ORMAT TECHNOLOGIES, INC. - FORM 8-K - EX-99.1 - EXHIBIT 99.1

Attached files

file	filename
8-K - 8-K - ORMAT TECHNOLOGIES, INC.	zk1211900.htm

Exhibit 99.1

North Brawley Power Plant

Asset Impairment Analysis

****

Prepared for

Ormat Industries Ltd.

August 2012

Table of Contents

Chapter A - Introduction	3
Chapter B - Executive Summary	13
Chapter C - Description of the Company and Subject Assets	18
Chapter D – General Economic Outlook and Industry Analysis	20
Chapter E - Valuation	32
Chapter F – Exhibits	41

Chapter A - Introduction

1.1

General

Giza Singer Even (Here and after "GSE") has been mandated by Ormat Industries Ltd. (“Ormat” or the “Company”) to assist Ormat's management with their asset impairment analysis in connection with the North Brawley power plant ("North Brawley" or the "Subject Assets") to meet the requirements under IFRS accounting standards ("the Report"). In order to prepare the Report, GSE and Ormat has retained the advisory services of Duff & Phelps, a world-class global independent financial advisory firm with strong expertise and capabilities in the area of valuation services ("D&P"). This report was prepared by GSE in cooperation with a D&P valuation team.

The Report includes a description of the methodology and main assumptions and analyses used by the Company, D&P and GSE for assessing the value of North Brawley. Having said that, the description does not purport to provide a full and detailed breakdown of all the procedures that we applied in formulating the Report.

1.2	Reliance on Information Received from the Company

In formulating this report, GSE and D&P assumed and relied on the accuracy, completeness, and up-to-datedness of the information received from the Company, including financial data and any forward-looking information. GSE is not responsible for independently verifying the information it has received, and accordingly, did not conduct an independent examination of this information, other than reasonability tests.

While preparing thus report, we also addressed, among other things, forecasts that were submitted to us by the Company. These projections are uncertain suppositions and expectations regarding the future, partly based on information existing in the Company as of the date of the valuation ("Valuation Date"), as well as various assumptions and expectations pertaining to the Company and to numerous extraneous factors, including the situation in the market segment in which the Company operates, potential competitors, and the general market situation. It should therefore be emphasized that there is no certainty that these forecasts and expectations will fully or partially materialize. The assessments and forecasts of the Company's Management, apart from being based on these assumptions, relate to the Company's future intentions and goals as of the Valuation Date. These intentions and goals are materially influenced by the situation in the Company and in the market and need to be continuously adjusted to the various changes in the working assumptions, the Company's situation and the general economic situation. Any such change stands to influence the chance that these estimations will materialize. If the estimations of the Company's Management do not materialize, the actual results may vary materially from the results projected or inferred from these estimations, insofar as they were used in this opinion, noting that the Fair Value was appraised in this report, as set out in the accounting standard chapter.

1.3	Forward-looking Information

In this report, we also addressed forward-looking information that was submitted to us by the Company's management. Forward-looking information is uncertain information concerning the future, which is based on information available to the Company on the Valuation Date and includes management's estimations or intentions as of the Valuation Date. If management's projections do not materialize, the actual results may vary materially from the results estimated or implied from this information, insofar as they were used in this report.

1.4	Limitations in the Application of the Report

An economic assessment is not an exact science, and is intended to reflect in a reasonable and fair manner the situation at a given time, based on known data, basic assumptions and forecasts. Changes in key variables and/or other information may alter the basis for the basic assumptions and alter the conclusions accordingly.

This report does not constitute a due diligence study and does not purport to contain the information, investigations and tests or any other information contained in a due diligence study, including an examination of the Company's contracts and engagements.

We emphasize that this report does not constitute legal advice or a legal opinion. The interpretation of various documents that we reviewed was done exclusively for the purpose of forming and providing this report.

The information appearing in the Report does not presume to include all the information required by a potential investor, and is not meant to determine the value for a specific investor. Different investors may have different objectives and methods of examination based on other assumptions, and accordingly, the price they would be willing to pay will vary.

1.5	Personal and Financial Relationship with the Company

We hereby confirm that we have no personal interest in the Company, other than the fact that we receive a fee for providing this report, and our professional fees are not contingent on the results of this report.

It should be noted that in past two years, GSE conducted an impairment analysis of the North Brawley Power Plant for the Company, in connection with the Company's annual financial statements as follows:

Subject of the Opinion	Date of the Opinion	Relevant accounting Standard	Work Method	Valuation Results ($ 000's)	WACC
North Brawley	December 2010	IFRS	DCF	139,009	8%
North Brawley	December 2011	IFRS	DCF	156,191	8%

In connection with this report, we should note that GSE will receive a letter of indemnity from the Company in the event that GSE is sued in a legal proceeding for the payment of any amount to the Company or to a third party for a cause of action that could stem, directly or indirectly, from this report. In such case, the Company shall indemnify GSE for any expense that GSE shall incur or be required to pay for legal representation, legal advice, professional consulting, defense against legal proceedings, negotiations, etc. The Company shall also indemnify GSE for the amount that it shall be ordered to pay to a third party in a legal proceeding.

1.6	Reference to the Report

We consent that this report will be included in the 2012 2nd quarter report of Ormat Industries Ltd, and in a current report on form 8-k of Ormat Technologies, Inc.

This report may not be used for any other purpose without receiving explicit prior and written permission from GSE. Anyone using the Report, in whole or in part, other than for the purposes for which it was submitted, and without the prior written approval of GSE, may be sued therefore.

1.7	Limitation of Liability

This report is intended for the use of the Company's Management and for the purpose described above, and it may not be used for any other purpose, including transferring the Report to a third party or citing it, without our prior written consent. In no event, whether we have given our consent or not, will we not assume any responsibility toward any third party which was forwarded the Report.

In the course of our work, we received information, explanations, data and representations from the Company and/or from D&P and/or someone on the Company's behalf (the “Information”). The responsibility for the information lies with whoever provided such information. The ambit of our work does not include an examination and/or verification of said Information. Consequently, our work shall not be considered and will not constitute a confirmation of the veracity, completeness or accuracy of the Information provided to us. In no event will we be liable for any loss, damage, cost or expenditure that might be caused in any manner or form from acts of fraud, misrepresentation, deception, submission of Information that is not true or complete or obstruction of information on the part of the Company and/or D&P and/or anyone on the Company's behalf, or any other reliance on the Information.

In general, forecasts tend to relate to future events and are based on reasonable assumptions made on the date of the forecast. Such assumptions may change over the forecasted period, and consequently forecasts made at the time of the valuation may differ from actual financial results and/or from estimates made at a later date. Therefore, these forecasts may not be treated with the same level of confidence attributed to data appearing in audited financial statements. We offer no opinion regarding the correctness of the forecasts made by the Company, D&P and/or by anyone on their behalf with the financial results that will actually be obtained.

The Report does not constitute a due diligence study and should not be relied on as such. Moreover, financial assessments do not presume to be an exact science, and their conclusions are often contingent on the subjective judgment exercised by the valuator. Although we believe that the value that we have set is reasonable based on the information submitted to us, another value appraiser may reach a different result.

1.8	Sources of Information and Valuation Procedures

Sources of Information

In the course of the Report, we relied upon financial and other information, including prospective financial information, obtained from the Company, D&P and from various public, financial, and industry sources. Our conclusion is dependent on such information being complete and accurate in all material respects. We will not accept responsibility for the accuracy and completeness of such provided information.

The principal sources of information used in performing our valuation include:

§	Discussions with the Company's management and with D&P, as follows:

·	Mrs. Yehudit Bronicki, CEO and Director, Ormat Industries Ltd. and Ormat Technologies, Inc.

·	Mr. Yoram Bronicki, President, COO and Director, Ormat Technologies, Inc.

·	Mr. Joseph Tenne, CFO, Ormat Industries Ltd. and Ormat Technologies, Inc.

·	Mr. Amit Gorka, V.P Corporate Controller, Ormat Industries Ltd. and Ormat Technologies, Inc.

·	Mr. Eyal Hen, Director of Finance, Ormat Technologies Inc.

·	Mr. Joseph Omoworare, Valuation Services Managing Director, Duff & Phelps

§	Historical cost and financial statement information provided by Ormat Technologies, Inc.

§	Ormat Technologies, Inc. Management’s financial projections for North Brawley under several capacity scenarios and for both pricing scenarios (Southern California Edison Company, and Third Party Off-taker)

§	Power Purchase Agreement (“PPA”) related to North Brawley

§	Documentation provided by Management in regards to Amendments to the current PPA with Southern California Edison company ( "SCE")

§	North Brawley plant basis summary, provided by Management, as of the Valuation Date

§	Other publicly available information from sources, but not limited to, Capital IQ, and SNL, deemed relevant to preparation of this report

§	Financial models, analyses and North Brawley Asset Impairment Analysis report prepared by D&P

Valuation Procedures

For the purpose of preparing this report, the Company's management provided D&P and GSE with historical and forecasted performance characteristics for North Brawley, including generation output, additional capital expenditure requirements to improve output, energy revenues, along with plant and operating expenses. D&P and GSE have adopted management forecasts and assumptions. To check the reasonability of said forecasts and assumptions, GSE and D&P have conducted several interviews and conversations with the management and have reviewed various relevant materials provided by the Company. Procedures, investigations, and financial analyses with respect to the preparation of this report included, but were not limited to, the items summarized below:

·	Analysis of conditions in, and the economic outlook for, the geothermal / renewable energy sector

·	Analysis of general market data, including economic, governmental, and environmental forces

·	Analysis of the assumptions and estimates made by the Company's management pertaining to the two pricing scenarios (Third Party Off-taker and SCE)

·	Discussions concerning the history, current state, and future operations of the Subject Asset;

·	Discussions with the Company's management to obtain an explanation and clarification of data provided

·	Review of the documentation provided by the Company's management in regards to amendments to the current Power Purchase Agreement (“PPA”) with Southern California Edison (SCE)

·	Review of certain long term contract pricing term sheets and existing PPAs for related geothermal facilities with various third parties

·	Review of the latest internal management memo on the status of the negotiations pertaining to a PPA for North Brawley with a third party Off-taker, as of the Valuation Date and related updated term sheet

Analysis of financial and operating projections including revenues, operating margins (e.g., earnings before interest and taxes), working capital investments, production tax credits, and capital expenditures based on the Subject Asset’s historical operating results, industry results and expectations, and management representations as it relates to the Subject Assets for the several capacity generation cases

·	Estimation of an appropriate Weighted Average Cost of Capital (“WACC”)

1.9	The Accounting Standard

At the request of the Company, the valuation will be used for implementing International Accounting Standard No. 36 regarding asset impairment (hereinafter: the "Standard" or "IAS 36") in its financial statements.

The purpose of the Standard is to prescribe the procedures that an enterprise must apply to ensure that its assets are carried at no more than their recoverable amount. An asset is carried at more than its recoverable amount when the carrying value of the asset exceeds the amount to be recovered through use or sale of the asset. In this case, the asset value has been impaired, and the Standard requires the corporation to recognize an impairment loss. The Standard also specifies when a corporation should reverse an impairment loss and requires certain disclosures for impaired assets, and for investments in investee companies that are not subsidiaries, which are carried in the financial statements in an amount that significantly exceeds their market value or net sale price.

The Standard prescribes the accounting treatment and statement required in the event of asset impairment. If an enterprise prepares consolidated financial statements (including proportionate consolidation), the Standard will be applied to the accounting treatment of the impairment of all the assets appearing in the enterprise's consolidated balance sheet, including investments in investee companies that are not subsidiaries, goodwill stemming from the acquisition of subsidiaries and fair value adjustments. In effect, this Standard applies to investments in subsidiaries and jointly controlled companies, so that provisions for impairment loss, which are recognized in the consolidated financial statements with respect to assets of the subsidiary or the jointly-controlled company, including goodwill and fair value adjustments, will be stated in the separate financial statements of the parent company as a reduction of the investment account in the subsidiary or jointly-controlled company.

The Standard prescribes that the recoverable amount of an asset should be estimated whenever there are indications that an asset may be impaired.

The Standard requires recognizing the impairment loss of an asset (i.e. the value of the asset has declined) whenever the carrying amount of the asset exceeds its recoverable amount. An impairment loss will be recognized in the statement of profit and loss for those assets stated at cost and should be treated as a revaluation decrease, and only for those assets carried at a revalued amount in accordance with other accounting standards or in accordance with the provisions of any law.

The Standard prescribes that a recoverable amount shall be calculated as the Fair Value less costs to sell or Value in Use, whichever is higher:

1.	The Value in Use of the asset is the estimate of the present value of future cash flows to be derived from use and disposal of the asset at the end of its useful life.

2.	Fair value less costs to sell is the amount obtainable from the sale of an asset or Cash-Generating Unit in an arm’s length transaction between knowledgeable, willing parties, less the costs of disposal.

The Standard states that the best evidence of an asset’s Fair Value less costs to sell is a price in a binding sale agreement in an arm’s length transaction, adjusted for incremental costs that would be directly attributable to the disposal of the asset.

If there is no binding sale agreement but an asset is traded in an active market, Fair Value less costs to sell is the asset’s market price less the costs of disposal. The appropriate market price is usually the current bid price. When current bid prices are unavailable, the price of the most recent transaction may provide a basis from which to estimate Fair Value less costs to sell, provided that there has not been a significant change in economic circumstances between the transaction date and the date as at which the estimate is made.

If there is no binding sale agreement or active market for an asset, Fair Value less costs to sell is based on the best information available to reflect the amount that an entity could obtain, at the balance sheet date, from the disposal of the asset in an arm’s length transaction between knowledgeable, willing parties, after deducting the costs of disposal. In determining this amount, an entity considers the outcome of recent transactions for similar assets within the same industry. Fair Value less costs to sell does not reflect a forced sale, unless management is compelled to sell immediately.

1.10	Details on the Valuating Company

Giza Singer Even is a leading Israeli financial advisory and investment banking firm. Throughout its 25 years of operations, the firm has been involved in the largest transactions and privatization processes in Israel and has serviced the largest corporations in the Israeli capital market.

Giza Singer Even is operating through three independent divisions:

§	Investment Banking and Underwriting: the division provides services for various transactions as mergers and acquisitions, corporate finance, public offerings and debt rating. The division provides underwriting services through its subsidiary- GSE Capital Markets.

§	Financial advisory services: the division offers a wide range of services, including business plans, valuation and fair value measurements services, applied economics services and legal expert opinions

Analytical Research and Corporate Governance: our subsidiary, GSE Analytical Research and Corporate Governance provides debt analysis and consulting services to leading financial institutions as banks and institutional investors in Israel. The firm has substantially advanced its operations in this area following the increased regulatory requirements in connection with investments in corporate bonds

This report has been prepared by a team headed by Eyal Szewach. Mr. Szewach holds a B.Sc in Electronics Engineering from the Technion – Israel institute of technology and a M.B.A in Finance from the Tel-Aviv University.

Sincerely yours,

Giza Singer Even

August 2012

Chapter B - Executive Summary

1. Description of the Company and Subject Assets

Ormat Technologies, Inc.

Ormat is the leading vertically-integrated company primarily engaged in the geothermal and recovered energy power business. The Company designs, develops, owns and operates geothermal and recovered energy-based power plants around the world. Additionally, the Company designs, manufactures and sells geothermal and recovered energy power units and other power-generating equipment, and provides related services. With more than four decades of experience in geothermal and recovered-energy generation, Ormat products and systems are covered by 84 U.S. patents.

§	North Brawley Facility

General

The North Brawley Geothermal Power Plant project ("The Plant") is located in Brawley, California. The plant was placed in service on January 15, 2010 and consists of five (5) water cooled Ormat Energy Converter Units, water system and other auxiliary systems to produce up to 50 MW of electricity. The Plant is an addition to the expanding network of geothermal type power plants in the area, which make use of the high temperature fluid beneath the surface to produce steam or brine and induce rotation in a turbine / generator configuration.

Since early 2009, Brawley has been hampered by four major factors:

·	Inability to circulate the design flow due to injection field limitations, and lack of available production wells

·	High operating costs due to the cost of maintaining filtration on the injection wells and cleanouts of the injection wells

·	High well field operating costs due to early failures of the production pumps

·	Additional capital expenditure investment in pursuit of solutions to the injection and the production issues, including filtration and separation systems, drilling or modifying the injection wells, drilling production wells, adding injection pumps and constructing pipelines for the new wells

As of the Valuation Date the facility is capable of producing approximately 25MW of electricity. Due to progress in the interpretation of the results from the 3-D seismic survey which was completed in 2011, Management now have detailed information about the resource.

Management’s assessment of the potential of the field remains unchanged and it believes that the generation targets of 45MW to 50MW that it has used in the past are still valid. Management expects that increased generation capacity is achievable by the beginning of 2014, commensurate with capital investment plan designed to improve capacity. Management also believes that there has been good progress in improving the service life of the production pumps which it currently sees as the biggest cost driver. The progress in interpretation of the nature of the reservoir through the use of a 3-D seismic survey improves the ability to define targets for hot low salinity production wells and matching injection wells to provide pressure support for the production wells.

Power Purchase Agreement – Renegotiation Status

North Brawley currently delivers power to Southern California Edison (“SCE”) under a 20 year Power Purchase Agreement (“PPA”) signed in 2007. In light of the current market conditions in the region, Ormat submitted a proposal to the Southern California Public Power Authority (“SCPPA”) for a long term PPA for North Brawley, on September 8, 2011. A Third Party Off-taker (“Third Party Off-taker”), which is a member of SCPPA, expressed interest in the proposal. After subsequent discussions and negotiations, revised term sheets were submitted to the Third Party Off-taker for North Brawley in November 2011, and December, 2011, with further revisions to the term sheet received from the Third Party Off-taker as of the Valuation Date.

Although a final decision has not yet been reached, Management has confirmed that the prospects of the negotiations remain favorable and the Third Party Off-taker has taken certain steps to further progress the contracting (including receiving key executives' approval and commitment) and has agreed to purchase up to 25 MW of capacity. Ormat is currently working with SCE on a bilateral amendment (“Amendment No. 6” or the “Amendment”) of the previous PPA, which will allow them to sign a new PPA with the Third Party Off-taker.

2. Description of the Valuation Methodology

To estimate the Fair Value of North Brawley under IAS 36, a DCF analysis was utilized. Under IFRS - IAS 36, an asset is considered to be impaired if the carrying value of the asset is greater than its estimated Fair Value. The impairment is recorded in the amount by which the carrying value exceeds the Fair Value of the asset.

In consideration of the current long term power purchase contract negotiations being currently undertaken by the Company, and as requested by the Company, the analysis has been conducted using the expected cash flow approach. To estimate a value for the long-lived assets we conducted a probability-weighted valuation analysis pertaining to the Third Party Off-taker and SCE pricing scenarios (further elaborated below) provided by the Company. Additionally, since the exact generation of the facility could not be calculated due to recent construction and addition of new wells, as mentioned in the Subject Asset description (see Chapter C), we used high probability and low probability generation assumptions under each of the two pricing scenarios (Third Party Off-taker and SCE), each with four power generation capacity cases; a 37MW case, a 40MW case, a 45MW case, and a 50MW case (collectively 8 cases).

The Fair Value of the assets of North Brawley as of the Valuation Date was therefore estimated by:

·	Determining operational characteristics of the Plant's four generation scenarios; a 37MW, a 40MW, a 45MW, and a 50MW scenario

·	Forecasting revenues and variable operating costs as applicable, including energy prices for the electric output under two pricing scenarios (Third Party Off-taker and SCE)

·	Forecasting fixed expenses and capital expenditures as applicable for each case

Performing a DCF analysis for each generation case under each pricing scenario. The DCF for each generation case was then assigned a probability, estimated by the Company's management, and thereafter each pricing scenario was assigned a probability, based on the Company's estimates of its probability to materialize. The Fair Value was then calculated by summing the total weighted expected value of all cases.

3. Weighted Average Cost of Capital

The weighted average cost of capital was calculated by weighting the required returns on fixed income and common equity capital in proportion to their estimated percentages in an expected capital structure. The valuation model assumes a 8% weighted average cost of capital (WACC) for the capacity under a contractual environment and a 9% weighted average cost of capital (WACC) for the capacity not under contract (reflecting the underlying increased uncertainty in the Third Party Off-taker scenario)

4. Valuation Conclusion

4.1 Fair Value

Based on probabilities provided by the Company's Management, the Fair Value of North Brawley is estimated at $141 million (pre disposal costs), as exemplified below:

Case	Third Party Off-taker DCF		Weighting			SCE DCF		Weighting			Probability weighted Valuation		Case Weighting			Expected Value
37MW Case		134,460		90	%		68,250		10	%		127,839		50.0	%		63,920
40MW Case		144,904		90	%		76,230		10	%		138,037		25.0	%		34,509
45MW Case		163,408		90	%		87,792		10	%		155,486		12.5	%		19,481
50MW Case		190,506		90	%		112,189		10	%		182,674		12.5	%		22,834
Total														100.0	%		140,744

4.2 Disposal Costs

Based on discussions with the management we assumed disposal costs estimated at 1% of the Fair Value, totaling $1.4 million

4.3 Conclusion

We estimate that the Fair Value of North Brawley, less costs to sell, is $139 million

4.4 Sensitivity Analysis

4.4.1 Sensitivity to the WACC

We have performed a sensitivity analysis for the value of North Brawley, less costs to sell, with respect to the weighted average cost of capital as follows:

% Change in WACC			(1	)%			(0.5	)%			8	%1			+0.50	%			+1	%
Fair Value (less costs to sell)			156.2				147.6				139.3				131.6				124.3

1	8% for the contracted capacity and 9% for the uncontracted capacity

4.4.2 Sensitivity – probability weighting - Third Party Off-taker vs. SCE pricing scenarios

We have performed a sensitivity analysis for the value of North Brawley, less costs to sell, with respect to the probability weighting of the Third Party Off-taker vs. SCE pricing scenarios, as follows:

Probability SCE / Third Party Off taker			40/60	%			30/70	%			20/80	%			10/90	%			0/100	%
Fair Value (less costs to sell)			118.7				125.5				132.5				139.3				146.2

Chapter C - the Company and Subject Assets

Ormat Technologies, Inc.

Description of Subject Assets

General

The North Brawley Geothermal Power Plant project ("The Plant") is located in Brawley, California. The plant was placed in service on January 15, 2010 and consists of five (5) water cooled Ormat Energy Converter Units, water system and other auxiliary systems to produce up to 50 MW of electricity. The Plant is an addition to the expanding network of geothermal Type Power Plants in the area, which make use of the high temperature fluid beneath the surface to produce steam or brine and induce rotation in a turbine / generator configuration.

Since early 2009, Brawley has been hampered by four major factors:

· Inability to circulate the design flow due to injection field limitations, and lack of available production wells

· High operating costs due to the cost of maintaining filtration on the injection wells and cleanouts of the injection wells

· High well field operating costs due to early failures of the production pumps

· Additional capital expenditure investment in pursuit of solutions to the injection and the production issues, including filtration and separation systems, drilling or modifying the injection wells, drilling production wells, adding injection pumps and constructing pipelines for the new wells

As of the Valuation Date the facility is producing approximately 25MW of electricity. Due to progress in the interpretation of the results from the 3-D seismic survey which was completed in 2011, Management now have detailed information about the resource, and as a result are currently in the process of re-drilling a damaged well and drilling a new production well.

Management’s assessment of the potential of the field remains unchanged and it believes that the generation targets of 45MW to 50MW that it has used in the past are still valid. Management also believes that there has been good progress in improving the service life of the production pumps which it currently sees as the biggest cost driver. The progress in interpretation of the nature of the reservoir through the use of a 3-D seismic survey improves the ability to define targets for hot low salinity production wells and matching injection wells to provide pressure support for the production wells.

Power Purchase Agreement – Renegotiation Status

Although a final decision has not yet been reached, Management has confirmed that the prospects of the negotiations remain favorable and the Third Party Off- taker has taken certain steps to further progress the contracting (including receiving key executives' approval and commitment) and has agreed to purchase up to 25 MW of capacity. Ormat is currently working with SCE on a bilateral amendment (“Amendment No. 6” or the “Amendment”) of the previous PPA, which will allow them to sign a new PPA with the Third Party Off-taker.

Chapter D – General Economic Outlook and Industry Analysis2

General Economic Outlook

Introduction

In performing our analysis, we considered the general economic outlook as of the Valuation Date and its potential impact on the Subject Assets. An assessment of the general economy can often identify underlying causes for fluctuations in the financial and operating performance of a company. This overview of the general economic outlook is based on our examination of various economic analyses and the consensus forecasts of Blue Chip Economic Indicators and Blue Chip Financial Forecasts (collectively, the “consensus”).

Economic Growth

The United States’ economy is continuing to recover from one of its worst recessions in history. The 2008-2009 recession was declared officially over in June 2009, and was of greater duration than those of 1974-1975 and 1981-1982. Real GDP (i.e., output adjusted for the impact of inflation) contracted by 3.5% in 2009 on a year-over-year basis. This was the biggest decline since 1946 and was primarily attributed to sharp decreases in residential and non-residential fixed investments, real personal consumption expenditures (“PCE”) and, to a lesser extent, business inventories. In fact, 2009 saw the largest liquidation ever on record of business inventories.

The current recovery also falls short of the rebound observed in other post-World War II recessions. Real GDP growth in the year following the recessions of 1957-58, 1973-75, and 1981-82 was on average 5.6%. In contrast, real GDP grew by 3.0% during 2010, aided by a rebuilding of business inventories and a recovery in consumer spending. This sub-par growth trend did not improve in 2011. For example, real GDP grew by a dismal annualized 0.4% in the first quarter of 2011 and by an only slightly improved 1.3% in the second quarter of 2011. This lower than expected growth was attributable to harsh winter weather, continued cutbacks by state and local governments, political turmoil in several North African and Middle Eastern countries, a major earthquake and tsunami in Japan, and a resurfacing of the European sovereign debt crisis. Third quarter growth improved somewhat to an annualized 1.8%, primarily due to an increase in consumer spending. However, business inventories subtracted 1.4% from the growth rate for the quarter; reflecting businesses’ somewhat pessimistic expectations for consumer spending during the holiday season.

Sources– D&P North Brawley Impairment Analysis - Aug 2012, the IMF, and capital IQ.

In contrast, the fourth quarter of 2011 experienced 3.0% real GDP growth, the fastest pace since the second quarter of 2010. However, a surge in business inventories accounted for 60% of the fourth quarter’s growth, raising some questions about the sustainability of the recent growth trends. For overall 2011, real GDP grew by a below-trend rate of 1.7%.

The U.S. economy, shadowed by this continued trend, expanded by only 1.9% in the first quarter of 2012. Real GDP growth was primarily driven by a 2.7% rise in real personal consumption, which stemmed from a surge in auto and light truck unit sales driven by mild winter weather. Looking ahead, the consensus estimates real GDP will grow 2.1% during 2012, improving to 2.4% in 2013, but this is still below the U.S. long-term trend. Recent economic indicators have shown mixed results. Lower gas prices are expected to drive continued growth of real PCE, which the consensus projects at 2.2% in 2012. On the negative side, potential risks to U.S. economic growth include regulatory uncertainties resulting from upcoming U.S. presidential elections (and related impact on fiscal policy), effects of a deteriorating Euro sovereign debt crisis, and weakened economic growth in China.

In its most recent semi-annual update to long-range projections, the consensus estimated a five-year average real GDP growth rate of 2.8% for the period of 2014-2018, with a 2.5% average growth for the subsequent five-year-period. This is consistent with the most recent Livingston Survey, published by the Federal Reserve Bank of Philadelphia (the “Philadelphia Fed”), which projects a long-run (ten-year) average real GDP growth rate of 2.7%.3

3 Source: “The Livingston Survey – June 2012,” Federal Reserve Bank of Philadelphia, June 7, 2012.

In its most recent semi-annual update to long-range projections, the consensus estimates a five-year average real GDP growth rate of 2.8% for the period of 2013-2017, with a 2.5% average growth for the subsequent five-year-period. This is consistent with the most recent Livingston Survey published by the Federal Reserve Bank of Philadelphia (hereinafter the “Philadelphia Fed”).

Inflation

The primary inflation index of the U.S., the consumer price index (“CPI”), expanded at an annualized rate of 3% in 2011, a substantially higher growth rate compared with the CPI growth rate in 2010, of 1.6%. During 2010 CPI was somewhat volatile, but ultimately registered an overall 1.6% increase, fueled by rising food, energy, and raw commodity prices. Price pressure from crude oil, which was exacerbated by the ongoing turmoil in North Africa and Middle East, persisted during the first half of 2011. This led to CPI’s annualized rise of 4.5% and 4.4% in the first and second quarters respectively. During the third quarter, the increase in CPI slowed down to an annualized 3.1%, but energy prices were still a large contributing factor. Further deceleration in CPI inflation was experienced during the fourth quarter at a surprisingly low annualized rate of 1.3%, largely due to the decline in gasoline and new vehicle prices. This contributed to an overall 2011 CPI inflation of 3.2%. A sudden rebound in oil prices during the first quarter of 2012 led to a 2.5% (annualized) rise in CPI. However, CPI inflation is set to decline in the second quarter due to a recent drop in prices of crude oil related products (driven by a slowing global economy), as well as energy services (attributable to plummeting natural gas prices and warm winter weather). The consensus estimates that CPI will rise by 2.2% and 2.1% in 2012 and 2013, respectively. In addition, the IMF estimates an average long-term inflation of 2%.

Unemployment

In October 2009, the rate of unemployment peaked at 10.0%, the worst level since June 1983. In 2010 new jobs were created, led primarily by an increase in private sector payrolls, but restrained by layoffs of government employees, resulting in a 9.6% average unemployment rate. Conditions improved during the first quarter of 2011, driven primarily by private sector payrolls, lowering the average unemployment rate to 9.0%. A majority of first quarter job gains were eliminated during the second quarter of 2011 and the unemployment rate rose again to 9.0% in June 2011, slightly increasing in the third quarter of 2011 to 9.1%. Despite the continued job losses in the government sector, the unemployment rate finally declined to 8.7% in the fourth quarter, reflecting improvement in private sector employment. This resulted in an average 9.0% unemployment rate for 2011. Robust job creation continued in the first two months of 2012, primarily driven by a mild winter, but job growth slowed down significantly since then. The May 2012 unemployment rate rose to 8.2%, the first rise since June 2011. Some of the recent softness in labor markets appears to be a catch-up from the strength seen in the beginning of the year, which analysts now believe benefitted from the record warm winter weather. Overall, the consensus expects an average unemployment rate of 8.1% in 2012 and 7.8% in 2013.

Interest Rate Environment and Global Economic Trends

U.S. interest rates remain historically low. A flight to quality led U.S. Treasury yields to drop sharply in May 2011, and continue to decline through 2012. Poor labor markets, signs of a global economic slowdown, rising capital and liquidity requirements for banks, and most notably an escalation of the Euro-zone sovereign debt crisis, all contributed to investors becoming more risk averse. Based on these trends, the Federal Open Market Committee (“FOMC”) announced in January 2012 that it will continue to keep interest rates exceptionally low through late 2014.

Due to increasing market uncertainty in the latter half of 2010, the Federal Reserve (“Fed”) was forced to revive some of its purchase programs to inject liquidity into the financial system. In August 2010, the Fed introduced a variety of quantitative easing measures (also known as “QE2”) to support the U.S. economy, a program completed in June 2011. In September 2011, the Fed announced plans to purchase $400 billion of Treasury securities (known as “Operation Twist”), with the intent to drive down long-term interest rates and revive the economy. In June 2012, citing weakness in labor markets and strains in global financial markets, the Fed announced plans to continue Operation Twist through the end of 2012.

Geopolitical and economic uncertainty is still very high across the globe. Concerns about the possibility of a global sovereign debt crisis first surfaced in February-March 2010, due to investors’ reactions to swelling budget deficits in several Euro-zone member states, especially in Greece. The European Union (“EU”) and the International Monetary Fund (“IMF”) first approved a bailout package for Greece in May 2010. Both Ireland (November 2010) and Portugal (April 2011) were forced to request similar EU-IMF bailouts. In July 2011, EU politicians approved a tentative restructuring of Greece’s debt, pursuant to a second bailout agreement. However, markets reacted negatively and the crisis spread to Spain and Italy, which are considered by markets as “too big to fail”. As a result, the European Central Bank (“ECB”) was forced to reenact its government bonds purchase program and to provide additional liquidity to banks under a program known as long-term refinancing operations (“LTRO”). While the LTRO program was considered successful in strengthening liquidity in the Euro-zone, concerns have resurfaced that Portugal and Spain will need extra financial assistance. The mid-June Greek elections generated a viable majority in support of the bailout plan; however relief was short-lived, as global financial markets’ concerns quickly turned back to troubled Spain and Italy, pushing their respective sovereign yields higher.

The Euro-zone registered overall 2010 real GDP growth of 1.9%; primarily driven by Germany’s export-led recovery. Growth during the first quarter of 2011 reached an annualized 2.9%, with economic expansion widening to other countries beyond Germany. However, the second and third quarters were hit by softened consumer spending, partly driven by higher energy prices and the deterioration of the Euro debt crisis, leading to an annualized 0.6% real GDP growth rate in both quarters. For overall 2011, the Euro-zone economy grew by 1.5%, in real terms. Exports and better than anticipated growth in Germany prevented the GDP from a decline in the beginning of 2012. A contraction in Euro-zone real GDP of 0.5% is now projected for 2012, followed by minimal growth of 0.7% in 2013. The actual growth trajectory for 2012 and 2013 will be dependent on politicians and the ECB’s ability to control the ongoing sovereign debt crisis.

The United Kingdom economy experienced 2.1% real growth in 2010, despite a fourth quarter 1.6% contraction. Real GDP grew an annualized 1.0% in the first quarter of 2011, but contracted by an annualized 0.2% in the second quarter, partially due to temporary factors such as the April 2011 royal wedding and the effects from the Japanese tsunami/earthquake. Third quarter saw annualized 2.3% growth, primarily as an offset to the stagnation seen in the prior quarter. Downside risks to growth persisted, leading the Bank of England (“BOE”) to announce a new QE2 program in October 2011. Real GDP contracted by an annualized 1.2% in the fourth quarter, largely due to weakened Euro-zone growth and high inflation, leading the BOE to increase the size of QE2 in February 2012. Overall, real GDP grew by only 0.7% in 2011. The U.K. slipped back into recession in the first quarter of 2012, as real GDP contracted by an annualized 1.3%. The consensus projects real GDP growth of 0.3% and 1.6% in 2012 and 2013, respectively.

Japan’s economy grew by 4.4% in real terms in 2010, recovering from its worst recession since World War II. In March 2011, Japan was hit by a devastating earthquake and subsequent tsunami, which created significant economic and fiscal challenges. Real GDP contracted by an annualized rate of 7.7% in the first quarter of 2011 and 1.7% during the second quarter, as consumer spending, business investment, and exports collapsed following the disaster. The third quarter rebounded significantly, with a 7.8% annualized real GDP growth rate. Nonetheless, concerns regarding the rising yen and subsequent decline in Japanese exports pushed the Bank of Japan (“BOJ”) to a new round of QE measures and currency market intervention. Despite the QE measures, real GDP only grew by an annualized 0.1% in the fourth quarter of 2011, contributing to an overall 2011 decline of 0.7%. Initial estimates of the first quarter of 2012 show the economy bounced back to a 4.7% annualized real growth. The consensus projects real GDP to grow by 2.2% and 1.7% in 2012 and 2013, respectively.

U.S. Geothermal Market Update

Introduction

The development of geothermal energy resources for utility-scale electricity production in the United States has continued since the 1960’s, and in turn has positioned the US as a leader in the global geothermal industry. The US currently has approximately 3187 MW of installed geothermal capacity, more than any other country in the world, as depicted in the figure below.

US & Global Geothermal Installed Capacity (1960 – 2012)

Source: GEA

Geothermal companies continue to increase the development of geothermal resources in the US. In 2010 geothermal energy accounted for 3% of renewable energy-based electricity consumption in the United States. While the majority of geothermal installed capacity in the US is concentrated in California and Nevada, geothermal power plants are also operating in Alaska, Hawaii, Idaho, Oregon, Utah, and Wyoming.

While the recent economic downturn adversely impacted the rate of geothermal resource development, the geothermal industry has maintained steady growth in the US through 2012. Geothermal companies continue to explore and develop geothermal resources at a growing number of sites throughout the United States. Geothermal capacity in 2011 and 2012 was installed by four different geothermal companies. An increasing number of Geothermal projects are located in California and especially Nevada, where strong state policies and a geothermal friendly regulatory structure support strong industry growth.

Industry Growth Trends and Future Development

The number of developing geothermal projects reported to GEA in 2012 (130 projects) represents an increase of approximately 6% from 2011 (123 projects). By the end of 2012, the geothermal industry is expected to develop 130 confirmed geothermal projects, which inclusive of projects not confirmed (i.e. “unconfirmed”) by the developing companies, is closer to 147 total projects.

Geothermal companies increased installed capacity from 3102 MW to 3187 MW in 2011 and the first quarter of 2012. As the economy recovers and federal and state policy incentives driving investment in renewable energy resources remain in effect, the geothermal industry is expected to continue to bring geothermal capacity online in 2012 and subsequent years. As advanced geothermal projects enter or near the construction phase of development, geothermal companies in the US are also acquiring and developing early stage geothermal resources. Within the United States, most geothermal reservoirs are located in the western states, Alaska, and Hawaii. Wells, in these areas, can be drilled into underground reservoirs for the generation of electricity, with a high probability of success and longevity.

According to development companies within the industry, new projects were identified under development in 15 states: Nevada, California, Utah, Idaho, Oregon, Alaska, Louisiana, Hawaii, New Mexico, Arizona, Colorado, Mississippi, Texas, Washington, and Wyoming in-spite of the economic downturn and risk-averse investors. As indicated in Figure 2 below, Nevada and California maintain to be leaders in geothermal power development.

Figure 2: Developing Projects by State and Phase, Source: GEA

Developers of geothermal facilities are progressively exploring new areas where little or no previous development has taken place. Of the 147 projects surveyed by the GEA, 116 (approximately 80%) are developing conventional hydrothermal resources in “unproduced” areas (CH Unproduced) where the geothermal resource has not been developed to support electricity generation via a power plant. Additionally, 18 are developing conventional hydrothermal projects in “produced” (CH Produced) areas, and five are expansions to existing conventional hydrothermal power plants (CH Expansion). The remaining projects are five geothermal and hydrocarbon coproduction (“Coproduction”) and three enhanced geothermal systems (“EGS”) projects.

Currently, geothermal companies are developing 1779 - 1821 MW of confirmed Planned Capacity Additions (“PCA”) projects in the US. When accounting for unconfirmed projects, the range of PCA in development is approximately 1961 – 2023 MW. Of this, 949 – 956 MW are advanced-stage (Phase 3 – 4) geothermal projects. The figure below, details PCA projects by state that are in advanced stages of development, as of April, 2012.

Advanced-stage planned capacity additions by state: Source: GEA

The exploration for and development of new resources, as well as the application of new technologies, has the potential to expand the geographic extent of the industry. Projects featuring the development of conventional hydrothermal resources as well as EGS pilot projects are increasing in the western US. At the same time, the potential to generate geothermal electricity from low-temperature fluids left over as a byproduct from oil and gas production is being explored through demonstration scale projects in states along the Gulf of Mexico and in North Dakota.

Federal Incentives and Drivers of Development

Increased progress in the development of geothermal projects has been fueled by federal incentives and funding which help offset the risk and high capital cost of development. Subject to certain criteria, geothermal power projects are eligible for the full Production Tax Credit (“PTC”) if placed in service by December 31, 2013. Additionally, the American Recovery and Reinvestment Act of 2009 (“ARRA”) has made projects eligible for the PTC also eligible for a grant in lieu of the tax credit from the Treasury Department. Section 1603 of the ARRA allows developers of geothermal power plants the option of applying for the Investment Tax Credit or an ITC cash grant. The grant is equivalent to a 30% tax credit for the eligible portions of their capital investment.

Projects which are in construction by the end of calendar year 2011 and are placed in service by the end of calendar year 2013 may receive the 30% ITC or the ITC cash grant (after 2013 a 10% ITC is still available). Geothermal developers have cited the cash grant as a particularly important factor in sustaining development through the economic recession. Since 2009 approximately $262.9M and $4.6M in cash grants have been provided to utility-scale geothermal projects and geothermal heat pump projects respectively. Projects receiving cash grants span 19 different states.

The ITC cash grant was included in the ARRA in response to the decreasing number of tax equity investors following the global credit crisis which began in 2008, as well as the fact that tax credits for many developers became less valuable in light of decreasing profits, and consequently shrinking tax burdens.

Many geothermal developers are building several projects in the US, and the cash grant provides them an effective incentive that quickly reduces their debt -- an important factor in the present economic recession. In addition, four of the top five states with geothermal power under development have substantial renewable standards. Those states in order of geothermal development and their state renewable requirement are: 1) Nevada (25%), 2) California (33%), 3) Utah (20%), 4) Idaho (none), and 5) Oregon (25%).

Department of Energy (“DOE”) federal stimulus legislation funding is also having an important influence on the US geothermal market. As part of the ARRA section 1705, the DOE has offered loan guarantees for eligible projects. In October 2009, the DOE also announced the results of its competitive solicitation under ARRA for geothermal technology projects. DOE announced awards that could result in up to $338 million in ARRA funding to geothermal research and development, and would require an additional $280 million in recipient cost-share. As of June 2010, ARRA awards administered through the DOE Geothermal Technologies Program (“GTP”) totaled nearly $363.5 million. Total cost share contributes an additional $362.4M, bringing the combined ARRA/cost share geothermal technology investment to more than $725.88M. The vast majority of projects that have yet to be completed indicate that much of this total will be spent in the coming year, boosting job growth within the geothermal sector.

Total DOE GTP ARRA/Cost-Share Geothermal Investment, Source: GEA

A review of GTP ARRA awards reveals that the impact of stimulus funding has not yet peaked for geothermal. As reported by the GEA in 2011, of the 122 projects receiving ARRA funding through the DOE GTP: 1 has been completed, 18 are more than 50% complete, 98 are less than 50% complete, 1 has not been started, and 4 are unaccounted for on Recovery.gov.

Figure 5: ARRA Funded Geothermal Project Progress, Source: GEA

As indicated in Figure 5, about 98% of the projects receiving ARRA funding are either less than 50% complete. With the majority of ARRA funded projects still in early stages of development, GEA anticipates that much of this total will be spent in the coming years, boosting job growth within the geothermal sector.

Industry Outlook

As of the first quarter of 2012, number of confirmed geothermal projects recorded by the GEA accounts for approximately 4116 - 4525 MW of geothermal resources in development, spread among 15 states in the western US. Including unconfirmed projects in resource development totals increases these levels to 4882 - 5366 MW. Figure 6 below, outlines the number of confirmed projects by year, with significant additions over the last two years.

Figure 6: Total confirmed projects +2011 and 2012 prospects, Source: GEA

As of the same period, companies developing geothermal resources have identified vendors in 39 different states (including the District of Columbia) supplying goods and services for the development of geothermal resources as well, which further shows signs of growth in the industry.

As indicated above, the outlook for the geothermal industry remains promising in the US and geothermal companies continue to explore and develop geothermal resources at a growing number of sites throughout the United States.

Chapter E - Valuation

1. Valuation methodology

1.1 General

In our estimation of Fair Value we consider the income approach. The income approach is a valuation technique that provides an estimation of the Fair Value of an asset based on market participant expectations about the cash flows that an asset would generate over its remaining useful life. The Income Approach begins with an estimation of the annual cash flows a market participant would expect the subject asset (or business) to generate over a discrete projection period. The estimated cash flows for each of the years in the discrete projection period are then converted to their present value equivalent using a rate of return appropriate for the risk of achieving the projected cash flows. The present value of the estimated cash flows are then added to the present value equivalent of the residual value of the asset (if any) or the business at the end of the discrete projection period to arrive at an estimate of Fair Value.

In some situations, the expected cash flow approach is a more effective measurement tool than the traditional approach. In developing a measurement, the expected cash flow approach uses all expectations about possible cash flows, taking into consideration assumed probabilities of future events and/or future scenarios, instead of the single cash flow scenario.

1.2 Application of the Income Approach in this analysis

The Fair Value of the assets of North Brawley as of the Valuation Date was therefore estimated by:

·	Determining operational characteristics of the Plant's four generation scenarios; a 37MW, a 40MW, a 45MW, and a 50MW scenario

·	Forecasting revenues and variable operating costs as applicable, including energy prices for the electric output under two pricing scenarios (Third Party Off-taker and SCE)

·	Forecasting fixed expenses and capital expenditures as applicable for each case

2. North Brawley Valuation

2.1 Valuation Scenarios

Based on the uncertainty of events related to the current negotiations on the proposed PPA, as of the Valuation Date, the North Brawley valuation analysis has been performed by probability weighting of two pricing scenarios. In consideration of the recent significant progress in negotiations with the Third Party Off-taker, management assigned a 90% probability to the Third Party Off-taker scenario, while the SCE Scenario was assigned a 10% probability. The two pricing scenarios provided by management are described below:

Third Party Off-taker Scenario: This scenario constitutes the implementation of a 10-Year PPA (currently being negotiated) with Third Party Off-taker for up to 25 MW of capacity. In addition, it is assumed that the remaining capacity, or the capacity above 25 MW, in each of the scenarios could be contracted at terms similar to that expected for the Third Part Off-taker. Under this Scenario, the company expects to:

o	Subject to SCE approval, have the option to move the current PPA to a new project (the aggregation of ORMESA #1, ORMESA #2 and GEM facilities collectively referred to as the “ORMESA facility” or “ORMESA”)

o	Establish a Holiday Period of 5 years in form of a letter agreement which begins on a date that is no later than one month from the date of the Company's notice to SCE of their election to begin the Holiday Period (hereinafter the “Commencement of the Holiday Period”) and ends on the later of:

(i) Five years from the Commencement of the Holiday Period; or

(ii) Upon the completion of the term of the ORMESA Standard

Offer PPA which is 11/30/2017

o	Enter into an up to 25 MW capacity contract with a Third Party Off-Taker for a 10 year term to begin by the end of 2012

o	Enter into an additional long term contract for the capacity above 25 MW, as well as the period after the first 10 years, at negotiated terms similar to the contract expected to be signed with the Third Party Off-Taker

o	Not incur generation related PPA penalties previously forecasted with SCE

o	Consists of four power generation cases for North Brawley, 37MW case, 40MW case, 45MW case, and 50MW case

It should be noted that the parameters of the Third Party Off-taker scenario used in this analysis are different than the ones used in the impairment analysis conducted in December 2011 as follows:

o	This analysis assumes a slightly lower price per MW/h, based on recent negotiation status with Third party Off-taker

o	The Third party Off-taker contract term is now 10 years instead of 20 years, based on recent negotiation status with Third party Off-taker

o	Contracted capacity is 25 MW instead of the Plant full capacity. Remaining capacity is assumed to be contracted at terms similar to the Third party Off-taker terms

o	Based on Management's representation, the probability for the scenario increased to 90%

SCE Scenario: This scenario, is based on the existing PPA dated June, 2007 with SCE, it is reflective of the current obligations of the Company to SCE and as such, is curtailed around the prevailing market conditions of the time at which it was put into effect. Under this Scenario, Management is obligated to:

o	Minimum generation commitment

o	Contracted prices that are significantly lower than the proposed Third Party Off-taker case

o	Penalties in the event of non-compliance

Based on the Company's assessment the probability for this scenario was updated to 10%.

2.2 Key assumptions

2.2.1 Operating Characteristics

As of the Valuation Date the facility is producing approximately 25MW of electricity. However, as detailed in the Subject Asset description (see Chapter C), management’s assessment of the potential of the field remains unchanged and it believes that the generation targets of 45MW to 50MW that it has used in the past are still valid. Management expects that increased generation capacity is achievable by the beginning of 2014, commensurate with capital investment plan designed to improve capacity. Based on management's technical analysis and operational plan, management assigned probabilities for the different generation cases, as follows: (1) 50MW – 12.5% probability; (2) 45MW – 12.5% probability; (3) 40MW – 25% probability; and (4) 37MW – 50% probability.

2.2.2 Production and Revenues

The Company's management provided production estimates and forecasts for each of the four generation cases considered in this analysis, which were considered to be reasonable and appropriate. Revenues were then derived by assuming the average realized price, provided by management, and in accordance with the PPA terms in each price scenario (Third Party Off-taker and SCE) as follows:

SCE Pricing Scenario – reflects the current pricing including seasonality adjustment under the 20 year contract with SCE. Thereafter, in 2031, a replacement contract was assumed using equivalent MPR pricing of $101.7/MWh escalated thereafter by ~1% (in line with the recently released 2011 MPR pricing model).

·	New Off taker Pricing Scenario (Third Party Off-taker) – reflects the proposed 3rd party off taker pricing scenario with the proposed pricing escalated through the life of the generation facility

2.2.3 Operating Costs

The Company provided D&P and GSE with forecasted fixed and variable operating expenses, including costs such as plant operating expenses, utilities, insurance, royalties, and administrative expenses through year 2040 for the Subject Assets in all four generation scenarios. Management's estimates and forecast of operating costs were based on its experience in the operations of the North-Brawley plant and similar geothermal facilities. Variable costs were determined based on estimates of actual material, equipment and services required to operate the Plant subject to assumed production in each generation scenario. Fixed operating costs, primarily labor, were based on the company experience in the operation of the Plant and similar facilities. To adjust these cost estimates to inflation, we have used a 2% long term inflation rate in all generation cases and in both pricing scenarios.

Property taxes, based on managements' guidance, were calculated as 1% of the property value in each of the generation and pricing scenarios

2.2.4 Capital Expenditures

The Company provided D&P and GSE with forecasted capital expenditures through year 2040 for the Subject Assets in all four generation scenarios. Management's estimates and forecast of capital expenditures were based on its experience in the operations of the North-Brawley plant and similar geothermal facilities. Capital expenditures varied in the different generation scenarios to reflect further investments required to achieve increased generation capacity.

To adjust these cost estimates to inflation, we have used a 2% long term inflation rate in all generation cases and in both pricing scenarios.

2.2.5 Depreciation

Positive cash flow is generated by the tax shield that arises from tax depreciation charges that reduce the amount of taxes paid. To arrive at Fair Value from a market participant view, the Plant has been valued assuming an asset purchase, which means that, for U.S. tax purposes, the price paid becomes the new tax basis of the acquired asset (i.e. the tax basis is adjusted to the value or price paid of the acquired asset). We calculated the depreciation step-up using a 5-year MACRS half-year schedule applicable to geothermal facilities. Additionally, we have also included the allowed tax exemption in the amount of 3.26% of the concluded Fair Value in the analysis. The total plant and impairment loss depreciation benefit was limited to the Plant's existing tax basis (approximately $300 million).

As the concluded Fair Value includes the value of the future tax benefits, we used an iterative process to arrive at the Fair Value of the Plant, and used the Fair Value as the assumed tax basis for all cases.

2.2.6 Tax

We utilized the corporate tax rate that a market participant that will operate the assets at their highest and best use would be expected to incur, and which is not necessarily the tax rate that is incurred by the Company or the Plant. The tax rate that we therefore used in our analysis is 40.75%.

2.2.7 Working Capital

In accordance with our assumptions in the past, we assumed 30 receivable days and 30 payable days to calculate the expected change in working capital.

2.3 Weighted Average Cost Of Capital (WACC)

2.3.1 General

In accordance with the Standard guidelines, the discount rate should reflect current market estimates of:

a. The time value of money

b. Specific risks with respect to which the cash flows were adjusted

The discount rate reflects, among other things, the business-operating risk inherent in the company’s activities. Some of the risk is attributed to the nature of the market sector in which the company operates, and some of it stems from specific characteristics of the company.

The Weighted Average Cost of Capital used in this analysis is 8% based on the following calculation, and in-line with the weighted average cost of capital used in previous analyses. The exception to this is that the uncontracted capacity in the Third Party Off-taker scenario was discounted at 9% to reflect the associated additional risk

2.3.1 Cost of Equity

The following table presents the sum of the key parameters that we used in calculating the Cost of Equity (Ke):

Estimation of the Cost of Equity

Risk Free Rate (nominal)	2.7	%	1
Market Risk Premium	6.04	%	2
Re-levered Beta	1.16		3
Risk Premium	1.98	%	4
Cost of Equity	11.68	%

Notes to the table:

(1)	The nominal rate of return on a US government bond4 for a 30-year period.

(2)	Average difference between the annual real return on stock indexes and the risk free interest in the U.S5.

(3)	To determine the Company's beta, we examined a group of companies in the same field of business. We chose companies with similar features as the Company. Following is a list of peer companies used for calculating the beta6:

Calculation of Levered Beta by Peer Companies:

Company	Levered Beta		Unlevered Beta		D/V
Calpine Corp.		1.26		0.73	0.54
Ram Power Corp.		1.06		0.41	0.73
US Geothermal Inc.		1.54		0.97	0.49
Alterra power corp.		0.78		0.52	0.43
Ormat Technologies Inc.		1.17		0.74	0.49
Median		1.17		0.73	0.49

(4)	The specific risk premium, relevant to the size of the company in market of operation7.

4 Source: Federal Reserve - www.federalreserve.gov/Releases/H15/Current.

5 Source: Study published by Damodaran (as of December 2011) -http://pages.stern.nyu.edu/~adamodar

6 Source: Capital IQ

7 Acording to data published in Ibbotson (December, 2011).

2.3.3 WACC - Summary

Parameters for Calculating the WACC

Parameter	Value			Comments
Risk-free Rate		2.70	%
Relevered Beta		1.16			1
Market Risk Premium		6.04	%
Specific Risk Premium		1.98	%
The Cost of Equity		11.68	%
Cost of Debt		6.75	%		2
Tax rate		40.75	%
D/V		49	%		3
WACC		7.9	%		4

Notes to the table:

1.	Re-levered beta based on the assumed D/E ratio and tax rate

2.	Based on the coupon rate set on the company's bonds.

3.	The median Debt-to-Value ratio of comparable companies

4.	The WACC was rounded to 8%

3. Valuation Conclusion

3.1 Fair Value

Based on probabilities provided by the Company's Management, the Fair Value of North Brawley is estimated at $141 million (pre disposal costs), as exemplified below:

Case	Third Party Off-taker DCF		Weighting			SCE DCF		Weighting			Probability weighted Valuation		Case Weighting			Expected Value
37MW Case		134,460		90	%		68,250		10	%		127,839		50.0	%		63,920
40MW Case		144,904		90	%		76,230		10	%		138,037		25.0	%		34,509
45MW Case		163,408		90	%		87,792		10	%		155,486		12.5	%		19,481
50MW Case		190,506		90	%		112,189		10	%		182,674		12.5	%		22,834
Total														100.0	%		140,744

3.2 Disposal Costs

Based on discussions with the Company's Management we assumed disposal costs estimated at 1% of the Fair Value, totaling approximately 1.4 Million $.

3.3 Conclusion

Therefore we estimate that the Fair Value of North Brawley, less costs to sell, is 139 Million $.

3.4 Sensitivity Analysis

3.4.1 Sensitivity to the WACC

We have performed a sensitivity analysis for the value of North Brawley, less costs to sell, with respect to the weighted average cost of capital as follows:

% Change in WACC			(1	)%			(0.5	)%			8	%8			+0.50	%			+1	%
Fair Value (less costs to sell)			156.2				147.6				139.3				131.6				124.3

3.4.2 Sensitivity – probability weighting - Third Party Off-taker vs. SCE pricing scenarios

Probability SCE / Third Party Off taker			40/60	%			30/70	%			20/80	%			10/90	%			0/100	%
Fair Value (less costs to sell)			118.7				125.5				132.5				139.3				146.2

8 8% for the contracted capacity and 9% for the uncontracted capacity

Chapter F – Exhibits

1. Discounted Cash Flow Analysis – Third Party Off-taker 37MW Scenario

		2012-H2		2013		2014		2015		2016		2017		2018		2019		2020		2021		2022		2023		2024		2025
Total Revenue		9,611		24,357		30,046		30,197		30,350		30,504		30,658		30,813		30,969		31,126		31,283		31,441		31,600		31,760
Total Operating Costs		8,505		14,741		15,866		16,028		16,229		16,429		16,665		16,937		17,215		17,498		17,785		18,078		18,375		18,678
EBITDA		1,106		9,616		14,180		14,170		14,121		14,074		13,993		13,876		13,754		13,628		13,498		13,364		13,225		13,082
Depreciation		32,675		49,856		32,082		21,427		21,561		13,549		5,481		5,503		5,526		5,549		5,572		5,596		5,620		5,645
EBIT		(31,569	)	(40,240	)	(17,902	)	(7,257	)	(7,440	)	525		8,512		8,372		8,228		8,079		7,926		7,768		7,605		7,438
Income Tax		(12,863	)	(16,396	)	(7,294	)	(2,957	)	(3,031	)	214		3,468		3,411		3,353		3,292		3,230		3,165		3,099		3,031
After-tax Operating Profit		(18,706	)	(23,844	)	(10,608	)	(4,300	)	(4,408	)	311		5,044		4,961		4,875		4,787		4,697		4,603		4,506		4,407
Plus: (Increase)/Decrease in Working Capital		(92	)	(709	)	(380	)	1		4		4		7		10		10		10		11		11		12		12
Less: CAPEX		(7,000	)	(1,025	)	(1,051	)	(1,072	)	(1,093	)	(1,115	)	(1,137	)	(1,160	)	(1,183	)	(1,207	)	(1,231	)	(1,256	)	(1,281	)	(1,306	)
Plus: Depreciation Benefit		32,675		49,856		32,082		21,427		21,561		13,549		5,481		5,503		5,526		5,549		5,572		5,596		5,620		5,645
Free Cash Flow from Operations		6,877		24,278		20,043		16,056		16,064		12,749		9,394		9,314		9,228		9,140		9,048		8,954		8,857		8,757
PV of Free Cash Flow from Operations		6,741		22,412		17,081		12,632		11,666		8,548		5,815		5,322		4,867		4,450		4,067		3,470		3,149		2,856
Sum of PV of Free Cash Flow from Operations	134,460

		2026		2027		2028		2029		2030		2031		2032		2033		2034		2035		2036		2037		2038		2039		2040
Total Revenue		31,921		32,083		32,245		32,408		32,573		32,738		32,942		33,146		33,351		33,556		33,761		33,966		34,171		34,376		34,581
Total Operating Costs		18,986		19,299		19,617		19,941		20,270		20,605		20,946		21,292		21,644		22,001		22,363		22,730		23,102		23,478		23,860
EBITDA		12,935		12,784		12,628		12,467		12,302		12,133		11,996		11,854		11,707		11,555		11,398		11,236		11,069		10,898		10,721
Depreciation		5,670		5,696		5,722		5,749		5,776		5,804		5,832		5,861		5,891		5,921		5,951		5,983		6,015		6,047		9,181
EBIT		7,266		7,088		6,906		6,719		6,527		6,329		6,164		5,993		5,816		5,634		5,447		5,253		5,055		4,850		1,540
Income Tax		2,960		2,888		2,814		2,738		2,659		2,579		2,512		2,442		2,370		2,296		2,219		2,141		2,060		1,976		628
After-tax Operating Profit		4,305		4,200		4,092		3,981		3,867		3,750		3,652		3,551		3,446		3,339		3,227		3,113		2,995		2,874		913
Plus: (Increase)/Decrease in Working Capital		12		13		13		13		14		14		11		12		12		13		13		13		14		14		908
Less: CAPEX		(1,332	)	(1,359	)	(1,386	)	(1,414	)	(1,442	)	(1,471	)	(1,501	)	(1,531	)	(1,561	)	(1,592	)	(1,624	)	(1,657	)	(1,690	)	(1,724	)	(1,758	)
Plus: Depreciation Benefit		5,670		5,696		5,722		5,749		5,776		5,804		5,832		5,861		5,891		5,921		5,951		5,983		6,015		6,047		9,181
Free Cash Flow from Operations		8,655		8,549		8,441		8,329		8,215		8,097		7,995		7,893		7,788		7,680		7,568		7,452		7,334		7,212		9,244
PV of Free Cash Flow from Operations		2,590		2,347		2,126		1,925		1,741		1,575		1,427		1,292		1,170		1,058		957		864		780		704		828
Sum of PV of Free Cash Flow from Operations	134,460

Discounted Cash Flow Analysis – Third Party Off-taker 40MW Scenario

		2012-H2		2013		2014		2015		2016		2017		2018		2019		2020		2021		2022		2023		2024		2025
Total Revenue		9,611		24,357		32,431		32,594		32,759		32,924		33,091		33,258		33,426		33,594		33,764		33,935		34,106		34,279
Total Operating Costs		8,505		15,125		16,418		16,574		16,773		16,970		17,206		17,484		17,767		18,054		18,346		18,643		18,945		19,252
EBITDA		1,106		9,232		16,012		16,020		15,986		15,954		15,884		15,774		15,659		15,541		15,418		15,292		15,161		15,026
Depreciation		36,705		56,098		35,964		23,892		24,026		14,952		5,821		5,844		5,866		5,889		5,912		5,936		5,960		5,985
EBIT		(35,598	)	(46,866	)	(19,951	)	(7,872	)	(8,041	)	1,002		10,063		9,930		9,793		9,652		9,506		9,355		9,200		9,041
Income Tax		(14,505	)	(19,096	)	(8,129	)	(3,208	)	(3,276	)	408		4,100		4,046		3,990		3,933		3,873		3,812		3,749		3,684
After-tax Operating Profit		(21,093	)	(27,770	)	(11,822	)	(4,664	)	(4,764	)	594		5,963		5,884		5,803		5,719		5,633		5,543		5,452		5,357
Plus: (Increase)/Decrease in Working Capital		(92	)	(677	)	(565	)	(1	)	3		3		6		9		10		10		10		11		11		11
Less: CAPEX		(15,000	)	(1,025	)	(1,051	)	(1,072	)	(1,093	)	(1,115	)	(1,137	)	(1,160	)	(1,183	)	(1,207	)	(1,231	)	(1,256	)	(1,281	)	(1,306	)
Plus: Depreciation Benefit		36,705		56,098		35,964		23,892		24,026		14,952		5,821		5,844		5,866		5,889		5,912		5,936		5,960		5,985
Free Cash Flow from Operations		519		26,626		22,526		18,155		18,172		14,433		10,653		10,577		10,495		10,411		10,324		10,235		10,142		10,047
PV of Free Cash Flow from Operations		509		24,569		19,179		14,263		13,173		9,654		6,575		6,024		5,515		5,048		4,619		3,966		3,606		3,277
Sum of PV of Free Cash Flow from Operations	144,904

		2026		2027		2028		2029		2030		2031		2032		2033		2034		2035		2036		2037		2038		2039		2040
Total Revenue		34,452		34,626		34,801		34,977		35,154		35,331		35,561		35,792		36,023		36,254		36,486		36,718		36,951		37,183		37,416
Total Operating Costs		19,564		19,882		20,204		20,531		20,863		21,200		21,545		21,894		22,247		22,605		22,968		23,335		23,706		24,081		24,459
EBITDA		14,887		14,744		14,597		14,446		14,291		14,131		14,017		13,898		13,776		13,649		13,518		13,383		13,245		13,103		12,957
Depreciation		6,010		6,036		6,062		6,089		6,116		6,144		6,173		6,202		6,231		6,261		6,292		6,323		6,355		6,388		9,522
EBIT		8,877		8,708		8,535		8,357		8,174		7,987		7,844		7,697		7,544		7,388		7,226		7,060		6,889		6,715		3,435
Income Tax		3,617		3,548		3,478		3,405		3,331		3,254		3,196		3,136		3,074		3,010		2,944		2,877		2,807		2,736		1,400
After-tax Operating Profit		5,260		5,160		5,057		4,952		4,844		4,733		4,648		4,561		4,470		4,377		4,282		4,183		4,082		3,979		2,036
Plus: (Increase)/Decrease in Working Capital		12		12		12		13		13		13		10		10		10		11		11		11		12		12		1,092
Less: CAPEX		(1,332	)	(1,359	)	(1,386	)	(1,414	)	(1,442	)	(1,471	)	(1,501	)	(1,531	)	(1,561	)	(1,592	)	(1,624	)	(1,657	)	(1,690	)	(1,724	)	(1,758	)
Plus: Depreciation Benefit		6,010		6,036		6,062		6,089		6,116		6,144		6,173		6,202		6,231		6,261		6,292		6,323		6,355		6,388		9,522
Free Cash Flow from Operations		9,949		9,849		9,745		9,639		9,531		9,419		9,330		9,241		9,151		9,057		8,960		8,861		8,759		8,655		10,891
PV of Free Cash Flow from Operations		2,977		2,704		2,455		2,227		2,020		1,832		1,665		1,513		1,374		1,248		1,133		1,028		932		845		975
Sum of PV of Free Cash Flow from Operations	144,904

2.	Discounted Cash Flow Analysis – Third Party Off-taker 45MW Scenario

		2012·H2		2013		2014		2015		2016		2017		2018		2019		2020		2021		2022		2023		2024		2025
Total Revenue		9,611		24,357		36,406		36,589		36,773		36,959		37,145		37,332		37,520		37,709		37,899		38,090		38,282		38,475
Total Operating Costs		8,505		15,563		17,348		17,484		17,673		17,864		18,095		18,374		18,664		18,957		19,255		19,557		19,864		20,176
EBITDA		1,106		8,794		19,057		19,105		19,101		19,095		19,050		18,958		18,857		18,752		18,645		18,533		18,418		18,300
Depreciation		39,409		64,063		44,984		29,545		28,143		18,464		7,577		6,447		6,469		6,492		6,516		6,539		6,564		6,588
EBIT		(38,302	)	(55,269	)	(25,926	)	(10,441	)	(9,043	)	631		11,473		12,511		12,387		12,260		12,129		11,994		11,855		11,712
Income Tax		(15,607	)	(22,520	)	(10,564	)	(4,254	)	(3,685	)	257		4,675		5,098		5,047		4,996		4,942		4,887		4,830		4,772
After-tax Operating Profit		(22,696	)	(32,749	)	(15,362	)	(6,187	)	(5,358	)	374		6,798		7,413		7,340		7,265		7,187		7,107		7,024		6,940
Plus: (Increase)/Decrease in Working Capital		(92	)	(641	)	(855	)	(4	)	0		0		4		8		8		9		9		9		10		10
Less: CAPEX		(7,000	)	(21,025	)	(1,051	)	(1,072	)	(1,093	)	(1,115	)	(1,137	)	(1,160	)	(1,183	)	(1,207	)	(1,231	)	(1,256	)	(1,281	)	(1,306	)
Plus: Depreciation Benefit		39,409		64,063		44,984		29,545		28,143		18,464		7,577		6,447		6,469		6,492		6,516		6,539		6,564		6,588
Free Cash Flow from Operations		9,621		9,648		27,715		22,283		21,693		17,723		13,242		12,708		12,635		12,559		12,480		12,400		12,317		12,231
PV of Free Cash Flow from Operations		9,428		8,897		23,567		17,473		15,685		11,817		8,141		7,205		6,605		6,055		5,548		4,805		4,379		3,990
Sum of PV of Free Cash Flow from Operations	163,408

		2026		2027		2028		2029		2030		2031		2032		2033		2034		2035		2036		2037		2038		2039		2040
Total Revenue		38,669		38,864		39,060		39,257		39,455		39,655		39,927		40,201		40,476		40,752		41,028		41,305		41,583		41,862		42,141
Total Operating Costs		20,491		20,812		21,136		21,465		21,798		22,135		22,479		22,827		23,177		23,531		23,887		24,267		24,653		25,043		25,437
EBITDA		18,178		18,053		17,924		17,792		17,657		17,519		17,448		17,375		17,299		17,221		17,141		17,038		16,930		16,819		16,704
Depreciation		6,613		6,639		6,665		6,692		6,720		6,747		6,776		6,805		6,834		6,864		1,917		1,599		1,631		1,664		4,798
EBIT		11,565		11,414		11,259		11,100		10,938		10,772		10,672		10,570		10,465		10,357		15,224		15,438		15,298		15,155		11,907
Income Tax		4,712		4,651		4,587		4,523		4,457		4,389		4,349		4,307		4,264		4,220		6,203		6,291		6,233		6,175		4,851
After-tax Operating Profit		6,852		6,763		6,671		6,577		6,481		6,383		6,324		6,263		6,201		6,137		9,021		9,148		9,065		8,980		7,055
Plus: (Increase)/Decrease in Working Capital		10		10		11		11		11		12		6		6		6		6		7		9		9		9		1,402
Less: CAPEX		(1,332	)	(1,359	)	(1,386	)	(1,414	)	(1,442	)	(1,471	)	(1,501	)	(1,531	)	(1,561	)	(1,592	)	(1,624	)	(1,657	)	(1,690	)	(1,724	)	(1,758	)
Plus: Depreciation Benefit		6,613		6,639		6,665		6,692		6,720		6,747		6,776		6,805		6,834		6,864		1,917		1,599		1,631		1,664		4,798
Free Cash Flow from Operations		12,144		12,054		11,961		11,866		11,770		11,671		11,605		11,543		11,480		11,415		9,320		9,099		9,015		8,929		11,496
PV of Free Cash Flow from Operations		3,634		3,309		3,013		2,742		2,495		2,270		2,071		1,890		1,724		1,573		1,178		1,055		959		872		1,029
Sum of PV of Free Cash Flow from Operations	163,408

3.	Discounted Cash Flow Analysis – Third Party Off-taker 50MW Scenario

		2012·H2		2013		2014		2015		2016		2017		2018		2019		2020		2021		2022		2023		2024		2025
Total Revenue		9,611		24,357		40,381		40,584		40,788		40,993		41,199		41,406		41,615		41,824		42,035		42,246		42,459		42,672
Total Operating Costs		8,505		16,162		18,229		18,354		18,535		18,717		18,945		19,227		19,518		19,812		20,110		20,412		20,717		21,025
EBITDA		1,106		8,195		22,151		22,230		22,253		22,276		22,254		22,180		22,097		22,012		21,925		21,835		21,742		21,647
Depreciation		45,712		73,617		51,070		33,551		32,149		20,908		8,460		7,330		7,353		7,376		7,399		7,423		7,447		7,472
EBIT		(44,605	)	(65,423	)	(28,918	)	(11,321	)	(9,896	)	1,367		13,794		14,849		14,744		14,637		14,526		14,412		14,295		14,175
Income Tax		(18,175	)	(26,657	)	(11,783	)	(4,613	)	(4,032	)	557		5,621		6,050		6,008		5,964		5,919		5,872		5,825		5,776
After-tax Operating Profit		(26,430	)	(38,766	)	(17,135	)	(6,708	)	(5,864	)	810		8,174		8,799		8,737		8,673		8,607		8,540		8,470		8,399
Plus: (Increase)/Decrease in Working Capital		(92	)	(591	)	(1,163	)	(7	)	(2	)	(2	)	2		6		7		7		7		8		8		8
Less: CAPEX		(7,000	)	(21,025	)	(1,051	)	(1,072	)	(1,093	)	(1,115	)	(1,137	)	(1,160	)	(1,183	)	(1,207	)	(1,231	)	(1,256	)	(1,281	)	(1,306	)
Plus: Depreciation Benefit		45,712		73,617		51,070		33,551		32,149		20,908		8,460		7,330		7,353		7,376		7,399		7,423		7,447		7,472
Free Cash Flow from Operations		12,189		13,236		31,721		25,764		25,190		20,602		15,498		14,975		14,913		14,849		14,782		14,714		14,644		14,573
PV of Free Cash Flow from Operations		11,943		12,199		26,945		20,171		18,176		13,701		9,500		8,460		7,765		7,126		6,538		5,702		5,207		4,753
Sum of PV of Free Cash Flow from Operations	190,506

		2026		2027		2028		2029		2030		2031		2032		2033		2034		2035		2036		2037		2038		2039		2040
Total Revenue		42,887		43,103		43,320		43,538		43,757		43,978		44,293		44,611		44,929		45,249		45,570		45,892		46,216		46,540		46,866
Total Operating Costs		21,337		21,652		21,970		22,310		22,662		23,019		23,384		23,754		24,127		24,504		24,884		25,268		25,654		26,043		26,434
EBITDA		21,550		21,451		21,350		21,228		21,095		20,959		20,909		20,857		20,802		20,745		20,686		20,625		20,562		20,498		20,432
Depreciation		7,497		7,523		3,072		1,365		1,392		1,420		1,449		1,478		1,507		1,537		1,568		1,599		1,631		1,664		4,798
EBIT		14,053		13,929		18,279		19,863		19,703		19,539		19,461		19,379		19,295		19,208		19,118		19,025		18,930		18,834		15,635
Income Tax		5,726		5,675		7,448		8,093		8,028		7,961		7,929		7,896		7,862		7,826		7,790		7,752		7,713		7,674		6,371
After-tax Operating Profit		8,327		8,253		10,831		11,770		11,675		11,577		11,531		11,483		11,433		11,381		11,328		11,273		11,217		11,160		9,264
Plus: (Increase)/Decrease in Working Capital		8		8		8		10		11		11		4		4		5		5		5		5		5		5		1,708
Less: CAPEX		(1,332	)	(1,359	)	(1,386	)	(1,414	)	(1,442	)	(1,471	)	(1,501	)	(1,531	)	(1,561	)	(1,592	)	(1,624	)	(1,657	)	(1,690	)	(1,724	)	(1,758	)
Plus: Depreciation Benefit		7,497		7,523		3,072		1,365		1,392		1,420		1,449		1,478		1,507		1,537		1,568		1,599		1,631		1,664		4,798
Free Cash Flow from Operations		14,500		14,425		12,525		11,731		11,636		11,538		11,483		11,434		11,384		11,331		11,277		11,221		11,164		11,105		14,012
PV of Free Cash Flow from Operations		4,339		3,960		3,155		2,711		2,467		2,244		2,049		1,872		1,710		1,561		1,425		1,301		1,188		1,084		1,255
Sum of PV of Free Cash Flow from Operations	190,506

4.	Discounted Cash Flow Analysis – SCE 37MW Scenario

			2012·H2		2013		2014		2015		2016		2017		2018		2019		2020		2021		2022		2023		2024		2025
Total Revenue			8,580		20,858		25,596		25,468		25,341		25,214		25,088		24,963		24,838		24,714		24,590		24,467		24,345		24,223
Total Operating Costs			8,561		15,344		15,744		15,948		16,176		16,406		16,660		16,937		17,222		17,514		17,813		18,121		18,437		18,761
EBITDA			18		5,514		9,853		9,520		9,165		8,808		8,429		8,026		7,616		7,200		6,777		6,346		5,908		5,462
Depreciation			17,275		26,510		17,211		11,641		11,775		7,577		3,323		3,345		3,367		3,390		3,413		3,437		3,461		3,486
EBIT			(17,257	)	(20,996	)	(7,358	)	(2,121	)	(2,610	)	1,231		5,106		4,681		4,249		3,810		3,363		2,909		2,447		1,976
Income Tax		40.7%	(7,031	)	(8,555	)	(2,998	)	(864	)	(1,063	)	502		2,080		1,907		1,731		1,552		1,370		1,185		997		805
After-tax Operating Profit			(10,225	)	(12,441	)	(4,360	)	(1,257	)	(1,546	)	729		3,026		2,774		2,518		2,257		1,993		1,724		1,450		1,171
Plus: (Increase)/Decrease in Working Capital			(2	)	(458	)	(362	)	28		30		30		32		34		34		35		35		36		37		37
Less: CAPEX			(7,000	)	(1,025	)	(1,051	)	(1,072	)	(1,093	)	(1,115	)	(1,137	)	(1,160	)	(1,183	)	(1,207	)	(1,231	)	(1,256	)	(1,281	)	(1,306	)
Plus: Depreciation Benefit			17,275		26,510		17,211		11,641		11,775		7,577		3,323		3,345		3,367		3,390		3,413		3,437		3,461		3,486
Free Cash Flow from Operations			48		12,586		11,439		9,340		9,165		7,221		5,242		4,992		4,736		4,475		4,211		3,941		3,667		3,388
PV of Free Cash Flow from Operations			47		11,654		9,807		7,415		6,737		4,915		3,304		2,913		2,559		2,239		1,950		1,690		1,456		1,246
Sum of PV of Free Cash Flow from Operations	68,250

			2026		2027		2028		2029		2030		2031		2032		2033		2034		2035		2036		2037		2038		2039		2040
Total Revenue			24,102		23,981		23,862		23,742		23,624		28,632		28,773		28,916		29,059		29,203		29,347		29,493		29,639		29,785		29,933
Total Operating Costs			19,094		19,436		19,788		20,150		20,522		21,110		21,488		21,869		22,257		22,654		23,059		23,472		23,893		24,323		24,762
EBITDA			5,008		4,545		4,073		3,592		3,101		7,522		7,286		7,047		6,802		6,549		6,289		6,021		5,745		5,462		5,170
Depreciation			3,511		3,537		3,563		3,590		3,617		3,645		3,674		3,703		3,732		3,762		3,793		3,824		3,856		3,889		7,023
EBIT			1,497		1,008		510				(516	)	3,876		3,612		3,345		3,069		2,786		2,496		2,196		1,889		1,573		(1,852	)
Income Tax		40.7%	610		411		208				(210	)	1,579		1,472		1,363		1,251		1,135		1,017		895		770		641		(755	)
After-tax Operating Profit			887		597		302				(306	)	2,297		2,140		1,982		1,819		1,651		1,479		1,301		1,119		932		(1,098	)
Plus: (Increase)/Decrease in Working Capital			38		39		39		40		41		(368	)	20		20		20		21		22		22		23		24		455
Less: CAPEX			(1,332	)	(1,359	)	(1,386	)	(1,414	)	(1,442	)	(1,471	)	(1,501	)	(1,531	)	(1,561	)	(1,592	)	(1,624	)	(1,657	)	(1,690	)	(1,724	)	(1,758	)
Plus: Deprecaition Benefit			3,511		3,537		3,563		3,590		3,617		3,645		3,674		3,703		3,732		3,762		3,793		3,824		3,856		3,889		7,023
Free Cash Flow from Operations			3,104		2,814		2,519		2,217		1,910		4,103		4,333		4,174		4,010		3,842		3,669		3,491		3,309		3,121		4,622
PV of Free Cash Flow from Operations			1,057		887		735		599		478		951		930		829		738		654		579		510		447		391		536
Sum of PV of Free Cash Flow from Operations	68,250

5.	Discounted Cash Flow Analysis – SCE 40MW Scenario

		2012-H2		2013		2014		2015		2016		2017		2018		2019		2020		2021		2022		2023		2024		2025
Total Revenue		8,580		20,858		27,672		27,533		27,396		27,259		27,122		26,987		26,852		26,717		26,584		26,451		26,319		26,187
Total Operating Costs		8,561		15,785		16,265		16,464		16,689		16,916		17,170		17,451		17,740		18,036		18,340		18,652		18,972		19,301
EBITDA		18		5,073		11,406		11,069		10,707		10,342		9,952		9,535		9,112		8,681		8,244		7,799		7,346		6,886
Depreciation		20,731		31,884		20,539		13,742		13,876		8,758		3,583		3,605		3,627		3,650		3,673		3,697		3,722		3,746
EBIT		(20,713	)	(26,811	)	(9,133	)	(2,673	)	(3,170	)	1,585		6,370		5,930		5,484		5,031		4,570		4,102		3,625		3,140
Income Tax		(8,440	)	(10,924	)	(3,721	)	(1,089	)	(1,291	)	646		2,595		2,416		2,235		2,050		1,862		1,671		1,477		1,279
After-tax Operating Profit		(12,273	)	(15,886	)	(5,412	)	(1,584	)	(1,878	)	939		3,774		3,514		3,250		2,981		2,708		2,430		2,148		1,861
Plus: (Increase)/Decrease in Working Capital		(2	)	(421	)	(528	)	28		30		30		32		35		35		36		36		37		38		38
Less: CAPEX		(15,000	)	(1,025	)	(1,051	)	(1,072	)	(1,093	)	(1,115	)	(1,137	)	(1,160	)	(1,183	)	(1,207	)	(1,231	)	(1,256	)	(1,281	)	(1,306	)
Plus: Depreciation Benefit		20,731		31,884		20,539		13,742		13,876		8,758		3,583		3,605		3,627		3,650		3,673		3,697		3,722		3,746
Free Cash Flow from Operations		(6,544	)	14,551		13,549		11,115		10,935		8,612		6,252		5,994		5,729		5,460		5,187		4,909		4,626		4,339
PV of Free Cash Flow from Operations		(6,419	)	13,473		11,616		8,823		8,038		5,861		3,940		3,497		3,095		2,731		2,403		2,105		1,837		1,595
Sum of PV of Free Cash Flow from Operations	76,230

		2026		2027		2028		2029		2030		2031		2032		2033		2034		2035		2036		2037		2038		2039		2040
Total Revenue		26,056		25,926		25,796		25,667		25,539		30,953		31,106		31,260		31,415		31,571		31,727		31,884		32,042		32,200		32,360
Total Operating Costs		19,638		19,985		20,342		20,708		21,085		21,694		22,075		22,459		22,850		23,249		23,655		24,069		24,491		24,921		25,359
EBITDA		6,418		5,941		5,454		4,959		4,454		9,259		9,031		8,801		8,565		8,322		8,072		7,815		7,551		7,280		7,001
Depreciation		3,771		3,797		3,823		3,850		3,877		3,905		3,934		3,963		3,992		4,022		4,053		4,085		4,117		4,149		7,283
EBIT		2,646		2,143		1,631		1,109		576		5,353		5,007		4,839		4,573		4,300		4,019		3,731		3,435		3,131		(282	)
Income Tax		1,078		873		665		452		235		2,181		2,077		1,972		1,863		1,752		1,638		1,520		1,399		1,276		(115	)
After-tax Operating Profit		1,568		1,270		966		657		342		3,172		3,020		2,867		2,710		2,548		2,381		2,211		2,035		1,855		(167	)
Plus: (Increase)/Decrease in Working Capital		39		40		41		41		42		(400	)	19		19		20		20		21		21		22		23		607
Less: CAPEX		(1,332	)	(1,359	)	(1,386	)	(1,414	)	(1,442	)	(1,471	)	(1,501	)	(1,531	)	(1,561	)	(1,592	)	(1,624	)	(1,657	)	(1,690	)	(1,724	)	(1,758	)
Plus: Deprecaition Benefit		3,771		3,797		3,823		3,850		3,877		3,905		3,934		3,963		3,992		4,022		4,053		4,085		4,117		4,149		7,283
Free Cash Flow from Operations		4,046		3,748		3,444		3,135		2,819		5,206		5,473		5,318		5,160		4,998		4,831		4,660		4,484		4,303		5,964
PV of Free Cash Flow from Operations		1,378		1,181		1,005		847		705		1,206		1,174		1,057		949		851		762		680		606		539		691
Sum of PV of Free Cash Flow from Operations	76,230

6.	Discounted Cash Flow Analysis – SCE 45MW Scenario

		2012·H2		2013		2014		2015		2016		2017		2018		2019		2020		2021		2022		2023		2024		2025
Total Revenue		8,580		20,576		30,710		30,556		30,403		30,251		30,100		29,949		29,800		29,651		29,502		29,355		29,208		29,062
Total Operating Costs		8,561		16,283		17,107		17,289		17,505		17,730		17,980		18,265		18,561		18,864		19,176		19,495		19,824		20,160
EBITDA		18		4,292		13,603		13,267		12,898		12,521		12,119		11,685		11,239		10,786		10,327		9,859		9,385		8,902
Depreciation		21,821		37,401		28,000		18,369		16,967		11,644		5,112		3,982		4,004		4,027		4,050		4,074		4,098		4,123
EBIT		(21,802	)	(33,108	)	(14,398	)	(5,103	)	(4,070	)	878		7,008		7,703		7,235		6,759		6,276		5,785		5,286		4,779
Income Tax		(8,884	)	(13,490	)	(5,867	)	(2,079	)	(1,658	)	358		2,855		3,139		2,948		2,754		2,557		2,357		2,154		1,947
After-tax Operating Profit		(12,919	)	(19,618	)	(8,531	)	(3,024	)	(2,411	)	520		4,152		4,564		4,287		4,005		3,719		3,428		3,132		2,832
Plus: (Increase)/Decrease in Working Capital		(2	)	(356	)	(776	)	28		31		31		33		36		37		38		38		39		40		40
Less: CAPEX		(7,000	)	(21,025	)	(1,051	)	(1,072	)	(1,093	)	(1,115	)	(1,137	)	(1,160	)	(1,183	)	(1,207	)	(1,231	)	(1,256	)	(1,281	)	(1,306	)
Plus: Depreciation Benefit		21,821		37,401		28,000		18,369		16,967		11,644		5,112		3,982		4,004		4,027		4,050		4,074		4,098		4,123
Free Cash Flow from Operations		1,900		(3,598	)	17,643		14,302		13,494		11,080		8,160		7,422		7,145		6,863		6,577		6,286		5,990		5,689
PV of Free Cash Flow from Operations		1,864		(3,332	)	15,126		11,354		9,918		7,541		5,142		4,331		3,860		3,433		3,046		2,696		2,379		2,092
Sum of PV of Free Cash Flow from Operations	87,792

		2026		2027		2028		2029		2030		2031		2032		2033		2034		2035		2036		2037		2038		2039		2040
Total Revenue		28,917		28,772		28,628		28,485		28,343		34,368		34,538		34,709		34,881		35,054		35,227		35,402		35,577		35,753		35,930
Total Operating Costs		20,506		20,861		21,226		21,601		21,986		22,629		23,017		23,407		23,803		24,206		24,617		25,034		25,459		25,891		26,330
EBITDA		8,411		7,911		7,402		6,884		6,356		11,739		11,521		11,303		11,078		10,847		10,610		10,367		10,118		9,862		9,600
Depreciation		4,148		4,174		4,200		4,227		4,254		4,282		4,311		4,340		4,369		4,396		4,430		4,461		4,493		4,526		7,660
EBIT		4,262		3,737		3,202		2,657		2,102		7,456		7,211		6,963		6,709		6,448		6,180		5,906		5,624		5,336		1,940
lncome Tax		1,737		1,523		1,305		1,083		856		3,038		2,938		2,837		2,734		2,627		2,518		2,406		2,292		2,174		790
After-tax Operating Profit		2,526		2,214		1,897		1,574		1,246		4,418		4,273		4,126		3,975		3,821		3,662		3,499		3,333		3,162		1,149
Plus: (Increase)/Decrease in Working Capital		41		42		42		43		44		(449	)	18		18		19		19		20		20		21		21		822
Less: CAPEX		(1,332	)	(1,369	)	(1,386	)	(1,414	)	(1,442	)	(1,471	)	(1,501	)	(1,531	)	(1,561	)	(1,592	)	(1,624	)	(1,657	)	(1,690	)	(1,724	)	(1,758	)
Plus: Depreciation Benefit		4,148		4,174		4,200		4,227		4,254		4,282		4,311		4,340		4,369		4,396		4,430		4,461		4,493		4,526		7,660
Free Cash Flow from Operations		5,383		5,071		4,754		4,431		4,102		6,781		7,101		6,953		6,802		6,647		6,488		6,324		6,157		5,985		7,873
PV of Free Cash Flow from Operations		1,833		1,599		1,388		1,198		1,026		1,571		1,523		1,381		1,251		1,132		1,023		923		832		749		913
Sum of PV of Free Cash Flow from Operations	87,792

7.	Discounted Cash Flow Analysis – SCE 50MW Scenario

		2012·H2		2013		2014		2015		2016		2017		2018		2019		2020		2021		2022		2023		2024		2025
Total Revenue		8,580		20,294		33,654		33,486		33,318		33,152		32,986		32,821		32,657		32,494		32,331		32,169		32,009		31,849
Total Operating Costs		8,561		16,987		17,936		18,111		18,323		18,544		18,795		19,086		19,390		19 ,701		20,020		20,347		20,682		21,027
EBITDA		18		3,307		15,718		15,375		14,995		14,608		14,191		13,735		13,267		12,793		12,312		11,823		11,326		10,822
Depreciatoin		27,495		46,003		33,480		21,975		20,573		13,844		5,907		4,777		4,800		4 ,822		4,846		4,870		4,894		4,919
EBIT		(27,477	)	(42,696	)	(17,762	)	(6,600	)	(5,579	)	764		8,284		8,957		8,467		7,970		7,466		6,953		6,433		5,903
Income Tax		(11,196	)	(17,397	)	(7,237	)	(2,689	)	(2,273	)	311		3,375		3,650		3,450		3,248		3,042		2,833		2,621		2,405
After-tax Operating Profit		(16,281	)	(25,299	)	(10,525	)	(3,911	)	(3,305	)	453		4,908		5,308		5,017		4 ,723		4,424		4,120		3,812		3,498
Plus: (Increase)/Decrease in Working Capital		(2	)	(274	)	(1,034	)	29		32		32		35		38		39		40		40		41		41		42
Less: CAPEX		(7,000	)	(21,025	)	(1,051	)	(1,072	)	(1,093	)	(1,115	)	(1,137	)	(1,160	)	(1,183	)	(1,207	)	(1,231	)	(1,256	)	(1,281	)	(1,306	)
Plus: Depreciation Benefit		27,495		46,003		33,480		21,975		20,573		13,844		5,907		4,777		4,800		4 ,822		4,846		4,870		4,894		4,919
Free Cash Flow from Operations		4,212		(595	)	20,870		17,021		16,206		13,214		9,713		8,963		8,673		8,378		8,079		7,775		7,466		7,152
PV of Free Cash Flow from Operations		4,132		(551	)	17,893		13,512		11,912		8,993		6,121		5,230		4,686		4 ,191		3,742		3,334		2,965		2,630
Sum of PV of Free Cash Flow from Operations	112,189

		2026		2027		2028		2029		2030		2031		2032		2033		2034		2035		2036		2037		2038		20l9		2040
Total Revenue		31,689		31,531		31,373		31,216		31,060		37,677		37,864		38,051		36,240		36,429		38,619		38,810		39,003		39,196		l9,390
Total Operating Costs		21,380		21,743		22,116		22,499		22,893		23,568		23,962		24,357		24,758		25,165		25,579		26,000		26,426		26,859		27,298
EBITDA		10,309		9,788		9,257		8,717		8,168		14,110		13,902		13,695		13,482		13,264		13,040		12,811		12,576		12,336		12,091
Depreciation		4,944		4,969		4,996		5,022		5,050		5,078		5,106		5,135		5,165		5,195		5,225		5,257		5,289		5,321		8,455
EBIT		5,365		4,818		4,262		3,695		3,118		9,032		8,796		8,560		8,317		8,069		7,815		7,554		7,288		7,015		3,636
Income Tax		2,186		1,963		1,736		1,506		1,270		3,680		3,584		3,488		3,389		3,288		3,184		3,078		2,969		2,858		1,482
After-tax Operating Profit		3,179		2,855		2,525		2,189		1,848		5,352		5,212		5,072		4,928		4,781		4,630		4,476		4,318		4,157		2,155
Plus: (Increase)/Decrease in Working Capital		43		43		44		45		46		(495	)	17		17		1	S	18		19		19		20		20		1,028
Less: CAPEX		(1,332	)	(1,359	)	(1,386	)	(1,414	)	(1,442	)	(1,471	)	(1,501	)	(1,531	)	(1,561	)	(1,592	)	(1,624	)	(1,657	)	(1,690	)	(1,724	)	(1,758	)
Plus: Depreciation Benefit		4,944		4,969		4,996		5,022		5,050		5,078		5,106		5,135		5,165		5,195		5,225		5,257		5,289		5,321		8,455
Free Cash Flow from Operations		6,833		6,509		6,179		5,843		5,501		8,463		8,835		8,694		8,550		8,402		8,250		8,095		7,937		7,774		9,880
PV of Free Cash Flow from Operations		2,326		2,052		1,804		1,579		1,377		1,961		1,896		1,727		1,573		1,431		1,301		1,182		1,073		973		1,145
Sum of PV of Free Cash Flow from Operations	112,189

Attached files

Stock widget

Investing forum

ORMAT TECHNOLOGIES, INC. Reports