expenses for the three months ended March 31, 2012 were $4.9 million, compared to $2.7 million for the three months ended March 31, 2011, which represented an 85.0% increase. The increase reflects additional selling and marketing expenses associated with the increased Product Segment revenues. Selling and marketing expenses for the three months ended March 31, 2012 constituted 3.7% of total revenues, compared to 2.7% for the three months ended March 31, 2011.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2012 were $7.3 million, compared to $7.0 million for the three months ended March 31, 2011, which represented a 4.4% increase. General and administrative expenses for the three months ended March 31, 2012 constituted 5.5% of total revenues compared to 7.2% for the three months ended March 31, 2011.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the three months ended March 31, 2012 was $0.8 million, which represented 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. We did not have a write-off of unsuccessful exploration activities in the three months ended March 31, 2011.

Operating Income

Operating income for the three months ended March 31, 2012 was $25.7 million, compared to $3.1 million for the three months ended March 31, 2011. Such increase of $22.6 million in operating income was principally attributable to an increase in our gross margin due to the increase in revenues, as described above. Operating income attributable to our Electricity Segment for the three months ended March 31, 2012 was $15.9 million, compared to $4.0 million for the three months ended March 31, 2011. Operating income attributable to our Product Segment for the three months ended March 31, 2012 was $9.9 million, compared to an operating loss of $0.9 million for the three months ended March 31, 2011.

Interest Expense, Net

Interest expense, net for the three months ended March 31, 2012 was $14.9 million, compared to $13.1 million for the three months ended March 31, 2011, which represented a 13.7% increase. The $1.8 million increase is primarily due to additional interest expense as a result of: (i) the issuance of Series A Senior Secured Notes in October 2011 by OFC 2 to finance a portion of the construction costs of Phase I of the McGinness Hills

 

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and Tuscarora facilities; and (ii) the full quarter impact in 2012 of the issuance of Senior Unsecured Bonds in February 2011. The increase was partially offset by: (i) an increase of $1.1 million in interest capitalized to projects as a result of increased aggregate investment in projects under construction; and (ii) a decrease in interest expense as a result of principal repayments.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits to institutional equity investors (as described in “OPC Transaction” below) for the three months ended March 31, 2012 was $2.5 million, compared to $2.1 million for the three months ended March 31, 2011. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The increase resulted from the sale of Class B membership units of OPC LLC to JPM Capital Corporation on February 3, 2011.

Income Taxes

Income tax provision for the three months ended March 31, 2012 was $5.5 million, compared to $0.6 million for the three months ended March 31, 2011. The effective tax rate for the three months ended March 31, 2012 was 40.1%, compared to 7.4% for the three months ended March 31, 2011. The increase in the effective tax rate primarily resulted from the $6.4 million increase in the valuation allowance against our U.S. deferred tax assets in respect of net operating loss carryforwards and unutilized tax credits.

Net Income (Loss)

Net income for the three months ended March 31, 2012 was $8.0 million, compared to net loss of $9.0 million for the three months ended March 31, 2011. Such increase in net income of $17.0 million was principally attributable to a $22.6 million increase in operating income. The increase was partially offset by: (i) a $1.8 million increase in interest expense, net of capitalized interest; and (ii) a $4.9 million increase in income tax provision.

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 Ormat Funding Corp. (OFC), OrCal Geothermal Inc. (OrCal), and OFC 2 LLC (OFC 2) of their respective Senior Secured Notes, project financing (including the Puna lease and the OPC Transaction described below), and cash grants we received under the ARRA. We have utilized this cash to fund our acquisitions, to develop and construct power generation plants, and to meet our other cash and liquidity needs.

As of March 31, 2012, we have access to the following sources of funds: (i) $100.3 million in cash, cash equivalents and marketable securities; and (ii) $52.6 million of unused corporate borrowing capacity under existing committed lines of credit with different commercial banks.

Our estimated capital needs for the remainder of 2012 include approximately $270 million for capital expenditures on new projects in development or construction, exploration activity, operating projects, and machinery and equipment, as well as $51.7 million for debt repayment.

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) cash flows from our operations; (iii) future project financing and refinancing (including construction loans); and (iv) cash grants available to us under the ARRA relating to new projects that will be placed in service before the end of 2013. Management believes that these sources will meet our anticipated liquidity, capital expenditures and other investment requirements.

 

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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 under the heading “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 under the heading “Full-Recourse Third-Party Debt.”

Non-Recourse and Limited-Recourse Third-Party Debt

OFC Senior Secured Notes — Non-Recourse

On February 13, 2004, OFC, one of our subsidiaries, issued $190.0 million, 8 1/4% Senior Secured Notes (OFC Senior Secured Notes) in an offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended (the Securities Act), for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1 and 1A power plants, and the financing of the acquisition cost of the Steamboat 2 and 3 power plants. 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 which commenced on September 30, 2004. 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 a required historical and projected 12-month debt service coverage ratio (DSCR) of not less than 1.25 (which are measured semi-annually as of June 30 and December 31 of each year) and other limitations on additional indebtedness. If OFC fails to comply with these financial ratios it will be precluded from making distributions to its shareholders. In addition, subject to certain cure rights, such failure will constitute an event of default by OFC. We expect that the transition to variable energy prices under the Ormesa and Mammoth PPAs and the impact of the low natural gas prices on our revenues will cause OFC to be below DSCR requirements for dividend distribution, but we do not expect an event of default by OFC. As of December 31, 2011 (the last measurement date of the covenants), the actual historical 12-month DSCR was 1.49. As of March 31, 2012, there were $125.0 million of OFC Senior Secured Notes outstanding.

OrCal Secured Notes — Non-Recourse

On December 8, 2005, OrCal, one of our subsidiaries, issued $165.0 million, 6.21% Senior Secured Notes (OrCal Senior Secured Notes) in an offering subject to Rule 144A and Regulation S of the Securities Act, for the purpose of refinancing the acquisition cost of the Heber power plants. The OrCal Senior Secured Notes have been rated BBB- by Fitch. 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 that commenced on September 30, 2006. 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 a required historical and projected 12-month DSCR of not less than 1.25 (which are measured semi-annually as of June 30 and December 31 of each year) and other limitations on additional indebtedness. If OrCal fails to comply with these financial ratios it will be precluded from making distributions to its shareholders. In addition, subject to certain cure rights, such failure will constitute an event of default by OrCal. As of December 31, 2011 (the last measurement date of the covenants), the actual historical 12-month DSCR was 2.02. As of March 31, 2012, there were $85.9 million of OrCal Senior Secured Notes outstanding.

 

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

On September 23, 2011, OFC 2, one of our subsidiaries, and its wholly owned project subsidiaries (collectively, the 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 U.S Department of Energy (DOE), as guarantor, in connection with the offer and sale of up to $350.0 million aggregate principal amount of OFC 2 Senior Secured Notes 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 facilities owned by the 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 in accordance with an amortization schedule attached to such Notes 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 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 (the DOE Guarantee) 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 the DOE Guarantee.

On October 31, 2011 the Issuers completed the sale of $151.7 million in aggregate principal amount of 4.687% Series A Notes due 2032 (the Series A Notes). The net proceeds from the sale of the Series A Notes, after deducting transaction fees and expenses, were approximately $147.4 million, and were used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora facilities and to fund certain reserves. Interest on the Series A Notes is payable quarterly in arrears on the last day of March, June, September and December, commencing December 31, 2011. Principal on the Series A Notes is payable on the same quarterly dates, commencing September 30, 2012.

Issuance of the Series B Notes is dependent on the Jersey Valley facility 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 will be used to finance a portion of the construction costs of Phase I of the Jersey Valley facility.

The Issuers have sole discretion regarding whether to commence construction of Phase II of any of the Jersey Valley, McGinness Hills and Tuscarora facilities. If Phase II construction is undertaken for any of the facilities, the Issuers may issue Phase II tranches of Notes, comprised of one or more of the Series C Notes, the Series D Notes, the Series E Notes and the 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 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 and certain restrictions on dividend payments. Among other things, the dividend restrictions include a DSCR requirement of at least 1.2 (on a blended basis for all of the OFC 2 facilities) and 1.5 on a pro forma basis (giving effect to the dividend payment) which will be measured after the McGinness Hills and Tuscarora facilities have been constructed and have met certain completion requirements.

 

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In addition, in connection with the issuance of each Series of OFC 2 Senior Secured Notes, we will provide a guarantee with respect to the OFC 2 Senior Secured Notes, which will be available to be drawn upon if specific 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 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 Issuers into compliance with certain coverage ratios. A demand on our guarantee based on the other trigger event is not so limited.

As of March 31, 2012, there were $151.7 million of OFC 2 Senior Secured Notes outstanding.

Olkaria III Loan — Non-Recourse

OrPower 4, Inc. (OrPower 4), has a project financing loan of $105.0 million which refinanced its investment in the 48 MW Olkaria III complex located in Kenya. The loan was provided by a group of European Development Finance Institutions (DFIs) arranged by DEG — Deutsche Investitions- und Entwicklungsgesellschaft mbH (DEG). The 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 $77.0 million of the loan at 6.90% per annum. There are various restrictive covenants under the loan, including a requirement to comply with the following financial ratios for each calculation period (measured as of June 15 and December 15 of each year): (i) an historical and projected 12-month DSCR of not less than 1.15; (ii) a debt to equity ratio which does not exceed 3; and (iii) an equity to total assets ratio of not less than 0.25. If OrPower 4 fails to comply with these financial ratios it will be precluded from making distributions to its shareholders. In addition, subject to certain cure rights, such failure will constitute an event of default by OrPower 4. As of December 31, 2011(the last measurement date of the covenants),: (i) the actual 12-month historical DSCR was 2.34; (ii) the debt to equity ratio was 1.3; and (iii) the equity to total assets ratio was 0.34. As of March 31, 2012, $77.4 million of the Olkaria III loan was outstanding.

We plan to refinance the existing Olkaria III Loan as described under “New Financing of Our Projects” below.

Amatitlan Loan — Non-Recourse

Ortitlan Limitada (Ortitlan) entered into a note purchase agreement in an aggregate principal amount of $42.0 million which refinanced its investment in the 20 MW Amatitlan geothermal power plant located in Amatitlan, Guatemala. The loan was provided by TCW Global Project Fund II, Ltd. (TCW). The loan will mature on June 15, 2016, and is payable in 28 quarterly installments, that commenced on September 15, 2009. The annual interest rate on the loan is 9.83%, but the effective cost for us is approximately 8%, due to the elimination, following the refinancing, of the political risk insurance premiums that we had been paying on our equity investment in the project. As a result of new tax regulations in Guatemala we will need to gross up a 10% withholding tax on the interest paid to TCW, which will increase the effective cost of the loan by approximately 1% during the period from March 13, 2012 to December 31, 2012. There are various restrictive covenants under the loan, which include a projected 12-month DSCR of not less than 1.2, a long-term debt to equity ratio not to exceed 4.0 and other limitations on Ortitlan’s ability to make distributions to its shareholders. If Ortitlan fails to comply with these financial ratios it will be precluded from making distributions to its shareholders. In addition, subject to certain cure rights, such failure will constitute an event of default by Ortitlan. As of March 31, 2012, the projected 12-month DSCR was 1.55 and the debt to equity ratio was 2.29. As of March 31, 2012, Ortitlan was in compliance with the covenants under the loan. As of March 31, 2012, $36.2 million of the Amatitlan loan was outstanding.

 

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New Financing of Our Projects

Refinancing of the Olkaria III Loan and Financing of the Construction of the Olkaria III Complex Expansion

In September 2011, Ormat International, Inc., one of our subsidiaries, signed a commitment letter with the Overseas Private Investment Corporation (OPIC) to provide project financing of up to $310.0 million to refinance and expand our 52 MW Olkaria III geothermal complex located in Kenya. Under the agreed term sheet attached to the commitment letter, the loan will be comprised of a refinancing tranche of up to $85.0 million to prepay the existing loan with DEG and fund transaction costs, a construction loan tranche of up to $165.0 million to finance the construction of an additional 36 MW expansion currently underway, and a $60.0 million stand-by facility to finance an optional additional capacity expansion of up to 16 MW, that, if exercised by Ormat, could bring the total capacity of the complex to approximately 100 MW. The maturity dates of the construction tranche and the refinancing tranche are expected to be June 2030 and December 2030, respectively. The maturity date and certain other terms of the stand-by facility will be finalized following our decision, if any, to exercise the option to construct the additional capacity expansion of up to 16 MW.

Full-Recourse Third-Party Debt

On February 7, 2012, our wholly owned subsidiary, Ormat Nevada, entered into an amended and restated credit agreement with Union Bank, N.A. (Union Bank). Under the amended and restated agreement, the credit termination date was extended to February 7, 2014 and the aggregate amount available under the credit agreement was increased 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 have 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, which include: (i) 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. As of March 31, 2012: (i) the actual 12-month debt to EBITDA ratio was 3.45; (ii) the 12-month DSCR was 2.64; and (iii) the distribution leverage ratio was 0.79. 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, 2012, letters of credit in the aggregate amount of $33.6 million remain issued and outstanding under this credit agreement with Union Bank.

We also have credit agreements with five commercial banks for an aggregate amount of $370.0 million. Under the terms of these credit agreements, we, or our Israeli subsidiary, Ormat Systems Ltd. (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 $265.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $105.0. The credit agreements mature between December 2012 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, 2012, loans in the total amount of $227.6 million (including $10.0 million under a non-committed line of credit with an additional commercial bank) were outstanding, and letters of credit with an aggregate stated amount of $116.1 million were issued and outstanding under these credit agreements. The $227.6 million in loans are for terms of three months or less and bear interest at a weighted average rate of 3.0%.

 

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We have a $20.0 million term loan with a group of financial institutions, which matures on July 16, 2015, is payable in 12 semi-annual installments that commenced January 16, 2010, and bears annual interest of 6.5%. As of March 31, 2012, $12.6 million was outstanding under this loan.

We have a $20.0 million term loan with a group of financial institutions, which matures on August 1, 2017, is payable in 12 semi-annual installments commencing February 1, 2012, and bears annual interest at 6-month LIBOR plus 5.0%. As of March 31, 2012, $18.3 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 10 semi-annual installments commencing May 16, 2012, and bears annual interest of 5.75%. As of March 31, 2012, $20.0 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 10 semi-annual installments that commenced May 10, 2010, and bears annual interest at 6-month LIBOR plus 3.45%. As of March 31, 2012, $30.0 million was outstanding under this loan.

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% per annum, 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% per annum. We issued the bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act.

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 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, such as: (i) equity of at least $600 million and in no event less than 30% of total assets; (ii) 12-month debt, net of cash, cash equivalents and marketable securities to EBITDA ratio not to exceed 7.0; and (iii) dividend distributions not to exceed 35% of net income for that year. As of March 31, 2012, the actual equity to total assets ratio was 39.4%, total equity was $916.0 million, and the 12-month debt, net of cash, cash equivalents and marketable securities to EBITDA ratio was 4.9. 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 plan of 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

 

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cash deposits in reserve accounts under certain financing arrangements. In addition, our subsidiary, Ormat Systems, is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products.

As of March 31, 2012, letters of credit in the aggregate amount of $225.1 million remained issued and outstanding (out of which $149.7 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 $75.4 million were issued under non-committed lines of credit).

Puna Complex Lease Transactions

On May 19, 2005, our subsidiary in Hawaii, Puna Geothermal Venture (PGV), entered into a transaction involving the Puna geothermal power plant 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, our wholly owned subsidiary, 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 LLC (OPC), entitling the investors to certain tax benefits (such as production tax credits (PTCs) and accelerated depreciation) and distributable cash associated with four geothermal power plants.

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 it recovers the capital that it invested in the power plants, which occurred in the fourth quarter of 2010, the investors receive both the distributable cash flow and the Economic Benefits. The investors’ return is limited by the term of the transaction. Once the investors reach a target after-tax yield on their investment in OPC (the Flip Date), Ormat Nevada will receive 95% of both distributable cash and taxable income, on a going forward basis. Following the Flip Date, Ormat Nevada also has the option to buy out the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the power plants.

The Class B membership units are provided with a 5% residual economic interest in OPC. The 5% residual interest commences on achievement by the investors of a contractually stipulated return that triggers the Flip Date. The actual Flip Date is not known with certainty, and is determined by the operating results of OPC. This residual 5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. The Class B membership units are currently held by Morgan Stanley Geothermal LLC and JPM Capital Corporation.

 

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Our voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. We own, through our subsidiary, Ormat Nevada, all of the Class A membership units, which represent 75% of the voting rights in OPC. The investors own all of the Class B membership units, which represent 25% of the voting rights 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 Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investors’ voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore consolidates OPC.

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 $6.4 million as of March 31, 2012. This liability is included in long-term liabilities in our 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, but believe that the ultimate settlement of our obligations will not materially affect our liquidity.

Dividend

The following are the dividends declared by us during the past two years:

 

Date Declared

   Dividend Amount
per Share
    

Record Date

  

Payment Date

May 5, 2010

   $ 0.05       May 18, 2010    May 25, 2010

August 4, 2010

   $ 0.05       August 17, 2010    August 26, 2010

November 2, 2010

   $ 0.05       November 17, 2010    November 30, 2010

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

Historical Cash Flows

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

 

     Three Months Ended
March 31,
 
     2012     2011  
     (In thousands)  

Net cash provided by operating activities

   $ 41,874     $ 13,066  

Net cash used in investing activities

     (62,333     (107,924

Net cash provided by financing activities

     5,153       52,718  

Net change in cash and cash equivalents

     (15,306     (42,140

For the Three Months Ended March 31, 2012

Net cash provided by operating activities for the three months ended March 31, 2012 was $41.9 million, compared to $13.1 million for the three months ended March 31, 2011. The net increase of $28.8 million resulted primarily from: (i) an increase in net income to $8.0 million in the three months ended March 31, 2012, from net loss of $9.0 million in the three months ended March 31, 2011, mainly as a result of an increase in operating income as described above; (ii) a decrease in receivables of $9.1 million in the three months ended March 31,

 

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2012, compared to an increase of $14.4 million in the three months ended March 31, 2011, as a result of timing of collections from our customers; (iii) an increase in accounts payable and accrued expenses of $4.9 million in the three months ended March 31, 2012, compared to a decrease of $3.2 million in the three months ended March 31, 2011, as a result of timing of payments to our vendors; and (iv) an increase in deferred income tax provision, net of $3.9 million in the three months ended March 31, 2012, compared to $0.1 million in the three months ended March 31, 2011. Such increase was partially offset by a decrease in billing in excess of costs and estimated earnings on uncompleted contracts, net of $5.6 million relating to our Product Segment in the three months ended March 31, 2012, compared to an increase of $14.8 million in the three months ended March 31, 2011, as a result of timing in billing of our customers.

Net cash used in investing activities for the three months ended March 31, 2012 was $62.3 million, compared to $107.9 million for the three months ended March 31, 2011. The principal factors that affected our net cash used in investing activities during the three months ended March 31, 2012 was capital expenditures of $65.4 million, primarily for our facilities under construction. The principal factors that affected our net cash used in investing activities during the three months ended March 31, 2011 were: (i) capital expenditures of $55.1 million, primarily for our power facilities under construction; (ii) net increase of $29.9 million in restricted cash, cash equivalents and marketable securities; and (iii) net increase of $23.0 million in marketable securities.

Net cash provided by financing activities for the three months ended March 31, 2012 was $5.2 million, compared to $52.7 million for the three months ended March 31, 2011. The principal factors that affected the 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. The principal factors that affected our net cash provided by financing activities during the three months ended March 31, 2011 were: (i) the issuance of an aggregate amount of approximately $107.4 million Senior Unsecured Bonds in February 2011; and (ii) proceeds from the sale of all of the Class B membership units of OPC acquired on October 30, 2009 for a sale price of $24.9 million, offset by: (i) the repayment of long-term debt in the amount of $2.4 million; (ii) a net decrease of $71.0 million against our revolving lines of credit with commercial banks; (iii) cash paid to non-controlling interest in the amount of $2.6 million; and (iv) the payment of a dividend to our shareholders in the amount of $2.3 million.

EBITDA

We calculate EBITDA as net income before interest, taxes, depreciation and amortization. EBITDA is not a measurement of financial performance or liquidity under accounting principles generally accepted in the United States of America (GAAP) and should not be considered as an alternative to cash flow from operating activities or as a measure of liquidity or an alternative to net earnings as indicators of our operating performance or any other measures of performance derived in accordance with GAAP. EBITDA is presented because we believe it is 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 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.

EBITDA for the three months ended March 31, 2012 was $51.5 million, compared to $27.2 million for the three months ended March 31, 2011.

 

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The following table reconciles net cash provided by operating activities to EBITDA for the three-month periods ended March 31, 2012 and 2011:

 

     Three Months Ended
March 31,
 
     2012     2011  
     (In thousands)  

Net cash provided by operating activities

   $ 41,874     $ 13,066  

Adjusted for:

    

Interest expense, net (excluding amortization of deferred financing costs)

     13,647       12,296  

Interest income

     (388     (135

Income tax provision

     5,457       586  

Adjustments to reconcile net income or loss to net cash provided by operating activities (excluding depreciation and amortization)

     (9,105     1,339  
  

 

 

   

 

 

 

EBITDA

   $ 51,485     $ 27,152  
  

 

 

   

 

 

 

Net cash used in investing activities

   $ (62,333   $ (107,924
  

 

 

   

 

 

 

Net cash provided by financing activities

   $ 5,153     $ 52,718  
  

 

 

   

 

 

 

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.

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 have prevented substantial progress on the project site until late last year. This has 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 joint operating agreement with NV Energy. However, we received approval from the BLM for the required Environmental Impact Study. We have recently started the drilling activity in the project’s field.

CD 4 Project    We are currently developing 30 MW of new capacity at the Mammoth complex, on land which is comprised mainly of BLM leases. We have commenced field development, and drilling of additional wells is subject to permits.

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 in 2013, subject to timely completion of the interconnection that is to be provided by IID.

Mammoth Complex    We plan to repower the Mammoth complex located in Mammoth Lakes, California, by replacing part of the old units with new Ormat-manufactured equipment. The replacement of the equipment will optimize generation and add approximately 3 MW of generating capacity to the complex. We have not yet received the required permits to start construction. As a result, we suspended the equipment fabrication and expect delays in the execution of the project.

McGinness Hills Project    We are developing the first phase of the 30 MW McGinness Hills project on private and Bureau of Land Management leases located in Lander County, Nevada. Field development is in process, the power plant equipment is on site, and construction is in advanced stages. We signed a 20-year PPA with Nevada Power Company, which was approved by the PUCN on July 28, 2010. Commercial operation of the project’s first phase is expected in the third quarter of 2012. We have secured financing under the DOE 1705 Loan Guarantee Program and plan to file an application for an ITC cash grant for the project.

Olkaria III Phase 3    Development of Phase 3 of the Olkaria III complex located in Naivasha, Kenya is in process. Field development and manufacturing of the power plant equipment for a new 36 MW power plant at the Olkaria III complex are in advanced stages. The new power plant is scheduled to come online in 2013.

 

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Wild Rose Project    We are currently developing the 15 to 20 MW Wild Rose project located in Mineral County, Nevada. We are continuing with the drilling activity. The new power plant is expected to come online in 2013. Actual generation capacity will be determined based on field development results.

We have estimated approximately $680 million in capital expenditures for construction of new projects that are still under construction and that are expected to be completed by 2013, of which we have invested approximately $255 million as of March 31, 2012. We expect to invest an additional $146 million of such total during the remainder of 2012. The remaining $279 million will be invested in 2013.

In addition, we estimate approximately $124 million in additional capital expenditures during the remainder of 2012 to be allocated as follows: (i) $33 million for development of new projects; (ii) $63 million for enhancement of our operating power plants; (iii) $23 million for exploration activities in various leases for geothermal resources in which we have started the exploration activity; and (iv) $5 million for enhancement of our production facilities. In the aggregate, we estimate our total capital expenditures for the remainder of 2012 to be approximately $270 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. A prolonged economic slowdown could reduce worldwide demand for energy, including our geothermal energy, REG and other products.

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) have fixed or escalating rate provisions that limit our exposure to changes in electricity prices. However, beginning in May 2012, the energy payments under the PPAs of the Heber 1 and 2 power plants, the Ormesa complex, and the Mammoth complex will be 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. The Puna complex is currently benefiting from energy prices which are higher than the floor under the 25 MW PPA for the Puna complex as a result of the high fuel costs that impact HELCO’s avoided costs. In addition, we have recently hedged our exposure to the price of oil, under the 25 MW PPA of the Puna complex, until March 31, 2013 (for further details please see discussion under “Recent Developments” above).

As of March 31, 2012, 71.3% of our consolidated long-term debt was in the form of fixed rate securities and therefore not subject to interest rate volatility risk. As of such date, 28.7% of our debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. As of March 31, 2012, $296.5 million of our 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 expectations 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.

 

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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 New Israeli Shekel (NIS). Risks attributable to fluctuations in currency exchange rates can arise when we or any of our foreign subsidiaries borrows funds or incurs operating or other expenses in one type of currency but receives revenues in another. In such cases, an adverse change in exchange rates can reduce our or 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.

Concentration of Credit Risk

Our credit risk is currently concentrated with a limited number of major customers: Southern California Edison, HELCO, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy), and Kenya Power and Lighting Co. Ltd. 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.

Southern California Edison accounted for 19.7% and 27.0% of the Company’s total revenues for the three months ended March 31, 2012 and 2011, respectively.

Sierra Pacific Power Company and Nevada Power Company accounted for 12.9% and 16.2% of the Company’s total revenues for the three months ended March 31, 2012 and 2011, respectively.

HELCO accounted for 9.3% and 10.6% of the Company’s total revenues for the three months ended March 31, 2012 and 2011, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 7.3% and 8.9% of the Company’s total revenues for the three months ended March 31, 2012 and 2011, respectively.

Government Grants and Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the ARRA. We are permitted to claim 30% of the eligible costs of each new geothermal power plant in the United States as an ITC against our federal income taxes. Alternatively, we are permitted to claim a PTC, which in 2011 was 2.2 cents per kWh and which is adjusted annually for inflation. The PTC may be claimed for ten years on the electricity output of new geothermal power plants put into service by December 31, 2013. The owner of the project must choose between the PTC and the 30% ITC described above. In either case, under current tax rules, any unused tax credit has a 1-year carry back and a 20-year carry forward. Whether we claim the PTC or the ITC, we are also permitted to depreciate most of the plant for tax purposes over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period. If we claim the ITC, our “tax basis” in the plant that we can recover through depreciation must be reduced by half of the tax credit. If we claim a PTC, there is no reduction in the tax basis for depreciation. Companies that place qualifying renewable energy facilities in service, during 2009, 2010 or 2011 or that begin 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. Department of Treasury (U.S. Treasury) in an amount equal to the ITC. 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.

 

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Our subsidiary, 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 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 that started in 2007, and thereafter such income is subject to reduced Israeli income tax rates which will not exceed 25% for an additional five years (see also below). These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and our affiliates are at arm’s length, and that the management and control of Ormat Systems will be from Israel during the entire period of the tax benefits. A change in control should be reported to the Israel Tax Authority in order 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 would apply to all qualified income of certain industrial companies, as opposed to the current law’s incentives that are limited to income from a “Benefited Enterprise” during its 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.

 

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, 2012, 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.

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.

b. Changes in internal controls over financial reporting

There were no changes in our internal controls over financial reporting in the first quarter of 2012 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

 

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PART II — OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

Securities Class Actions

Following the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs, three securities class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints assert claims against the Company and certain officers and directors for alleged violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the Exchange Act). One complaint also asserts claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act. All three complaints allege claims on behalf of a putative class of purchasers of Company common stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010. These three lawsuits were consolidated by the Court in an order issued on June 3, 2010 and the Court appointed three of the Company’s stockholders to serve as lead plaintiffs.

Lead plaintiffs filed a consolidated amended class action complaint (CAC) on July 9, 2010 that asserts claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of Company common stock between May 7, 2008 and February 24, 2010. The CAC alleges that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate certain of its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleges that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC seeks compensatory damages, expenses, and such further relief as the Court may deem proper.

Defendants filed a motion to dismiss the CAC on August 13, 2010. On March 3, 2011, the court granted in part and denied in part defendants’ motion to dismiss. The court dismissed plaintiffs’ allegations that the Company’s statements regarding the North Brawley project were false or misleading, but did not dismiss plaintiffs’ allegations regarding the 2008 restatement. Defendants answered the remaining allegations in the CAC regarding the restatement on April 8, 2011 and the case has now entered the discovery phase. On July 22, 2011, plaintiffs filed a motion to certify the case as a class action on behalf of a class of purchasers of Company common stock between February 25, 2009 and February 24, 2010, and defendants filed an opposition to the motion for class certification on October 4, 2011.

Subsequently, the parties participated in a mediation where they reached an agreement in principle to settle the securities class action lawsuits. The parties thereafter filed a stipulation of settlement with the U.S. District Court for the District of Nevada on March 27, 2012 providing that the claims against the Company and its officers and directors will be dismissed with prejudice and plaintiffs will release the defendants from all claims in exchange for a cash payment of $3.1 million to be funded by the Company’s insurers. The stipulation of settlement received preliminary approval by the Court on March 30, 2012. It still remains subject to final approval by the Court following notice to members of the class.

The Company and the individual defendants have steadfastly maintained that the claims raised in the securities class action lawsuits were without merit, and have vigorously contested those claims. As part of the settlement, the Company and the individual defendants continue to deny any liability or wrongdoing under the securities laws or otherwise.

Stockholder Derivative Cases

Four stockholder derivative lawsuits have also been filed in connection with the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting

 

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treatment for certain exploration and development costs. Two cases were filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe on March 16, 2010 and April 21, 2010 and two cases were filed in the United States District Court for the District of Nevada on March 29, 2010 and June 7, 2010. All four lawsuits assert claims brought derivatively on behalf of the Company against certain of its officers and directors for alleged breach of fiduciary duty and other claims, including waste of corporate assets and unjust enrichment.

The two stockholder derivative cases filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe were consolidated by the Court in an order dated May 27, 2010 and the plaintiffs filed a consolidated derivative complaint on September 7, 2010. In accordance with a stipulation between the parties, defendants filed a motion to dismiss on November 16, 2010. On April 18, 2011, the Court stayed the state derivative case pending the resolution of the securities class action lawsuit. The Company cannot make an estimate of the reasonably possible loss or range of reasonably possible loss on the state derivative case.

The two stockholder derivative cases filed in the United States District Court for the District of Nevada were consolidated by the Court in an order dated August 31, 2010, and plaintiffs filed a consolidated derivative complaint on October 28, 2010. The Company filed a motion to dismiss on December 13, 2010. On March 7, 2011, the Court transferred the federal derivative case to the Court presiding over the securities class action, and on August 29, 2011, the Court stayed the federal derivative case pending the resolution of the securities class action lawsuit. The Company cannot make an estimate of the reasonably possible loss or range of reasonably possible loss on the federal derivative case.

The Company believes the allegations in these purported derivative actions are without merit and is defending the actions vigorously.

Other

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 asks 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 the 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 Ormat Energy Converters 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 Ormat Energy Converters capable of generating more than 50 MW.

The Company believes that the petition is without merit and intends to respond and take necessary legal action to dismiss the proceedings. The Company was notified that CURE intends to file the administrative record from the underlying administrative proceeding in the Alameda County Superior Court proceeding. This notice extended the time for the Company to respond to CURE’s petition. Once the Company is served with a certified copy of the administrative record, the Company will have thirty days in which to respond to CURE’s petition, unless the Company agrees to a shorter time. Filing of the petition in and of itself does not have any immediate adverse implications for the North Brawley or East Brawley projects and the Company continues to operate the North Brawley project in the ordinary course of business and continues with its development work on the East Brawley project.

 

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In addition, from time to time, the Company is named as a party to various 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 financial statements as a whole.

 

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, 2011 filed with the SEC on February 29, 2012.

 

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 fiscal quarter of 2012.

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Our management believes that we are currently in compliance with our covenants with respect to our third-party debt.

 

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

ITEM 5. OTHER INFORMATION

None.

 

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ITEM 6. EXHIBITS

 

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   

Third 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 February 26, 2009.

  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 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.

  4.2   

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.

  4.3   

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.

  4.4   

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.

  4.5   

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.

  4.6   

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.

  4.7   

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

  4.8   

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.

 

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Exhibit No.

  

Document

  4.9   

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.

10.1.1   

Credit Agreement, dated as of November 21, 2011, between Lightning Dock Geothermal HI-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.24.1 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.1.2   

Subordination Agreement, dated as of January 11, 2012, among CYRQ ENERGY, Inc., Lightning Dock Geothermal HI-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.24.2 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.1.3   

Accounts Agreement, dated as of January 25, 2012, among Lightning Dock Geothermal HI-01, LLC, Ormat Nevada Inc., and Wells Fargo Bank, National Association, as Depositary, incorporated by reference to Exhibit 10.24.3 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.2.1   

Credit Agreement, dated December 19, 2011, between Thermo NO. 1 BE-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.25.1 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.2.2   

Subordination Agreement, dated as of January 11, 2012, among CYRQ ENERGY, INC., Thermo NO. 1 BE-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.25.2 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.2.3   

Accounts Agreement, dated as of January 25, 2012 among Thermo NO. 1 BE-01, LLC, Ormat Nevada Inc., and Wells Fargo Bank, National Association, as Depositary, incorporated by reference to Exhibit 10.25.3 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.3   

Amendment to Employment Agreement of Lucien Bronicki dated March 21, 2012 by and between Ormat Technologies, Inc. and Lucien Bronicki, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on March 26, 2012.

10.4   

Second Amendment to Employment Agreement of Yehudit Bronicki dated March 21, 2012 by and between Ormat Technologies, Inc. and Yehudit Bronicki, incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on March 26, 2012.

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, filed 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, filed herewith.

 

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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/    JOSEPH TENNE        

  Name:  

    Joseph Tenne

  Title:  

    Chief Financial Officer

Date: May 10, 2012

 

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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   

Third 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 February 26, 2009.

  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 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.

  4.2   

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.

  4.3   

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.

  4.4   

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.

  4.5   

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.

  4.6   

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.

  4.7   

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

  4.8   

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.

 

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Exhibit No.

  

Document

  4.9   

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.

10.1.1   

Credit Agreement, dated as of November 21, 2011, between Lightning Dock Geothermal HI-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.24.1 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.1.2   

Subordination Agreement, dated as of January 11, 2012, among CYRQ ENERGY, Inc., Lightning Dock Geothermal HI-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.24.2 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.1.3   

Accounts Agreement, dated as of January 25, 2012, among Lightning Dock Geothermal HI-01, LLC, Ormat Nevada Inc., and Wells Fargo Bank, National Association, as Depositary, incorporated by reference to Exhibit 10.24.3 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.2.1   

Credit Agreement, dated December 19, 2011, between Thermo NO. 1 BE-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.25.1 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.2.2   

Subordination Agreement, dated as of January 11, 2012, among CYRQ ENERGY, INC., Thermo NO. 1 BE-01, LLC, and Ormat Nevada Inc., incorporated by reference to Exhibit 10.25.2 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.2.3   

Accounts Agreement, dated as of January 25, 2012 among Thermo NO. 1 BE-01, LLC, Ormat Nevada Inc., and Wells Fargo Bank, National Association, as Depositary, incorporated by reference to Exhibit 10.25.3 to Ormat Technologies, Inc. Annual Report on Form 10-K to the Securities and Exchange Commission on February 29, 2012.

10.3   

Amendment to Employment Agreement of Lucien Bronicki dated March 21, 2012 by and between Ormat Technologies, Inc. and Lucien Bronicki, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on March 26, 2012.

10.4   

Second Amendment to Employment Agreement of Yehudit Bronicki dated March 21, 2012 by and between Ormat Technologies, Inc. and Yehudit Bronicki, incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on March 26, 2012.

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, filed 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, filed herewith.

 

55

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