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Ormat Technologies 10-Q 2011
Form 10-Q
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 September 30, 2011

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes        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 SEPTEMBER 30, 2011

 

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

     27   

ITEM 3.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     60   

ITEM 4.

 

CONTROLS AND PROCEDURES

     60   

PART II — OTHER INFORMATION

  

ITEM 1.

 

LEGAL PROCEEDINGS

     61   

ITEM 1A.

 

RISK FACTORS

     62   

ITEM 2.

 

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

     62   

ITEM 3.

 

DEFAULTS UPON SENIOR SECURITIES

     62   

ITEM 5.

 

OTHER INFORMATION

     62   

ITEM 6.

 

EXHIBITS

     63   

SIGNATURES

     65   

 

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)

 

     September 30,
2011
     December 31,
2010
 
     (In thousands)  
ASSETS      

Current assets:

     

Cash and cash equivalents

   $ 59,077      $ 82,815  

Marketable securities

     21,189          

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

     61,791        23,309  

Receivables:

     

Trade

     53,084        54,495  

Related entity

     381        303  

Other

     7,028        8,173  

Due from Parent

     151        272  

Inventories

     17,899        12,538  

Costs and estimated earnings in excess of billings on uncompleted contracts

     3,518        6,146  

Deferred income taxes

     1,582        1,674  

Prepaid expenses and other

     22,972        14,929  
  

 

 

    

 

 

 

Total current assets

     248,672        204,654  

Long-term marketable securities

             1,287  

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

             1,740  

Unconsolidated investments

     3,997        4,244  

Deposits and other

     21,481        21,353  

Deferred income taxes

     17,087        17,087  

Deferred charges

     36,930        37,571  

Property, plant and equipment, net ($1,365,870 and $1,371,400 related to VIEs, respectively)

     1,422,450        1,425,467  

Construction-in-process ($295,422 and $149,851 related to VIEs, respectively)

     399,002        270,634  

Deferred financing and lease costs, net

     23,238        19,017  

Intangible assets, net

     37,864        40,274  
  

 

 

    

 

 

 

Total assets

   $ 2,210,721      $ 2,043,328  
  

 

 

    

 

 

 
LIABILITIES AND EQUITY      

Current liabilities:

     

Accounts payable and accrued expenses

   $ 99,362      $ 85,549  

Billings in excess of costs and estimated earnings on uncompleted contracts

     35,664        3,153  

Current portion of long-term debt:

     

Limited and non-recourse (all related to VIEs)

     13,485        15,020  

Full recourse

     18,543        13,010  

Senior secured notes (non-recourse) (all related to VIEs)

     20,622        20,990  
  

 

 

    

 

 

 

Total current liabilities

     187,676        137,722  

Long-term debt, net of current portion:

     

Limited and non-recourse (all related to VIEs)

     106,759        114,132  

Full recourse:

     

Senior unsecured bonds (plus unamortized premium based upon 7% of $1,822)

     250,119        142,003  

Other

     70,623        84,166  

Revolving credit lines with banks (full recourse)

     221,322        189,466  

Senior secured notes (non-recourse) (all related to VIEs)

     203,382        210,882  

Liability associated with sale of tax benefits

     74,448         66,587  

Deferred lease income

     69,483        71,264  

Deferred income taxes

     28,244         30,878  

Liability for unrecognized tax benefits

     4,245        5,431  

Liabilities for severance pay

     20,987        20,706  

Asset retirement obligation

     21,086        19,903  

Other long-term liabilities

     4,242        4,961  
  

 

 

    

 

 

 

Total liabilities

     1,262,616        1,098,101  
  

 

 

    

 

 

 

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, respectively

     46        46  

Additional paid-in capital

     724,074        716,731  

Retained earnings

     215,411        221,311  

Accumulated other comprehensive income

     565        1,044  
  

 

 

    

 

 

 
     940,096        939,132  

Noncontrolling interest

     8,009        6,095  
  

 

 

    

 

 

 

Total equity

     948,105        945,227  
  

 

 

    

 

 

 

Total liabilities and equity

   $ 2,210,721      $ 2,043,328  
  

 

 

    

 

 

 

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

 

4


Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
           2011                 2010                 2011                 2010        
     (In thousands, except per
share data)
    (In thousands, except per
share data)
 

Revenues:

        

Electricity

   $ 86,815     $ 83,357     $ 246,273     $ 218,269  

Product

     24,026       18,120       67,002       62,128  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     110,841       101,477       313,275       280,397  
  

 

 

   

 

 

   

 

 

   

 

 

 

Cost of revenues:

        

Electricity

     57,941       61,530       186,090       179,551  

Product

     17,137       14,764       43,276       41,316  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total cost of revenues

     75,078       76,294       229,366       220,867  
  

 

 

   

 

 

   

 

 

   

 

 

 

Gross margin

     35,763       25,183       83,909       59,530  

Operating expenses:

        

Research and development expenses

     2,346       1,252       7,128       8,133  

Selling and marketing expenses

     2,940       3,333       9,325       9,221  

General and administrative expenses

     6,269       5,780       20,755       19,796  

Write-off of unsuccessful exploration activities

                          3,050  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     24,208       14,818       46,701       19,330  

Other income (expense):

        

Interest income

     438       140       1,289       432  

Interest expense, net

     (23,909     (10,961     (54,431     (30,101

Foreign currency translation and transaction gains (losses)

     (2,659     1,074       (1,546     475  

Income attributable to sale of tax benefits

     2,344       2,183       7,624       6,392  

Gain on acquisition of controlling interest

            36,928              36,928  

Other non-operating income (expense), net

     347       233       465       (47
  

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations, before income taxes and equity in income (losses) of investees

     769       44,415       102       33,409  

Income tax benefit (expense)

     305       (11,931     726       (6,009

Equity in income (losses) of investees, net

     (71     (83     (552     942  
  

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations

     1,003       32,401       276       28,342  

Discontinued operations:

        

Income from discontinued operations, net of related tax of $0, $0, $0 and $6, respectively

                          14  

Gain on sale of a subsidiary in New Zealand, net of related tax of $0, $0, $0 and $2,000, respectively

                          4,336  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     1,003       32,401       276       32,692  

Net (income) loss attributable to noncontrolling interest

     (137     58       (252     168  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to the Company’s stockholders

   $ 866     $ 32,459     $ 24     $ 32,860  
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss):

        

Net income

     1,003       32,401       276       32,692  

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

        

Currency translation adjustment

                          43  

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

     (53     (61     (159     (177

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

     (111            (320     (80
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

     839       32,340       (203 )     32,478  

Comprehensive (income) loss attributable to noncontrolling interest

     (137     58       (252     168  
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 702     $ 32,398     $ (455 )   $ 32,646  
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings per share attributable to the Company’s stockholders — basic and diluted:

        

Income from continuing operations

   $ 0.02     $ 0.71     $ 0.00     $ 0.62  

Discontinued operations

                          0.10  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 0.02     $ 0.71     $ 0.00     $ 0.72  
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average number of shares used in computation of earnings per share attributable to the Company’s stockholders:

        

Basic

     45,431       45,431       45,431       45,431  
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

     45,440       45,450       45,442       45,452  
  

 

 

   

 

 

   

 

 

   

 

 

 

Dividend per share declared

   $ 0.04     $ 0.05     $ 0.13     $ 0.22  
  

 

 

   

 

 

   

 

 

   

 

 

 

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

 

5


Table of Contents

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, 2009

    45,431     $ 46      $ 709,354      $ 196,950      $ 622      $ 906,972      $ 4,723      $ 911,695   

Stock-based compensation

                  4,637                     4,637              4,637  

Cumulative effect of adopting the guidance on evaluation of credit derivatives embedded in beneficial interests in securitized financial assets as of July 1, 2010 (net of related tax of $370)

                         (693     693                       

Cash dividend declared, $0.22 per share

                         (9,995            (9,995            (9,995

Net income (loss)

                         32,860              32,860       (168     32,692  

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

               

Currency translation adjustment

                                43       43              43  

Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $108)

                                (177     (177            (177

Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $43)

                                (80     (80            (80
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at September 30, 2010

    45,431     $ 46      $ 713,991      $ 219,122      $ 1,101      $ 934,260      $ 4,555      $ 938,815   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2010

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

Stock-based compensation

                  5,000                     5,000              5,000  

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

                  2,343                     2,343       1,662       4,005  

Cash dividend declared, $0.13 per share

                         (5,924            (5,924            (5,924

Net income

                         24               24        252       276   

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 $96)

                                (159     (159            (159

Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $0)

                                (320     (320            (320
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at September 30, 2011

    45,431     $ 46      $ 724,074      $ 215,411      $ 565      $ 940,096      $ 8,009      $ 948,105   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

 

6


Table of Contents

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

    Nine Months Ended
September 30,
 
    2011     2010  
    (In thousands)  

Cash flows from operating activities:

   

Net income

  $ 276     $ 32,692  

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

   

Depreciation and amortization

    71,261       64,461  

Amortization of premium from senior unsecured bonds

    (72       

Accretion of asset retirement obligation

    1,183       888  

Stock-based compensation

    5,000       4,637  

Amortization of deferred lease income

    (2,014     (2,014

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

    (2,243     (2,281

Equity in income (losses) of investees

    552       (942

Impairment of auction rate securities

    205         

Loss on disposal of property, plant and equipment

           571  

Write-off of unsuccessful exploration activities

           3,050  

Return on investment in unconsolidated investments

           3,734  

Changes in unrealized loss in respect of derivative instruments, net

    11,052         

Gain (loss) on severance pay fund asset

    282       (1,099

Premium from issuance Senior Unsecured Bonds

    1,957         

Gain on sale of a subsidiary

           (6,350

Gain on acquisition of controlling interest

           (36,928

Deferred income tax provision (benefit)

    (1,805     5,717  

Liability for unrecognized tax benefits

    (1,186     717  

Deferred lease revenues

    233       820  

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

   

Receivables

    2,556       (5,691

Costs and estimated earnings in excess of billings on uncompleted contracts

    2,628       13,869  

Inventories

    (5,361     871  

Prepaid expenses and other

    (8,043     (3,995

Deposits and other

    (471     (253

Accounts payable and accrued expenses

    (9,592     5,571  

Due from/to related entities, net

    (78     (60

Billings in excess of costs and estimated earnings on uncompleted contracts

    32,511       1,420  

Liabilities for severance pay

    281       1,508  

Other long-term liabilities

    (719     (1,091

Due from/to Parent

    121       (178
 

 

 

   

 

 

 

Net cash provided by operating activities

    98,514       79,644  
 

 

 

   

 

 

 

Cash flows from investing activities:

   

Return of investment in unconsolidated investments

           3,516  

Purchases of marketable securities, net

    (20,287       

Net change in restricted cash, cash equivalents and marketable securities

    (36,884     (23,352

Cash received from sale of a subsidiary

           19,594  

Capital expenditures

    (180,771     (194,926

Cash grant received from the U.S. Treasury under Section 1603 of the ARRA

           108,286  

Investment in unconsolidated companies

    (305     (511

Cash paid for acquisition of controlling interest in a subsidiary, net of cash acquired

           (64,517

Intangible assets acquired

           (875

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

    61       (235
 

 

 

   

 

 

 

Net cash used in investing activities

    (238,186     (153,020
 

 

 

   

 

 

 

Cash flows from financing activities:

   

Proceeds from issuance of senior unsecured bonds

    107,447       142,003  

Proceeds from the sale of limited liability company interest in OPC LLC, net of transaction costs

    24,878         

Proceeds from revolving credit lines with banks

    419,156        518,064  

Repayment of revolving credit lines with banks

    (387,300     (535,600

Repayments of long-term debt

    (26,002     (37,670

Cash paid to non-controlling interest

    (10,769       

Deferred debt issuance costs

    (5,552     (493

Cash dividends paid

    (5,924     (9,995
 

 

 

   

 

 

 

Net cash provided by financing activities

    115,934       76,309  
 

 

 

   

 

 

 

Net change in cash and cash equivalents

    (23,738     2,933  

Cash and cash equivalents at beginning of period

    82,815       46,307  
 

 

 

   

 

 

 

Cash and cash equivalents at end of period

  $ 59,077     $ 49,240  
 

 

 

   

 

 

 

Supplemental non-cash investing and financing activities:

   

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

  $ 11,046     $ 6,153  
 

 

 

   

 

 

 

Accrued liabilities related to financing activities

  $ 1,309     $   
 

 

 

   

 

 

 

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

 

7


Table of Contents

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 September 30, 2011, the consolidated results of operations and comprehensive income (loss) for the three and nine-month periods ended September 30, 2011 and 2010, and the consolidated cash flows for the nine-month periods ended September 30, 2011 and 2010.

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 and nine-month periods ended September 30, 2011 are not necessarily indicative of the results to be expected for the year ending December 31, 2011.

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, 2010. The condensed consolidated balance sheet data as of December 31, 2010 was derived from the audited consolidated financial statements for the year ended December 31, 2010, 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 September 30, 2011 and December 31, 2010, the Company had deposits totaling $19,834,000 and $55,537,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At September 30, 2011 and December 31, 2010, the Company’s deposits in foreign countries amounted to approximately $47,302,000 and $37,929,000, respectively.

At September 30, 2011 and December 31, 2010, accounts receivable related to operations in foreign countries amounted to approximately $24,786,000 and $26,128,000, respectively. At September 30, 2011 and December 31, 2010, accounts receivable from the Company’s major customers that have generated 10% or more of its revenues amounted to approximately 57% and 40% of the Company’s accounts receivable, respectively.

Southern California Edison Company (“SCE”) accounted for 34.5% and 35.9% of the Company’s total revenues for the three months ended September 30, 2011 and 2010, respectively, and 30.5% and 29.6% of the Company’s total revenues for the nine months ended September 30, 2011 and 2010, respectively. SCE is the

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

power purchaser and revenue source for the Mammoth complex, which was accounted for under the equity method through August 1, 2010. Following the Company’s acquisition of the remaining 50% interest in the Mammoth complex, as described in Note 3, the Company has included the results of the Mammoth complex in its consolidated financial statements.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 10.5% and 12.2% of the Company’s total revenues for the three months ended September 30, 2011 and 2010, respectively, and 12.8% and 14.7% of the Company’s total revenues for the nine months ended September 30, 2011 and 2010, respectively.

Hawaii Electric Light Company accounted for 10.3% and 10.1% of the Company’s total revenues for the three months ended September 30, 2011 and 2010, respectively, and 10.9% and 8.3% of the Company’s total revenues for the nine months ended September 30, 2011 and 2010, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 8.0% and 8.7% of the Company’s total revenues for the three months ended September 30, 2011 and 2010, respectively, and 8.4% and 9.4% of the Company’s total revenues for the nine months ended September 30, 2011 and 2010, 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 nine-month period ended September 30, 2011

Accounting for Revenue Recognition

In October 2009, the Financial Accounting Standards Board (“FASB”) issued amendments to the accounting and disclosures for revenue recognition. These amendments modify the criteria for recognizing revenue in multiple element arrangements and require companies to develop a best estimate of the selling price to separate deliverables and allocate arrangement consideration using the relative selling price method. Additionally, the amendments eliminate the residual method for allocating arrangement considerations. The adoption by the Company on January 1, 2011 did not have a material impact on the Company’s consolidated financial statements.

In April 2010, the FASB issued guidance for revenue recognition — milestone method, which provides guidance on the criteria that should be met for determining whether the milestone method of revenue recognition is appropriate. A vendor can recognize consideration that is contingent upon achievement of a milestone in its entirety as revenue in the period in which the milestone is achieved only if the milestone meets all criteria to be considered substantive. A milestone should be considered substantive in its entirety. An individual milestone may not be bifurcated. This guidance is effective on a prospective basis for milestones achieved in fiscal years, and interim periods within those years, beginning on or after the effective date of the guidance. The adoption by the Company on January 1, 2011 did not have a material impact on the Company’s consolidated financial statements.

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Accounting for Share-based Payments

In April 2010, the FASB issued an accounting standards update, which addresses the classification of an employee share-based payment award with an exercise price denominated in the currency of a market in which the underlying equity securities trades. This update clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity should not classify such an award as a liability if it otherwise qualifies as equity. The adoption by the Company on January 1, 2011 did not have a material impact on the Company’s consolidated financial statements.

New accounting pronouncements effective in future periods

Accounting for Fair Value Measurement

In May 2011, the FASB amended authoritative accounting guidance regarding fair value measurement. The amendment prohibits the application of block discounts for all fair value measurements, permits the fair value of certain financial instruments to be measured on the basis of the net risk exposure and allows the application of premiums or discounts to the extent consistent with the applicable unit of account. The amendment clarifies that the highest-and-best use and valuation-premise concepts are not relevant to financial instruments. Expanded disclosures are required under the amendment, including quantitative information about significant unobservable inputs used for Level 3 measurements, a qualitative discussion about the sensitivity of recurring Level 3 measurements to changes in unobservable inputs disclosed, a discussion of the Level 3 valuation processes, any transfers between Levels 1 and 2 and the classification of items whose fair value is not recorded but is disclosed in the notes. The amendment is effective prospectively during interim and annual periods beginning after December 15, 2011 (January 1, 2012 for the Company). The adoption of this amendment is not expected to have a material effect on the Company’s consolidated financial statements.

Update on Presentation of Comprehensive Income in the Financial Statements

In June 2011, the FASB issued new accounting guidance that revises the manner in which entities present comprehensive income in their financial statements. The new guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. The new guidance does not change the items that must be reported in other comprehensive income and does not affect the calculation or reporting of earnings per share. The amendment is applicable retrospectively effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 (January 1, 2012 for the Company). Early adoption is permitted. The adoption of this amendment is not expected to have a material effect on the Company’s consolidated financial statements.

NOTE 3 — MAMMOTH COMPLEX ACQUISITION

On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth-Pacific, L.P. (“Mammoth Pacific”), which owns the Mammoth complex located near the city of Mammoth, California, for a purchase price of $72.5 million in cash. The Company acquired the remaining interest in Mammoth Pacific to increase its geothermal power plant operations in the United States.

Prior to the acquisition, the Company had a 50% interest in Mammoth Pacific that was accounted for under the equity method of accounting. Following the acquisition, the Company became the sole owner of the

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Mammoth complex, as well as the sole owner of rights to over 10,000 acres of undeveloped federal lands.

As a result of the acquisition of the remaining 50% interest in Mammoth Pacific, the financial statements of Mammoth Pacific have been consolidated with the Company’s financial statements effective August 2, 2010. The acquisition date fair value of the previously held 50% equity interest was $64.9 million, which takes into account a “control premium” of $7.6 million. In the three and nine-month periods ended September 30, 2010, the Company recognized a pre-tax gain of $36.9 million, which is equal to the difference between the acquisition date fair value of the previously held 50% equity interest in Mammoth Pacific and the acquisition date carrying value of such investment. The gain is included in “gain on acquisition of controlling interest” in the condensed consolidated statements of operations and comprehensive income (loss).

Revenues and net income of the Mammoth complex were $5,257,000 and $597,000 for the three months ended September 30, 2011, respectively. Revenues and net income of the Mammoth complex were $14,696,000 and $1,029,000 for the nine months ended September 30, 2011, respectively.

The following unaudited consolidated pro forma financial information for the three and nine-month periods ended September 30, 2010 assumes the Mammoth Pacific acquisition occurred as of January 1, 2010, after giving effect to certain adjustments, including the depreciation based on the adjustments to the fair market value of the property, plant and equipment acquired, and related income tax effects. The pro forma results have been prepared for comparative purposes only and are not necessarily indicative of the results of operations that may occur in the future or that would have occurred had the acquisition of Mammoth Pacific been effected on the date indicated.

 

     Three Months  Ended
September 30, 2010
     Nine Months  Ended
September 30, 2010
 
    

(Dollars in thousands,

except per share data)

 

Revenues

   $ 103,155      $ 291,881  

Income from continuing operations

     8,710        5,273  

Net income

   $ 8,697      $ 9,532  

Net loss attributable to noncontrolling interest

     58        168  
  

 

 

    

 

 

 

Net income attributable to the Company’s stockholders

   $ 8,755      $ 9,700  
  

 

 

    

 

 

 

Earnings per share attributable to the Company’s stockholders — basic and diluted:

     

Income from continuing operations

   $ 0.19      $ 0.12  

Income from discontinued operations

     —          0.10  
  

 

 

    

 

 

 

Net income

   $ 0.19      $ 0.22  
  

 

 

    

 

 

 

NOTE 4 — INVENTORIES

Inventories consist of the following:

 

     September 30,
2011
     December 31,
2010
 
     (Dollars in thousands)  

Raw materials and purchased parts for assembly

   $ 9,006      $ 7,030  

Self-manufactured assembly parts and finished products

     8,893        5,508  
  

 

 

    

 

 

 

Total

   $ 17,899      $ 12,538  
  

 

 

    

 

 

 

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

NOTE 5 — UNCONSOLIDATED INVESTMENTS

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

 

     September 30,
2011
     December 31,
2010
 
     (Dollars in thousands)  

Sarulla

   $ 2,287      $ 2,244  

Watts & More Ltd.

     1,710        2,000  
  

 

 

    

 

 

 
   $ 3,997      $ 4,244  
  

 

 

    

 

 

 

The Mammoth Complex

Prior to August 2, 2010, the Company had a 50% interest in Mammoth Pacific, which owns the Mammoth complex. The Company’s 50% ownership interest in Mammoth Pacific was accounted for under the equity method of accounting as the Company had the ability to exercise significant influence, but not control, over Mammoth Pacific. On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth Pacific (see Note 3).

The condensed results of operations of Mammoth Pacific for the period from January 1, 2010 to August 1, 2010 are summarized below:

 

     (Dollars in thousands)  

Condensed statements of operations:

  

Revenues

   $ 11,484  

Gross margin

     2,670  

Net income

     2,528  

Company’s equity in income of Mammoth:

  

50% of Mammoth net income

   $ 1,264  

Plus amortization of basis difference

     345  
  

 

 

 
     1,609  

Less income taxes

     (611
  

 

 

 

Total

   $ 998  
  

 

 

 

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 (“PGE”). 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.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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.

The Company’s share in the results of operations of W&M was not significant for the three and nine-month periods ended September 30, 2011.

NOTE 6 — 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 September 30, 2011 and December 31, 2010 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
September 30,
2011
     Fair Value at September 30, 2011  
        Total     Level 1      Level 2     Level 3  
     (Dollars in thousands)  

Assets

            

Current assets:

            

Cash equivalents (including restricted cash accounts)

   $ 45,274      $ 45,274     $ 45,274      $      $   

Marketable Securities

     20,867        21,190       21,190                 

Liabilities:

            

Current liabilities:

            

Derivatives(1)

             (12,227             (12,227       
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 
   $ 66,141      $ 54,237     $ 66,464      $ (12,227   $   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 
            

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

     Cost or
Amortized
Cost at
December 31,
2010
     Fair Value at December 31, 2010  
        Total      Level 1      Level 2      Level 3  
     (Dollars in thousands)  

Assets

              

Current assets:

              

Cash equivalents (including restricted cash accounts)

   $ 14,370      $ 14,370      $ 14,370      $       $   

Derivatives(2)

             1,030                1,030          

Non-current assets:

              

Illiquid auction rate securities (including restricted cash accounts) ($4.5 million par value), see below(3)

     4,011        3,027                        3,027  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
   $ 18,381      $ 18,427      $ 14,370      $ 1,030      $ 3,027  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Including: (i) $11,052,000 relating to derivatives which represent interest rate lock transactions which are valued primarily based on observable inputs, including 10-year U.S. Treasury interest rates, and are included within “accounts payable and accrued expenses” in the balance sheet with the corresponding gain or loss being recognized within “interest expense, net” in the condensed consolidated statement of operations and comprehensive income (loss); and (ii) $1,175,000 relating to derivatives which represent currency forward contracts which are valued primarily based on observable inputs , including forward and spot prices for currencies, 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).

 

(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, 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).

 

(3) Included in the consolidated balance sheets as follows:

 

     December 31,
2010
 
     (Dollars in thousands)  

Long-term marketable securities

   $ 1,287  

Long-term restricted cash, cash equivalents and marketable securities

     1,740  
  

 

 

 
   $ 3,027  
  

 

 

 

The Company’s financial assets measured at fair value (including restricted cash accounts) at September 30, 2011 include investments in debt instruments (which are included in marketable securities) and money market funds (which are included in cash equivalents). The Company’s financial assets measured at fair value (including restricted cash accounts) at December 31, 2010 include investments in auction rate securities and money market funds (which are included in cash equivalents). Those securities, except for the auction rate securities, are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

As of December 31, 2010, 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. Such auction rate securities 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 utilizes 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 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.

The table below sets forth a summary of the changes in the fair value of the Company’s financial assets as Level 3 (i.e., illiquid auction rate securities) for the nine-month periods ended September 30, 2011 and 2010:

 

     Nine Months Ended
September 30,
 
         2011             2010      
     (Dollars in thousands)  

Balance at beginning of period

   $ 3,027     $ 3,164  

Total unrealized losses:

    

Included in net income

     (205       

Included in other comprehensive income (loss)

            (135

Transferred to Level 2

     (2,822       
  

 

 

   

 

 

 

Balance at end of period

   $      $ 3,029  
  

 

 

   

 

 

 

Effective July 1, 2010, the Company adopted an accounting standards update that amends and clarifies the guidance on how entities should evaluate credit derivatives embedded in beneficial interests in securitized financial assets. The updated guidance eliminates the scope exception for bifurcation of embedded credit derivatives in interests in securitized financial assets unless they are created solely by subordination of one beneficial interest to another. The auction rate securities held by the Company are considered securitized financial assets. Based on the abovementioned guidance, the Company elected the fair value option for its auction rate securities and reclassified $693,000 (net of income taxes of $377,000) to retained earnings with an offset to other comprehensive income. Effective with the adoption of this new guidance, all changes in the fair value of auction rate securities are recognized in earnings.

The funds invested in auction rate securities that have experienced failed auctions are not accessible until a successful auction occurs, a buyer is found outside of the auction process or the underlying securities reach maturity. As a result, the Company classified those securities with failed auctions as long-term assets in the consolidated balance sheets as of December 31, 2010.

There were no transfers of assets or liabilities between Level 1 and Level 2 during the nine months ended September 30, 2011.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

 

     Fair Value      Carrying Amount  
     September 30,
2011
     December 31,
2010
     September 30,
2011
     December 31,
2010
 
     (Dollars in millions)      (Dollars in millions)  

Olkaria III Loan

   $ 83.2      $ 88.7      $ 82.9      $ 88.4  

Amatitlan Loan

     37.8        39.5        37.3        39.0  

Senior Secured Notes:

           

Ormat Funding Corp. (“OFC”)

     129.5        129.5        130.8        136.3  

OrCal Geothermal Inc. (“OrCal”)

     92.8        93.5        93.2        95.6  

Senior Unsecured Bonds

     252.8        144.8        248.3        142.0  

Loans from institutional investors

     34.2        37.1        34.2        37.2  

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 current market pricing curves.

NOTE 7 — LONG-TERM DEBT

Issuance of Senior Unsecured Bonds

On August 3, 2010, the Company entered into a trust instrument governing the issuance of, and accepted subscriptions for, an aggregate principal amount of approximately $142.0 million of Senior Unsecured Bonds (the “Bonds”). The Company issued the Bonds outside of 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 of 1933, as amended (the “Securities Act”).

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.

In February 2011, the Company accepted subscriptions for an aggregate principal amount of approximately $108.0 million of additional Senior Unsecured Bonds (the “Additional Bonds”) under two addendums to the trust instrument. The Company issued the Additional Bonds outside of 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. The terms and conditions of the Additional Bonds are identical to the Bonds. The Additional Bonds were issued at a premium which reflects an effective fixed interest of 6.75% per annum.

OFC 2 Senior Secured Notes

On September 23, 2011, the Company’s subsidiary OFC 2 LLC (“OFC 2”) and its wholly owned subsidiaries (collectively, the “Issuers”) entered into a note purchase agreement (the “Note Purchase Agreement”) with OFC 2 Noteholder Trust, as purchaser, John Hancock Life Insurance Company (U.S.A.), as administrative agent, and the United States Department of Energy (“DOE”), as guarantor, in connection with the offer and sale of up to $350 million aggregate principal amount of OFC 2’s Senior Secured Notes (“OFC 2 Senior Secured Notes”) due December 31, 2034.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Subject to the fulfillment of customary and other specified conditions precedent, the OFC 2 Senior Secured Notes will 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 (collectively, the “Project”) owned by the Issuers, as follows: Series A Notes, Series B Notes, Series C Notes, Series D Notes, and, if the Issuers so elect, Series E Notes and Series F Notes. The Phase I tranche, comprised of the Series A Notes and the Series B Notes, will be issued in an aggregate principal amount not to exceed $180 million, of which up to $155 million will be allocated to the Series A Notes, and up to $25 million will be allocated to the Series B Notes. 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. Proceeds of the Series A Notes will be used to finance a portion of the construction costs of Phase I of the McGinness Hills and the Tuscarora facilities. Proceeds of the Series B Notes, if issued, 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 a facility Phase II 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 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 DOE will guarantee payment of 80% of principal and interest on the 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.

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 payment of dividends.

In addition, in connection with the issuance of each Series of OFC 2 Senior Secured Notes, the Company 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(ies) financed by such OFC 2 Senior Secured Notes reaches completion and meets certain operational performance levels. A demand on the Company’s 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 the Company’s guarantee based on the other trigger event is not limited.

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.

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

On October 31, 2011, OFC 2 and the Issuers completed the sale of $151.7 million aggregate principal amount of 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 will be used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora facilities. The Issuers will pay 4.687% interest on the Series A Notes quarterly in arrears on the last day of each of March, June, September and December in each year, commencing on December 31, 2011.

NOTE 8 — OPC TRANSACTION

In June 2007, the Company’s wholly owned subsidiary Ormat Nevada Inc. (“Ormat Nevada”) entered into agreements with affiliates of Morgan Stanley & Co. Incorporated (Morgan Stanley Geothermal LLC) and Lehman Brothers Inc. (Lehman-OPC LLC (“Lehman-OPC”)), 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 and accelerated depreciation) and distributable cash associated with four geothermal power plants.

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

Ormat Nevada continues to operate and maintain the power plants. Under the agreements, Ormat Nevada initially received all of the distributable cash flow generated by the power plants, while the investors received substantially all of the production tax credits (“PTC”) and taxable income or loss (together, the “Economic Benefits”). Once it recovered the capital that it has invested in the power plants, which occurred in the fourth quarter of 2010, the investors receive both the distributable cash flow and the Economic Benefits. The investors’ return is limited by the term of the transaction. Once the investors reach a target after-tax yield on their investment in OPC (the “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. Cash is distributed each period in accordance with the cash allocation percentages stipulated in the agreements. Until the fourth quarter of 2010, Ormat Nevada was allocated the cash earnings in OPC and therefore, the amount allocated to the 5% residual interest represented the noncash loss of OPC which principally represented depreciation on the property, plant and equipment. As from the fourth quarter of 2010, the distributable cash is allocated to the Class B membership units.

The Company’s voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. The Company owns, through its 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 in 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 continues to consolidate OPC.

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

On February 3, 2011, Ormat Nevada sold to JPM Capital Corporation (“JPM”) all of the Class B membership units of OPC that it had acquired on October 30, 2009 for a sale price of $24.9 million in cash. The Company did not record any gain from the sale of its Class B membership interests in OPC to JPM. A substantial portion of the Class B membership units are accounted for as a financing transaction. As a result, the majority of these proceeds were recorded as a liability. In addition, $2.3 million has been reclassified from additional paid-in capital to noncontrolling interest representing the 1.5% residual interest of JPM’s Class B membership units.

NOTE 9 — STOCK-BASED COMPENSATION

On March 31, 2011, the Company granted to employees 622,150 stock appreciation rights (“SAR”) under the Company’s 2004 Incentive Plan. The exercise price of each SAR is $25.65, 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, 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. The fair value of each SAR on the date of grant was $9.82.

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

 

Risk-free interest rates

     2.32%   

Expected term (in years)

     5.125  

Dividend yield

     0.80%   

Expected volatility

     46.29%   

Forfeiture rate

     5.69%   

On November 3, 2011, the Company granted to its non-employee directors options to purchase 30,000 shares of common stock under the Company’s 2004 Incentive Plan (see Note 18).

NOTE 10 — DISCONTINUED OPERATIONS

In January 2010, a former shareholder of Geothermal Development Limited (“GDL”) exercised a call option to purchase from the Company its shares in GDL for approximately $2.8 million. In addition, the Company received $17.7 million to repay the loan a subsidiary of the Company provided to GDL to build the plant. The Company did not exercise its right of first refusal and, therefore, the Company transferred its shares in GDL to the former shareholder after the former shareholder paid all of GDL’s obligations to the Company. As a result, the Company recorded a pre-tax gain of approximately $6.3 million in the nine months ended September 30, 2010 ($4.3 million after-tax).

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The operations and gain on sale of GDL have been included in discontinued operations in the condensed consolidated statements of operations and comprehensive income (loss) for all periods prior to the sale of GDL in January 2010. Electricity revenues related to GDL were $0 and $64,000 during the three and nine-month periods ended September 30, 2010, respectively. Basic and diluted earnings per share related to a $4.3 million after-tax gain on sale of GDL was $0.02 and $0.10 during the three and nine-month periods ended September 30, 2010, respectively.

NOTE 11 — ELECTRICITY REVENUES AND COST OF REVENUES

The components of electricity revenues and cost of revenues are as follows:

 

    Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
            2011                     2010                          2011                      2010          
    (Dollars in thousands)     (Dollars in thousands)  

Revenues:

       

Energy and capacity

  $ 33,313     $ 30,113     $ 93,194     $ 80,460  

Lease portion of energy and capacity

    52,831       52,573       151,065       135,795  

Lease income

    671       671       2,014       2,014  
 

 

 

   

 

 

   

 

 

   

 

 

 
  $ 86,815     $ 83,357     $ 246,273     $ 218,269  
 

 

 

   

 

 

   

 

 

   

 

 

 

Cost of revenues:

       

Energy and capacity

  $ 28,840     $ 31,752     $ 96,732     $ 95,710  

Lease portion of energy and capacity

    27,790       28,467       85,426       79,909  

Lease income

    1,311       1,311       3,932       3,932  
 

 

 

   

 

 

   

 

 

   

 

 

 
  $ 57,941     $ 61,530     $ 186,090     $ 179,551  
 

 

 

   

 

 

   

 

 

   

 

 

 

NOTE 12 — INTEREST EXPENSE, NET

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

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
             2011                     2010                     2011                     2010          
     (Dollars in thousands)     (Dollars in thousands)  

Parent

   $      $      $      $ 310  

Interest related to sale of tax benefits

     1,360       1,382       5,236       4,110  

Loss on interest rate lock transactions*

     11,645              16,380         

Other

     14,266       12,072       41,364       32,010  

Less — amount capitalized

     (3,362     (2,493     (8,549     (6,329
  

 

 

   

 

 

   

 

 

   

 

 

 
   $ 23,909     $ 10,961     $ 54,431     $ 30,101  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

* The interest rate lock transactions are related to the OFC 2 Senior Secured Notes and were not accounted for as hedge transactions (see Note 7).

NOTE 13 — EARNINGS PER SHARE

Basic earnings per share attributable to the Company’s stockholders (“earnings per share”) is computed by dividing net income 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 options.

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
             2011                      2010                      2011                      2010          
     (In thousands)      (In thousands)  

Weighted average number of shares used in computation of basic earnings per share

     45,431        45,431        45,431        45,431  

Add:

           

Additional shares from the assumed exercise of employee stock options

     9        19        11        21  
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted average number of shares used in computation of diluted earnings per share

     45,440        45,450        45,442        45,452  
  

 

 

    

 

 

    

 

 

    

 

 

 

The number of stock options that could potentially dilute future earnings per share and that were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was 2,884,314 and 2,245,190 for the three months ended September 30, 2011 and 2010, respectively, and 2,699,790 and 2,022,549 for the nine months ended September 30, 2011 and 2010, respectively.

NOTE 14 — 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 September 30, 2011:

        

Net revenues from external customers

   $ 86,815      $ 24,026      $ 110,841  

Intersegment revenues

             15,264        15,264  

Operating income

     21,087         3,121        24,208  

Segment assets at period end *

     2,121,932        88,789        2,210,721  

* Including unconsolidated investments

     2,287        1,710        3,997  

Three Months Ended September 30, 2010:

        

Net revenues from external customers

   $ 83,357      $ 18,120      $ 101,477  

Intersegment revenues

             10,977        10,977  

Operating income

     13,461        1,357        14,818  

Segment assets at period end *

     1,895,469        69,240        1,964,709  

* Including unconsolidated investments

     2,040                2,040  

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

     Electricity      Product      Consolidated  
     (Dollars in thousands)  

Nine Months Ended September 30, 2011:

        

Net revenues from external customers

   $ 246,273      $ 67,002      $ 313,275  

Intersegment revenues

             46,013        46,013  

Operating income

     34,917        11,784        46,701  

Segment assets at period end *

     2,121,932        88,789        2,210,721  

* Including unconsolidated investments

     2,287        1,710        3,997  

Nine Months Ended September 30, 2010:

        

Net revenues from external customers

   $ 218,269      $ 62,128      $ 280,397  

Intersegment revenues

             39,273        39,273  

Operating income

     11,447        7,883        19,330  

Segment assets at period end *

     1,895,469        69,240        1,964,709  

* Including unconsolidated investments

     2,040                2,040  

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

 

     Three Months Ended September 30,     Nine Months Ended September 30,  
             2011                     2010                     2011                     2010          
     (Dollars in thousands)     (Dollars in thousands)  

Operating income

   $ 24,208     $ 14,818     $ 46,701     $ 19,330  

Interest income

     438       140       1,289       432  

Interest expense, net

     (23,909     (10,961     (54,431     (30,101

Foreign currency translation and transaction gains (losses)

     (2,659     1,074       (1,546     475  

Income attributable to sale of equity interest

     2,344       2,183       7,624        6,392  

Gain on acquisition of controlling interest

            36,928              36,928  

Other non-operating income (expense), net

     347       233       465       (47
  

 

 

   

 

 

   

 

 

   

 

 

 

Total income from continuing operations, before income taxes and equity in income (losses) of investees

   $ 769     $ 44,415     $ 102     $ 33,409  
  

 

 

   

 

 

   

 

 

   

 

 

 

NOTE 15 — 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, as amended (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.

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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. The Company cannot make an estimate of the possible loss or range of loss.

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 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.

The Company believes that these lawsuits have no merit and is defending the actions vigorously.

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. The Company cannot make an estimate of the possible loss or range of 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.

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

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Other

On May 19, 2011, the Federal Energy Regulatory Commission (“FERC”) issued an order which denied the Company’s exemptions for requirements relating to Sections 205 and 206 of the Federal Power Act and directed the Company’s recovered energy generation facilities to make refunds to their customers, equaling “the time value of the revenues collected during the periods of non-compliance with the qualifying facilities”, in an amount of approximately $1.6 million. On June 17, 2011, the Company requested a rehearing to obtain relief on this refund payment. On July 18, 2011, FERC issued an Order Granting Rehearing for Further Consideration in order to afford additional time for consideration of the matters raised. To date, FERC has not taken further action on the rehearing.

The Company believes that it is not probable that a refund payment will ultimately need to be made.

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 materially affect its business, financial condition, financial results or cash flow.

NOTE 16 — CASH DIVIDENDS

On February 22, 2011, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.3 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 15, 2011. Such dividend was paid on March 24, 2011.

On May 4, 2011, 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 18, 2011. Such dividend was paid on May 25, 2011.

On August 3, 2011, 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 August 16, 2011. Such dividend was paid on August 25, 2011.

NOTE 17 — INCOME TAXES

The Company’s effective tax rate for the three months ended September 30, 2011 and 2010 was 39.7% and 26.9%, respectively. The Company’s effective tax rate for the nine months ended September 30, 2011 and 2010 was 711.8% and 18.0%, respectively. The effective tax rate differs from the federal statutory rate of 35% for the nine months ended September 30, 2011 primarily due to: (i) the benefit of production tax credits for qualified power plants placed in service since 2005; (ii) lower tax rates in Israel; (iii) a tax credit and tax exemption related to the Company’s subsidiaries in Guatemala; and (iv) provision to return adjustments related to foreign activities.

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The anticipated annual production tax credits (“PTCs”) associated with the Class B membership interest in OPC (see Note 8), an entity the Company is consolidating, had a significant impact on the Company’s expected overall annual tax benefit in 2010. During 2010, the Company was negotiating to sell such interest to a third party, which sale occurred in February 2011. Upon the sale of the Class B membership interest, the Company was no longer eligible to receive PTCs associated with the Class B membership interest. Due to uncertainties in the timing of selling its Class B membership interest and the significance of the PTCs to the Company’s overall tax benefit in 2010, the Company recognized in 2010 PTCs as they were earned rather than including forecasted PTCs in the annual effective tax rate estimate from continuing operations.

Realization of the U.S. deferred tax assets in the amount of approximately $18.1 million as of December 31, 2010 is dependent on generating sufficient taxable income prior to expiration of the U.S net operating loss carryforwards and U.S. tax credits. Although realization is not assured, management believes it is more likely than not that all of the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

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 is subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years. Ormat Systems is 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 is subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years. These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and its 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 may opt to irrevocably comply with the new law while waiving benefits provided under the current law or continue to comply with the current law during the next years. Changing from the current law to the new law is permissible 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 nine months ended September 30, 2011 by such amount.

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

 

     Nine Months Ended September 30,  
           2011                 2010        
     (Dollars in thousands)  

Balance at beginning of period

   $ 5,431     $ 4,931  

Additions based on tax positions taken in prior years

     190       717  

Decrease for settlements with taxing authorities

     (1,376       
  

 

 

   

 

 

 

Balance at end of period

   $ 4,245     $ 5,648  
  

 

 

   

 

 

 

 

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

NOTE 18 — SUBSEQUENT EVENTS

Options Grant

On November 3, 2011, the Company granted to its four non-employee directors non-qualified stock options, under the Company’s 2004 Incentive Plan, to purchase 30,000 shares of common stock (7,500 shares each) at an exercise price equal to the closing price of the Company’s common stock on November 4, 2011 (since the Company released its quarterly results on November 2, 2011). Such options will expire seven years from the date of grant and will vest on the first anniversary of the date of grant.

OFC 2 Senior Secured Notes

On October 31, 2011, OFC 2 and the Issuers completed the sale of $151.7 million aggregate principal amount of the Series A Notes due 2032 (see Note 7).

 

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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;

 

   

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 authorization;

 

   

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 power purchase agreements (PPAs) for our power plants;

 

   

contract counterparty risk;

 

   

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;

 

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

 

   

current and future litigation;

 

   

our ability to successfully identify, integrate and complete acquisitions;

 

   

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

 

   

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 terrorist incidents or responses to such incidents, 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;

 

   

the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2010;

 

   

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, 2010 and any updates contained herein as well as those set forth in our reports and other filings made with the SEC.

General

Overview

We are a leading vertically integrated company engaged 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

 

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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 recently 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) power plants in the United States. During the nine months ended September 30, 2011, and 2010, our consolidated power plants generated 2,935,854 MWh and 2,735,018 MWh, respectively.

For the nine months ended September 30, 2011, our Electricity Segment revenues represented approximately 78.6% of our total revenues, while our Product Segment revenues represented approximately 21.4% of our total revenues .

For the nine months ended September 30, 2011, our total revenues increased by 11.7% (from $280.4 million to $313.3 million) over the same period last year. Revenues from the Electricity Segment increased by 12.8% and revenues from the Product Segment increased by 7.8%.

For the nine months ended September 30, 2011, total Electricity Segment revenues from the sale of electricity by our consolidated power plants were $246.3 million, compared to $218.3 million for the nine months ended September 30, 2010, an increase of 12.8%.

For the nine months ended September 30, 2011, revenues attributable to our Product Segment were $67.0 million, compared to $62.1 million for the nine months ended September 30, 2010, an increase of 7.8%.

Revenues from our Electricity Segment are relatively predictable, as they are derived from sales of electricity generated by our power plants pursuant to long-term PPAs. The price for electricity under all but one of our PPAs is effectively a fixed price at least through April 2012. The exception is the PPA of the Puna power plant. It has a monthly variable energy rate 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. In the nine months ended September 30, 2011, approximately 82.7% of our electricity revenues were derived from contracts with fixed energy rates, and therefore most of our electricity revenues were 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 significantly from period to period because of the timing of our receipt of purchase orders and the progress of our execution of each project.

Our management assesses the performance of our two segments of operation differently. In the case of our Electricity Segment, when making decisions about potential acquisitions or the development of new projects, we typically focus on the internal rate of return of the relevant investment, 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.

 

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Recent Developments

 

   

In October 2011, the Chilean Committee on Geothermal Energy Analysis recommended that the Chilean Ministry of Energy award Ormat five exploration concessions in Chile. Under the applicable regulatory framework governing the concessions, in order to maintain the development rights granted under these concessions, Ormat will need to make certain investments in an exploration program over the next two years. Successful exploration results will be followed by an Exploitation License, which is the first step toward power plant construction.

 

   

In September 2011, our wholly-owned indirect subsidiary, OFC 2 LLC (OFC 2), and its project subsidiaries, finalized and signed loan documentation for a 20-year loan for up to $350 million aggregate principal amount of senior secured notes due December 31, 2034 (Notes) under a financing with John Hancock Life Insurance Company (USA) and John Hancock Life & Health Insurance Company (collectively, John Hancock). The transaction will be guaranteed by the United States Department of Energy (DOE)’s Loan Programs Office in accordance with, and subject to, the DOE’s Loan Guarantee Program under Section 1705 of Title XVII of the Energy Policy Act of 2005. The financing will support power generation from three Nevada-based facilities built in two phases that are expected to generate up to 113 MW of power. The three facilities, Jersey Valley, McGinness Hills, and Tuscarora, will provide baseload power through 20-year PPAs with Nevada Power Company, a subsidiary of NV Energy. The capacity of the first phase is expected to be up to approximately 60 MW. The second phase development is subject to a feasibility assessment of the geothermal resource, which will be performed following completion of the first phase of each facility and fulfillment of other conditions in the loan documents. On October 31, 2011, OFC 2 and the Issuers completed the sale of $151.7 million aggregate principal amount of 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 will be used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora facilities.

 

   

In September 2011, our wholly-owned indirect subsidiary, Ormat International, Inc., signed a commitment letter issued by the Overseas Private Investment Corporation (OPIC) to provide project financing of up to $310 million to refinance and expand our 48 MW Olkaria III geothermal complex located in Naivasha, Kenya. Under the agreed term sheet attached to the commitment letter, the loan will be comprised of a refinancing tranche of up to $85 million to prepay the existing loan and fund transaction costs, a construction loan tranche of up to $165 million to finance the construction of an additional 36 MW expansion currently underway, and a $60 million stand-by facility to finance an additional optional 16 MW capacity expansion, 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 16 MW expansion.

 

   

We have completed the modification of the 20 MW Burdette (Galena 1) power plant into an evaporative cooling configuration. Evaporative cooling provides increased power generation from air-cooled facilities, compared to regular air-cooled facilities by as much as 30% during the peak heat hours of the day. The implementation of this system in moderate to dry climates, especially in the high desert, generates more energy per year than water-cooled systems, and with a fraction of the water and chemical consumption of traditional water-cooled systems.

 

   

Since the beginning of 2011, we have increased our land inventory by approximately 21,000 acres of federal or private land in Nevada, Oregon, California, Hawaii and New Zealand.

 

   

Since the beginning of 2011, we have entered into new contracts for the supply of geothermal power plants and other power generating units outside of the United States (including the Ngatamariki and Norske contracts described below) and have thereby increased our backlog for the Product Segment as of September 30, 2011 to approximately $200 million.

 

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In February 2011, we signed a 20-year PPA with NV Energy, Inc. (NV Energy) to sell 30 MW from the Dixie Meadows geothermal project that we are developing in Churchill County, Nevada. The PPA is subject to approval by the Public Utilities Commission of Nevada (PUCN). On July 22, 2011, the PUCN issued an order requiring NV Energy to either (i) file an integrated resource plan amendment requesting approval of five renewable energy PPAs, including the Dixie Meadows PPA; or (ii) make a submission explaining why NV Energy is not requesting approval of the five renewable energy PPAs, including the Dixie Meadows PPA, and directed NV Energy, as part of that submission, to provide the PUCN with certain additional information to facilitate its review and analysis of these five renewable energy PPAs prior to its decision. In October 2011, NV Energy filed its request for a rehearing (Docket #11-03014) which included a request for approval of the Dixie Meadows PPA. The PUCN decision is expected by February 2012. The Dixie Meadows project is currently in the exploration phase. If the Dixie Meadows project reaches completion prior to the end of 2013, it would be eligible for a cash grant under the American Recovery and Reinvestment Act of 2009 (ARRA).

 

   

In June 2011, we signed a lease agreement for approximately 300 acres with Kibbutz Revivim in Israel. We plan to use the land to build a solar power plant.

 

   

In June 2011, we entered into a build, operate and transfer (BOT) agreement with Tikitere Geothermal Power Limited (TGL) to explore, develop, supply, construct, own and operate a geothermal power plant in the Tikitere geothermal area near Rotorua, New Zealand. Under the BOT agreement, the parties will jointly develop a geothermal power plant with an estimated capacity of approximately 45 MW. We will own and operate the project for an initial period of 14 years following commercial operation and then the ownership interests in the project will be transferred to TGL. The project will utilize Ormat’s generating units. The BOT agreement is conditional upon receiving regulatory approval. Construction of the power plant will commence following the obtaining of local permits, as well as satisfactory feasibility results following exploration and development activities to be carried out by us.

 

   

In June 2011, two of our subsidiaries signed a supply contract and an engineering, procurement and construction (EPC) contract with Mighty River Power Limited (Mighty River Power) of New Zealand, for the first stage of the Ngatamariki geothermal project valued at a total of approximately $130 million. The new power plant is to be constructed on the Ngatamariki Geothermal Field in New Zealand. Construction of the power plant is expected to be completed within 24 months from the contract date. Mighty River Power, a state-owned enterprise, is a New Zealand electricity generation and electricity retailing company.

 

   

In May 2011, we entered into a supply contract with Norske Skog Tasman Limited of New Zealand to supply a new geothermal power plant that is to be constructed in the Kawerau Geothermal Field in New Zealand. The contract is valued at a total of approximately $20 million and delivery of the power plant is expected to be completed within 13 months from the contract date.

 

   

In April 2011, we amended and restated the PPA with Kenya Power and Lighting Co. Ltd. (KPLC), the off-taker of the Olkaria III complex located in Naivasha, Kenya. The amended and restated PPA governs our construction of, and KPLC’s purchase of electricity from, a new 36 MW power plant at the Olkaria III complex. The new power plant is scheduled to come online in 2013. The PPA amendment includes an option to increase the combined 84 MW capacity from the new and existing plants to a maximum of 100 MW, subject to monitoring and assessment of the geothermal reservoir capacity.

 

   

In March 2011, we entered into an agreement with the Weyerhaeuser Company granting us an option to enter into geothermal leases covering approximately 264,000 acres of land in Oregon and Washington. Under this agreement we have the exclusive right to explore the land for geothermal resources and may enter into one or more geothermal leases within the optioned land.

 

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On March 31, 2011, Southern California Edison Company (Southern California Edison) set the demonstrated capacity of the North Brawley power plant at 33 MW. Southern California Edison also agreed to modify the North Brawley PPA to allow us the option of performing an additional capacity demonstration within one year from the first capacity demonstration on March 31, 2011, which would enable us to increase the demonstrated capacity of the plant.

 

   

In February 2011, we completed the sale of our part ownership interest in OPC LLC (OPC) to JPM Capital Corporation for $24.9 million in a transaction to monetize production tax credits (PTCs) and other tax benefits.

 

   

In February 2011, we signed a PPA with Hawaii Electric Light Company (HELCO) to sell to HELCO an additional 8 MW from the Puna power plant, at a fixed price (subject to escalation) independent of oil prices. The 20-year PPA is subject to approval by the Public Utilities Commission of Hawaii (PUCH), with input from the Hawaii Division of Consumer Advocacy. The construction of the power plant has been completed and will be fully commissioned to deliver power as soon as the PPA is approved by the PUCH.

 

   

In February 2011, we concluded the issuance of Senior Unsecured Bonds in an aggregate amount of approximately $250 million (Senior Unsecured Bonds). The Senior Unsecured Bonds were issued in two tranches. On August 3, 2010, we entered into a trust instrument governing the issuance of, and accepted subscriptions for, an aggregate principal amount of approximately $142 million of Senior Unsecured Bonds, and in February 2011, we entered into addendums to the trust instrument governing the issuance of, and accepted subscriptions for, an additional $108 million in aggregate principal amount of Senior Unsecured Bonds (the Additional Bonds). Subject to early redemption, the principal of the Senior Unsecured Bonds is repayable in a single bullet payment upon the final maturity of the Senior Unsecured Bonds on August 1, 2017. The Senior Unsecured Bonds bear interest at a fixed rate of 7% per annum, payable semi-annually. The Additional Bonds were issued at a premium which reflects an effective fixed interest of 6.75% per annum.

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”). 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 fully-contracted long-term PPAs. We also intend to continue to pursue growth in our recovered energy business and in the solar sector.

 

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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 the implementation of our organic growth through exploration, development, and construction of new projects and enhancements of existing projects. We expect that this investment in organic growth will increase our total generating capacity, consolidated revenues and operating income attributable to our Electricity Segment year over year. We also routinely look at acquisition opportunities.

 

   

We expect that the increased 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 permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs apply to certain major sources of greenhouse gas 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 greenhouse gas emissions and aims to reduce greenhouse gas emissions to 1990 levels by 2020. In 2008, the California Air Resources Board (CARB) approved a Scoping Plan to carry out regulations implementing AB 32. In December 2010, CARB approved cap-and-trade regulations to reduce California’s greenhouse gas emissions under AB 32. The cap-and-trade regulation, the first phase of which is contemplated to be initiated in January of 2012 with compliance obligations commencing in January 2013, will set a statewide limit on emissions from sources responsible for emitting 80% of California’s greenhouse gases and, according to CARB, will help establish a price signal needed to drive long-term investment in cleaner fuels and more efficient use of energy. 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 are reflected in Executive Order S-3-05, which requires a reduction in greenhouse gases 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 greenhouse gas 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 seven U.S. states and four Canadian provinces) and the Midwest Greenhouse Gas Reduction Accord (which includes six U.S. states and one Canadian province), are also being developed to reduce greenhouse gas 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 ten Northeast and Mid-Atlantic States (though New Jersey will withdraw by the end of 2011). Under RGGI, the participating states plan to stabilize power section carbon emissions at their capped level, and then reduce the cap by 10% at a rate of 2.5% each year between 2015 and 2018. In addition, twenty-nine states and the District of Columbia have all adopted renewable portfolio standards (RPS) and eight other states have adopted renewable portfolio goals. In California, on April 12, 2011, Governor Jerry Brown signed Senate Bill X1-2 (SBX1-2) to increase California’s RPS to 33% by December 31, 2020, among the most aggressive renewable energy goals in the United States. 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 and in particular the impact of the increase in California RPS, as one of the most significant opportunities for us to expand existing projects and build new power plants.

 

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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 industries to continue. The current demand for renewable energy is large enough that this increased competition has not materially impacted our ability to obtain new PPAs. However, 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 industries, 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.

 

   

We expect increased competition from binary power plant equipment suppliers. While we believe that we have a distinct competitive advantage based on our accumulated experience and current worldwide share of installed binary generation capacity, which is in excess of 90%, an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to a reduction in prices that we are able to charge for our binary equipment, which in turn may impact our profitability.

 

   

Our PPA for the Puna power plant has a monthly variable energy rate based on the local utility’s 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 any other variable energy rate in PPAs that we may enter into in the future.

 

   

While the current demand for renewable energy is large enough that increased competition has not impacted our ability to obtain new PPAs and new leases, increased competition in the power generation industry may contribute to a reduction in electricity prices, and increased competition in geothermal leasing may contribute to an increase in lease costs.

 

   

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 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.

 

   

Our foreign operations are subject to significant political, economic and financial risks, which vary by country. 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

 

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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 (our Steamboat 1 power plant, which sells its electricity to Sierra Pacific Power Company on a year-by-year basis) are long-term. 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.

 

   

In December 2010, a global settlement (Global Settlement) relating primarily to the purchase and payment obligations of investor-owned utilities to “Qualifying Facilities” under PURPA was approved by the California Public Utilities Commission (CPUC). The Global Settlement will become effective upon the satisfaction of certain conditions precedent, including: (a) a final and non-appealable order from the FERC approving the investor-owned utilities’ request for a waiver of the Qualifying Facility must-take purchase obligation for Qualifying Facilities above 20 MW; and (b) that the CPUC order becomes final and non-appealable. On June 16, 2011, the FERC granted the application of the three California investor-owned utilities to terminate each utility’s must-take purchase obligation under PURPA for Qualifying Facilities larger than 20 MW. Once the Global Settlement becomes effective, it will affect most of our PPAs with Southern California Edison, which accounted for approximately 30.5% and 29.6 % of our revenues during the nine-month periods ended September 30, 2011 and 2010, respectively. In accordance with the Global Settlement, we expect to amend our existing PPAs, which must be done within 180 days of the effectiveness of the Global Settlement. Upon amendment, our existing PPAs will reflect a pricing option based on a short-run avoided cost (SRAC) methodology with certain applied modifiers in accordance with our selected pricing option (that may differ between the different PPAs that will be amended) until December 2014, and thereafter convert to a mandatory SRAC methodology pricing for all of such amended PPAs determined as set forth in the Global Settlement. We anticipate this will expose our revenues from these PPAs to greater fluctuations and may adversely affect our revenues under these PPAs. Our expectation is that the new pricing, which will be based in large part on future natural gas prices, will reduce our revenues in 2012 and 2013 by $9.5 million and $6.5 million, respectively. It is not possible at this point to estimate the impact on revenues beyond 2013.

Notwithstanding the Global Settlement, each of Southern California Edison and Pacific Gas & Electric, two of the three California investor-owned utilities, recently separately filed with the CPUC to approve fixed energy price amendments or fixed energy price PPAs with different existing renewable energy qualifying facilities. While there can be no assurance that such utilities will agree to enter into further such contracts, a fixed energy price alternative will eliminate the uncertainties inherent in pricing based in large part on future natural gas prices, but may not necessarily compensate for any reduction in revenues that might otherwise result from the Global Settlement pricing.

 

   

In addition to increasing the California RPS target to 33% by December 31, 2020, California’s Senate Bill X1-2 (SBX1-2), signed into law by Governor Jerry Brown on April 12, 2011, also instituted a tradable renewable energy credit (REC) program. 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, which 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 tradable RECs can account for only 25% of a utility’s annual RPS though this limit does not apply to municipal utilities and many other small entity companies. 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 in selling electricity from our projects.

 

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Revenues

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

Revenues attributable to our Electricity Segment are relatively predictable as they are derived from the sale of electricity from our power plants pursuant to long-term PPAs. However, such revenues are subject to seasonal variations, as more fully described below in the section entitled “Seasonality”. Electricity Segment revenues may also be affected by higher-than-average ambient temperatures, 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 levels and the potential forfeiture of payments if we fail to meet minimum target 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 along with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.

The prices paid for electricity pursuant to the PPA of the Puna power plant are impacted by the price of oil. Accordingly, our revenues for that power plant, which accounted for approximately 10.9% and 8.3% of our total revenues for the nine-month periods ended September 30, 2011 and 2010, respectively, may be volatile.

Revenues attributable to our Product Segment are generally less predictable than revenues from our Electricity Segment. This is because 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 long 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 and may not be able to replace 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. However, we experienced a significant increase in our Product Segment customer orders in 2011, which increased our Product Segment backlog to $200 million as of September 30, 2011. 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:

 

     Revenues in Thousands      % of Revenues for Period Indicated  
     Three Months Ended
September 30,
     Nine Months Ended
September 30,
     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
         2011              2010              2011              2010              2011             2010             2011             2010      

Revenues:

                    

Electricity

   $ 86,815       $ 83,357       $ 246,273       $ 218,269         78.3     82.1     78.6     77.8

Product

     24,026        18,120        67,002        62,128        21.7       17.9       21.4       22.2  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $ 110,841       $ 101,477       $ 313,275       $ 280,397         100.0     100.0     100.0     100.0
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

 

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Geographical Breakdown of Revenues

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

 

     Revenues in Thousands      % of Revenues for Period Indicated  
     Three Months Ended
September 30,
     Nine Months Ended
September 30,
     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
         2011              2010              2011              2010              2011             2010             2011             2010      

Electricity Segment:

                    

United States

   $ 66,951       $ 65,556       $ 188,400       $ 164,055         77.1     78.6     76.5     75.2

Foreign

     19,864        17,801        57,873        54,214        22.9       21.4       23.5       24.8  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $ 86,815       $ 83,357       $ 246,273       $ 218,269         100.0     100.0     100.0     100.0
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Product Segment:

                    

United States

   $       $ 3,512       $       $ 8,535         0.0     19.4     0.0     13.7

Foreign

     24,026        14,608        67,002        53,593        100.0       80.6       100.0       86.3  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $ 24,026       $ 18,120       $ 67,002       $ 62,128         100.0     100.0     100.0     100.0
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Seasonality

The prices paid for the electricity generated by some of our domestic power plants pursuant to our PPAs are subject to seasonal variations. The prices paid for electricity under the PPAs with 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 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 projects from quarter to quarter. Payments made to government agencies and private entities relating to 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. For the nine months ended September 30, 2011, royalties constituted approximately 3.5% of Electricity Segment revenues, compared to approximately 3.8% for the nine months ended September 30, 2010.

 

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Product Segment

The principal cost of revenues attributable to our Product Segment includes materials, salaries and related employee benefits, expenses related to subcontracting activities, transportation expenses and sales commissions to sales representatives. 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 September 30, 2011 decreased to $80.3 million from $82.8 million as of December 31, 2010. This decrease is principally due to: (i) our use of $180.8 million to fund capital expenditures; (ii) repayment of $26.0 million of long-term debt; (iii) a net change in restricted cash, cash equivalents and marketable securities of $36.9 million; and (iv) cash paid to non-controlling interest of $10.8 million. The decrease in our cash resources was partially offset by: (i) our issuance of an aggregate principal amount of approximately $107.4 million of Senior Unsecured Bonds in February 2011; (ii) $24.9 million of proceeds from the sale of Class B membership units of OPC to JPM Capital in February 2011; (iii) $98.5 million derived from operating activities during the nine months ended September 30, 2011; and (iv) net proceeds of $31.9 million against our revolving credit lines with commercial banks. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of September 30, 2011 was $409.0 million, as described below in the section entitled “Liquidity and Capital Resources”, of which we utilized $306.7 million (including $97.4 million of letters of credit) as of September 30, 2011.

Critical Accounting Policies

A comprehensive discussion of our critical accounting policies 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, 2010.

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 September 30,     Nine Months Ended September 30,  
            2011                     2010                     2011                     2010          
   

(In thousands, except

per share data)

   

(In thousands, except

per share data)

 

Statements of Operations Historical Data:

       

Revenues:

       

Electricity

  $ 86,815     $ 83,357     $ 246,273     $ 218,269  

Product

    24,026       18,120       67,002       62,128  
 

 

 

   

 

 

   

 

 

   

 

 

 
    110,841       101,477       313,275       280,397  
 

 

 

   

 

 

   

 

 

   

 

 

 

Cost of revenues:

       

Electricity

    57,941       61,530       186,090       179,551  

Product

    17,137       14,764       43,276       41,316  
 

 

 

   

 

 

   

 

 

   

 

 

 
    75,078       76,294       229,366       220,867  
 

 

 

   

 

 

   

 

 

   

 

 

 

Gross margin:

       

Electricity

    28,874       21,827       60,183       38,718  

Product

    6,889       3,356       23,726       20,812  
 

 

 

   

 

 

   

 

 

   

 

 

 
    35,763       25,183       83,909       59,530  

Operating expenses:

       

Research and development expenses

    2,346       1,252       7,128       8,133  

Selling and marketing expenses

    2,940       3,333       9,325       9,221  

General and administrative expenses

    6,269       5,780       20,755       19,796  

Write-off of unsuccessful exploration activities

    —          —          —          3,050  
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    24,208       14,818       46,701       19,330  

Other income (expense):

       

Interest income

    438       140       1,289       432  

Interest expense, net

    (23,909     (10,961     (54,431     (30,101

Foreign currency translation and transaction gains (losses)

    (2,659     1,074       (1,546     475  

Income attributable to sale of tax benefits

    2,344       2,183       7,624       6,392  

Gain on acquisition of controlling interest

    —          36,928       —          36,928  

Other non-operating income (expense), net

    347       233       465       (47
 

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations, before income taxes and equity in income (losses) of investees

    769       44,415       102       33,409  

Income tax benefit (expense)

    305       (11,931     726       (6,009

Equity in income (losses) of investees, net

    (71     (83     (552     942  
 

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations

    1,003       32,401       276       28,342  

Discontinued operations:

       

Income from discontinued operations, net of related tax

    —          —          —          14  

Gain on sale of a subsidiary in New Zealand, net of related tax

    —          —          —          4,336  
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income

    1,003       32,401       276       32,692  

Net loss (income) attributable to noncontrolling interest

    (137     58       (252     168  
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to the Company’s stockholders

  $ 866     $ 32,459     $ 24     $ 32,860  
 

 

 

   

 

 

   

 

 

   

 

 

 

Earnings per share attributable to the Company’s stockholders— basic and diluted:

       

Income from continuing operations

  $ 0.02     $ 0.71     $ 0.00     $ 0.62  

Discontinued operations

    —          —          —          0.10  
 

 

 

   

 

 

   

 

 

   

 

 

 

Net Income

  $ 0.02     $ 0.71     $ 0.00     $ 0.72  
 

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average number of shares used in computation of earnings per share attributable to the Company’s stockholders:

       

Basic

    45,431       45,431       45,431       45,431  
 

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

    45,440       45,450       45,442       45,452  
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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    Three Months Ended September 30,     Nine Months Ended September 30,  
            2011                     2010                     2011                     2010          

Statements of Operations Percentage Data:

       

Revenues:

       

Electricity

    78.3     82.1     78.6     77.8

Product

    21.7       17.9       21.4       22.2  
 

 

 

   

 

 

   

 

 

   

 

 

 
    100.0       100.0       100.0       100.0  
 

 

 

   

 

 

   

 

 

   

 

 

 

Cost of revenues:

       

Electricity

    66.7       73.8       75.6       82.3  

Product

    71.3       81.5       64.6       66.5  
 

 

 

   

 

 

   

 

 

   

 

 

 
    67.7       75.2       73.2       78.8  
 

 

 

   

 

 

   

 

 

   

 

 

 

Gross margin:

       

Electricity

    33.3       26.2       24.4       17.7  

Product

    28.7       18.5       35.4       33.5  
 

 

 

   

 

 

   

 

 

   

 

 

 
    32.3       24.8       26.8       21.2  

Operating expenses:

       

Research and development expenses

    2.1       1.2       2.3       2.9  

Selling and marketing expenses

    2.6       3.3       3.0       3.3  

General and administrative expenses

    5.7       5.7       6.6       7.1  

Write-off of unsuccessful exploration activities

    0.0       0.0       0.0       1.1  
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    21.9       14.6       14.9       6.8  

Other income (expense):

       

Interest income

    0.4       0.1       0.4       0.2  

Interest expense, net

    (21.6     (10.8     (17.4     (10.7

Foreign currency translation and transaction gains (losses)

    (2.4     1.1       (0.5     0.2  

Income attributable to sale of tax benefits

    2.1       2.2       2.5       2.3  

Gain on acquisition of controlling interest

    0.0       36.4       0.0       13.2  

Other non-operating income (expense), net

    0.3       0.2       0.2       (0.0
 

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations, before income taxes and equity in income (losses) of investees

    0.7        43.8       0.1       12.0   

Income tax benefit (expense)

    0.3        (11.8     0.2       (2.1

Equity in income (losses) of investees, net

    (0.1     (0.1     (0.2     0.3  
 

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations

    0.9        31.9       0.1       10.2  

Discontinued operations:

       

Income from discontinued operations, net of related tax

    0.0       0.0       0.0       0.0  

Gain on sale of a subsidiary in New Zealand, net of related tax

    0.0       0.0       0.0       1.5  
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income

    0.9        31.9       0.1       11.7  

Net loss (income) attributable to noncontrolling interest

    (0.1     0.1       (0.1     0.1  
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to the Company’s stockholders

    0.8     32.0     0.0     11.8
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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Comparison of the Three Months Ended September 30, 2011 and the Three Months Ended September 30, 2010

Total Revenues

Total revenues for the three months ended September 30, 2011 were $110.8 million, compared to $101.5 million for the three months ended September 30, 2010, which represented a 9.2% increase in total revenues. This increase is attributable to both our Electricity and Product Segments whose revenues increased by 4.1% and 32.6%, respectively, over the same period last year.

Electricity Segment

Revenues attributable to our Electricity Segment for the three months ended September 30, 2011 were $86.8 million, compared to $83.4 million for the three months ended September 30, 2010, which represented a 4.1% increase in such revenues. This result is due to an increase in the electricity rates in our Amatitlan and Puna power plants. As a result, the average revenue rate of our electricity portfolio increased from $89 per MWh in the three months ended September 30, 2010 to $95 per MWh in the three months ended September 30, 2011. The increase in our average rate did not fully impact our electricity revenues in the third quarter because the electricity generation in our power plants declined by 3% from 937,402 MWh in the three months ended September 30, 2010 to 909,054 MWh in the three months ended September 30, 2011 due to major maintenance activity in some of our power plants. The revenues from our North Brawley power plant in the third quarter of 2011 decreased to $4.0 million from $5.1 million during the same period in 2010 due to our decision to mitigate losses at that plant by idling wells that have a negative impact on our margins.

Product Segment

Revenues attributable to our Product Segment for the three months ended September 30, 2011 were $24.0 million, compared to $18.1 million for the three months ended September 30, 2010, which represented a 32.6% increase in such revenues. The increase in our product revenues reflects the increase in new customer orders that we secured in the second quarter of 2011.

Total Cost of Revenues

Total cost of revenues for the three months ended September 30, 2011 was $75.1 million, compared to $76.3 million for the three months ended September 30, 2010, which represented a slight decrease of 1.6% in total cost of revenues. As a percentage of total revenues, our total cost of revenues for the three months ended September 30, 2011 was 67.7%, compared to 75.2% for the same period in 2010.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the three months ended September 30, 2011 was $57.9 million, compared to $61.5 million for the three months ended September 30, 2010, which represented a 5.8% decrease in total cost of revenues for such segment, while the increase in revenues was 4.1%. We incurred lower costs associated with operating and maintaining the North Brawley power plant in the third quarter of 2011 ($7.5 million), compared to the third quarter of 2010 ($10.1 million). Although we expect the high level of operating expenses at the North Brawley power plant to continue, such expenses are expected to trend downward. The cost per MWh in the current quarter was the same as in the third quarter of 2010, and as noted below slightly higher for the nine months ended September 30, 2011 than the nine months ended September 30, 2010. The cost per MWh in the current quarter was impacted by lower maintenance costs in most of our other power plants over the same quarter last year, which lower maintenance costs were offset by increased depreciation costs in the Mammoth complex, resulting from our program to repower the complex by

 

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replacing part of the old units with new equipment. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the three months ended September 30, 2011 was 66.7%, compared to 73.8% for the three months ended September 30, 2010.

Product Segment

Total cost of revenues attributable to our Product Segment for the three months ended September 30, 2011 was $17.1 million, compared to $14.8 million for the three months ended September 30, 2010, which represented a 16.1% 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 September 30, 2011 was 71.3%, compared to 81.5% for the three months ended September 30, 2010. Such decrease in the percentage of Product Segment cost of revenues from total Product Segment revenues is mainly attributable to: (i) higher revenues; (ii) a different product mix; and (iii) different margins in the sales contracts.

Research and Development Expenses

Research and development expenses for the three months ended September 30, 2011 were $2.3 million, compared to $1.3 million for the three months ended September 30, 2010, which represented a 87.4% increase. Our research and development activities during the three months ended September 30, 2011 included: (i) continued development of enhanced geothermal systems (EGS); and (ii) development of a solar thermal system for the production of electricity.

Selling and Marketing Expenses

Selling and marketing expenses for the three months ended September 30, 2011 were $2.9 million, compared to $3.3 million for the three months ended September 30, 2010, which represented an 11.8% decrease. Selling and marketing expenses for the three months ended September 30, 2011 constituted 2.6% of total revenues, compared to 3.3% for the three months ended September 30, 2010.

General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2011 were $6.3 million, compared to $5.8 million for the three months ended September 30, 2010, which represented an 8.5% increase. General and administrative expenses for each of the three months ended September 30, 2011 and September 30, 2010 constituted 5.7% of total revenues.

Operating Income

Operating income for the three months ended September 30, 2011 was $24.2 million, compared to $14.8 million for the three months ended September 30, 2010. Such increase of $9.4 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 September 30, 2011 was $21.1 million, compared to $13.5 million for the three months ended September 30, 2010. Operating income attributable to our Product Segment for the three months ended September 30, 2011 was $3.1 million, compared to $1.4 million for the three months ended September 30, 2010.

Interest Expense, Net

Interest expense, net for the three months ended September 30, 2011 was $23.9 million, compared to $11.0 million for the three months ended September 30, 2010, which represented a 118.1% increase. The $12.9 million increase is primarily due to: (i) an $11.6 million loss on interest rate lock transactions in the three months ended

 

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September 30, 2011 relating to the DOE loan guarantee transaction that was consummated in September 2011, and which were not accounted for as hedge transactions; and (ii) the issuance of Senior Unsecured Bonds in August 2010 and February 2011. The increase was partially offset by: (i) an increase of $0.9 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.

Foreign Currency Translation and Transaction Gains (Losses)

Foreign currency translation and transaction losses for the three months ended September 30, 2011 were $2.7 million, compared to gains of $1.1 million for the three months ended September 30, 2010. The $3.7 million decrease is primarily due to losses on forward foreign exchange transactions for the three months ended September 30, 2011, which were not accounted for as hedge transactions, compared to gains in the three months ended September 30, 2010.

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 September 30, 2011 was $2.3 million, compared to $2.2 million for the three months ended September 30, 2010. 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.

Gain on acquisition of controlling interest

Gain on acquisition of controlling interest for the three months ended September 30, 2010 was $36.9 million. This gain relates to the acquisition of the remaining 50% interest in Mammoth Pacific as discussed above. The acquisition date fair value of the previous 50% equity interest was $64.9 million. In the three months ended September 30, 2010, we recognized a pre-tax gain of $36.9 million ($22.6 million after tax), which is equal to the difference between the acquisition date fair value of the initial investment in Mammoth Pacific and the acquisition date carrying value of such investment.

Income Taxes

Income tax benefit for the three months ended September 30, 2011 was $0.3 million, compared to income tax expense of $11.9 million for the three months ended September 30, 2010. The effective tax rate for the three months ended September 30, 2011 was 39.7%, compared to 26.9% for the three months ended September 30, 2010. The change in the effective tax rate primarily resulted from a higher impact of PTCs on the effective tax rate due to a lower projected pre-tax annual income.

Net Income

Net income for the three months ended September 30, 2011 was $1.0 million, compared to $32.4 million for the three months ended September 30, 2010. Such decrease in net income of $31.4 million was principally attributable to: (i) a gain on acquisition of controlling interest of $36.9 million in the three months ended September 30, 2010; (ii) a $12.9 million increase in interest expense; and (iii) a $3.7 million increase in foreign currency translation and transaction losses. The decrease was partially offset by: (i) a $9.4 million increase in operating income; and (ii) an $12.2 million decrease in income tax expense.

 

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Comparison of the Nine Months Ended September 30, 2011 and the Nine Months Ended September 30, 2010

Total Revenues

Total revenues for the nine months ended September 30, 2011 were $313.3 million, compared to $280.4 million for the nine months ended September 30, 2010, which represented an 11.7% increase in total revenues. This increase is attributable to both our Electricity and Product Segments whose revenues increased by 12.8% and 7.8%, respectively, over the same period last year.

Electricity Segment

Revenues attributable to our Electricity Segment for the nine months ended September 30, 2011 were $246.3 million, compared to $218.3 million for the nine months ended September 30, 2010, which represented a 12.8% increase in such revenues. This result is due to increased electricity generation of our power plants from 2,735,018 MWh in the nine months ended September 30, 2010 to 2,935,854 MWh in the nine months ended September 30, 2011. The most significant contributors to the increase in our electricity generation were: (i) an increase in the generation of the Puna power plant due to repair work that was completed in the second quarter of 2010; (ii) an increase in the generation of our North Brawley power plant, with revenues of $12.7 million in the nine months ended September 30, 2011, compared to $11.3 million in the nine months ended September 30, 2010; (iii) the consolidation of the Mammoth complex, effective August 2, 2010, with revenues of $14.7 million in the nine months ended September 30, 2011, compared to $3.5 million in the nine months ended September 30, 2010, resulting from the acquisition of the remaining 50% interest in Mammoth Pacific in August 2010; and (iv) an increase in generation of our REG facilities due to the addition of one plant and a higher availability of the pipeline providing the heat to most of our REG power plants. The increase in our Electricity Segment revenues is also attributable to an increase in the average revenue rate of our electricity portfolio from $80 per MWh in the nine months ended September 30, 2010 to $84 per MWh in the nine months ended September 30, 2011. Such increase was mainly due to higher rates under the PPA of the Puna power plant.

Product Segment

Revenues attributable to our Product Segment for the nine months ended September 30, 2011 were $67.0 million, compared to $62.1 million for the nine months ended September 30, 2010, which represented a 7.8% increase in such revenues. The increase relative to the nine months ended September 30, 2011 was primarily due to $7.9 million in revenues relating to an LNG energy recovery unit in Spain (See “Research and Development Expenses” below).

Total Cost of Revenues

Total cost of revenues for the nine months ended September 30, 2011 was $229.4 million, compared to $220.9 million for the nine months ended September 30, 2010, which represented a 3.8% increase in total cost of revenues. This increase is attributable mainly to our Electricity Segment. As a percentage of total revenues, our total cost of revenues for the nine months ended September 30, 2011 was 73.2%, compared to 78.8% for the same period in 2010. The decrease in total cost of revenues as a percentage of total revenues is due to the 12.8% increase in Electricity Segment revenues, which outpaced the 4.8% increase in Electricity Segment cost of revenues, and the 7.8% increase in Product Segment revenues, which outpaced the 3.4% increase in Product Segment cost of revenues.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the nine months ended September 30, 2011 was $186.1 million, compared to $179.6 million for the nine months ended September 30, 2010, which represented a 3.6% increase in total cost of revenues for such segment. We incurred slightly higher costs

 

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associated with operating and maintaining the North Brawley power plant in the nine months ended September 30, 2011 ($32.1 million), compared to the nine months ended September 30, 2010 ($31.5 million). The overall cost per MWh in the nine months ended September 30, 2011 decreased compared to the nine months ended September 30, 2010, as a result of lower maintenance costs, which were offset by: (i) the higher costs in the North Brawley power plant, as described above; and (ii) increased depreciation costs in the Mammoth complex, resulting from the program to repower the complex by replacing part of the old units with new equipment. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the nine months ended September 30, 2011 was 75.6%, compared to 82.3% for the nine months ended September 30, 2010.

Product Segment

Total cost of revenues attributable to our Product Segment for the nine months ended September 30, 2011 was $43.3 million, compared to $41.3 million for the nine months ended September 30, 2010, which represented a 4.7% 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 nine months ended September 30, 2011 was 64.6%, compared to 66.5% for the nine months ended September 30, 2010.

Research and Development Expenses

Research and development expenses for the nine months ended September 30, 2011 were $7.1 million, compared to $8.1 million for the nine months ended September 30, 2010, which represented a 12.4% decrease. This decrease is primarily attributable to the costs related to an experimental REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminals, including developing and building a unit at a customer’s premises in Spain, as the costs related to the experimental REG plant were incurred through the second quarter of 2010. Our research and development activities during the nine months ended September 30, 2011 also included: (i) continued development of EGS; and (ii) development of a solar thermal system for the production of electricity.

Selling and Marketing Expenses

Selling and marketing expenses for the nine months ended September 30, 2011 were $9.3 million, compared to $9.2 million for the nine months ended September 30, 2010, which represented a 1.1% increase. Selling and marketing expenses for the nine months ended September 30, 2011 constituted 3.0% of total revenues, compared to 3.3% for the nine months ended September 30, 2010.

General and Administrative Expenses

General and administrative expenses for the nine months ended September 30, 2011 were $20.8 million, compared to $19.8 million for the nine months ended September 30, 2010, which represented a 4.8% increase. General and administrative expenses for the nine months ended September 30, 2011 constituted 6.6% of total revenues, compared to 7.1% for the nine months ended September 30, 2010.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the nine months ended September 30, 2010 was $3.1 million, which represented the write-off of exploration costs related to the Gabbs Valley project, which we determined in the second quarter of 2010 would not support commercial operations. We did not have a write-off of unsuccessful exploration activities in the nine months ended September 30, 2011.

 

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Operating Income

Operating income for the nine months ended September 30, 2011 was $46.7 million, compared to $19.3 million for the nine months ended September 30, 2010. Such increase of $27.4 million in operating income was principally attributable to an increase in our gross margin due to the increase in revenues, as described above, and to a decrease in the write-off of unsuccessful exploration activities. Operating income attributable to our Electricity Segment for the nine months ended September 30, 2011 was $34.9 million, compared to $11.4 million for the nine months ended September 30, 2010. Operating income attributable to our Product Segment for the nine months ended September 30, 2011 was $11.8 million, compared to $7.9 million for the nine months ended September 30, 2010.

Interest Expense, Net

Interest expense, net, for the nine months ended September 30, 2011 was $54.4 million, compared to $30.1 million for the nine months ended September 30, 2010, which represented an 80.3% increase. The $24.3 million increase is primarily due to: (i) a $16.4 million loss on interest rate lock transactions in the nine months ended September 30, 2011, relating to the DOE loan guarantee transaction that was consummated in September 2011, and which are not accounted for as hedge transactions; and (ii) the issuance of Senior Unsecured Bonds in August 2010 and February 2011. The increase was partially offset by: (i) an increase of $2.2 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.

Foreign Currency Translation and Transaction Gains (Losses)

Foreign currency translation and transaction losses for the nine months ended September 30, 2011 were $1.5 million, compared to gains of $0.5 million for the nine months ended September 30, 2010. The $2.0 million decrease is primarily due to losses on forward foreign exchange transactions for the nine months ended September 30, 2011, which were not accounted for as hedge transactions, compared to gains in the nine months ended September 30, 2010.

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 nine months ended September 30, 2011 was $7.6 million, compared to $6.4 million for the nine months ended September 30, 2010. 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.

Gain on acquisition of controlling interest

Gain on acquisition of controlling interest for the nine months ended September 30, 2010 was $36.9 million. This gain relates to the acquisition of the remaining 50% interest in Mammoth Pacific as discussed above. The acquisition date fair value of the previous 50% equity interest was $64.9 million. In the nine months ended September 30, 2010, we recognized a pre-tax gain of $36.9 million ($22.4 million after tax), which is equal to the difference between the acquisition date fair value of the initial investment in Mammoth Pacific and the acquisition date carrying value of such investment.

Income Taxes

Income tax benefit for the nine months ended September 30, 2011 was $0.7 million, compared to income tax expense of $6.0 million for the nine months ended September 30, 2010. The effective tax rate for the nine months ended September 30, 2011 was 711.8%, compared to 18.0% for the nine months ended September 30, 2010. The change in the effective tax rate resulted primarily from a higher impact of PTCs on the effective tax rate due to a lower projected pre-tax annual income.

 

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Income from Continuing Operations

Income from continuing operations for the nine months ended September 30, 2011 was $0.3 million, compared to $28.3 million for the nine months ended September 30, 2010. Such decrease of $28.0 million was principally attributable to: (i) a gain on acquisition of controlling interest of $36.9 million in the nine months ended September 30, 2010; and (ii) a $24.3 million increase in interest expense. The decrease was partially offset by: (i) a $27.4 million increase in operating income; and (ii) a $6.7 million decrease in income tax expense.

Discontinued Operations

In January 2010, a former shareholder of GDL exercised a call option to purchase from us our shares in GDL for approximately $2.8 million. In addition, we received $17.7 million to repay the loan our subsidiary provided to GDL to build the plant. We did not exercise our right of first refusal and, therefore, we transferred our shares in GDL to the former shareholder. As a result, we recorded an after-tax gain of $4.3 million in the nine months ended September 30, 2010. The operations of GDL have been included in discontinued operations for all periods prior to the sale of GDL in January 2010.

Net Income

Net income for the nine months ended September 30, 2011 was $0.3 million, compared to $32.7 million for the nine months ended September 30, 2010. The decrease in net income was principally attributable to the decrease in income from continuing operations in the amount of $28.0 million, as discussed above, and the decrease in income from discontinued operations of $4.3 million.

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) and OrCal Geothermal Inc. (OrCal) of their respective Senior Secured Notes, project financing (including the Puna lease and the OPC Transaction described below), and a cash grant we received under the ARRA relating to the North Brawley power plant. We have utilized this cash to fund our acquisitions, develop and construct power generation plants, and meet our other cash and liquidity needs.

As of September 30, 2011, we have access to the following sources of funds: (i) $80.3 million in cash, cash equivalents and marketable securities; and (ii) $102.3 million of unused corporate borrowing capacity under existing committed lines of credit with different commercial banks.

Our estimated capital needs for the remainder of 2011 include approximately $108.0 million for capital expenditures on new projects in development or construction, exploration activity, operating projects, and machinery and equipment, as well as $24.2 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) additional borrowing capacity under future lines of credit with commercial banks that are under negotiations; (iv) future project financing and refinancing; and (v) 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. We intend to file a shelf registration statement on Form S-3 that, pending effectiveness 95 declared by the SEC, will provide us with the ability to raise additional capital of up to $1.5 billion through the issuance of securities, subject to market conditions.

 

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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 1/1A power plants, and the financing of the acquisition cost of the Steamboat 2/3 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 limitations on additional indebtedness and payment of dividends. As of September 30, 2011, OFC was in compliance with the covenants under the OFC Senior Secured Notes. As of September 30, 2011, there were $130.8 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 limitations on additional indebtedness and payment of dividends. As of September 30, 2011, OrCal was in compliance with the covenants under the OrCal Senior Secured Notes. As of September 30, 2011, there were $93.2 million of OrCal Senior Secured Notes outstanding.

OFC 2 Senior Secured Notes — Limited Recourse

On September 23, 2011, OFC 2, one of our subsidiaries, and its wholly owned subsidiaries (collectively, the Issuers) entered into a note purchase agreement (the Note Purchase Agreement) with OFC 2 Noteholder Trust, as purchaser, John Hancock Life Insurance Company (U.S.A.), as administrative agent, and the United States Department of Energy (DOE), as guarantor, in connection with the offer and sale of up to $350 million aggregate principal amount of OFC 2’s Senior Secured Notes (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 will 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 (collectively, the Project) owned

 

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by the Issuers, as follows: Series A Notes, Series B Notes, Series C Notes, Series D Notes, and, if the Issuers so elect, Series E Notes and Series F Notes. The Phase I tranche, comprised of the Series A Notes and the Series B Notes, will be issued in an aggregate principal amount not to exceed $180 million, of which up to $155 million will be allocated to the Series A Notes, and up to $25 million will be allocated to the Series B Notes. 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. Proceeds of the Series A Notes will be used to finance a portion of the construction costs of Phase I of the McGinness Hills and the Tuscarora facilities. Proceeds of the Series B Notes, if issued, 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 a facility Phase II 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 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 DOE will guarantee payment of 80% of principal and interest on the 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.

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 payment of dividends.

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(ies) 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 limited.

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.

On October 31, 2011, OFC 2 and the Issuers completed the sale of $151.7 million aggregate principal amount of 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 will be used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora facilities. The Issuers will pay 4.687% interest on the Series A Notes quarterly in arrears on the last day of each of March, June, September and December in each year, commencing on December 31, 2011.

 

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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 geothermal power plant located in Kenya. The loan was provided by a group of European Development Finance Institutions 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%. There are various restrictive covenants under the loan, which include limitations on OrPower 4’s ability to make distributions to its shareholders. As of September 30, 2011, OrPower 4 was in compliance with the covenants under the loan. As of September 30, 2011, $82.9 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. The loan will mature on June 15, 2016, and is payable in 28 quarterly installments, that commenced on September 15, 2009. The 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. There are various restrictive covenants under the loan, which include limitations on Ortitlan’s ability to make distributions to its shareholders. As of September 30, 2011, Ortitlan was in compliance with the covenants under the loan. As of September 30, 2011, $37.3 million of the Amatitlan loan was outstanding.

Senior Loan from International Finance Corporation (IFC) — (The Zunil Power Plant) — Non-Recourse

Orzunil I de Electricidad, Limitada (Orzunil), a wholly owned subsidiary in Guatemala, had a senior loan agreement with IFC. The loan was fully repaid in the third quarter of 2011.

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, we signed a commitment letter issued by the Overseas Private Investment Corporation (OPIC) to provide project financing of up to $310 million to refinance and expand our 48 MW Olkaria III geothermal complex located in Naivasha, Kenya. Under the agreed term sheet attached to the commitment letter, the loan will be comprised of a refinancing tranche of up to $85 million to prepay the existing loan with DEG and fund transaction costs, a construction loan tranche of up to $165 million to finance the construction of an additional 36 MW expansion currently underway, and a $60 million stand-by facility to finance an optional additional 16 MW capacity expansion, 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 16 MW expansion.

Full-Recourse Third Party Debt

In December 2008, our wholly owned subsidiary, Ormat Nevada, entered into an amendment of its credit agreement with Union Bank, N.A. (Union Bank), extending the final maturity of the facility and increasing its total amount to $37.5 million. In August 2011 such line of credit was increased to $39.0 million. Under the credit agreement, Ormat Nevada can request extensions of credit in the form of loans and/or the issuance of one or

 

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more 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 by any of its (or any of its subsidiaries’) assets.

Loans and draws under the letters of credit (if any) under the credit agreement will bear interest at a floating rate based on the Eurodollar plus a margin. There are various restrictive covenants under the credit agreement, which include maintaining certain levels of tangible net worth, leverage ratio, minimum coverage ratio, and a distribution coverage ratio. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and Ormat Nevada is subject to a negative pledge in favor of Union Bank.

As of September 30, 2011, letters of credit in the aggregate amount of $38.5 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, 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 million. The credit agreements mature between October 2011 and September 2013. 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. Credit agreements in the amount of $115.0 million are due to expire in the fourth quarter of 2011. We are currently negotiating the extension of these credit agreements for up to three years. We anticipate that these extensions will include an increase in the annual average interest rates.

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 interest of 6.5%. As of September 30, 2011, $14.2 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 interest at 6-month LIBOR plus 5.0%. As of September 30, 2011, $20.0 million was outstanding under this loan.

We have a $20.0 million term loan with a group of institutional investors, which matures on November 16, 2016, is payable in 10 semi-annual installments commencing May 16, 2012, and bears interest of 5.75%. As of September 30, 2011, $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 interest at 6-month LIBOR plus 3.25%. As of September 30, 2011, $35.0 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%, 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%. 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.

 

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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. Certain 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 a debt service coverage ratio, a debt to equity ratio, and a debt to adjusted EBITDA ratio. There are also certain restrictions on distribution of dividends. The failure to perform or comply with 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.

We are currently in compliance with our covenants with respect to the credit agreements, the loan agreements and the trust instrument, and believe that compliance with 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

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

Three commercial banks have issued such performance letters of credit in favor of our customers from time to time. As of September 30, 2011, such banks have issued letters of credit totaling $39.8 million. These letters of credit were not issued under the credit agreements discussed under “Full-Recourse Third Party Debt” above.

In addition, we and certain of our subsidiaries may request letters of credit under the credit agreements with Union Bank and five other commercial banks as described under “Full-Recourse Third Party Debt” above. As of September 30, 2011, letters of credit in the aggregate amount of $97.4 million remained issued and outstanding under the Union Bank credit agreement and our other agreements with commercial banks.

Puna Project 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 of Hawaii. 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 deferred lease payments by such financing parties to PGV in the aggregate amount of $83.0 million.

OPC Transaction

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

 

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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.

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 continues to consolidate OPC.

On October 30, 2009, Ormat Nevada acquired from Lehman-OPC all of the Class B membership units of OPC held by Lehman-OPC pursuant to a right of first offer for a purchase price of $18.5 million.

On February 3, 2011, Ormat Nevada sold to JPM Capital Corporation (JPM) all of the Class B membership units of OPC that it had acquired on October 30, 2009 for a sale price of $24.9 million in cash.

Liquidity Impact of Uncertain Tax Positions

As discussed in Note 17 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 $4.2 million as of September 30, 2011. 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.

 

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Dividend

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

 

Date Declared

   Dividend Amount
per Share
    

Record Date

  

Payment Date

November 4, 2009

   $ 0.06       November 18, 2009    December 1, 2009

February 23, 2010

   $ 0.12       March 16, 2010    March 25, 2010

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

Historical Cash Flows

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

 

     Nine Months Ended
September 30,
 
     2011     2010  
     (In thousands)  

Net cash provided by operating activities

   $ 98,514     $ 79,644  

Net cash used in investing activities

     (238,186     (153,020

Net cash provided by financing activities

     115,934       76,309  

Net change in cash and cash equivalents

     (23,738     2,933  

For the Nine Months Ended September 30, 2011

Net cash provided by operating activities for the nine months ended September 30, 2011 was $98.5 million, compared to $79.6 million for the nine months ended September 30, 2010. The net increase of $18.9 million resulted primarily from: (i) an increase of $6.8 million in depreciation and amortization mainly due to the placement in service of our Jersey Valley power plant in January 2011, and higher depreciation in the Mammoth complex, resulting from the plan to repower the complex by replacing part of the old units with new Ormat-manufactured equipment, as described above; (ii) a gain on acquisition of controlling interest of $36.9 million in the nine months ended September 30, 2010; (iii) a gain on sale of GDL of $6.3 million in the nine months ended September 30, 2010; (iv) a decrease in receivables of $2.6 million in the nine months ended September 30, 2011, compared to an increase of $5.7 million in the nine months ended September 30, 2010, as a result of timing of collections from our customers; and (v) an increase in billing in excess of costs and estimated earnings on uncompleted contracts, net of $35.1 million relating to our Product Segment in the nine months ended September 30, 2011, compared to $15.3 million in the nine months ended September 30, 2010, as a result of timing in billing of our customers. Such decrease was partially offset by: (i) a decrease in net income to $0.3 million in the nine months ended September 30, 2011, from $32.7 million in the nine months ended September 30, 2010, mainly as a result of a gain on acquisition of controlling interest of $36.9 million in the nine months ended September 30, 2010 and the increase in interest expense, net offset by the increase in operating income, and the decrease in income tax expense as described above and (ii) a decrease in accounts payable and accrued expenses of $9.6 million in the nine months ended September 30, 2011, compared to an increase of $5.6 million in the nine months ended September 30, 2010, as a result of timing of payments to our vendors.

Net cash used in investing activities for the nine months ended September 30, 2011 was $238.2 million, compared to $153.0 million for the nine months ended September 30, 2010. The principal factors that affected our net cash used in investing activities during the nine months ended September 30, 2011 were: (i) capital

 

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expenditures of $180.8 million, primarily for our facilities under construction; (ii) net increase of $36.9 million in restricted cash, cash equivalents and marketable securities; and (iii) net increase of $20.3 million in marketable securities. The principal factors that affected our net cash used in investing activities during the nine months ended September 30, 2010 were: (i) capital expenditures of $194.9 million, primarily for our power facilities under construction; (ii) net payment of $64.5 million for acquisition of controlling interest in Mammoth Pacific ($72.5 million purchase price less $8.0 million available cash in such subsidiary at the acquisition date); and (iii) net increase of $23.4 million in restricted cash, cash equivalents and marketable securities, offset by: (i) $108.3 million received in September 2010 for Specified Energy Property in Lieu of Tax Credits relating to our North Brawley geothermal power plant under Section 1603 of the ARRA; and (ii) $19.6 million received from the sale of GDL.

Net cash provided by financing activities for the nine months ended September 30, 2011 was $115.9 million, compared to $76.3 million for the nine months ended September 30, 2010. The principal factors that affected the net cash provided by financing activities during the nine months ended September 30, 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; and (iii) a net increase of $31.9 million against our revolving lines of credit with commercial banks, offset by: (i) the repayment of long-term debt in the amount of $26.0 million; (ii) cash paid to non-controlling interest in the amount of $10.8 million; and (iii) the payment of a dividend to our shareholders in the amount of $5.9 million. The principal factor that affected our net cash provided by financing activities during the nine months ended September 30, 2010 was the issuance of an aggregate amount of approximately $142.0 million senior unsecured bonds on August 3, 2010, offset by: (i) the repayment of long-term debt in the amount of $37.7 million; (ii) a net decrease of $17.5 million against our revolving lines of credit with commercial banks; and (iii) the payment of a dividend to our shareholders in the amount of $10.0 million.

Adjusted EBITDA

Adjusted EBITDA for the three months ended September 30, 2011 was $46.7 million, compared to $78.8 million in the three months ended September 30, 2010. Adjusted EBITDA for the nine months ended September 30, 2011 was $121.6 million, compared to $134.9 million for the nine months ended September 30, 2010. Adjusted EBITDA includes consolidated EBITDA and our share in the interest, taxes, depreciation and amortization related to our unconsolidated 50% interest in the Mammoth complex in California in the three and nine months ended September 30, 2010.

We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate adjusted EBITDA to include depreciation and amortization, interest and taxes attributable to our equity investments in the Mammoth complex. EBITDA and adjusted EBITDA are not measurements of financial performance or liquidity under GAAP and should not be consider