UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
|
|
|
þ
|
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the quarterly period ended
March 31, 2010
|
or
|
o
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|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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|
|
For the transition period
from to
|
Commission file number:
001-32347
ORMAT TECHNOLOGIES,
INC.
(Exact name of registrant as
specified in its charter)
|
|
|
DELAWARE
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|
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)
Registrants 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
o
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
o
No
o
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
o
|
Non-accelerated
filer
o
|
Smaller
reporting
company
o
|
(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).
o
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 $0.001 per share.
ORMAT
TECHNOLOGIES, INC
FORM 10-Q
FOR THE
QUARTER ENDED MARCH 31, 2010
2
Certain
Definitions
Unless the context otherwise requires, all references in this
quarterly report to Ormat, the Company,
we, us, our company,
Ormat Technologies or our refer to Ormat
Technologies, Inc. and its consolidated subsidiaries.
3
PART I
UNAUDITED FINANCIAL INFORMATION
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|
ITEM 1.
|
CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
|
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
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March 31,
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December 31,
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2010
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2009
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|
(In thousands)
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|
|
ASSETS
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Current assets:
|
|
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|
|
|
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Cash and cash equivalents
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$
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43,111
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$
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46,307
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|
Restricted cash, cash equivalents and marketable securities (all
related to VIEs)
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52,266
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|
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40,955
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Receivables:
|
|
|
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Trade
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49,904
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|
|
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53,423
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Related entity
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|
647
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|
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|
441
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Other
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9,629
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|
|
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7,884
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Due from Parent
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|
709
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|
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|
422
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|
Inventories
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20,014
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15,486
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|
Costs and estimated earnings in excess of billings on
uncompleted contracts
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3,112
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14,640
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Deferred income taxes
|
|
|
3,860
|
|
|
|
3,617
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|
Prepaid expenses and other
|
|
|
9,914
|
|
|
|
12,080
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|
|
|
|
|
|
|
|
|
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Total current assets
|
|
|
193,166
|
|
|
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195,255
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Long-term marketable securities
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1,304
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|
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|
652
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Restricted cash, cash equivalents and marketable securities (all
related to VIEs)
|
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|
1,764
|
|
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2,512
|
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Unconsolidated investments ($27,294 related to VIEs at
March 31, 2010)
|
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|
29,104
|
|
|
|
35,188
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|
Deposits and other
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19,259
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18,653
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Deferred charges
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30,466
|
|
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22,532
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Property, plant and equipment, net ($826,520 related to VIEs at
March 31, 2010)
|
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1,320,754
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998,693
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Construction-in-process
($41,478 related to VIEs at March 31, 2010)
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239,505
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|
518,595
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Deferred financing and lease costs, net
|
|
|
20,175
|
|
|
|
20,940
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Intangible assets, net
|
|
|
41,203
|
|
|
|
41,981
|
|
|
|
|
|
|
|
|
|
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Total assets
|
|
$
|
1,896,700
|
|
|
$
|
1,855,001
|
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|
|
|
|
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LIABILITIES AND EQUITY
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Current liabilities:
|
|
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Accounts payable and accrued expenses
|
|
$
|
87,511
|
|
|
$
|
73,993
|
|
Billings in excess of costs and estimated earnings on
uncompleted contracts
|
|
|
7,681
|
|
|
|
3,351
|
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Current portion of long-term debt:
|
|
|
|
|
|
|
|
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Limited and non-recourse (all related to VIEs at March 31,
2010)
|
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|
16,055
|
|
|
|
19,191
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Full recourse
|
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12,916
|
|
|
|
12,823
|
|
Senior secured notes (non-recourse) (all related to VIEs at
March 31, 2010)
|
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|
20,227
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|
|
|
20,227
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|
Due to Parent, including current portion of notes payable to
Parent
|
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10,198
|
|
|
|
10,018
|
|
|
|
|
|
|
|
|
|
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Total current liabilities
|
|
|
154,588
|
|
|
|
139,603
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Long-term debt, net of current portion:
|
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|
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Limited and non-recourse (all related to VIEs at March 31,
2010)
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128,199
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|
129,152
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Full recourse
|
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|
75,695
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|
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|
77,177
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|
Revolving credit lines with banks (full recourse)
|
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|
158,500
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|
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134,000
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|
Senior secured notes (non-recourse) (all related to VIEs at
March 31, 2010)
|
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|
231,872
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|
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|
231,872
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Liability associated with sale of equity interests
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72,454
|
|
|
|
73,246
|
|
Deferred lease income
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|
72,590
|
|
|
|
72,867
|
|
Deferred income taxes
|
|
|
52,130
|
|
|
|
44,530
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Liability for unrecognized tax benefits
|
|
|
5,184
|
|
|
|
4,931
|
|
Liabilities for severance pay
|
|
|
19,477
|
|
|
|
18,332
|
|
Asset retirement obligation
|
|
|
14,350
|
|
|
|
14,238
|
|
Other long-term liabilities
|
|
|
2,297
|
|
|
|
3,358
|
|
|
|
|
|
|
|
|
|
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Total liabilities
|
|
|
987,336
|
|
|
|
943,306
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|
|
|
|
|
|
|
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Commitments and contingencies
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|
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|
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Equity:
|
|
|
|
|
|
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The Companys stockholders equity:
|
|
|
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Common stock, par value $0.001 per share;
200,000,000 shares authorized; 45,430,886 and
45,353,120 shares issued and outstanding, respectively
|
|
|
46
|
|
|
|
46
|
|
Additional paid-in capital
|
|
|
710,770
|
|
|
|
709,354
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|
Retained earnings
|
|
|
193,333
|
|
|
|
196,950
|
|
Accumulated other comprehensive income
|
|
|
545
|
|
|
|
622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
904,694
|
|
|
|
906,972
|
|
Noncontrolling interest
|
|
|
4,670
|
|
|
|
4,723
|
|
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
909,364
|
|
|
|
911,695
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
1,896,700
|
|
|
$
|
1,855,001
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
4
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND
COMPREHENSIVE INCOME
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands, except per share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Electricity
|
|
$
|
66,105
|
|
|
$
|
62,060
|
|
Product
|
|
|
16,549
|
|
|
|
37,251
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
82,654
|
|
|
|
99,311
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues:
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
54,523
|
|
|
|
43,686
|
|
Product
|
|
|
12,437
|
|
|
|
24,243
|
|
|
|
|
|
|
|
|
|
|
Total cost of revenues
|
|
|
66,960
|
|
|
|
67,929
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
|
15,694
|
|
|
|
31,382
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Research and development expenses
|
|
|
3,267
|
|
|
|
801
|
|
Selling and marketing expenses
|
|
|
3,202
|
|
|
|
4,301
|
|
General and administrative expenses
|
|
|
7,020
|
|
|
|
7,535
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
2,205
|
|
|
|
18,745
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
197
|
|
|
|
152
|
|
Interest expense, net
|
|
|
(9,714
|
)
|
|
|
(3,290
|
)
|
Foreign currency translation and transaction gains (losses)
|
|
|
434
|
|
|
|
(2,393
|
)
|
Income attributable to sale of tax benefits
|
|
|
2,139
|
|
|
|
4,168
|
|
Other non-operating loss, net
|
|
|
(359
|
)
|
|
|
(150
|
)
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes and
equity in income of investees
|
|
|
(5,098
|
)
|
|
|
17,232
|
|
Income tax benefit (provision)
|
|
|
2,557
|
|
|
|
(3,429
|
)
|
Equity in income of investees, net
|
|
|
546
|
|
|
|
550
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
(1,995
|
)
|
|
|
14,353
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of related tax of $6
and $60, respectively
|
|
|
14
|
|
|
|
153
|
|
Gain on sale of a subsidiary in New Zealand, net of related tax
of $2,570
|
|
|
3,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
1,785
|
|
|
|
14,506
|
|
Net loss attributable to noncontrolling interest
|
|
|
53
|
|
|
|
79
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to the Companys stockholders
|
|
$
|
1,838
|
|
|
$
|
14,585
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,785
|
|
|
$
|
14,506
|
|
Other comprehensive income (loss), net of related taxes:
|
|
|
|
|
|
|
|
|
Currency translation adjustment
|
|
|
43
|
|
|
|
(52
|
)
|
Amortization of unrealized gains in respect of derivative
instruments designated for cash flow hedge
|
|
|
(58
|
)
|
|
|
(65
|
)
|
Change in unrealized gains or losses on marketable securities
available-for-sale
|
|
|
(62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
1,708
|
|
|
|
14,389
|
|
Comprehensive loss attributable to noncontrolling interest
|
|
|
53
|
|
|
|
79
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income attributable to the Companys
stockholders
|
|
$
|
1,761
|
|
|
$
|
14,468
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share attributable to the Companys
stockholders basic and diluted:
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$
|
(0.04
|
)
|
|
$
|
0.32
|
|
Income from discontinued operations
|
|
|
0.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
0.04
|
|
|
$
|
0.32
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares used in computation of
earnings (loss) per share attributable to the Companys
stockholders:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
45,431
|
|
|
|
45,353
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
45,457
|
|
|
|
45,405
|
|
|
|
|
|
|
|
|
|
|
Dividend per share declared
|
|
$
|
0.12
|
|
|
$
|
0.07
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
5
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Paid-in
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
|
|
|
Noncontrolling
|
|
|
Total
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Earnings
|
|
|
Income
|
|
|
Total
|
|
|
Interest
|
|
|
Equity
|
|
|
|
(In thousands, except per share data)
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
45,353
|
|
|
$
|
45
|
|
|
$
|
701,273
|
|
|
$
|
138,241
|
|
|
$
|
645
|
|
|
$
|
840,204
|
|
|
$
|
7,031
|
|
|
$
|
847,235
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
1,262
|
|
|
|
|
|
|
|
|
|
|
|
1,262
|
|
|
|
|
|
|
|
1,262
|
|
Cash dividend declared, $0.07 per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,175
|
)
|
|
|
|
|
|
|
(3,175
|
)
|
|
|
|
|
|
|
(3,175
|
)
|
Exercise of options by employees
|
|
|
1
|
|
|
|
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
|
|
|
|
|
|
32
|
|
Net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,585
|
|
|
|
|
|
|
|
14,585
|
|
|
|
(79
|
)
|
|
|
14,506
|
|
Other comprehensive income (loss), net of related taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currency translation adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(52
|
)
|
|
|
(52
|
)
|
|
|
|
|
|
|
(52
|
)
|
Amortization of unrealized gains in respect of derivative
instruments designated for cash flow hedge (net of related tax
of $40)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(65
|
)
|
|
|
(65
|
)
|
|
|
|
|
|
|
(65
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at March 31, 2009
|
|
|
45,354
|
|
|
$
|
45
|
|
|
$
|
702,567
|
|
|
$
|
149,651
|
|
|
$
|
528
|
|
|
$
|
852,791
|
|
|
$
|
6,952
|
|
|
$
|
859,743
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
45,431
|
|
|
|
46
|
|
|
|
709,354
|
|
|
|
196,950
|
|
|
|
622
|
|
|
|
906,972
|
|
|
|
4,723
|
|
|
|
911,695
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
1,416
|
|
|
|
|
|
|
|
|
|
|
|
1,416
|
|
|
|
|
|
|
|
1,416
|
|
Cash dividend declared, $0.12 per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,455
|
)
|
|
|
|
|
|
|
(5,455
|
)
|
|
|
|
|
|
|
(5,455
|
)
|
Net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,838
|
|
|
|
|
|
|
|
1,838
|
|
|
|
(53
|
)
|
|
|
1,785
|
|
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 $36)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(58
|
)
|
|
|
(58
|
)
|
|
|
|
|
|
|
(58
|
)
|
Change in unrealized gains or losses on marketable securities
available-for-sale
(net of related tax of $34)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(62
|
)
|
|
|
(62
|
)
|
|
|
|
|
|
|
(62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at March 31, 2010
|
|
|
45,431
|
|
|
$
|
46
|
|
|
$
|
710,770
|
|
|
$
|
193,333
|
|
|
$
|
545
|
|
|
$
|
904,694
|
|
|
$
|
4,670
|
|
|
$
|
909,364
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
6
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,785
|
|
|
$
|
14,506
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
20,449
|
|
|
|
16,132
|
|
Accretion of asset retirement obligation
|
|
|
276
|
|
|
|
258
|
|
Stock-based compensation
|
|
|
1,416
|
|
|
|
1,262
|
|
Amortization of deferred lease income
|
|
|
(671
|
)
|
|
|
(671
|
)
|
Income attributable to sale of tax benefits, net of interest
expense
|
|
|
(792
|
)
|
|
|
(2,238
|
)
|
Equity in income of investees
|
|
|
(546
|
)
|
|
|
(550
|
)
|
Impairment of auction rate securities
|
|
|
|
|
|
|
280
|
|
Return on investment in unconsolidated investments
|
|
|
3,734
|
|
|
|
|
|
Loss (gain) on severance pay fund asset
|
|
|
(420
|
)
|
|
|
1,219
|
|
Gain on sale of a subsidiary
|
|
|
(6,336
|
)
|
|
|
|
|
Deferred income tax provision (benefit)
|
|
|
(856
|
)
|
|
|
3,041
|
|
Liability for unrecognized tax benefits
|
|
|
253
|
|
|
|
232
|
|
Deferred lease revenues
|
|
|
394
|
|
|
|
582
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
1,155
|
|
|
|
(1,711
|
)
|
Costs and estimated earnings in excess of billings on
uncompleted contracts
|
|
|
11,528
|
|
|
|
(5,867
|
)
|
Inventories
|
|
|
(4,528
|
)
|
|
|
1,000
|
|
Prepaid expenses and other
|
|
|
2,166
|
|
|
|
1,918
|
|
Deposits and other
|
|
|
(183
|
)
|
|
|
(122
|
)
|
Accounts payable and accrued expenses
|
|
|
15,315
|
|
|
|
1,100
|
|
Due from/to related entities, net
|
|
|
(206
|
)
|
|
|
(208
|
)
|
Billings in excess of costs and estimated earnings on
uncompleted contracts
|
|
|
4,330
|
|
|
|
14,575
|
|
Liabilities for severance pay
|
|
|
1,145
|
|
|
|
(1,337
|
)
|
Other long-term liabilities
|
|
|
(1,061
|
)
|
|
|
|
|
Due from/to Parent
|
|
|
(107
|
)
|
|
|
(867
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
48,240
|
|
|
|
42,534
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Return of investment in unconsolidated investments
|
|
|
3,516
|
|
|
|
30
|
|
Net change in restricted cash, cash equivalents and marketable
securities
|
|
|
(11,315
|
)
|
|
|
(17,233
|
)
|
Cash received from sale of a subsidiary, net
|
|
|
19,594
|
|
|
|
|
|
Capital expenditures
|
|
|
(76,492
|
)
|
|
|
(73,795
|
)
|
Investment in unconsolidated company
|
|
|
(281
|
)
|
|
|
|
|
Increase in severance pay fund asset, net of payments made to
retired employees
|
|
|
(3
|
)
|
|
|
(227
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(64,981
|
)
|
|
|
(91,225
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Proceeds from long-term loans
|
|
|
|
|
|
|
90,000
|
|
Proceeds from exercise of options by employees
|
|
|
|
|
|
|
32
|
|
Proceeds from revolving credit lines with banks
|
|
|
47,200
|
|
|
|
285,000
|
|
Repayment of revolving credit lines with banks
|
|
|
(22,700
|
)
|
|
|
(305,000
|
)
|
Repayments of long-term debt
|
|
|
|
|
|
|
|
|
Parent
|
|
|
|
|
|
|
(7,000
|
)
|
Other
|
|
|
(5,478
|
)
|
|
|
(1,590
|
)
|
Deferred debt issuance costs
|
|
|
(22
|
)
|
|
|
(1,281
|
)
|
Cash dividends paid
|
|
|
(5,455
|
)
|
|
|
(3,175
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
13,545
|
|
|
|
56,986
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(3,196
|
)
|
|
|
8,318
|
|
Cash and cash equivalents at beginning of year
|
|
|
46,307
|
|
|
|
34,393
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
43,111
|
|
|
$
|
42,711
|
|
|
|
|
|
|
|
|
|
|
Supplemental non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
Decrease in accounts payable related to purchases of property,
plant and equipment
|
|
$
|
(1,649
|
)
|
|
$
|
(4,722
|
)
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
7
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 Companys consolidated financial position as of
March 31, 2010, and the consolidated results of operations
and comprehensive income and the consolidated cash flows for the
three-month periods ended March 31, 2010 and 2009.
The financial data and other information disclosed in the notes
to the condensed consolidated financial statements related to
these periods are unaudited. The results for the three-month
period ended March 31, 2010 are not necessarily indicative
of the results to be expected for the year ending
December 31, 2010.
These condensed consolidated financial statements should be read
in conjunction with the audited consolidated financial
statements and notes thereto included in the Companys
annual report on
Form 10-K
for the year ended December 31, 2009. The condensed
consolidated balance sheet data as of December 31, 2009 was
derived from the audited consolidated financial statements for
the year ended December 31, 2009, 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.
Certain comparative figures have been reclassified to conform to
the current period presentation (see Note 7).
Concentration
of credit risk
Financial instruments that potentially subject the Company to a
concentration of credit risk consist principally of temporary
cash investments, marketable securities and accounts receivable.
The Company places its temporary cash investments with high
credit quality financial institutions located in the United
States (U.S.) and in foreign countries. At
March 31, 2010 and December 31, 2009, the Company had
deposits totaling $31,834,000 and $24,561,000, respectively, in
seven U.S. financial institutions that were federally
insured up to $250,000 per account (after December 31,
2013, the deposits will be insured up to $100,000 per account).
At March 31, 2010 and December 31, 2009, the
Companys deposits in foreign countries amounted to
approximately $21,634,000 and $35,095,000, respectively.
At March 31, 2010 and December 31, 2009, accounts
receivable related to operations in foreign countries amounted
to approximately $27,655,000 and $30,761,000, respectively. At
March 31, 2010 and December 31, 2009, accounts
receivable from the Companys major customers that have
generated 10% or more of its revenues amounted to approximately
47% and 61% of the Companys accounts receivable,
respectively.
Southern California Edison Company (SCE) accounted
for 25.5% and 17.9% of the Companys total revenues for the
three months ended March 31, 2010 and 2009, respectively.
SCE is also the power purchaser and revenue source for the
Companys Mammoth complex, which is accounted for under the
equity method.
Sierra Pacific Power Company and Nevada Power Company
(subsidiaries of NV Energy, Inc.) accounted for 19.2% and 13.9%
of the Companys total revenues for the three months ended
March 31, 2010 and 2009, respectively.
8
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
Hawaii Electric Light Company accounted for 7.1% and 9.9% of the
Companys total revenues for the three months ended
March 31, 2010 and 2009, respectively.
Kenya Power and Lighting Co. Ltd. accounted for 10.7% and 8.3%
of the Companys total revenues for the three months ended
March 31, 2010 and 2009, respectively,
The Company performs ongoing credit evaluations of its
customers financial condition. The Company has
historically been able to collect on all of its receivable
balances, and accordingly, no provision for doubtful accounts
has been made.
|
|
NOTE 2
|
NEW
ACCOUNTING PRONOUNCEMENTS
|
New
accounting pronouncements effective in the three-month period
ended March 31, 2010
Accounting
for Transfers of Financial Assets
In June 2009, the Financial Accounting Standards Board
(FASB) issued an amendment to the accounting and
disclosure requirements for transfers of financial assets. This
amendment requires greater transparency and additional
disclosures for transfers of financial assets and the
entitys continuing involvement with them and changes the
requirements for derecognizing financial assets. In addition,
this amendment eliminates the concept of a qualifying
special-purpose entity (QSPE). The adoption by the
Company of this amendment on January 1, 2010 did not have
any effect on the Companys financial position, results of
operations, or liquidity.
Consolidation
Guidance for Variable Interest Entities
In June 2009, the FASB issued an amendment to the accounting and
disclosure requirements for the consolidation of variable
interest entities (VIEs). The elimination of the
concept of a QSPE removes the exception from applying the
consolidation guidance within this amendment. This amendment
requires a company to perform a qualitative analysis when
determining whether or not it must consolidate a VIE. The
amendment also requires a company to continuously reassess
whether it must consolidate a VIE. Additionally, the amendment
requires enhanced disclosures about a companys involvement
with VIEs and any significant change in risk exposure due to
that involvement, as well as how its involvement with VIEs
impacts the companys financial statements. Finally, a
company is required to disclose significant judgments and
assumptions used to determine whether or not to consolidate a
VIE. The Company adopted this amendment on January 1, 2010.
The impact of the adoption of this amendment on the
Companys condensed consolidated financial statements is
disclosed in Note 5.
Updated
Disclosure for Fair Value Measurements
In January 2010, the FASB updated the fair value measurements
disclosures. This update will require an entity to disclose
separately the amounts of significant transfers in and out of
Levels 1 and 2 fair value measurements and to describe the
reasons for the transfers. In addition, information about
purchases, sales, issuances and settlements are required to be
presented separately (i.e., present the activity on a gross
basis rather than net) in the reconciliation for fair value
measurements using significant unobservable inputs (Level 3
inputs). This update clarifies existing disclosure requirements
for the level of disaggregation used for classes of assets and
liabilities measured at fair value, and requires disclosures
about the valuation techniques and inputs used to measure fair
value for both recurring and nonrecurring fair value
measurements using Level 2 and Level 3 inputs. This
update became effective as of the first interim or annual
reporting period beginning after December 15, 2009
(January 1, 2010 for the Company), except for the gross
presentation of the Level 3 roll forward information, which
is required for annual reporting periods beginning after
December 15, 2010 (January 1, 2011 for the Company)
and for interim reporting periods within those years. The
adoption by the
9
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
Company of the new guidance on January 1, 2010 did not have
a material impact on the Companys consolidated financial
statements (see Note 6).
New
accounting pronouncements effective in future periods
Accounting
for Revenue Recognition
In October 2009, the FASB issued amendments to the accounting
and disclosures for revenue recognition. These amendments,
effective for fiscal years beginning on or after June 15,
2010 (January 1, 2011 for the Company) with early adoption
permitted, 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
Company is currently evaluating the potential impact, if any, of
the adoption of this amendment on its consolidated financial
statements.
Inventories consist of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Raw materials and purchased parts for assembly
|
|
$
|
11,378
|
|
|
$
|
7,322
|
|
Self-manufactured assembly parts and finished products
|
|
|
8,636
|
|
|
|
8,164
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
20,014
|
|
|
$
|
15,486
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 4
|
UNCONSOLIDATED
INVESTMENTS
|
Unconsolidated investments, mainly in power plants, consist of
the following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Mammoth
|
|
$
|
27,294
|
|
|
$
|
33,659
|
|
Sarulla
|
|
|
1,810
|
|
|
|
1,529
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
29,104
|
|
|
$
|
35,188
|
|
|
|
|
|
|
|
|
|
|
The
Mammoth Complex
The Company has a 50% interest in the Mammoth complex
(Mammoth), located near the city of Mammoth,
California. The purchase price was less than the underlying net
equity of Mammoth by approximately $9.3 million. As such,
the basis difference will be amortized over the remaining useful
life of the property, plant and equipment and the power purchase
agreements (PPAs), which range from 12 to
17 years. The Company operates and maintains the geothermal
power plants under an operating and maintenance
(O&M) agreement. The Companys 50%
ownership interest in Mammoth is accounted for under the equity
method of accounting as the Company has the ability to exercise
significant influence, but not control, over Mammoth.
10
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
The condensed financial position and results of operations of
Mammoth are summarized below:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
|
|
2010
|
|
2009
|
|
|
(Dollars in thousands)
|
|
Condensed balance sheets:
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
8,046
|
|
|
$
|
19,257
|
|
Non-current assets
|
|
|
63,168
|
|
|
|
64,728
|
|
Current liabilities
|
|
|
853
|
|
|
|
659
|
|
Non-current liabilities
|
|
|
3,258
|
|
|
|
3,196
|
|
Partners capital
|
|
|
67,103
|
|
|
|
80,130
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Condensed statements of operations:
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
5,065
|
|
|
$
|
4,858
|
|
Gross margin
|
|
|
1,533
|
|
|
|
1,618
|
|
Net income
|
|
|
1,466
|
|
|
|
1,538
|
|
Companys equity in income of Mammoth:
|
|
|
|
|
|
|
|
|
50% of Mammoth net income
|
|
$
|
733
|
|
|
$
|
769
|
|
Plus amortization of basis difference
|
|
|
148
|
|
|
|
148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
881
|
|
|
|
917
|
|
Less income taxes
|
|
|
(335
|
)
|
|
|
(348
|
)
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
546
|
|
|
$
|
569
|
|
|
|
|
|
|
|
|
|
|
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 340 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 Companys designed and supplied power
generation units of 110 MW to 120 MW. The consortium
is currently negotiating certain amendments to the energy sales
contract, including an adjustment of commercial terms, and
intends to proceed with the project after those amendments have
become effective. On April 26, 2010, the parties agreed to
change the price of the power sold under the energy sales
contract.
The Companys investment in the Sarulla project was not
significant for each of the periods presented in these condensed
consolidated financial statements.
|
|
NOTE 5
|
CONSOLIDATION
GUIDANCE FOR VARIABLE INTEREST ENTITIES
|
Effective January 1, 2010, the Company adopted new
accounting and disclosure guidance for variable interest
entities (VIEs). Among other accounting and
disclosure requirements, the new guidance requires the primary
beneficiary of a VIE to be identified as the party that both
(i) has the power to direct the activities of a VIE that
most significantly impact its economic performance; and
(ii) has an obligation to absorb losses or a
11
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
right to receive benefits that could potentially be significant
to the VIE. The adoption of this new accounting guidance did not
result in the Company consolidating any additional VIEs or
deconsolidating any VIEs.
The Company evaluated all transactions and relationships with
VIEs to determine whether the Company is the primary beneficiary
of the entities in accordance with the guidance. The
Companys overall methodology for evaluating transactions
and relationships under the VIE requirements includes the
following two steps: (i) determining whether the entity
meets the criteria to qualify as a VIE; and
(ii) determining whether the Company is the primary
beneficiary of the VIE.
In performing the first step, the significant factors and
judgments that the Company considers in making the determination
as to whether an entity is a VIE include:
|
|
|
|
|
The design of the entity, including the nature of its risks and
the purpose for which the entity was created, to determine the
variability that the entity was designed to create and
distribute to its interest holders;
|
|
|
|
The nature of the Companys involvement with the entity;
|
|
|
|
Whether control of the entity may be achieved through
arrangements that do not involve voting equity;
|
|
|
|
Whether there is sufficient equity investment at risk to finance
the activities of the entity; and
|
|
|
|
Whether parties other than the equity holders have the
obligation to absorb expected losses or the right to receive
residual returns.
|
If the Company identifies a VIE based on the above
considerations, it then performs the second step and evaluates
whether it is the primary beneficiary of the VIE by considering
the following significant factors and judgments:
|
|
|
|
|
Whether the Company has the power to direct the activities of
the VIE that most significantly impact the entitys
economic performance; and
|
|
|
|
Whether the Company has the obligation to absorb losses of the
entity that could potentially be significant to the VIE or the
right to receive benefits from the entity that could potentially
be significant to the VIE.
|
The Companys VIEs include certain of its wholly owned
subsidiaries that own one or more power plants with long-term
power purchase agreements (PPAs). In most cases, the
PPAs require the utility to purchase substantially all of the
plants electrical output over a significant portion of its
estimated useful life. Most of the VIEs have associated project
financing debt that is non-recourse to the general creditors of
the Company, is collateralized by substantially all of the
assets of the VIE and those of its wholly owned subsidiaries
(also VIEs) and is fully and unconditionally guaranteed by such
subsidiaries. The Company has concluded that such entities are
VIEs primarily because the entities do not have sufficient
equity at risk
and/or
subordinated financial support is provided through the long-term
PPAs. The Company has evaluated each of its VIEs to determine
the primary beneficiary by considering the party that has the
power to direct the most significant activities of the entity.
Such activities include, among others, construction of the power
plant, operations and maintenance, dispatch of electricity,
financing and strategy. The Company controls such activities at
each of its VIEs and, therefore, is considered the primary
beneficiary. The Company will perform an ongoing reassessment of
the VIEs to determine the primary beneficiary and may be
required to deconsolidate certain of its VIEs in the future. The
Company has aggregated its consolidated VIEs into the following
categories: (1) consolidated subsidiaries with project debt
and (2) consolidated subsidiaries with PPAs.
12
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
The tables below detail the assets and liabilities (excluding
intercompany balances which are eliminated in consolidation) for
the Companys VIEs, combined by VIE classification, that
were included in the Condensed Consolidated Balance Sheets as of
March 31, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010
|
|
|
|
Project Debt
|
|
|
PPAs
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
Restricted cash, cash equivalents and marketable securities
|
|
$
|
54,030
|
|
|
$
|
|
|
Other current assets
|
|
|
51,363
|
|
|
|
8,365
|
|
Unconsolidated investments
|
|
|
27,294
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
826,520
|
|
|
|
445,405
|
|
Construction-in-process
|
|
|
41,478
|
|
|
|
1,127
|
|
Other long-term assets
|
|
|
56,854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,057,539
|
|
|
$
|
454,897
|
|
|
|
|
|
|
|
|
|
|
Liability:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
19,852
|
|
|
$
|
4,439
|
|
Long-term debt
|
|
|
396,353
|
|
|
|
|
|
Other long-term liabilities
|
|
|
85,889
|
|
|
|
3,261
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
502,094
|
|
|
$
|
7,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
Project Debt
|
|
|
PPAs
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
Restricted cash, cash equivalents and marketable securities
|
|
$
|
43,467
|
|
|
$
|
|
|
Other current assets
|
|
|
58,037
|
|
|
|
1,459
|
|
Unconsolidated investments
|
|
|
33,659
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
866,024
|
|
|
|
89,822
|
|
Construction-in-process
|
|
|
12,151
|
|
|
|
239,799
|
|
Other long-term assets
|
|
|
58,282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,071,620
|
|
|
$
|
331,080
|
|
|
|
|
|
|
|
|
|
|
Liability:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
11,328
|
|
|
$
|
1,749
|
|
Long-term debt
|
|
|
400,442
|
|
|
|
|
|
Other long-term liabilities
|
|
|
87,181
|
|
|
|
3,198
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
498,951
|
|
|
$
|
4,947
|
|
|
|
|
|
|
|
|
|
|
|
|
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
13
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
measurements) and the lowest priority to unobservable inputs
(Level 3 measurements). The three levels of the fair value
hierarchy under the fair value measurement guidance are
described below:
Level 1 Unadjusted quoted prices in active
markets that are accessible at the measurement date for
identical assets or liabilities;
Level 2 Quoted prices in markets that are not
active, or inputs that are observable, either directly or
indirectly, for substantially the full term of the asset or
liability;
Level 3 Prices or valuation techniques that
require inputs that are both significant to the fair value
measurement and unobservable (supported by little or no market
activity).
The following table sets forth certain fair value information at
March 31, 2010 and December 31, 2009 for financial
assets and liabilities measured at fair value by level within
the fair value hierarchy, as well as cost or amortized cost. As
required by the fair value measurement guidance, assets and
liabilities are classified in their entirety based on the lowest
level of inputs that is significant to the fair value
measurement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost or
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortized
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost at
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
Fair Value at March 31, 2010
|
|
|
|
2010
|
|
|
Total
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
|
(Dollars in thousands)
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents (including restricted cash accounts)
|
|
$
|
7,469
|
|
|
$
|
7,469
|
|
|
$
|
7,469
|
|
|
$
|
|
|
|
$
|
|
|
Derivatives*
|
|
|
|
|
|
|
441
|
|
|
|
|
|
|
|
441
|
|
|
|
|
|
Non-current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illiquid auction rate securities including restricted cash
accounts) ($4.5 million par value), see below
|
|
|
4,110
|
|
|
|
3,068
|
|
|
|
|
|
|
|
|
|
|
|
3,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
11,579
|
|
|
$
|
10,978
|
|
|
$
|
7,469
|
|
|
$
|
441
|
|
|
$
|
3,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost or
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortized
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost at
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Fair Value at December 31, 2009
|
|
|
|
2009
|
|
|
Total
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
|
(Dollars in thousands)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents (including restricted cash accounts)
|
|
$
|
20,227
|
|
|
$
|
20,227
|
|
|
$
|
20,227
|
|
|
$
|
|
|
|
$
|
|
|
Derivatives*
|
|
|
|
|
|
|
91
|
|
|
|
|
|
|
|
91
|
|
|
|
|
|
Non-current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illiquid auction rate securities including restricted cash
accounts) ($4.5 million par value), see below
|
|
|
4,099
|
|
|
|
3,164
|
|
|
|
|
|
|
|
|
|
|
|
3,164
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives*
|
|
|
|
|
|
|
(32
|
)
|
|
|
|
|
|
|
(32
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
24,326
|
|
|
$
|
23,450
|
|
|
$
|
20,227
|
|
|
$
|
59
|
|
|
$
|
3,164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
|
|
|
*
|
|
Derivatives represent foreign currency forward and option
contracts which are valued primarily based on observable inputs
including forward and spot prices for currencies.
|
The Companys financial assets measured at fair value
(including restricted cash accounts) at March 31, 2010 and
December 31, 2009 include investments in auction rate
securities and money market funds (which are included in cash
equivalents). Those securities, except for the illiquid 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.
The Companys auction rate securities are valued using
Level 3 inputs. As of March 31, 2010 and
December 31, 2009, all of the Companys auction rate
securities are associated with failed auctions. Such securities
have par values totaling $4.5 million at March 31,
2010 and December 31, 2009, all of which have been in a
loss position since the fourth quarter of 2007. Historically,
the carrying value of auction rate securities approximated fair
value due to the frequent resetting of the interest rates. While
the Company continues to earn interest on these investments at
the contractual rates, the estimated market value of these
auction rate securities no longer approximates par value. Due to
the lack of observable market quotes on the Companys
illiquid auction rate securities, the Company utilizes valuation
models that rely 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 are subject to
uncertainties that are difficult to predict. Therefore, such
auction rate securities have been classified as Level 3 in
the fair value hierarchy.
The table below sets forth a summary of the changes in the fair
value of the Companys financial assets classified as
Level 3 (i.e., illiquid auction rate securities) for the
three months ended March 31, 2010 and 2009, respectively:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Balance at beginning of period
|
|
$
|
3,164
|
|
|
$
|
4,945
|
|
Sale of auction rate securities
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses):
|
|
|
|
|
|
|
|
|
Included in net income
|
|
|
|
|
|
|
(280
|
)
|
Included in other comprehensive income
|
|
|
(96
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
3,068
|
|
|
$
|
4,665
|
|
|
|
|
|
|
|
|
|
|
Effective April 1, 2009, the Company adopted the
recognition and presentation of the
other-than-temporary
impairments standard, which requires an entity to separate an
other-than-temporary
impairment of a debt security into two components when there are
credit-related losses associated with the impaired security for
which management does not have the intent to sell the security
and it is not more likely than not, that it will be required to
sell the security before recovery of its cost basis. For those
securities, the amount of the
other-than-temporary
impairment related to a credit loss is recognized in earnings
and reflected as a reduction in the cost basis of the security,
and the amount of the
other-than-temporary
impairment related to other factors is recorded in other
comprehensive loss with no change to the cost basis of the
security. For securities for which there is an intent to sell
before recovery of the cost basis, the full amount of the
other-than-temporary
15
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
impairment is recognized in earnings and reflected as a
reduction in the cost basis of the security. Upon adoption of
this standard, the Company reclassified $1.2 million (net
of taxes of $0.7 million) to other comprehensive income
with an offset to retained earnings related to the
other-than-temporary
impairment charges previously recognized in earnings. This
cumulative effect adjustment relates to auction rate securities
for which the Company does not have the intent to sell and will
not, more likely than not, be required to sell prior to recovery
of its cost basis.
The amount of credit losses represents the difference between
the present value of cash flows expected to be collected on
these securities and the amortized cost. The credit loss was
calculated as the difference between the current cash flows
discounted at present value to the expected cash flows at the
date of purchase. The analysis incorporates managements
best estimate of current key assumptions, including the default
rate of such securities and probability of passing auction.
The changes in
other-than-temporary
impairment losses in the three months ended March 31, 2010
were not material.
The funds invested in auction rate securities that have
experienced failed auctions will not be 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 has classified those securities with
failed auctions as long-term assets on the consolidated balance
sheets as of March 31, 2010 and December 31, 2009.
The Company continues to monitor the market for auction rate
securities and to consider the markets impact (if any) on
the fair market value of the Companys investments. If
current market conditions deteriorate further, the Company may
be required to record additional impairment charges in the rest
of 2010.
There were no transfers of assets or liabilities between
Level 1 and Level 2 during the three-month period
ended March 31, 2010.
The fair value of the Companys long-term debt approximates
its carrying amount, except for the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
Carrying Amount
|
|
|
March 31,
|
|
December 31,
|
|
March 31,
|
|
December 31,
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
(Dollars in millions)
|
|
(Dollars in millions)
|
|
Orzunil Senior Loans
|
|
$
|
4.3
|
|
|
$
|
5.3
|
|
|
$
|
4.2
|
|
|
$
|
5.2
|
|
Olkaria III Loan
|
|
|
98.0
|
|
|
|
96.6
|
|
|
|
99.5
|
|
|
|
99.5
|
|
Amatitlan Loan
|
|
|
40.6
|
|
|
|
41.1
|
|
|
|
40.6
|
|
|
|
41.1
|
|
Senior Secured Notes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ormat Funding Corp.(OFC)
|
|
|
132.0
|
|
|
|
132.0
|
|
|
|
146.3
|
|
|
|
146.3
|
|
OrCal Geothermal Inc.(OrCal)
|
|
|
105.5
|
|
|
|
103.7
|
|
|
|
105.8
|
|
|
|
105.8
|
|
Loan from institutional investors
|
|
|
18.6
|
|
|
|
20.0
|
|
|
|
18.6
|
|
|
|
20.0
|
|
Parent Loan
|
|
|
9.6
|
|
|
|
9.7
|
|
|
|
9.6
|
|
|
|
9.6
|
|
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.
16
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
|
|
NOTE 7
|
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 GDLs obligations to the
Company. As a result, the Company s recorded a pre-tax gain of
approximately $6.3 million in the three months ended
March 31, 2010 ($3.8 million after-tax).
The net assets of GDL on January 1, 2010 were as follows:
|
|
|
|
|
|
|
(Dollars in
|
|
|
|
thousands)
|
|
|
Cash and cash equivalents
|
|
$
|
871
|
|
Accounts receivables
|
|
|
434
|
|
Prepaid expenses and other
|
|
|
184
|
|
Property, plant and equipment
|
|
|
16,293
|
|
Accounts payables and accrued liabilities
|
|
|
(164
|
)
|
Other comprehensive income translation adjustments
|
|
|
(156
|
)
|
|
|
|
|
|
Net assets
|
|
$
|
17,462
|
|
|
|
|
|
|
The operations and gain on sale of GDL have been included in
discontinued operations on the condensed consolidated statements
of operations and comprehensive income for all periods prior to
the sale of GDL in January 2010. Electricity revenues related to
GDL were $64,000 and $578,000 during the three months ended
March 31, 2010 and 2009, respectively. Basic and diluted
earnings per share related to the $3.8 million after-tax
gain on sale of GDL was $0.08. There was no impact on basic and
diluted earnings per share related to income from discontinued
operations during the three months ended March 31, 2010 and
2009.
|
|
NOTE 8
|
ELECTRICITY
REVENUES AND COST OF REVENUES
|
The components of electricity revenues and cost of revenues are
as follows:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Energy and capacity
|
|
$
|
24,718
|
|
|
$
|
23,772
|
|
Lease portion of energy and capacity
|
|
|
40,716
|
|
|
|
37,617
|
|
Lease income
|
|
|
671
|
|
|
|
671
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
66,105
|
|
|
$
|
62,060
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues:
|
|
|
|
|
|
|
|
|
Energy and capacity
|
|
$
|
27,254
|
|
|
$
|
22,898
|
|
Lease portion of energy and capacity
|
|
|
25,958
|
|
|
|
19,477
|
|
Lease income
|
|
|
1,311
|
|
|
|
1,311
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
54,523
|
|
|
$
|
43,686
|
|
|
|
|
|
|
|
|
|
|
17
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
|
|
NOTE 9
|
INTEREST
EXPENSE, NET
|
The components of interest expense are as follows:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Parent
|
|
$
|
180
|
|
|
$
|
443
|
|
Interest related to sale of tax benefits
|
|
|
1,375
|
|
|
|
1,930
|
|
Other
|
|
|
9,773
|
|
|
|
6,732
|
|
Less amount capitalized
|
|
|
(1,614
|
)
|
|
|
(5,815
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
9,714
|
|
|
$
|
3,290
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 10
|
EARNINGS
PER SHARE
|
Basic earnings per share attributable to the Companys
stockholders (earnings per share) is computed by
dividing net income attributable to the Companys
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.
The table below shows the reconciliation of the number of shares
used in the computation of basic and diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Weighted average number of shares used in computation of basic
earnings per share
|
|
|
45,431
|
|
|
|
45,353
|
|
Add:
|
|
|
|
|
|
|
|
|
Additional shares from the assumed exercise of employee stock
options
|
|
|
26
|
|
|
|
52
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares used in computation of diluted
earnings per share
|
|
|
45,457
|
|
|
|
45,405
|
|
|
|
|
|
|
|
|
|
|
The number of stock options that could potentially dilute future
earnings per share and were not included in the computation of
diluted earnings per share because to do so would have been
antidilutive was 2,048,750 and 1,953,670, respectively, for the
three months ended March 31, 2010 and 2009.
|
|
NOTE 11
|
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 Companys power plants pursuant to PPAs. The Product
Segment is engaged in the manufacture, including design and
development, of turbines and power units for the supply of
electrical energy and in the associated construction of power
plants utilizing the power units manufactured by the Company to
supply energy from geothermal fields and other alternative
energy sources. Transfer prices between the operating segments
are determined based on current market values or cost plus
markup of the sellers business segment.
18
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
Summarized financial information concerning the Companys
reportable segments is shown in the following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity
|
|
Product
|
|
Consolidated
|
|
|
(Dollars in thousands)
|
|
Three Months Ended March 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net revenues from external customers
|
|
$
|
66,105
|
|
|
$
|
16,549
|
|
|
$
|
82,654
|
|
Intersegment revenues
|
|
|
|
|
|
|
7,194
|
|
|
|
7,194
|
|
Operating income (loss)
|
|
|
3,095
|
|
|
|
(890
|
)
|
|
|
2,205
|
|
Segment assets at period end*
|
|
|
1,816,648
|
|
|
|
80,052
|
|
|
|
1,896,700
|
|
Three Months Ended March 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net revenues from external customers
|
|
$
|
62,060
|
|
|
$
|
37,251
|
|
|
$
|
99,311
|
|
Intersegment revenues
|
|
|
|
|
|
|
12,835
|
|
|
|
12,835
|
|
Operating income
|
|
|
10,825
|
|
|
|
7,920
|
|
|
|
18,745
|
|
Segment assets at period end*
|
|
|
1,651,351
|
|
|
|
76,843
|
|
|
|
1,728,194
|
|
|
|
|
*
|
|
Segment assets of the Electricity Segment include unconsolidated
investments.
|
Reconciling information between reportable segments and the
Companys consolidated totals is shown in the following
table:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Operating income
|
|
$
|
2,205
|
|
|
$
|
18,745
|
|
Interest income
|
|
|
197
|
|
|
|
152
|
|
Interest expense, net
|
|
|
(9,714
|
)
|
|
|
(3,290
|
)
|
Foreign currency translation and transaction gains (losses)
|
|
|
434
|
|
|
|
(2,393
|
)
|
Income attributable to sale of tax benefits
|
|
|
2,139
|
|
|
|
4,168
|
|
Other non-operating loss, net
|
|
|
(359
|
)
|
|
|
(150
|
)
|
|
|
|
|
|
|
|
|
|
Total consolidated income (loss) from continuing operations
before income taxes and equity in income of investees
|
|
$
|
(5,098
|
)
|
|
$
|
17,232
|
|
|
|
|
|
|
|
|
|
|
Securities
Class Actions
Following the Companys public announcement that it would
restate certain of its financial results due to a change in the
Companys accounting treatment for certain exploration and
development costs, three securities class action lawsuits were
filed in the United States District Court for the District of
Nevada on March 9, 2010, March 18, 2010 and
April 7, 2010. These complaints assert claims against the
Company and certain officers and directors for alleged violation
of Sections 10(b) and 20(a) of the Securities Exchange Act
of 1934 (the Exchange Act). One complaint also
asserts claims for alleged violations of Sections 11,
12(a)(2) and 15 of the Securities Act of 1933 (the
Securities Act). All three complaints allege claims
on behalf of a putative class of purchasers of Company stock
between May 6, 2008 or May 7, 2008 and
February 23, 2010 or February 24, 2010. The complaints
allege, inter alia, that the defendants made false
and/or
misleading statements
and/or
failed to make disclosures regarding the Companys
financial results and compliance with U.S. GAAP; that these
misstatements
and/or
nondisclosures resulted in overstatement of Company financial
19
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
results
and/or
artificially inflated the Companys stock price; and that
following the Companys February 24, 2010 public
announcement, the price of the Companys stock declined.
Each complaint seeks certification as a class action and
unspecified compensatory damages plus interest as well as
counsel fees and expert fees. The Company does not believe that
these lawsuits have merit and intends to defend itself
vigorously.
Stockholder
Derivative Cases
Three stockholder derivative lawsuits have also been filed in
connection with the Companys public announcement that it
would restate certain of its financial results due to a change
in the Companys 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 the other in the United States District Court for the
District of Nevada on March 29, 2010. All three 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 federal court derivative
complaint seeks compensatory damages on behalf of the Company
and both the federal and state court derivative complaints seek
restitution from the defendants on behalf of the Company. The
derivative complaints also seek other relief, including counsel
fees. The Company believes the allegations in these purported
derivative actions are also without merit and is defending the
actions vigorously.
Other
The Company is a defendant in various legal and regulatory
proceedings in the ordinary course of business. It is the
opinion of the Companys management that the expected
outcome of these matters, individually or in the aggregate, will
not have a material effect on the results of operations and
financial condition of the Company.
On February 23, 2010, the Companys Board of Directors
declared, approved and authorized payment of a quarterly
dividend of $5.5 million ($0.12 per share) to all holders
of the Companys issued and outstanding shares of common
stock on March 16, 2010. Such dividend was paid on
March 25, 2010.
The Companys effective tax rate for the three months ended
March 31, 2010 and 2009 was a tax benefit of 50.2% and tax
expense of 19.9%, respectively which differs from the federal
statutory rate of 35% 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; and
(iii) a tax credit and tax exemption related to the
Companys subsidiaries in Guatemala.
A reconciliation of the beginning and ending amounts of
unrecognized tax benefits is as follows:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Balance at beginning of year
|
|
$
|
4,931
|
|
|
$
|
3,425
|
|
Additions based on tax positions taken
|
|
|
|
|
|
|
|
|
in prior years
|
|
|
253
|
|
|
|
964
|
|
Additions based on tax positions taken
|
|
|
|
|
|
|
|
|
in the current year
|
|
|
|
|
|
|
1,282
|
|
Decrease for settlements with taxing authorities
|
|
|
|
|
|
|
(740
|
)
|
|
|
|
|
|
|
|
|
|
Balance at end of year
|
|
$
|
5,184
|
|
|
$
|
4,931
|
|
|
|
|
|
|
|
|
|
|
20
ORMAT
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Unaudited)
|
|
NOTE 15
|
SUBSEQUENT
EVENTS
|
Options
grant
On April 16, 2010, the Company granted to employees 592,900
stock appreciation rights (SARs) under the
Companys 2004 Incentive Plan. The exercise price of each
SAR is $29.95, which represented the fair market value of the
Companys common stock on the date of the 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.
On May 6, 2010, the Company granted to a non-employee
director non-qualified stock options, under the 2004 Incentive
Plan, to purchase 7,500 shares of common stock at an
exercise price of $29.21, which is equal to the closing price of
the Companys common stock on May 6, 2010 (since the
Company released its quarterly results on May 5, 2010).
Such options will expire seven years from the date of grant and
will vest on the first anniversary of the date of grant.
Cash
Dividend
On May 5, 2010, the Companys 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 Companys issued and outstanding shares of common
stock on May 18, 2010, payable on May 25, 2010.
21
|
|
ITEM 2.
|
MANAGEMENTS
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 Managements 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 managements 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 of the
reservoir, useful life and geological formation);
|
|
|
|
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;
|
|
|
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the enforceability of the long-term power purchase agreements
(PPAs) for our power plants;
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contract counterparty risk;
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weather and other natural phenomena;
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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 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;
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current and future litigation;
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22
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our ability to successfully identify, integrate and complete
acquisitions;
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competition from other similar geothermal energy projects,
including any such new geothermal energy projects developed in
the future, and from alternative electricity producing
technologies;
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the effect of and changes in economic conditions in the areas in
which we operate;
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market or business conditions and fluctuations in demand for
energy or capacity in the markets in which we operate;
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the direct or indirect impact on our companys business
resulting from terrorist incidents or responses to such
incidents, including the effect on the availability of and
premiums on insurance;
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the effect of and changes in current and future land use and
zoning regulations, residential, commercial and industrial
development and urbanization in the areas in which we operate;
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the risk factors set forth in our Annual Report on
Form 10-K
for the year ended December 31, 2009;
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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
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other risks and uncertainties detailed from time to time in our
filings with the Securities and Exchange Commission (SEC).
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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, 2009 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 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 decided to expand our activities in the
Electricity Segment to include the ownership and operation of
power plants that produce electricity generated by
solar-photovoltaic (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 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
three months ended
23
March 31, 2010 and 2009, our consolidated power plants
generated 917,324 MWh and 875,668 MWh, respectively.
For the three months ended March 31, 2010, our Electricity
Segment represented approximately 80.0% of our total revenues,
while our Product Segment represented approximately 20.0% of our
total revenues during such period.
For the three months ended March 31, 2010, our total
revenues decreased by 16.8% (from $99.3 million to
$82.7 million) over the same period last year.
Revenues from the Electricity Segment increased by 6.5%, while
revenues from the Product Segment decreased by 55.6%.
For the three months ended March 31, 2010, total
Electricity Segment revenues from the sale of electricity by our
consolidated power plants were $66.1 million, compared to
$62.1 million for the three months ended March 31,
2009. In addition, revenues from our 50% ownership of the
Mammoth complex in the three months ended March 31, 2010
and 2009 were $2.5 million and $2.4 million,
respectively. This additional data is a Non-Generally Accepted
Accounting Principles (Non-GAAP) financial measure, as defined
by the SEC. There is no comparable GAAP measure. We believe that
such Non-GAAP data is useful to the readers as it provides a
more complete view of the scope of activities of the power
plants that we operate. Our investment in the Mammoth complex is
accounted for in our consolidated financial statements under the
equity method and the revenues are not included in our
consolidated revenues for the three months ended March 31,
2010 and 2009.
For the three months ended March 31, 2010, revenues
attributable to our Product Segment were $16.5 million,
compared to $37.3 million for the three months ended
March 31, 2009, a decrease of 55.6%. The revenues in the
Product Segment in 2009 were significantly higher primarily due
to three large EPC contracts entered into for the construction
of three large binary geothermal projects in 2009, namely the
Blue Mountain project in Nevada, the Centennial Binary Plant in
New Zealand, and the Las Paillas project in Costa Rica.
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 May 2012. The
exception is the PPA of the Puna power plant. It has a monthly
variable energy rate based on the local utilitys 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 three months ended
March 31, 2010, the variable energy rate in the Puna power
plant decreased significantly mainly as a result of lower oil
prices, which in turn impacted the gross margin in our
Electricity Segment. In the three months ended March 31,
2010, 88.1% 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 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 projects 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.
24
Recent
Developments
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On April 26, 2010, the Medco-Ormat-Itochu-Kyushu
Consortium, which consists of Medco Energi Internasional Tbk,
Ormat International Inc., our wholly owned subsidiary, Itochu
Corporation and Kyushu Electric Power Co. Inc., signed the
Sarulla Project Joint Confirmation with the
state-owned Indonesian power company PT Perusahaan Listrik
Negara (PLN) confirming an agreement on terms for amending the
Energy Sales Contract (ESC), with the concession holder PT
Pertamina Geothermal Energy (PGE), a wholly owned subsidiary of
the Indonesian state-owned oil and gas company PT Pertamina
(Persero), signing as witness. The ESC had been executed in
December 2007 for the 330 MW net power Sarulla Geothermal
Project. The Sarulla Project Joint Confirmation was signed
during the opening ceremony of the World Geothermal Congress in
Bali.
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The parties have agreed to change the price of the power sold
under the ESC to a levelized payment of 6.79 cents per kWh,
whereby the tariff payable in the early years after commercial
operation date shall be higher and shall be reduced in the later
years. The parties have as well agreed on a
90-day
schedule for resolving certain other contractual amendments for
facilitation of project financing and for signing the resulting
amended ESC. The modified tariff itself is subject to
verification by the State Audit Agency for Development and
approval from the Minister of Energy and Mineral Resources.
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Since the beginning of 2010, we entered into new lease
agreements covering approximately 46,000 acres of federal
or private land in Nevada, Utah, Hawaii, and California.
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In February 2010, we signed a letter of intent with Kenya Power
and Lighting Co. Ltd. (KPLC), the off-taker, of the
Olkaria III complex located in Naivasha, Kenya, to amend
the existing PPA by expanding the Olkaria III complex by up
to 52 MW within the framework of the existing PPA. The
expansion is to be developed in two phases. Phase I will be
comprised of 36 MW, to be completed within 3.5 years
from finalizing the amendment to the existing PPA. An optional
phase II may be comprised of up to 16 MW, to be
completed within 4.5 years from finalizing the amendment to
the existing PPA. The amendment to the existing PPA is subject
to applicable governmental approvals and the consent of the
lenders that provided the financing to the existing power plant.
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In February 2010, we signed an agreement to acquire 100% of the
membership interests in HSS II, LLC, which owns the Tuscarora
Project in the northern Independence Valley of northeast Nevada.
The project is in an advanced stage of development and has one
successful well. We plan to construct and operate a geothermal
plant on the site, the first phase of 16 MW of which is
expected to become operational in 2012, and sell electricity
under a new PPA which we signed with Nevada Power Company (a
subsidiary of NV Energy, Inc).
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In January 2010
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the North Brawley geothermal power plant
in California was placed in service and is currently operating
at a stable capacity of 20 MW. Southern California Edison
Company (Southern California Edison), the PPA off-taker, agreed
to extend the firm operation date until March 31, 2011.
This extension will give us time to bring the power plants
generation to its full design capacity of 50MW.
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In January 2010, we were awarded a geothermal exploration
concession in Chile. The concession is on approximately
26,000 acres located to the north of the
San Pablo/San Pedro twin volcanic complex in northern
Chile and is close to access roads and to copper mines that
could be potential users of the electricity. We plan to engage
in preliminary testing and studies to assess the feasibility of
the site for commercial development in accordance with the
milestones set forth in the concession.
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In January 2010, we sold our interest in GDL for
NZ$3.5 million (approximately US$2.8 million), and we
were repaid a loan we had made to GDL with an outstanding
balance of NZ$24.3 million (approximately
US$17.6 million).
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Trends
and Uncertainties
The geothermal industry in the United States has historically
experienced significant growth followed by a consolidation of
owners and operators of geothermal power plants. During the
1990s, growth and development in the geothermal industry
occurred primarily in foreign markets and only minimal growth
and development occurred in the United States. Since 2001, there
has been increased demand for energy generated
25
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
recently enacted American Recovery and Reinvestment Act (ARRA)
further encourages the use of geothermal energy through
production or investment tax credits 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. All of our current revenues from the sale
of electricity are derived from fully-contracted long-term PPAs.
We also intend to continue to pursue growth in our recovered
energy business. We expect our Product Segment revenues in 2010
to be significantly lower than the 2009 revenues in such segment.
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:
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The global recession resulting from the recent disruption in the
global credit markets, failures or material business
deterioration of investment banks, commercial banks, and other
financial institutions and intermediaries in the United States
and elsewhere around the world, significant reductions in asset
values across businesses, households and individuals, and the
slowdown in manufacturing and other business activity has also
resulted in reduced worldwide demand for energy. If these
conditions continue or worsen, they may adversely affect both
our Electricity and Product Segments. Among other things, we
might face: (i) potential declines in revenues in our
Products Segment due to reduced orders or other factors caused
by economic challenges faced by our customers and prospective
customers; (ii) potential declines in revenues from some of
our existing geothermal power projects as a result of curtailed
electricity demand and low oil and gas prices; and
(iii) potential adverse impacts on our customers
ability to pay, when due, amounts payable to us. In addition, we
may experience related increases in our cost of capital
associated with any increased working capital or borrowing needs
we may have if our customers do not pay, or if we are unable to
collect amounts payable to us in full (or at all) if any of our
customers fail or seek protection under applicable bankruptcy or
insolvency laws. In addition, the cost of obtaining financing
for our project needs may increase or such financing may be more
difficult to obtain.
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Our primary focus continues to be the implementation of our
organic growth through exploration, development, the
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 may look at acquisition opportunities that
may arise.
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In the United States, we expect to continue to benefit from the
increasing demand for renewable energy. Thirty-six states and
the District of Columbia, including California, Nevada and
Hawaii (where we have been most active in geothermal development
and in which all of our U.S. geothermal projects are
located) have adopted renewable portfolio standards (RPS),
renewable portfolio goals or other similar laws. These laws
require that an increasing percentage of the electricity
supplied by electric utility companies operating in such states
be derived from renewable energy resources until certain
pre-established goals are met. We expect that the additional
demand for renewable energy from utilities in such states will
outpace a possible reduction in general demand for energy due to
the economic slow down and will continue to create opportunities
for us to expand existing projects and build new power plants.
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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
going forward. Although federal legislation addressing climate
change appears likely, several states and regions are
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already addressing climate change. For example, the California
Global Warming Solutions Act of 2006, 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, representing an approximately 30% reduction in
greenhouse gas emissions from projected 2020 levels or about 15%
from 2008 levels. The California Air Resources Board is expected
to put in place measures for implementing the Global Warming
Solutions Act of 2006 by 2012. In September of 2006, California
also passed Senate Bill 1368, which prohibits the states
utilities from entering into long-term financial commitments for
base-load generation with power plants that fail to meet a
CO
2
emission performance standard established by the California
Energy Commission and the California Public Utilities
Commission. Californias 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-one other states have set greenhouse gas
emissions targets (Arizona, Colorado, Connecticut, Florida,
Hawaii, Illinois, Maine, Maryland, Massachusetts, 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, 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
CO
2
allowances was held under the RGGI, a regional
cap-and-trade
system, which includes ten Northeast and Mid-Atlantic States.
Under RGGI, the ten 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, thirty-six states and the District of
Columbia have all adopted RPS, as discussed above. In November
2008, California, by Executive Order
S-14-08,
adopted a goal for all retailers of electricity to serve 33% of
their load with renewable energy by 2020, and in September of
2009, Executive Order
S-21-09
directed the California Air Resources Board to adopt regulations
consistent with the 33% renewable energy target by July 31,
2010. Although it is currently difficult to quantify the direct
economic benefit of these efforts to reduce greenhouse gas
emissions, we believe they will prove advantageous to us.
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Outside of the United States, we expect that a variety of
governmental initiatives will create new opportunities for the
development of new projects, as well as create additional
markets for our products. These initiatives include the award of
long-term contracts to independent power generators, the
creation of competitive wholesale markets for selling and
trading energy, capacity and related energy products and the
adoption of programs designed to encourage clean
renewable and sustainable energy sources.
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We expect competition from the wind and solar power generation
industry 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 in the amount of renewable energy under
contract may contribute to a reduction in electricity prices.
Despite increased competition from the wind and solar power
generation industry, we believe that baseload electricity, such
as geothermal-based energy, will continue to be a leading source
of renewable energy in areas with commercially viable geothermal
resources.
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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 lead
to a reduction in prices that we are able to charge for our
binary equipment, which in turn may impact our profitability.
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We also expect increased competition from new developers which
may impact the prices and availability of new leases for
geothermal resource.
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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 space may contribute to a reduction in
electricity prices, and increased competition in geothermal
leasing may contribute to an increase in lease costs.
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27
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The viability of a geothermal resource depends on various
factors such as the resource temperature, the permeability of
the resource (i.e., the ability to get geothermal fluids to the
surface) and operational factors relating to the extraction 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 operations.
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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 such
decrease in availability.
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Our foreign operations are subject to significant political,
economic and financial risks, which vary by country. These 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.
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On May 5, 2009, President Obama and the U.S. Treasury
Department proposed changing certain of the U.S. tax rules
for U.S. corporations doing business outside the United
States. The proposed changes would limit the ability of
U.S. corporations to deduct expenses attributable to
offshore earnings, modify the foreign tax credit rules and
further restrict the ability of U.S. corporations to
transfer funds between foreign subsidiaries without triggering a
requirement to pay U.S. income tax. Although the scope of
the proposed changes is unclear, it is possible that these or
other changes in the U.S. tax laws may increase our
U.S. income tax liability and adversely affect our
profitability.
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The Energy Policy Act of 2005 authorizes the Federal Energy
Regulatory Commission (FERC) to revise the Public Utility
Regulatory Policies Act (PURPA) so as to terminate the
obligation of electric utilities to purchase the output of a
Qualifying Facility if FERC finds that there is an accessible
competitive market for energy and capacity from the Qualifying
Facility. The legislation does not affect existing PPAs. We do
not expect this change in law to affect our U.S. projects
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. FERC issued a final rule that makes it
easier to eliminate the utilities purchase obligation in
four regions of the country. None of those regions includes a
state in which our current projects operate. However, FERC has
the authority under the Energy Policy Act of 2005 to act, on a
case-by-case
basis, to eliminate the mandatory purchase obligation in other
regions. If the utilities in the regions in which our domestic
projects 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 PPAs, which could have an
adverse effect on our revenues.
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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,
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
28
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 purchasers 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 tied to the price of oil. Accordingly, our
revenues for that power plant, which accounted for approximately
7.1% of our total revenues for the three-month period ended
March 31, 2010 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 a
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 customers 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 existing orders that we have
completed with new ones. As a result, our revenues from our
Product Segment fluctuate (and at times, extensively) from
period to period. As discussed under Trends and
Uncertainties above, we may experience declines in
revenues in our Product Segment due to reduced orders or other
factors caused by the global recession and economic challenges
faced by our customers and prospective customers.
The following table sets forth a breakdown of our revenues for
the periods indicated:
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Revenues in Thousands
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% of Revenues for Period Indicated
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Three Months
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Three Months
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Ended
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Ended
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March 31,
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March 31,
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2010
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2009
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2010
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2009
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Revenues
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Electricity Segment
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$
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66,105
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$
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62,060
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80.0
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%
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62.5
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%
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Product Segment
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16,549
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37,251
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20.0
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37.5
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Total
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$
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82,654
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$
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99,311
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100.0
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%
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100.0
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%
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Geographical
Breakdown of Revenues
For the three months ended March 31, 2010, 72.0% of our
revenues attributable to our Electricity Segment were generated
in the United States, compared to 73.1% for the same period in
2009.
The following table sets forth the geographic breakdown of the
revenues attributable to our Electricity Segment for the periods
indicated:
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|
|
Revenues in Thousands
|
|
|
% of Revenues for Period Indicated
|
|
|
|
Three Months
|
|
|
Three Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
March 31,
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
United States
|
|
$
|
47,589
|
|
|
$
|
45,357
|
|
|
|
72.0
|
%
|
|
|
73.1
|
%
|
Foreign
|
|
|
18,516
|
|
|
|
16,703
|
|
|
|
28.0
|
|
|
|
26.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
66,105
|
|
|
$
|
62,060
|
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2010, 14.4% of our
revenues attributable to our Product Segment were generated in
the United States, compared to 62.2% for the same period in 2009.
29
A discussion of the reasons for these changes in the
geographical breakdown of our revenues is provided further below.
Seasonality
The prices paid for the electricity generated by some of our
domestic power plants pursuant to our PPAs are subject to
seasonal variations. The prices paid for electricity under the
PPAs with Southern California Edison Company (Southern
California Edison) for the Heber 1 and 2 plants, the Mammoth
complex and the Ormesa complex and the prices that will be paid
for the electricity under the PPA for the North Brawley project
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 projects 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 expenses attributable to our operating projects
include 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
and, for the California projects, 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 on account of site leases where
plants are located are included in cost of revenues. Royalty
payments, included in cost of revenues, are made as compensation
for the right to use certain geothermal resources and are paid
as a percentage of the revenues derived from the associated
geothermal rights. For the three months ended March 31,
2010, royalties constituted approximately 3.0% of the
Electricity Segment revenues, compared to approximately 4.0% for
the same period in 2009.
Product
Segment
The principal expenses attributable to our Product Segment
include 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
and Cash Equivalents
Our cash and cash equivalents as of March 31, 2010
decreased to $43.1 million from $46.3 million as of
December 31, 2009. This decrease is principally due to our
use of $76.5 million of cash resources to fund capital
expenditures, and $5.5 million to repay long-term debt to
third parties. The decrease in our cash resources was partially
offset by a net increase of $24.5 million in amounts drawn
under revolving credit lines with commercial banks, and
$48.2 million derived from operating activities during the
first quarter of 2010. Our corporate borrowing capacity under
committed lines of credit with different commercial banks as of
March 31, 2010 was $362.5 million, as described below
in the section entitled Liquidity and Capital
30
Resources, of which we utilized $220.9 million
(including $62.4 million of letters of credit) as of
March 31, 2010.
Critical
Accounting Policies
A comprehensive discussion of our critical accounting policies
is included in the Managements 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, 2009.
New
Accounting Pronouncements
On January 1, 2010, we adopted the amended consolidation
guidance for variable interest entities. As to the impact of the
adoption of this amendment on the consolidated financial
statements and the additional disclosure in such consolidated
financial statements, see Note 5 to our condensed
consolidated financial statements set forth in Item 1 of
this quarterly report.
See Note 2 to our condensed consolidated financial
statements set forth in Item 1 of this quarterly report for
additional information regarding new accounting pronouncements.
31
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 projects and enhancement of acquired
projects; and (ii) fluctuation in revenues from our Product
Segment.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands, except per share data)
|
|
|
Statements of Operations Historical Data:
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Electricity
|
|
$
|
66,105
|
|
|
$
|
62,060
|
|
Product
|
|
|
16,549
|
|
|
|
37,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82,654
|
|
|
|
99,311
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues:
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
54,523
|
|
|
|
43,686
|
|
Product
|
|
|
12,437
|
|
|
|
24,243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66,960
|
|
|
|
67,929
|
|
|
|
|
|
|
|
|
|
|
Gross margin:
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
11,582
|
|
|
|
18,374
|
|
Product
|
|
|
4,112
|
|
|
|
13,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,694
|
|
|
|
31,382
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Research and development expenses
|
|
|
3,267
|
|
|
|
801
|
|
Selling and marketing expenses
|
|
|
3,202
|
|
|
|
4,301
|
|
General and administrative expenses
|
|
|
7,020
|
|
|
|
7,535
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
2,205
|
|
|
|
18,745
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
197
|
|
|
|
152
|
|
Interest expense, net
|
|
|
(9,714
|
)
|
|
|
(3,290
|
)
|
Foreign currency translation and transaction gains (losses)
|
|
|
434
|
|
|
|
(2,393
|
)
|
Income attributable to sale of tax benefits
|
|
|
2,139
|
|
|
|
4,168
|
|
Other non-operating loss, net
|
|
|
(359
|
)
|
|
|
(150
|
)
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes and
equity in income of investees
|
|
|
(5,098
|
)
|
|
|
17,232
|
|
Income tax benefit (provision)
|
|
|
2,557
|
|
|
|
(3,429
|
)
|
Equity in income of investees, net
|
|
|
546
|
|
|
|
550
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
(1,995
|
)
|
|
|
14,353
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of related tax of $6
and $60, respectively
|
|
|
14
|
|
|
|
153
|
|
Gain on sale of of a subsidiary in New Zealand, net of related
tax of $2,570
|
|
|
3,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
1,785
|
|
|
|
14,506
|
|
Net loss attributable to noncontrolling interest
|
|
|
53
|
|
|
|
79
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to the Companys stockholders
|
|
$
|
1,838
|
|
|
$
|
14,585
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share basic and diluted:
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$
|
(0.04
|
)
|
|
$
|
0.32
|
|
Income from discontinued operations
|
|
|
0.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
0.04
|
|
|
$
|
0.32
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares used in computation of
earnings (loss) per share:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
45,431
|
|
|
|
45,353
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
45,457
|
|
|
|
45,405
|
|
|
|
|
|
|
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Statements of Operations Percentage Data:
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
80.0
|
%
|
|
|
62.5
|
%
|
Product
|
|
|
20.0
|
|
|
|
37.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100.0
|
|
|
|
100.0
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues:
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
82.5
|
|
|
|
70.4
|
|
Product
|
|
|
75.2
|
|
|
|
65.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81.0
|
|
|
|
68.4
|
|
|
|
|
|
|
|
|
|
|
Gross margin:
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
17.5
|
|
|
|
29.6
|
|
Product
|
|
|
24.8
|
|
|
|
34.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19.0
|
|
|
|
31.6
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Research and development expenses
|
|
|
4.0
|
|
|
|
0.8
|
|
Selling and marketing expenses
|
|
|
3.9
|
|
|
|
4.3
|
|
General and administrative expenses
|
|
|
8.5
|
|
|
|
7.6
|
|
Operating income
|
|
|
2.7
|
|
|
|
18.9
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
0.2
|
|
|
|
0.2
|
|
Interest expense, net
|
|
|
(11.8
|
)
|
|
|
(3.3
|
)
|
Foreign currency translation and transaction gains (losses)
|
|
|
0.5
|
|
|
|
(2.4
|
)
|
Income attributable to sale of tax benefits
|
|
|
2.6
|
|
|
|
4.2
|
|
Other non-operating loss, net
|
|
|
(0.4
|
)
|
|
|
(0.2
|
)
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes and
equity in income of investees
|
|
|
(6.2
|
)
|
|
|
17.4
|
|
Income tax benefit (provision)
|
|
|
3.1
|
|
|
|
(3.5
|
)
|
Equity in income of investees, net
|
|
|
0.7
|
|
|
|
0.6
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
(2.4
|
)
|
|
|
14.5
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of related tax
|
|
|
0.0
|
|
|
|
0.2
|
|
Gain on sale of of a subsidiary in New Zealand, net of related
tax
|
|
|
4.6
|
|
|
|
0.0
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
2.2
|
|
|
|
14.6
|
|
Net loss attributable to noncontrolling interest
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to the Companys stockholders
|
|
|
2.2
|
%
|
|
|
14.7
|
%
|
|
|
|
|
|
|
|
|
|
Comparison
of the Three Months Ended March 31, 2010 and the Three
Months Ended March 31, 2009
Total
Revenues
Total revenues for the three months ended March 31, 2010
were $82.7 million, compared with $99.3 million for
the three months ended March 31, 2009, which represented a
16.8% decrease in total revenues. This decrease is attributable
to reduced Product Segment revenues, which decreased by 55.6%
from
33
the same period in 2009 (for the reasons discussed above and
below). Revenues from our Electricity Segment increased by 6.5%
from the same period last year.
Electricity
Segment
Revenues attributable to our Electricity Segment for the three
months ended March 31, 2010 were $66.1 million,
compared to $62.1 million for the three months ended
March 31, 2009, which represented a 6.5% increase in such
revenues. This increase is a result of increased electricity
generation at most of our power plants (with the exception of
our Puna power plant) from 875,668 MWh in the three months
ended March 31, 2009 to 917,882 MWh in the three
months ended March 31, 2010. The single most significant
contributor to the increase in our electricity generation was
the placement in service of our North Brawley power plant in
January 2010. This increase in generation was offset by a
decrease in the generating capacity of the Puna power plant due
to mechanical problems in the production wells that limited the
generating capacity to 17 MW. Based on the progress that
was made in repair work in the Puna power plant, we expect its
revenues to improve in the second quarter of 2010. The increase
in our electricity segment revenues is also attributable to a
slight increase in the average revenue rate of our electricity
portfolio from $71 per MWh in the first quarter of 2009 to $72
per MWh in the first quarter of 2010.
Product
Segment
Revenues attributable to our Product Segment for the three
months ended March 31, 2010 were $16.5 million,
compared to $37.3 million for the three months ended
March 31, 2009, which represented a 55.6% decrease in such
revenues. This reduction in our product revenue reflects the
completion of the Blue Mountain project in Nevada, which was
primarily responsible for our significantly higher revenues in
the same period last year. We expect this downward fluctuation
to affect revenues from our Product Segment throughout this year.
Total
Cost of Revenues
Total cost of revenues for the three months ended March 31,
2010 was $67.0 million, compared to $67.9 million for
the three months ended March 31, 2009, which represented a
1.4% decrease in total cost of revenues. This decrease is
attributable to a decrease in our Product Segment cost of
revenues, as discussed below. The decrease was partially offset
by an increase in our Electricity Segment cost of revenues. As a
percentage of total revenues, our total cost of revenues for the
three months ended March 31, 2010 was 81.0% compared with
68.4% for the same period in 2009. This increase reflects a
decrease in our gross margin, which is mainly attributable to
the decrease in our Product Segment revenues and an increase in
our Electricity Segment cost of revenues.
Electricity
Segment
Total cost of revenues attributable to our Electricity Segment
for the three months ended March 31, 2010 was
$54.5 million, which includes $9.5 million (including
depreciation) related to the North Brawley power plant, compared
to $43.7 million for the three months ended March 31,
2009, which represented a 24.8% increase in total cost of
revenues for such segment. The increase over the same period
last year is mainly attributable to our North Brawley power
plant which was placed in service in January 2010. We have
incurred high fixed costs (including depreciation) associated
with a 50 MW power plant, even though the North Brawley
power plant performed at less than 50% of its generating
capacity. The higher costs in the North Brawley power plant
increased the cost per MWh in the current quarter compared to
the first quarter of 2009. As a percentage of total electricity
revenues, the total cost of revenues attributable to our
Electricity Segment for the three months ended March 31,
2010 was 82.5%, compared to 70.4% for the three months ended
March 31, 2009. We expect this trend to continue during the
remainder of 2010.
Product
Segment
Total cost of revenues attributable to our Product Segment for
the three months ended March 31, 2010 was
$12.4 million, compared to $24.2 million for the three
months ended March 31, 2009, which represented
34
a 48.7% decrease in total cost of revenues related to such
segment. This decrease is attributable to the decrease in
revenues associated with the completion of the Blue Mountain
project in Nevada, described above. Despite the decrease in the
Product Segment cost of revenues, as a percentage of total
Product Segment revenues, our total cost of revenues
attributable to this segment for the three months ended
March 31, 2010 was 75.2%, compared to 65.1% for the three
months ended March 31, 2009. This increase reflects a
decrease in our gross margin, which is mainly attributable to
the lower volume of the Product Segment revenues.
Research
and Development Expenses
Research and development expenses for the three months ended
March 31, 2010 were $3.3 million, compared to
$0.8 million for the three months ended March 31,
2009, which represented a 307.9% increase. Our research and
development activities during the three months ended
March 31, 2010 included: (i) an experimental REG plant
specifically designed to use the residual energy from the
vaporization process at liquefied natural gas regasification
terminals; (ii) enhanced geothermal systems (EGS); and
(iii) development of a solar thermal system for the
production of electricity. The large percentage increase is
primarily attributable to the costs related to the experimental
REG plant in the amount of $2.6 million (in addition to
$7.5 million recorded in the year ended December 31,
2009), that include developing and building a unit at a
customers premises in Spain. If the development of the
unit is not successful we will have to remove the unit from the
customers site. If the unit operates successfully and
passes acceptance tests, we will be paid by the customer an
amount of approximately $16.0 million which will be
recognized as revenue upon acceptance by the customer. The
research and development expenses are net of grants from the U.S
Department of Energy (DOE) in the amount of $0.1 million
with respect to the EGS project.
Selling
and Marketing Expenses
Selling and marketing expenses for the three months ended
March 31, 2010 were $3.2 million, compared to
$4.3 million for the three months ended March 31,
2009, which represented a 25.6% decrease. The decrease was due
primarily to the decrease in Product Segment revenues. Selling
and marketing expenses for the three months ended March 31,
2010 constituted 3.9% of total revenues for such period compared
to 4.3% for the three months ended March 31, 2009.
General
and Administrative Expenses
General and administrative expenses for the three months ended
March 31, 2010 were $7.0 million, compared to
$7.5 million for the three months ended March 31,
2009, which represented a 6.8% decrease. General and
administrative expenses for the three months ended
March 31, 2010 constituted 8.5% of total revenues for such
period, compared to 7.6% for the three months ended
March 31, 2009.
Operating
Income
Operating income for the three months ended March 31, 2010
was $2.2 million, compared to $18.7 million for the
three months ended March 31, 2009. Such decrease in
operating income was principally attributable to a decrease in
the total gross margin due to the decrease in Product Segment
revenues and the increase in Electricity Segment cost of
revenues. Operating income attributable to our Electricity
Segment for the three months ended March 31, 2010 was
$3.1 million, compared to $10.9 million for the three
months ended March 31, 2009, mainly due to the increase in
electricity cost of revenues, as explained above. Operating loss
attributable to our Product Segment for the three months ended
March 31, 2010 was $0.9 million, compared to operating
income of $7.9 million for the three months ended
March 31, 2009, mainly due to the decrease in product
revenues, as explained above.
Interest
Income
Interest income for each of the three months ended
March 31, 2010 and 2009 was $0.2 million. Interest
income includes interest payable on investments included in cash
and cash equivalents, marketable securities and restricted cash.
35
Interest
Expense, Net
Interest expense, net, for the three months ended March 31,
2010 was $9.7 million, compared to $3.3 million for
the three months ended March 31, 2009, which represented a
195.3% increase. The $6.4 million increase is primarily due
to: (i) a decrease of $4.2 million in interest
capitalized to projects as a result of decreased costs for
projects under construction primarily due to the commencement of
commercial operations of our North Brawley power plant in
January 2010; (ii) an increase in interest expenses related
to our long-term project finance loans of the Olkaria III
and Amatitlan power plants; (iii) borrowings under our
revolving credit lines with banks; and (iv) loan agreements
with two groups of institutional investors and a commercial
bank. The increase was partially offset by a decrease in
interest related to the sale of tax benefits in connection with
the acquisition of a thirty percent interest in the Class B
membership units of OPC in the fourth quarter of 2009 by Ormat
Nevada, as well as principal repayments.
Foreign
Currency Translation and Transaction Gains
(Losses)
Foreign currency translation and transaction gains for the three
months ended March 31, 2010 were $0.4 million,
compared to foreign currency translation and transaction losses
of $2.4 million for the three months ended March 31,
2009. The $2.8 million increase is primarily due to losses
on forward foreign exchange transactions which do not qualify as
hedge transactions for accounting purposes for the three months
ended March 31, 2009, compared to gains in the three months
ended March 31, 2010.
Income
Attributable to Sale of Tax Benefits
Income from the sale of tax benefits to institutional equity
investors (as described in the OPC Transaction) for
the three months ended March 31, 2010 was
$2.1 million, compared to $4.2 million for the three
months ended March 31, 2009. This income represents the
value of production tax credits (PTCs) and taxable income or
loss generated by OPC and allocated to the investors. The
decrease is due to lower depreciation for tax purposes as a
result of declining depreciation rates utilizing the Modified
Accelerated Cost Recovery System (MACRS) and to our purchase of
Class B membership units of OPC from Lehman-OPC.
Income
Taxes
Income tax benefit for the three months ended March 31,
2010 was $2.6 million, compared to income tax provision of
$3.4 million for the three months ended March 31,
2009. The effective tax rate for the three months ended
March 31, 2010 and 2009 was 50.2% and 19.9%, respectively.
The increase in the effective tax rate primarily resulted from a
higher impact of production tax credits on the effective tax
rate for the quarter ended March 31, 2010 due to a decrease
in our annual forecasted pre-tax income, which will result in an
annual tax benefit.
Equity
in Income of Investees
Our participation in the income generated from our investees in
each of the three months ended March 31, 2010 and 2009 was
$0.6 million. The amount is derived mainly from our 50%
ownership of the Mammoth complex.
Income
(Loss) from Continuing Operations
Loss from continuing operations for the three months ended
March 31, 2010 was $2.0 million, compared to income
from continuing operations of $14.3 million for the three
months ended March 31, 2009. Such decrease in income from
continuing operations was principally attributable to:
(i) a decrease of $16.5 million in operating income;
(ii) a $6.4 million increase in interest expense; and
(iii) a $2.1 million decrease in income attributable
to the sale of tax benefits. This was partially offset by:
(i) a $2.8 million increase in foreign currency
transaction and translation gains; and (ii) a
$6.0 million decrease in income tax provision.
36
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. 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 $3.8 million in the three months ended
March 31, 2010. The operations of GDL have been included in
discontinued operations for all periods prior to the sale of GDL.
Net
Income
Net income for the three months ended March 31, 2010 was
$1.8 million, compared to $14.5 million for the three
months ended March 31, 2009. Such decrease in net income
was principally attributable to the decrease in income from
continuing operations in the amount of $16.5 million, as
discussed above, partially offset by the gain on the sale of
shares in GDL in the amount of $3.8 million, net of related
income taxes.
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, issuance by
Ormat Funding Corp. (OFC) and OrCal Geothermal Inc. (OrCal) of
their respective Senior Secured Notes and project financing
(including the Puna lease and the OPC Transaction described
below) and 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 March 31, 2010, we have access to the following
sources of funds: (i) $43.1 million in cash and cash
equivalents; and (ii) $141.6 million of unused
corporate borrowing capacity under existing committed lines of
credit with different commercial banks.
Our estimated capital needs for the rest of 2010 include
approximately $264.0 million for capital expenditures on
new projects in development or construction, exploration
activity, operating projects, and machinery and equipment, as
well as $56.4 million for debt repayment (including to our
parent).
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) a cash grant available to us under the
ARRA in respect of the North Brawley power plant. Management
believes that these sources will address our anticipated
liquidity, capital expenditures and other investment
requirements. Our shelf registration statement on
Form S-3,
which was declared effective on October 2, 2008, provides
us with the ability to raise additional capital of up to
$1.5 billion through the issuance of securities, subject to
market conditions.
Loan
Agreements with our Parent
Under a loan agreement with Ormat Industries Ltd. (our parent
company), it agreed to make a loan to us in one or more advances
not exceeding a total aggregate amount of $150.0 million.
The proceeds of the loan were used to fund our general corporate
activities and investments. We are required to repay the loan
and accrued interest in full and in accordance with an
agreed-upon
repayment schedule and in any event on or prior to June 5,
2010. Interest on the loan is calculated on the balance from the
date of the receipt of each advance until the date of payment
thereof at a fixed rate of 7.5% per annum. All computations of
interest are made by Ormat Industries Ltd. on the basis of a
year consisting of 360 days. As of March 31, 2010 and
December 31, 2009, the outstanding balance of the loan was
$9.6 million.
37
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, 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 June 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 March 31, 2010, OFC was in compliance with the
covenants under the OFC Senior Secured Notes. As of
March 31, 2010, there were $146.3 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 of 1933, as amended,
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 June 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 March 31, 2010, OrCal was in compliance with the
covenants under the OrCal Senior Secured Notes. As of
March 31, 2010, there were $105.8 million of OrCal
Senior Secured Notes outstanding.
Olkaria III
Loan Non-Recourse
OrPower 4, Inc. (OrPower 4), has a project financing loan of
$105.0 million which refinanced its investment in the
48 MW Olkaria III geothermal power plant located in
Kenya. The loan was provided by a group of European Development
Finance Institutions (DFIs) arranged by DEG Deutsche
Investitions-und Entwicklungsgesellschaft mbH (DEG). The loan
will mature on December 15, 2018, and will be payable in 19
equal semi-annual installments, commencing December 15,
2009. Interest on the loan is variable based on
6-month
LIBOR plus 4.0%. We fixed the interest rate on
$77.0 million of the loan at 6.90% per annum. There are
various restrictive covenants under the loan, which include
limitations on OrPower 4s ability to make distributions to
its shareholders. As of March 31, 2010, OrPower 4 was in
compliance with the covenants under the loan. As of
March 31, 2010, $99.5 million of the Olkaria III
loan was outstanding.
38
Amatitlan
Loan Non-Recourse
Ortitlan Limitada (Ortitlan), entered into a note purchase
agreement in an aggregate principal amount of $42.0 million
which refinanced its investment in the 20 MW Amatitlan
geothermal power plant located in Amatitlan, Guatemala. The loan
was provided by TCW Global Project Fund II, Ltd. (TCW). The
loan will mature on June 15, 2016, and will be payable in
28 quarterly installments, commencing September 15, 2009.
The annual interest rate on the loan is 9.83%, but the effective
cost for us is approximately 8%, due to the elimination,
following the refinancing, of the political risk insurance
premiums that we had been paying on our equity investment in the
project. There are various restrictive covenants under the loan,
which include limitations on Ortitlans ability to make
distributions to its shareholders. Management believes that as
of March 31, 2010, Ortitlan was in compliance with the
covenants under the loan. As of March 31, 2010,
$40.6 million of the Amatitlan loan was outstanding.
Senior
Loans from International Finance Corporation (IFC) and
Commonwealth Development Corporation (CDC) (The
Zunil Power Plant) Non-Recourse
Orzunil I de Electricidad, Limitada (Orzunil), a wholly owned
subsidiary in Guatemala, has senior loan agreements with IFC and
CDC. The loan from IFC, of which $2.9 million was
outstanding as of March 31, 2010, has a fixed annual
interest rate of 11.775%, and matures on November 15, 2011.
The loan from CDC, of which $1.3 million was outstanding as
of March 31, 2010, has a fixed annual interest rate of
10.300%, and matures on August 15, 2010. There are various
restrictive covenants under the Senior Loans, which include
limitations on Orzunils ability to make distributions to
its shareholders. As of March 31, 2010, Orzunil was in
compliance with the covenants under these senior loans.
New
Financing of Our Projects
Financing
of the North Brawley Power Plant
As a result of the recent ARRA, we intend to refinance the
equity invested in the North Brawley power plant partially with
a cash grant available to us under the ARRA and with long-term
debt of approximately $100.0 million that we are currently
negotiating with a financial institution.
Full-Recourse
Third Party Debt
In December 2008, our subsidiary, Ormat Nevada Inc. (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. Under the credit agreement, Ormat Nevada can
request extensions of credit in the form of loans
and/or
the
issuance of one or 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 Nevadas obligations
under the credit agreement. Ormat Nevadas 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 the 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.
As of March 31, 2010, letters of credit in the amount of
$30.0 million remain issued and outstanding under this
credit agreement with Union Bank.
We also have credit agreements with six commercial banks for an
aggregate amount of $325.0 million. Under these credit
agreements, we or our Israeli subsidiary, Ormat Systems Ltd.,
can request extensions of credit in
39
the form of loans
and/or
the
issuance of one or more letters of credit. The credit agreements
mature between June 2010 and October 2011.
Loans and draws under the credit agreements or under any letters
of credit will bear interest at the respective banks cost
of funds plus a margin.
As of March 31, 2010, loans in the amount of
$158.5 million were outstanding, and letters of credit in
the total amount of 32.5 million remain issued and
outstanding under such credit agreements.
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 commencing January 16, 2010,
and bears annual interest of 6.5%. As of March 31, 2010,
$18.6 million was outstanding under this loan.
We have a $20.0 million term loan with a group of financial
institutions, which matures on August 1, 2017, is payable
in 12 semi-annual installments commencing February 1, 2012,
and bears interest at
6-month
LIBOR plus 5.0%. As of March 31, 2010, $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, and is payable in 10
semi-annual installments commencing May 10, 2010, and bears
interest at
6-month
LIBOR plus 3.25%. As of March 31, 2010, $50.0 million
was outstanding under this loan.
Our obligations under the credit and loan agreements, described
above, are unsecured, but we are subject to a negative pledge in
favor of the banks 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. In some cases, we have agreed
to maintain certain financial ratios such as a debt service
coverage ratio and a debt to equity ratio. The failure to
perform or observe any of the covenants set forth in such
agreements, subject to various cure periods, would result in the
occurrence of an event of default and would enable the lenders
to accelerate all amounts due under each such agreement.
Some of the credit and loan agreements contain cross-default
provisions with respect to other material indebtedness owed by
us to any third party.
We are currently in compliance with our covenants with respect
to these credit and loan agreements, and believe that the
restrictive covenants, financial ratios and other terms of any
of our (or Ormat Systems) full-recourse bank credit
agreements will not materially impact our business plan or plan
of operations.
Letters
of Credit
Some of our customers require our project subsidiaries to post
letters of credit in order to guarantee their respective
performance under relevant contracts. We are also required to
post letters of credit to secure our obligations under various
leases and licenses and may, from time to time, decide to post
letters of credit in lieu of 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.
Two commercial banks have issued such performance letters of
credit in favor of our customers from time to time. As of
March 31, 2010, such banks have agreed to make available to
us letters of credit totaling $60.9 million. As of such
date, such banks have issued letters of credit in the amount of
$43.8 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 six other commercial banks as described above under
Full-Recourse Third Party Debt. As of March 31,
2010, nine letters of credit in the amount of $62.4 million
remained issued and outstanding under the Union Bank credit
agreement.
40
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 and Lehman Brothers Inc. (Morgan Stanley
Geothermal LLC and 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.
The first closing under the agreements occurred in 2007 and
covered the Companys 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
and will receive initially all of the distributable cash flow
generated by the power plants until it recovers the capital that
it has invested in the power plants, while the investors will
receive substantially all of the PTCs and the taxable income or
loss, and the distributable cash flow after Ormat Nevada has
recovered its capital. 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. As a result of the
acquisition by Ormat Nevada, on October 30, 2009, of all of
the Class B membership units of OPC held by Lehman-OPC LLC
(see below), the residual interest decreased to 3.5%.
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 and 30% of the Class B membership units,
which represent 7.5% of the voting rights of OPC, and in total
we have 82.5% of the voting rights in OPC. The investors own 70%
of the Class B membership units, which represent 17.5% of
the voting rights of OPC. Other than in respect of customary
protective rights, all operational decisions in OPC are decided
by the vote of a majority of the membership units. Following the
Flip Date, Ormat Nevadas voting rights will increase to
96.5% and the investors voting rights will decrease to
3.5%. Ormat Nevada retains the controlling voting interest in
OPC both before and after the Flip Date and therefore has
continued to consolidate OPC.
On October 30, 2009, Ormat Nevada acquired from Lehman-OPC
LLC all of the Class B membership units of OPC held by
Lehman-OPC LLC pursuant to a right of first offer for a purchase
price of $18.5 million.
41
Liquidity
Impact of Uncertain Tax positions
As discussed in Note 14 to our Condensed Consolidated
Financial Statements set forth in Item 1 of this quarterly
report, we have a liability associated with unrecognized tax
benefits and related interest and penalties in the amount of
approximately $5.2 million as of March 31, 2010. This
liability is included in long-term liabilities in our
consolidated balance sheet, because we generally do not
anticipate that settlement of the liability will require payment
of cash within the next twelve months. We are not able to
reasonably estimate when we will make any cash payments required
to settle this liability, but believe that the ultimate
settlement of our obligations will not materially affect our
liquidity.
Dividend
The following are the dividends declared by us during the past
two years:
|
|
|
|
|
|
|
|
|
|
|
Dividend Amount
|
|
|
|
|
Date Declared
|
|
per Share
|
|
Record Date
|
|
Payment Date
|
|
May 6, 2008
|
|
$
|
0.05
|
|
|
May 20, 2008
|
|
May 27, 2008
|
August 5, 2008
|
|
$
|
0.05
|
|
|
August 19, 2008
|
|
August 29, 2008
|
November 5, 2008
|
|
$
|
0.05
|
|
|
November 19, 2008
|
|
December 2, 2008
|
February 24, 2009
|
|
$
|
0.07
|
|
|
March 16, 2009
|
|
March 26, 2009
|
May 8, 2009
|
|
$
|
0.06
|
|
|
May 20, 2009
|
|
May 27, 2009
|
August 5, 2009
|
|
$
|
0.06
|
|
|
August 18, 2009
|
|
August 27, 2009
|
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
|
Historical
Cash Flows
The following table sets forth the components of our cash flows
for the relevant periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Net cash provided by operating activities
|
|
$
|
48,240
|
|
|
$
|
42,534
|
|
Net cash used in investing activities
|
|
|
(64,981
|
)
|
|
|
(91,225
|
)
|
Net cash provided by financing activities
|
|
|
13,545
|
|
|
|
56,986
|
|
Translation adjustments on cash and cash equivalents
|
|
|
|
|
|
|
23
|
|
Net change in cash and cash equivalents
|
|
|
(3,196
|
)
|
|
|
8,318
|
|
For the
Three Months ended March 31, 2010
Net cash provided by operating activities for the three months
ended March 31, 2010 was $48.2 million, compared to
$42.5 million for the three months ended March 31,
2009. The net increase of $5.7 million resulted primarily
from: (i) a net decrease in costs and estimated earnings in
excess of billings on uncompleted contracts of
$15.9 million in the three months ended March 31,
2010, compared to a net decrease of $8.7 million in the
three months ended March 31, 2009; and (ii) an
increase in accounts payable and accrued expenses of
$15.3 million in the three months ended March 31,
2010, compared to an increase of $1.1 million in the three
months ended March 31, 2009. Such increase was partially
offset by: (i) the decrease in net income to
$1.8 million in the three months ended March 31, 2010,
from $14.5 million in the three months ended March 31,
2009, mainly as a result of the decrease in operating income, as
described above; and (ii) a gain on sale of GDL of
$6.3 million in the three months ended March 31, 2010.
Net cash used in investing activities for the three months ended
March 31, 2010 was $65.0 million, compared to
$91.2 million for the three months ended March 31,
2009. The principal factors that affected our net cash used in
investing activities during the three months ended
March 31, 2010 were capital expenditures of
$76.5 million, primarily for our facilities under
construction, and a $11.3 million increase in restricted
cash, cash equivalents and marketable securities, which was
offset by $19.6 million cash received from the sale of GDL.
The principal factors that affected our net cash used in
investing activities during the three months
42
ended March 31, 2009 were capital expenditures of
$73.8 million, primarily for our power facilities under
construction, and an $17.2 million increase in restricted
cash, cash equivalents and marketable securities.
Net cash provided by financing activities for the three months
ended March 31, 2010 was $13.5 million, compared to
$57.0 million for the three months ended March 31,
2009. The principal factor that affected the net cash provided
by financing activities during the three months ended
March 31, 2010 was $24.5 million drawn under revolving
lines of credit from banks, which was offset by: (i) the
repayment of long-term debt in the amount of $5.5 million;
and (ii) the payment of a dividend to our shareholders in
the amount of $5.5 million. The principal factor that
affected our net cash provided by financing activities during
the three months ended March 31, 2009 was the receipt of
proceeds of $90.0 million from the Olkaria III Loans,
which was offset by: (i) the repayment of revolving lines
of credit from banks in the amount of $20.0 million,
(ii) the repayment of debt to our parent in the amount of
$7.0 million; (iii) the payment of a dividend to our
shareholders in the amount of $3.2 million; and
(iv) the repayment of long-term debt in the amount of
$1.6 million.
Adjusted
EBITDA
Adjusted EBITDA for the three months ended March 31, 2010
was $32.1 million compared to $37.4 million for the
three months ended March 31, 2009. 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.
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 considered
as an alternative to cash flow from operating activities or as a
measure of liquidity or an alternative to net earnings as
indicators of our operating performance or any other measures of
performance derived in accordance with GAAP. EBITDA and adjusted
EBITDA are presented because we believe they are frequently used
by securities analysts, investors and other interested parties
in the evaluation of a Companys ability to service
and/or
incur
debt. However, other companies in our industry may calculate
EBITDA and adjusted EBITDA differently than we do.
The following table reconciles net cash provided by operating
activities to EBITDA and adjusted EBITDA, for the three months
ended March 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Net cash provided by operating activities
|
|
$
|
48,240
|
|
|
$
|
42,534
|
|
Adjusted for:
|
|
|
|
|
|
|
|
|
Interest expense, net (excluding amortization of deferred
financing costs)
|
|
|
9,021
|
|
|
|
2,391
|
|
Interest income
|
|
|
(197
|
)
|
|
|
(152
|
)
|
Income tax provision
|
|
|
19
|
|
|
|
3,489
|
|
Adjustments to reconcile net income to net cash provided by
operating activities (excluding depreciation and amortization)
|
|
|
(26,006
|
)
|
|
|
(11,896
|
)
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
|
31,077
|
|
|
|
36,366
|
|
Interest, taxes, depreciation and amortization attributable to
the Companys equity in Mammoth-Pacific L.P.
|
|
|
973
|
|
|
|
989
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
32,050
|
|
|
$
|
37,355
|
|
|
|
|
|
|
|
|
|
|
This comparative non-GAAP information is provided to assist
investors in evaluating the impact of the change in the way we
calculate these amounts in performing their financial analysis
of our operations for the periods presented. This information
should not be considered in isolation or as a substitute for, or
superior to, measures of financial performance prepared in
accordance with GAAP or other non-GAAP financial measures.
43
Capital
Expenditures
Our capital expenditures primarily relate to two principal
components: (i) the enhancement of our existing power
plants; and (ii) the development and construction of new
power plants. We expect that the following enhancements of our
existing power plants and the construction of new power plants
will be funded initially from internally generated cash or other
available corporate resources, which we expect to subsequently
refinance with limited or non-recourse debt at the project level.
Puna Project
An enhancement program for
the Puna project is underway to increase the output of the
project by an estimated 8 MW and improve the performance of
the wellfield. The enhancement includes recompletion of the
major production and injection wells and the construction of two
additional OEC units. Permits to start construction have been
obtained and site construction has begun. Equipment
manufacturing has been completed. We signed a memorandum of
understanding with Hawaii Electric Light Company for the sale of
additional electrical power from the Puna project and we are
currently negotiating the final terms of the PPA. Commercial
operation of the power plant is expected in 2010.
East Brawley Project
We have begun
construction and manufacturing of equipment for an additional
30 MW plant in the Brawley Known Geothermal Area in
Imperial County, California, adjacent to the North Brawley
project. We have already drilled several commercial size wells
that we plan to utilize for this project, and are otherwise
awaiting the required construction permits. However, at this
point in time, and until the North Brawley power plant is
stabilized, we are examining the possibility of using the East
Brawley wells on a temporary basis for the benefit of the North
Brawley power plant as part of our ongoing efforts to bring the
North Brawley power plant from its current operational level of
approximately 20 MW to its full design capacity of
50 MW. Any such use would be subject to obtaining
appropriate permits and, if effected, would be discontinued once
the North Brawley power plant is otherwise stabilized at an
acceptable operational level.
GRE Project
We completed the
construction of a 5.5 MW recovered energy generation
project for Great River Energy, which will be located along the
Northern Border pipeline in Martin County, Minnesota. We signed
a
20-year
PPA with Great River Energy. Plant interconnection to the
utility grid line is expected to take place in the second
quarter of 2010. Commercial operation will commence shortly
thereafter.
Jersey Valley Project
We are currently
constructing the Jersey Valley project on Bureau of Land
Management leases located in Churchill County, Nevada. We plan
to build the project with two units. Field development for the
15MW first phase has been completed. Production of the power
generating unit is completed and shipment is on its way. We are
in the process of applying for construction permits. Commercial
operation of the first phase is expected at the end of 2010.
McGinness Hills Project
We are
currently developing the 30 MW McGinness Hills project on Bureau
of Land Management leases located in Lander County, Nevada.
Basic well field site preparation has been completed and permits
to drill have been obtained. Two production wells have been
drilled and drilling for additional wells has begun. We are
progressing with the preparation of the required construction
permits. We signed a
20-year
PPA
with Nevada Power Company. Commercial operation of the power
plant is expected in 2012. Nevada Power Companys
obligation to purchase electricity under the McGinness Hills PPA
is subject to the approval by the Public Utility Commission of
Nevada (PUCN) of a north-south transmission line in Nevada that
will allow Nevada Power Company to take delivery of, and receive
credit for renewable generation in the north part of the state
and deliver such electricity to the southern part of the state.
The PUCN is reviewing the north-south transmission line as part
of Nevada Power Companys triennial Integrated Resource
Plan, which is currently in the discovery phase.
Tuscarora Project
We are currently
developing the 16 MW Tuscarora project on private and Bureau of
Land Management leases located in Elko County, Nevada. The land,
when acquired, contained a drilled production well and we are
continuing with field development work. We signed a
20-year
PPA
with Nevada Power Company. Commercial operation of the power
plant is expected in 2012. Nevada Power Companys
obligation to purchase electricity under the Tuscarora PPA is
subject to the approval by the PUCN of a north-south
transmission line in Nevada that will allow Nevada Power Company
to take delivery of, and receive credit for renewable generation
in the north part of the state and deliver such electricity to
the southern part of
44
the state. The PUCN is reviewing the north-south transmission
line as part of Nevada Power Companys triennial Integrated
Resource Plan, which is currently in the discovery phase.
Carson Lake
We are currently developing
the 20 MW Carson Lake project on Bureau of Land Management
leases located in Churchill County, Nevada. Our initial joint
venture with Nevada Power Company for this project contemplated
a larger project. We are in preliminary discussions to address
the implications of a smaller project. The project is expected
to start commercial operation in 2013.
We have estimated approximately $670 million for
construction of new projects that are still under construction
and have invested approximately $192 million of such
estimate as of March 31, 2010. We expect to invest
approximately $180 million for these power plants in the
rest of 2010 (including the North Brawley power plant).
In addition, we expect to invest approximately $50 million
in the rest of 2010 in new projects under development. In
addition, our operating power plants have capital expenditure
requirements for the rest of 2010 of approximately
$15 million. We have various leases for geothermal
resources, in which we have started exploration activity, for a
total investment amount of approximately $16 million for
the rest of 2010 and we also plan to invest approximately
$3 million in our production facilities.
Exposure
to Market Risks
While, based on current conditions, we believe that we have
sufficient financial resources to fund our activities and
execute our business plans, the cost of obtaining financing for
our project needs may increase significantly or such financing
may be difficult to obtain. A prolonged economic slowdown could
reduce worldwide demand for energy, including our geothermal
energy, REG and other products.
One market risk to which power plants are typically exposed is
the volatility of electricity prices. However, our exposure to
such market risk is currently limited because our long-term PPAs
(except for Puna) have fixed or escalating rate provisions that
limit our exposure to changes in electricity prices. However,
beginning in May 2012, the energy payments under the PPAs of the
Heber 1 and 2 power plants, the Ormesa complex and the Mammoth
complex will be determined by reference to the relevant power
purchasers short run avoided costs. The Puna power plant
is currently benefiting from energy prices which are higher than
the floor under the Puna PPA as a result of the high fuel costs
that impact HELCOs avoided costs.
As of March 31, 2010, 61.0% of our consolidated long-term
debt (including amounts owed to our parent) was in the form of
fixed rate securities, and therefore, not subject to interest
rate volatility risk. As of such date, 39.0% of our debt was in
the form of a floating rate instrument, exposing us to changes
in interest rates in connection therewith. As of March 31,
2010, $254.9 million of our debt remained subject to some
floating rate risk.
We currently maintain our surplus cash in short-term,
interest-bearing bank deposits, money market securities and
commercial paper (with a minimum investment grade rating of AA
by Standard & Poors Ratings Services).
Our cash equivalents and our portfolio of marketable securities
are subject to market risk due to changes in interest rates.
Fixed rate securities may have their market value adversely
impacted due to a rise in interest rates, while floating rate
securities may produce less income than expected if interest
rates fall. Due in part to these factors, our future investment
income may fall short of expectation due to changes in interest
rates or we may suffer losses in principal if we are forced to
sell securities that decline in market value due to changes in
interest rates. However, because we classify our debt securities
as
available-for-sale,
no gains or losses are recognized due to changes in interest
rates unless such securities are sold prior to maturity or
declines in fair value are determined to be
other-than-temporary.
Auction rate securities are securities that are structured with
short-term interest rate reset dates of generally less than
ninety days but with contractual maturities that can be well in
excess of ten years. At the end of each reset period, which
depending on the security can occur on a daily, weekly, or
monthly basis, investors can sell or continue to hold the
securities at par. These securities are subject to fluctuations
in fair value depending on the supply and demand at each auction.
45
Another market risk to which we are exposed is primarily related
to potential adverse changes in foreign currency exchange rates,
in particular the fluctuation of the U.S. dollar versus the
New Israeli Shekel (NIS). Risks attributable to fluctuations in
currency exchange rates can arise when any of our foreign
subsidiaries borrows funds or incurs operating or other expenses
in one type of currency but receives revenues in another. In
such cases, an adverse change in exchange rates can reduce such
subsidiarys ability to meet its debt service obligations,
reduce the amount of cash and income we receive from such
foreign subsidiary, or increase such subsidiarys overall
expenses. Risks attributable to fluctuations in foreign currency
exchange rates can also arise when the currency denomination of
a particular contract is not the U.S. dollar. Substantially
all of our PPAs in the international markets are either
U.S. dollar-denominated or linked to the U.S. dollar.
Our construction contracts from time to time contemplate costs
which are incurred in local currencies. The way we often
mitigate such risk is to receive part of the proceeds from the
sale contract in the currency in which the expenses are
incurred. Through most of 2009, we did not use any material
foreign currency exchange contracts or other derivative
instruments to reduce our exposure to this risk. Currently, we
have forward and option contracts in place to reduce our foreign
currency exposure, and expect to continue to use currency
exchange and other derivative instruments to the extent we deem
such instruments to be the appropriate tool for managing such
exposure. We do not believe that our exchange rate exposure has
or will have a material adverse effect on our financial
condition, results of operations or cash flows.
Concentration
of Credit Risk
Our credit risk is currently concentrated with a limited number
of major customers: Southern California Edison, Hawaii Electric
Light Company, and Sierra Pacific Power Company and Nevada Power
Company (subsidiaries of NV Energy, Inc.). If any of these
electric utilities fails to make payments under its PPAs with
us, such failure would have a material adverse impact on our
financial condition.
Southern California Edison accounted for 25.5% and 17.9% of our
total revenues for the three months ended March 31, 2010
and 2009, respectively. Southern California Edison is also the
power purchaser and revenue source for our Mammoth power plants,
which we account for separately under the equity method of
accounting.
Hawaii Electric Light Company accounted for 7.1% and 9.9% of our
total revenues for the three months ended March 31, 2010
and 2009, respectively.
Sierra Pacific Power Company and Nevada Power Company accounted
for 19.2% and 13.9% of our total revenues for the three months
ended March 31, 2010 and 2009, respectively.
Kenya Power and Lighting Co. Ltd. accounted for 10.7% and 8.3%
of the Companys total revenues for the three months ended
March 31, 2010 and 2009, respectively.
Government
Grants and Tax Benefits
The U.S. government encourages production of electricity
from geothermal resources through certain tax subsidies under
the recently enacted ARRA. We are permitted to claim 30% of the
cost of each new geothermal power plant in the United States as
an ITC against our federal income taxes. Alternatively, we are
permitted to claim a PTC, which in 2010 is 2.2 cents per kWh and
which is adjusted annually for inflation. The PTC may be claimed
for ten years on the electricity output of new geothermal power
plants put into service by December 31, 2013. The owner of
the project must choose between the PTC and the 30% ITC
described above. In either case, under current tax rules, any
unused tax credit has a
1-year
carry
back and a
20-year
carry forward. Whether we claim the PTC or the ITC, we are also
permitted to depreciate most of the plant for tax purposes over
five years on an accelerated basis, meaning that more of the
cost may be deducted in the first few years than during the
remainder of the depreciation period. If we claim the ITC, our
tax basis in the plant that we can recover through
depreciation must be reduced by half of the tax credit. If we
claim a PTC, there is no reduction in the tax basis for
depreciation. Companies that begin construction on, or place in
service qualifying renewable energy facilities, during 2009 or
2010 may choose to apply for a cash grant from the
U.S. Department of Treasury in an amount equal to the ITC.
Under the ARRA, the
46
U.S. Department of Treasury is instructed to pay the cash
grant within 60 days of the application or the date on
which the qualifying facility is placed in service.
Production of electricity from geothermal resources is also
supported under the new Temporary Program For Rapid
Deployment of Renewable Energy and Electric Power Transmission
Projects established with the DOE as part of the
DOEs existing Innovative Technology Loan Guarantee
Program. The new program: (i) extends the scope of the
existing federal loan guarantee program to cover renewable
energy projects, renewable energy component manufacturing
facilities, and electricity transmission projects that embody
established commercial, as well as innovative, technologies; and
(ii) provides an appropriation to cover the credit
subsidy costs of such projects (meaning the estimated
average costs to the federal government from issuing the loan
guarantee, equivalent to a lending banks loan loss
reserve).
To be eligible for a guarantee under the new program, a
supported project must break ground, and the guarantee must be
issued, by September 30, 2011. A project supported by the
federal guarantee under the new program must pay prevailing
federal wages.
Based on the appropriation of $6 billion dollars to pay the
credit subsidy costs of guarantees issued under the new program,
it is likely that between $60 billion to $120 billion
of financing (assuming average subsidy requirements between 10%
and 5%, respectively) will be available to eligible projects,
including geothermal power plants.
Our subsidiary, Ormat Systems, received Benefited
Enterprise status under Israels Law for
Encouragement of Capital Investments, 1959 (the Investment Law),
with respect to two of its investment programs. As a Benefited
Enterprise, Ormat Systems was exempt from Israeli income taxes
with respect to income derived from the first benefited
investment for a period of two years that started in 2004, and
thereafter such income 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 that started in 2007, and thereafter
such income is subject to reduced Israeli income tax rates which
will not exceed 25% for an additional five years. These benefits
are subject to certain conditions, including among other things,
that all transactions between Ormat Systems and our affiliates
are at arms length, and that the management and control of Ormat
Systems will be from Israel during the whole period of the tax
benefits. A change in control should be reported to the Israeli
Tax Authorities in order to maintain the tax benefits. In
addition, as an industrial company, Ormat Systems is entitled to
accelerated depreciation on equipment used for its industrial
activities. Under the provisions of certain tax regulations
published in Israel in 2005, industrial companies whose
operations are mostly Eligible Operations are
entitled to claim accelerated depreciation at the rate of 100%
on machinery and equipment acquired from July 1, 2005 to
December 31, 2006. Accelerated depreciation is to be
claimed over two years. In the year in which the equipment was
acquired, the regular depreciation rate is to be claimed with
the remainder to be claimed in the second year. Under the
provisions of certain tax regulations published in Israel in
July 2008, industrial companies whose operations are mostly
Eligible Operations are entitled to claim
accelerated depreciation at the rate of 50% on machinery and
equipment acquired from June 1, 2008 to May 31, 2009
and placed in service at the later of six months after
acquisition or before May 31, 2009.
|
|
ITEM 3.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
We incorporate by reference the information appearing under
Exposure to Market Risks and Concentration of
Credit Risk in Part I, Item 2 of this quarterly
report on
Form 10-Q.
|
|
ITEM 4.
|
CONTROLS
AND PROCEDURES
|
|
|
a.
|
Evaluation
of disclosure controls and procedures
|
Our management, with the participation of our Chief Executive
Officer and Chief Financial Officer, evaluated the effectiveness
of our disclosure controls and procedures to ensure that the
information required to be disclosed in our filings pursuant to
Rule 13a-15
under the Securities and Exchange Act of 1934, as amended, is
recorded, processed, summarized and reported within the time
periods specified in the Securities
47
and Exchange Commissions rules and forms and to ensure
that such information is accumulated and communicated to
management, including our Chief Executive Officer and Chief
Financial Officer as appropriate to allow timely decisions
regarding required disclosure. Based on that evaluation as of
March 31, 2010, our Chief Executive Officer and Chief
Financial Officer have concluded that our disclosure controls
and procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934, as amended) were
effective.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
|
|
b.
|
Changes
in internal controls over financial reporting
|
There were no changes in our internal controls over financial
reporting in the first quarter of 2010 that have materially
affected or are reasonably likely to materially affect our
internal controls over financial reporting.
PART II
OTHER INFORMATION
|
|
ITEM 1.
|
LEGAL
PROCEEDINGS
|
Securities
Class Actions
Following the Companys public announcement that it would
restate certain of its financial results due to a change in the
Companys accounting treatment for certain exploration and
development costs, three securities class action lawsuits were
filed in the United States District Court for the District of
Nevada on March 9, 2010, March 18, 2010 and
April 7, 2010. These complaints assert claims against the
Company and certain officers and directors for alleged violation
of Sections 10(b) and 20(a) of the Securities Exchange Act
of 1934 (the Exchange Act). One complaint also asserts claims
for alleged violations of Sections 11, 12(a)(2) and 15 of
the Securities Act of 1933 (the Securities Act). All three
complaints allege claims on behalf of a putative class of
purchasers of Company stock between May 6, 2008 or
May 7, 2008 and February 23, 2010 or February 24,
2010. The complaints allege, inter alia, that the defendants
made false
and/or
misleading statements
and/or
failed to make disclosures regarding the Companys
financial results and compliance with Generally Accepted
Accounting Principles (GAAP); that these misstatements
and/or
nondisclosures resulted in overstatement of Company financial
results
and/or
artificially inflated the Companys stock price; and that
following the Companys February 24, 2010 public
announcement, the price of the Companys stock declined.
Each complaint seeks certification as a class action and
unspecified compensatory damages plus interest as well as
counsel fees and expert fees. The Company does not believe that
these lawsuits have merit and intends to defend itself
vigorously.
Stockholder
Derivative Cases
Three stockholder derivative lawsuits have also been filed in
connection with the Companys public announcement that it
would restate certain of its financial results due to a change
in the Companys 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 the other in the United States District Court for the
District of Nevada on March 29, 2010. All three 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 federal court derivative
complaint seeks compensatory damages on behalf of the Company
and both the federal and state court derivative complaints seek
restitution from the defendants on behalf of the Company. The
derivative complaints also seek other relief, including counsel
fees. The Company believes the allegations in these purported
derivative actions are also without merit and is defending the
actions vigorously In addition, from time to time, we (and our
subsidiaries) are named as a party to various lawsuits, claims
and other legal
48
and regulatory proceedings that arise in the ordinary course of
our (and their) 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, we accrue
reserves in accordance with accounting principles generally
accepted in the U.S. We do not believe that any of these
proceedings, individually or in the aggregate, would materially
and adversely affect our business, financial condition, future
results and cash flows.
Other
The Company is a defendant in various legal and regulatory
proceedings in the ordinary course of business. It is the
opinion of the Companys management that the expected
outcome of these matters, individually or in the aggregate, will
not have a material effect on the results of operations and
financial condition of the Company.
A comprehensive discussion of our risk factors is included in
the Risk Factors section of our annual report on
Form 10-K
for the year ended December 31, 2009 filed with the SEC on
March 8, 2010.
|
|
ITEM 2.
|
UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
|
There were no unregistered sales of equity securities of the
Company during the first fiscal quarter of 2010.
|
|
ITEM 3.
|
DEFAULTS
UPON SENIOR SECURITIES
|
Our management believes that we are currently in compliance with
our covenants with respect to our third-party debt.
|
|
ITEM 5.
|
OTHER
INFORMATION
|
None.
|
|
|
|
|
Exhibit No.
|
|
Document
|
|
|
3
|
.1
|
|
Second Amended and Restated Certificate of Incorporation,
incorporated by reference to Exhibit 3.1 to Ormat
Technologies, Inc. Registration Statement on
Form S-1
(File
No. 333-117527)
to the Securities and Exchange Commission on July 20, 2004.
|
|
3
|
.2
|
|
Third Amended and Restated By-laws, incorporated by reference to
Exhibit 3.2 to Ormat Technologies, Inc. Current Report on
Form 8-K
to the Securities and Exchange Commission on February 26,
2009.
|
|
3
|
.3
|
|
Amended and Restated Limited Liability Company Agreement of OPC
LLC dated June 7, 2007, by and among Ormat Nevada Inc.,
Morgan Stanley Geothermal LLC, and Lehman-OPC LLC, incorporated
by reference to Exhibit 3.1 to Ormat Technologies, Inc.
Current Report on
Form 8-K
to the Securities and Exchange Commission on June 13, 2007.
|
|
4
|
.3
|
|
Form of Rights Agreement by and between Ormat Technologies, Inc.
and American Stock Transfer & Trust Company,
incorporated by reference to Exhibit 4.3 to Ormat
Technologies, Inc. Registration Statement Amendment No. 2
on
Form S-1
(File
No. 333-117527)
to the Securities and Exchange Commission on October 22,
2004.
|
|
4
|
.4
|
|
Indenture for Senior Debt Securities, dated as of
January 16, 2006, between Ormat Technologies, Inc. and
Union Bank of California, incorporated by reference to
Exhibit 4.2 to Ormat Technologies, Inc. Registration
Statement Amendment No. 1 on
Form S-3
(File
No. 333-131064)
to the Securities and Exchange Commission on January 26,
2006.
|
|
4
|
.5
|
|
Indenture for Subordinated Debt Securities, dated as of
January 16, 2006, between Ormat Technologies, Inc. and
Union Bank of California, incorporated by reference to
Exhibit 4.3 to Ormat Technologies, Inc. Registration
Statement Amendment No. 1 on
Form S-3
(File
No. 333-131064)
to the Securities and Exchange Commission on January 26,
2006
|
49
|
|
|
|
|
Exhibit No.
|
|
Document
|
|
|
10
|
.1.13
|
|
Membership Interest Purchase Agreement, dated as of
October 30, 2009, by and among
Lehman-OPC
LLC, Ormat Nevada Inc. and OPC LLC, incorporated by reference to
Exhibit 10.1.13 to Ormat Technologies, Inc. Current Report on
Form
8-K
to
the Securities and Exchange Commission on November 3, 2009.
|
|
31
|
.1
|
|
Certification of the Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, filed
herewith.
|
|
31
|
.2
|
|
Certification of the Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, filed
herewith.
|
|
32
|
.1
|
|
Certification of the Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, filed
herewith.
|
|
32
|
.2
|
|
Certification of the Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, filed
herewith.
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50
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
ORMAT TECHNOLOGIES, INC.
Name: Joseph Tenne
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Title:
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Chief Financial Officer
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Date: May 7, 2010
51
EXHIBIT INDEX
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Exhibit No.
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Document
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3
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.1
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Second Amended and Restated Certificate of Incorporation,
incorporated by reference to Exhibit 3.1 to Ormat
Technologies, Inc. Registration Statement on
Form S-1
(File
No. 333-117527)
to the Securities and Exchange Commission on July 20, 2004.
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3
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.2
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Third Amended and Restated By-laws, incorporated by reference to
Exhibit 3.2 to Ormat Technologies, Inc. Current Report on
Form 8-K
to the Securities and Exchange Commission on February 26,
2009.
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3
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.3
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Amended and Restated Limited Liability Company Agreement of OPC
LLC dated June 7, 2007, by and among Ormat Nevada Inc.,
Morgan Stanley Geothermal LLC, and Lehman-OPC LLC, incorporated
by reference to Exhibit 3.1 to Ormat Technologies, Inc.
Current Report on
Form 8-K
to the Securities and Exchange Commission on June 13, 2007.
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4
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.3
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Form of Rights Agreement by and between Ormat Technologies, Inc.
and American Stock Transfer & Trust Company,
incorporated by reference to Exhibit 4.3 to Ormat
Technologies, Inc. Registration Statement Amendment No. 2
on
Form S-1
(File
No. 333-117527)
to the Securities and Exchange Commission on October 22,
2004.
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4
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.4
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Indenture for Senior Debt Securities, dated as of
January 16, 2006, between Ormat Technologies, Inc. and
Union Bank of California, incorporated by reference to
Exhibit 4.2 to Ormat Technologies, Inc. Registration
Statement Amendment No. 1 on
Form S-3
(File
No. 333-131064)
to the Securities and Exchange Commission on January 26,
2006.
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4
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.5
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Indenture for Subordinated Debt Securities, dated as of
January 16, 2006, between Ormat Technologies, Inc. and
Union Bank of California, incorporated by reference to
Exhibit 4.3 to Ormat Technologies, Inc. Registration
Statement Amendment No. 1 on
Form S-3
(File
No. 333-131064)
to the Securities and Exchange Commission on January 26,
2006.
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10
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.1.13
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Membership Interest Purchase Agreement, dated as of
October 30, 2009, by and among
Lehman-OPC
LLC, Ormat Nevada Inc. and OPC LLC, incorporated by reference to
Exhibit 10.1.13 to Ormat Technologies, Inc. Current Report
on Form
8-K
to the Securities and Exchange Commission on November 3,
2009.
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31
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.1
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Certification of the Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, filed
herewith.
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31
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.2
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Certification of the Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, filed
herewith.
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32
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.1
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Certification of the Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, filed
herewith.
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32
|
.2
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Certification of the Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, filed
herewith.
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52
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