ORMAT TECHNOLOGIES, INC. - Quarter Report: 2017 March (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

Commission file number: 001-32347

ORMAT TECHNOLOGIES, INC.

(Exact name of registrant as specified in its charter)

(775) 356-9029

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☑     No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ☑     No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: As of May 8, 2017, the number of outstanding shares of common stock, par value $0.001 per share, was 49,706,450.

ORMAT TECHNOLOGIES, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2017

Certain Definitions

Unless the context otherwise requires, all references in this quarterly report to “Ormat”, “the Company”, “we”, “us”, “our company”, “Ormat Technologies” or “our” refer to Ormat Technologies, Inc. and its consolidated subsidiaries.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — GENERAL AND BASIS OF PRESENTATION

These unaudited condensed consolidated interim financial statements of Ormat Technologies, Inc. and its subsidiaries (collectively, the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial statements. Accordingly, they do not contain all information and notes required by U.S. GAAP for annual financial statements. In the opinion of management, these unaudited condensed consolidated interim financial statements reflect all adjustments, which include normal recurring adjustments, necessary for a fair statement of the Company’s consolidated financial position as of March 31, 2017, the consolidated results of operations and comprehensive income (loss) for the three-month periods ended March 31, 2017 and 2016 and the consolidated cash flows for the three-month periods ended March 31, 2017 and 2016.

The financial data and other information disclosed in the notes to the condensed consolidated financial statements related to these periods are unaudited. The results for the three-month period ended March 31, 2017 are not necessarily indicative of the results to be expected for the year ending December 31, 2017.

These condensed unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2016. The condensed consolidated balance sheet data as of December 31, 2016 was derived from the Company’s audited consolidated financial statements for the year ended December 31, 2016, but does not include all disclosures required by U.S. GAAP.

Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest $1,000.

Viridity transaction

On March 15, 2017, the Company completed the acquisition of substantially all of the business and assets of Viridity Energy, Inc. (“VEI”), a privately held Philadelphia-based company engaged in the provision of demand response, energy management and energy storage services. Pursuant to the Asset Purchase Agreement dated as of December 29, 2016, Viridity Energy Solutions Inc. (“Viridity”), a wholly owned subsidiary of the Company paid initial consideration of $35.3 million at closing. Additional contingent consideration with an estimated fair value of $ 12.8 million will be payable in two installments upon the achievement of certain performance milestones measured at the end of fiscal years 2017 and 2020. The acquired business and assets are operated by Viridity.

Using proprietary software and solutions, Viridity serves primarily retail energy providers, utilities, and large commercial and industrial customers. Viridity’s offerings enable its customers to optimize and monetize their energy management, demand response and storage facilities potential by interacting on their behalf with regional transmission organizations and independent system operators.

The Company accounted for the transaction in accordance with Accounting Standard Codification 805, Business Combinations, and consequently recorded intangible assets of $35.0 million primarily relating to Viridity’s storage and non-storage activities with a weighted-average amortization period of 17 years, approximately $0.3 million of working capital and fixed assets, and $13.5 million of goodwill. Following the transaction, the Company consolidated Viridity, in accordance with Accounting Standard Codification 810, Consolidation.

The revenues of Viridity for the period from March 15, 2017 to March 31, 2017 were included in the Company’s consolidated statements of operations and comprehensive income for the three months ended March 31, 2017.

Accounting guidance provides that the allocation of the purchase price may be modified for up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. 

Other comprehensive income

For the three months ended March 31, 2017 and 2016, the Company classified $2 thousand and $3 thousand, respectively, related to derivative instruments designated as cash flow hedges, from accumulated other comprehensive income, of which $3 thousand and $4 thousand, respectively, was recorded to reduce interest expense and $1 thousand, in both periods, was recorded against the income tax provision, in the condensed consolidated statements of operations and comprehensive income. The accumulated net loss included in Other comprehensive income as of March 31, 2017, is $0.6 million

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Write-offs of unsuccessful exploration activities

Write-offs of unsuccessful exploration activities for the three months ended March 31, 2017 and 2016 were $0.0 million and $0.6 million, respectively. The write-off of exploration costs in 2016 was related to the Company’s exploration activities in Nevada, which the Company determined would not support commercial operations.

Concentration of credit risk

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of temporary cash investments and accounts receivable.

The Company places its temporary cash investments with high credit quality financial institutions located in the United States (“U.S.”) and in foreign countries. At March 31, 2017 and December 31, 2016, the Company had deposits totaling $52.5 million and $72.5 million, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At March 31, 2017 and December 31, 2016, the Company’s deposits in foreign countries amounted to approximately $137.4 million and $166.2 million, respectively.

At March 31, 2017 and December 31, 2016, accounts receivable related to operations in foreign countries amounted to approximately $42.2 million and $53.3 million, respectively. At March 31, 2017 and December 31, 2016, accounts receivable from the Company’s primary customers amounted to approximately 60% of the Company’s accounts receivable.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 18.8% and 23.2% of the Company’s total revenues for the three months ended March 31, 2017 and 2016, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 14.3% and 17.4% of the Company’s total revenues for the three months ended March 31, 2017 and 2016, respectively.

Southern California Public Power Authority accounted for 9.0% and 12.1% of the Company’s total revenues for the three months ended March 31, 2017 and 2016, respectively.

Hyundai (Sarulla geothermal power project) accounted for 6.0% and 9.0% of the Company’s total revenues for the three months ended March 31, 2017 and 2016, respectively.

The Company has historically been able to collect on all of its receivable balances, and accordingly, no provision for doubtful accounts has been made.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements effective in the three-month period ended March 31, 2017

Improvement to Employee Share-Based Payment Accounting

In March 2016, the FASB issued ASU 2016-09, Improvement to Employee Share-Based Payment Accounting, an update to the guidance on stock-based compensation. Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in the income statement as they occur. This will replace the current guidance, which requires tax benefits that exceed compensation cost (windfalls) to be recognized in equity. It will also eliminate the need to maintain a “windfall pool,” and will remove the requirement to delay recognizing a windfall until it reduces current taxes payable. The new guidance will also change the cash flow presentation of excess tax benefits, classifying them as operating inflows, consistent with other cash flows related to income taxes. Today, windfalls are classified as financing activities. Also, this guidance will affect the dilutive effects in earnings per share, as there will no longer be excess tax benefits recognized in additional paid in capital. Today those excess tax benefits are included in assumed proceeds from applying the treasury stock method when computing diluted EPS. Under the amended guidance, companies will be able to make an accounting policy election to either (1) continue to estimate forfeitures or (2) account for forfeitures as they occur. This updated guidance is effective for annual and interim periods beginning after December 15, 2016. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

 Interests Held through Related Parties that are under Common Control

In October 2016, the FASB issued ASU 2016-17, Consolidation (Topic 810): Interests held through Related Parties that are under Common Control. The amendments in this update require that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory, Topic 330. The update contains no amendments to disclosure requirements, but replaces the concept of ‘lower of cost or market’ with that of ‘lower of cost and net realizable value’. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those reporting periods. The amendments should be applied prospectively with early adoption permitted. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

New accounting pronouncements effective in future periods

Business Combinations

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805). The update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this update primarily provide a screen to determine when a set of assets and activities is not a business and by that reduces the number of transactions that need to be further evaluated. The amendments in this update should be applied prospectively and are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Statement of Cash Flows

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) – Restricted Cash. The amendments in this update require that a statement of cash flows explain the changes during the period in total cash, cash equivalents, and the amounts generally described as restricted cash or cash equivalents. Therefore, amounts of restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Intra-Entity Transfers of Assets Other than Inventory

In October 2016, the FASB issued ASU 2016-16, Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory. The amendments in this update require that the entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The new guidance does not apply to intra-entity transfers on inventory. The amendments in this update should be applied for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The modified retrospective approach will be required for transition to the new guidance, with cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. Early adoption is permitted in the first quarter of 2017. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements.

Revenues from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenues from Contracts with Customers, Topic 606, which was a joint project of the FASB and the International Accounting Standards Board to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The update provides that an entity should recognize revenue in connection with the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Specifically, an entity is required to apply each of the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contracts; (3) determine the transaction price; (4) allocate the transaction price to the performance obligation in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also prescribes additional financial presentations and disclosures. The amendments in this update are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. Early adoption is permitted no earlier than 2017 for calendar fiscal year entities. The Company expects the adoption of this standard to have an immaterial impact, if any, on its Electricity segment as it accounts for its PPA’s under ASC 840, Leases. The Company still evaluates the potential impact of the adoption of the standard on its Product segment, however, it believes that such impact, if any, will be immaterial.

In March 2016, the FASB issued ASU 2016-08, Principal versus Agent Considerations. This update does not change the core principles of the guidance and is intended to clarify the implementation guidance on principal versus agent considerations. When another entity is involved in providing goods or services to a customer, an entity is required to determine if the nature of its promise is to provide the specific good or service itself (that is, the entity is a principal) or to arrange for that good or service to be provided by the other party (that is, the entity is an agent). The guidance includes indicators to assist an entity in determining whether it acts as a principal or agent in a specified transaction. The amendments in this update are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. Early adoption is permitted no earlier than 2017 for calendar fiscal year entities. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements, however, it believes that any such impact, if any, will be immaterial.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases, Topic 842. This update introduces a number of changes and simplifies previous guidance, primarily the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The update retains the distinction between finance leases and operating leases and the classification criteria between the two types remains substantially similar. Also, lessor accounting remains largely unchanged from previous guidance. However, key aspects of the update were aligned with the revenue recognition guidance in Topic 606. Additionally, the update defines a lease as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (a) the right to obtain substantially all of the economic benefits from the use of the asset and (b) the right to direct the use of the asset. The amendments in this update are effective for annual reporting periods beginning after December 15, 2018, including interim periods within those reporting periods. Early adoption is permitted. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. The update primarily requires that an entity present separately, in other comprehensive income, the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk if the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The application of this update should be by means of cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted as of the beginning of the fiscal year of adoption. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

NOTE 3 — INVENTORIES

Inventories consist of the following:

NOTE 4 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments consist of the following:

The Sarulla Project

The Company holds a 12.75% equity interest in a consortium which is in the process of developing the Sarulla geothermal power project in Indonesia with an expected generating capacity of approximately 330 megawatts (“MW”). The Sarulla project is located in Tapanuli Utara, North Sumatra, Indonesia and will be owned and operated by the consortium members under the framework of a Joint Operating Contract (“JOC”) and Energy Sales Contract (“ESC”) that were signed on April 4, 2013. Under the JOC, PT Pertamina Geothermal Energy (“PGE”), the concession holder for the project, has provided the consortium with the right to use the geothermal field, and under the ESC, PT PLN, the state electric utility, will be the off-taker at Sarulla for a period of 30 years. In addition to its equity holdings in the consortium, the Company designed the Sarulla plant and will supply its Ormat Energy Converters (“OECs”) to the power plant, as further described below. 

The project is being constructed in three phases of approximately 110 MW each, utilizing both steam and brine extracted from the geothermal field to increase the power plant’s efficiency. The first phase of the power plant commenced commercial operation on March 17, 2017. For the second phase of the power plant, engineering and procurement has been substantially completed, site construction is in progress and all of the major generating units, including those to be supplied by Ormat, were delivered. For the third phase of the power plant, engineering, procurement and construction work at the site are in progress and manufacturing of equipment to be supplied by Ormat is underway as planned. Ormat sent the first shipment of equipment manufactured by Ormat during the first quarter of 2017. Drilling for the second and third phases of the power plant is ongoing and the project has achieved to date, based on preliminary estimates, 100% of the required injection capacity and approximately 65% of the required production capacity.

On May 16, 2014, the consortium closed $1.17 billion in financing for the development of the Sarulla project with a consortium of lenders comprised of Japan Bank for International Cooperation (“JBIC”), the Asian Development Bank and six commercial banks and obtained construction and term loans on a limited recourse basis backed by a political risk guarantee from JBIC. Of the $1.17 billion, $0.1 billion (which was drawn down by the Sarulla project company on May 23, 2014) bears a fixed interest rate and $1.07 billion bears interest at a rate linked to LIBOR. The project has missed a few milestones under the loan documents, but has received waivers from the lenders and is currently in compliance with the lenders’ requirements. The project experienced delays in field development and cost overruns resulting from delays and excess drilling costs. Due to the cost overruns in drilling, the lenders requested that the sponsors commit to provide additional equity. The sponsors have agreed and the project’s financing documents were revised to reflect this request. Ormat, in its capacity as a supplier of equipment to the project, has achieved all contractual milestones under the supply agreement.

The Sarulla consortium entered into interest rate swap agreements with various international banks in order to fix the interest linked to LIBOR rate on up to $0.96 billion of the $1.07 billion credit facility at 3.4565%. The interest rate swap became effective as of June 4, 2014 along with the second draw-down by the project company of $50.0 million.

The Sarulla project company accounted for the interest rate swap as a cash flow hedge upon which changes in the fair value of the hedging instrument, relative to the effective portion, will be recorded in other comprehensive income. As such, during the three months ended March 31, 2017 and 2016, the project recorded a gain of $4.5 million and a net loss of $24.9 million, respectively, net of deferred tax, of which the Company's share was $0.6 million and $3.2 million, respectively, which were recorded in other comprehensive income. The related accumulated loss recorded by the Company in Other comprehensive income (loss) as of March 31, 2017 is $5.3 million.

Pursuant to a supply agreement that was signed in October 2013, the Company is supplying its OECs to the power plant and has added the $255.6 million supply contract to its Product Segment backlog. The Company started to recognize revenue from the project during the third quarter of 2014 and will continue to recognize revenue over the course of the year. The Company has eliminated the related intercompany profit of $13.7 million against Equity in loss of investees.

During the three months ended March 31, 2017, the Company made an additional cash equity investment in the Sarulla project of approximately $14.9 million and $26.9 million in total.

NOTE 5— FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received upon selling an asset or paid upon transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the fair value measurement guidance are described below:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities;

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability;

Level 3 — Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (supported by little or no market activity).

The following table sets forth certain fair value information at March 31, 2017 and December 31, 2016 for financial assets and liabilities measured at fair value by level within the fair value hierarchy, as well as cost or amortized cost. As required by the fair value measurement guidance, assets and liabilities are classified in their entirety based on the lowest level of inputs that is significant to the fair value measurement.

The amounts set forth in the tables above include investments in debt instruments and money market funds (which are included in cash equivalents). Those securities and deposits are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.

The following table presents the amounts of gain (loss) recognized in the consolidated statements of operations and comprehensive income on derivative instruments not designated as hedges:

In January, 2017, the Company entered into Henry Hub Natural Gas Future contracts under which it has bought a number of put options covering a notional quantity of approximately 4.1 million British Thermal Units ("MMbtu") with exercise prices of $3 and expiration dates ranging from January 26, 2017 until November 27, 2017 in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison. The Company paid an aggregate amount of approximately $0.7 million for these put options. The put option contracts have monthly expiration dates at which the options can be called and the transaction would be settled on a net cash basis.

On February 2, 2016, the Company entered into Henry Hub Natural Gas Future contracts under which it has written a number of call options covering a notional quantity of approximately 4.1 MMbtu with exercise prices of $2 and expiration dates ranging from February 24, 2016 until December 27, 2016 in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison. The Company received an aggregate premium of approximately $1.9 million from these call options. The call option contracts have monthly expiration dates on which the options can be called and the Company would have to settle its liability on a cash basis.

On February 24, 2016, the Company entered into Brent Oil Future contracts under which it has written a number of call options covering a notional quantity of approximately 185,000 barrels (“BBL”) of Brent with exercise prices of $32.80 to $35.50 and expiration dates ranging from March 24, 2016 until December 22, 2016 in order to reduce its exposure to fluctuations in Brent prices under its PPA with HELCO. The Company received an aggregate premium of approximately $1.1 million from these call options. The call option contracts have monthly expiration dates on which the options can be called and the Company would have to settle its liability on a cash basis. Moreover, during March 2016, the Company rolled 2 existing call options covering a total notional quantity of 31,800 BBL of Brent in order to limit its exposure to $41 to $42.50 instead of $32.80 to $33.50. In addition, the Company entered into short risk reversal transactions (sell call and buy put options) by rolling existing call options covering notional quantities of 16,500 BBL and 17,000 BBL in order to limit its exposure from the outstanding call options originally entered into in February 2016 to between $28.50 and $37.50 and $28 and $38.50, respectively.

The foregoing future and forward transactions were not designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “Derivatives and foreign currency transaction gains (losses).

There were no transfers of assets or liabilities between Level 1, Level 2 and Level 3 during the three months ended March 31, 2017.

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

The fair value of the OFC Senior Secured Notes is determined using observable market prices as these securities are traded. The fair value of all the other long-term debt is determined by a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current borrowing rates. The fair value of revolving lines of credit is determined using a comparison of market-based price sources that are reflective of similar credit ratings to those of the Company.

The carrying value of other financial instruments, such as revolving lines of credit, deposits, and other long-term debt approximates fair value.

The following table presents the fair value of financial instruments as of March 31, 2017:

The following table presents the fair value of financial instruments as of December 31, 2016:

NOTE 6 — STOCK-BASED COMPENSATION

The 2004 Incentive Compensation Plan

In 2004, the Company’s Board of Directors (the “Board”) adopted the 2004 Incentive Compensation Plan (“2004 Incentive Plan”), which provided for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, stock appreciation rights (“SARs”), stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2004 Incentive Plan, a total of 3,750,000 shares of the Company’s common stock were reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the 2004 Incentive Plan cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. Options granted to non-employee directors under the 2004 Incentive Plan cliff vest and are exercisable one year after the grant date. Vested stock-based awards may be exercised for up to ten years from the grant date. The shares of common stock issued in respect of awards under the 2004 Incentive Plan are issued from the Company’s authorized share capital upon exercise of options or SARs. The 2004 Incentive Plan expired in May 2012 upon adoption of the 2012 Incentive Compensation Plan (“2012 Incentive Plan”), except as to stock-based awards outstanding under the 2004 Incentive Plan on that date.

The 2012 Incentive Compensation Plan

In May 2012, the Company’s shareholders adopted the 2012 Incentive Plan, which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, SARs, stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2012 Incentive Plan, a total of 4,000,000 shares of the Company’s common stock have been reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the 2012 Incentive Plan typically vest and become exercisable as follows: 25% vest 24 months after the grant date, an additional 25% vest 36 months after the grant date, and the remaining 50% vest 48 months after the grant date. Options granted to non-employee directors under the 2012 Incentive Plan will vest and become exercisable one year after the grant date. The term of stock-based awards typically ranges from six to ten years from the grant date. The shares of common stock issued in respect of awards under the 2012 Incentive Plan are issued from the Company’s authorized share capital upon exercise of options or SARs.

The 2012 Incentive Plan empowers the Board, in its discretion, to amend the 2012 Incentive Plan in certain respects. Consistent with this authority, in February 2014 the Board adopted and approved certain amendments to the 2012 Incentive Plan. The key amendments are as follows:

●      Increase of per grant limit: Section 15(a) of the 2012 Incentive Plan was amended to allow the grant of up to 400,000 shares of the Company’s common stock with respect to the initial grant of an equity award to newly hired executive officers in any calendar year; and

●      Acceleration of vesting: Section 15(l) of the 2012 Incentive Plan was amended to clarify the Company’s ability to provide in the applicable award agreement that part and/or all of the award will be accelerated upon the occurrence of certain predetermined events and/or conditions, such as a "change in control" (as defined in the 2012 Incentive Plan, as amended).

NOTE 7 — INTEREST EXPENSE, NET

The components of interest expense are as follows:

NOTE 8 — EARNINGS PER SHARE

Basic earnings per share attributable to the Company’s stockholders is computed by dividing net income or loss attributable to the Company’s stockholders by the weighted average number of shares of common stock outstanding for the period. The Company does not have any equity instruments that are dilutive, except for employee stock-based awards.

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

The number of stock-based awards that could potentially dilute future earnings per share and that were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was 11,491 and 177,978 for the three months ended March 31, 2017 and 2016, respectively.

NOTE 9 — BUSINESS SEGMENTS

The Company has two reporting segments: the Electricity segment and the Product segment. These segments are managed and reported separately as each offers different products and serves different markets. The Electricity segment is engaged in the sale of electricity from the Company’s power plants pursuant to PPAs. The Product segment is engaged in the manufacture, including design and development, of turbines and power units for the supply of electrical energy and in the associated construction of power plants utilizing the power units manufactured by the Company to supply energy from geothermal fields and other alternative energy sources. Transfer prices between the operating segments are determined based on current market values or cost plus markup of the seller’s business segment.

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:

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

NOTE 10 — COMMITMENTS AND CONTINGENCIES

In addition, from time to time, the Company is named as a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, the Company accrues reserves when a loss is probable and the amount of such loss can be reasonably estimated. It is the opinion of the Company’s management that the outcome of these proceedings, individually and collectively, will not be material to the Company’s consolidated financial statements as a whole.

NOTE 11 — INCOME TAXES

The Company’s effective tax rate for the three months ended March 31, 2017 and 2016 was 20.8% and 23.0%, respectively. The effective rate differs from the federal statutory rate of 35% for the three months ended March 31, 2017 due to: (i) a full valuation allowance against the Company’s U.S. deferred tax assets in respect of net operating loss (“NOL”) carryforwards and unutilized tax credits (see below), (ii) a lower tax rate in Israel of 16%, partially offset by a tax rate in Kenya of 37.5%; and (iii) a tax credit and tax exemption related to the Company’s subsidiaries in Guatemala. The effect of the tax credit and tax exemption for the three months ended March 31, 2017 and 2016 was $0.9 million and $1.1 million, respectively.

The Company is currently in a net deferred tax asset position with a full valuation allowance. As of December 31, 2016, the Company had U.S. federal NOL carryforwards of approximately $299.6 million, which expire between 2029 and 2036, and state NOL carryforwards of approximately $244.7 million, which expire between 2018 and 2036, which are available to reduce future taxable income. The Company's investment tax credits (“ITCs”) in the amount of $1.3 million at December 31, 2016 are available for a 20-year period and expire between 2022 and 2024. The Company's production tax credits (“PTCs”) in the amount of $82.5 million at December 31, 2016 are available for a 20-year period and expire between 2026 and 2036. The Company also has offsetting deferred tax liabilities in the U.S.

Realization of the deferred tax assets and tax credits is dependent on generating sufficient taxable income in appropriate jurisdictions prior to expiration of the NOL carryforwards and tax credits. Based upon available evidence of the Company’s ability to generate additional taxable income in the future and historical losses in prior years, a full valuation allowance is recorded against the U.S. deferred tax assets, as it is more likely than not that the deferred tax assets will not be utilized.

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $367 million at December 31, 2016. It is the Company’s intention to reinvest undistributed earnings of its foreign subsidiaries and thereby indefinitely postpone their remittance. Accordingly, no provision has been made for foreign withholding taxes or U.S. income taxes which may become payable if undistributed earnings of foreign subsidiaries were paid as dividends to the Company. The additional taxes on that portion of undistributed earnings which is available for dividends are not practicably determinable.

The Company believes that based on its plans to increase operations outside of the U.S., the cash generated from the Company’s operations outside of the U.S. will be reinvested outside of the U.S. and, accordingly, we do not currently plan to repatriate the funds we have designated as being permanently invested outside of the U.S. If we change our plans, we may be required to accrue and pay U.S. taxes to repatriate these funds.

The Company is subject to income taxes in the U.S. (federal and state) and numerous foreign jurisdictions. Significant judgment is required in evaluating tax positions and determining the position for income taxes. Reserves are established to tax-related uncertainties based on estimates of whether, and the extent to which additional taxes will be due. As of March 31, 2017, the Company is unaware of any potentially significant uncertain tax positions for which a reserve has not been established.

As previously reported by the Company, the Kenya Revenue Authority (“KRA”) conducted an audit related to the Company’s operations in Kenya for fiscal years 2012 and 2013. In January 2017, KRA concluded its audit for the subject period and issued a demand letter to the Company for additional tax payments of approximately $16.1 million, including interest and penalties. On February 8, 2017, the Company submitted a notice of objection to the KRA demand letter in which it presented its tax positions. On March 29, 2017, the KRA submitted a response to the objection letter, primarily indicating that it accepted our position relating to the mining activity claim, as previously described in the Company’s annaul report on Form 10-K for the year ended December 31, 2016, and removed this claim from their tax assessment. As a result, the KRA reduced its demand for additional tax payment to approximately $10.0 million, including interest and penalties. On April 28, 2017, the Company submitted a Notice of Appeal to the KRA, noting that it intends to appeal to the Tax Tribunal on parts of the KRA assessment. The Company has recorded a provision based on its assessment of its reasonably expected potential exposure.

NOTE 12 — SUBSEQUENT EVENTS

Cash dividend

On May 8, 2017, the Board declared, approved and authorized payment of a quarterly dividend of $4.0 million ($0.08 per share) to all holders of the Company’s issued and outstanding shares of common stock on May 22, 2017, payable on May 31, 2017.

ORIX transaction

On May 4, 2017, we announced that ORIX Corporation ("ORIX") will acquire an approximately 22%  ownership stake in the Company  by purchasing approximately 11 million shares of the Company's common stock from FIMI ENRG Limited Partnership, FIMI ENRG, L.P. (collectively, "FIMI"), Bronicki Investments, Ltd. ("Bronicki"), and senior members of management. The per share sale price to be paid by ORIX at closing (subject to satisfaction of customary conditions, including regulatory approvals) is $57, which was the prevailing market price at the time that ORIX, FIMI and Bronicki reached agreement on the commercial terms of their transaction. 

Under related agreements, ORIX will have the right to designate three persons to our board of directors, which will be expanded to nine directors, and also propose a fourth person to be mutually agreed by us and ORIX to serve as a new independent director on our board.  In addition, for so long as ORIX is entitled to board representation, ORIX will be subject to certain customary standstill restrictions, including an effective 25% cap on its voting rights.  ORIX will also have certain customary registration rights with respect to the shares of our common stock that it will own.

Under terms of a new Commercial Cooperation Agreement between us and ORIX, we will have exclusive rights to develop, own, operate and provide equipment for ORIX geothermal energy projects in all markets outside of Japan.  In addition, we will have certain rights to serve as technical partner and co-invest in ORIX geothermal energy projects in Japan.  Also, ORIX will assist us in obtaining project financing for our geothermal energy projects from a variety of leading providers of renewable energy debt financing with which ORIX has relationships in Asia and around the world.

We entered into the agreements with ORIX following the unanimous recommendation of a Special Committee of our board of directors that was formed to evaluate and negotiate the shareholder arrangements proposed by ORIX, with independent legal advice from Davis Polk & Wardwell LLP, and following the unanimous approval by our board of directors.

We expect closing under the various agreements described above to occur in the third quarter of 2017. 

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

Cautionary Note Regarding Forward-Looking Statements

This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this quarterly report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as our projections of annual revenues, expenses and debt service coverage with respect to our debt securities, future capital expenditures, business strategy, competitive strengths, goals, development or operation of generation assets, market and industry developments and the growth of our business and operations, are forward-looking statements. When used in this quarterly report on Form 10-Q, the words “may”, “will”, “could”, “should”, “expects”, “plans”, “anticipates”, “believes”, “estimates”, “predicts”, “projects”, “potential”, or “contemplate” or the negative of these terms or other comparable terminology are intended to identify forward-looking statements, although not all forward-looking statements contain such words or expressions. The forward-looking statements in this quarterly report are primarily located in the material set forth under the headings “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Risk Factors”, and “Notes to Condensed Consolidated Financial Statements”, but are found in other locations as well. These forward-looking statements generally relate to our plans, objectives and expectations for future operations and are based upon management’s current estimates and projections of future results or trends. Although we believe that our plans and objectives reflected in or suggested by these forward-looking statements are reasonable, we may not achieve these plans or objectives. You should read this quarterly report on Form 10-Q completely and with the understanding that actual future results and developments may be materially different from what we expect due to a number of risks and uncertainties, many of which are beyond our control.

Specific factors that might cause actual results to differ from our expectations include, but are not limited to:

Investors are cautioned that these forward-looking statements are inherently uncertain. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results or outcomes may vary materially from those described herein. Other than as required by law, we undertake no obligation to update forward-looking statements even though our situation may change in the future. Given these risks and uncertainties, readers are cautioned not to place undue reliance on such forward-looking statements.

The following discussion and analysis of our financial condition and results of operations should be read together with our condensed consolidated financial statements and related notes included elsewhere in this report and the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2016 and any updates contained herein as well as those set forth in our reports and other filings made with the SEC.

General

Overview

We are a leading vertically integrated company that is currently primarily engaged in the geothermal and recovered energy power business. With the objective of becoming a leading global provider of renewable energy, we focus on several key initiatives under our new strategic plan, as described below.

We design, develop, build, sell, own, and operate clean, environmentally friendly geothermal and recovered energy-based power plants, usually using equipment that we design and manufacture.

Our geothermal power plants include both power plants that we have built and power plants that we have acquired, while we have built all of our recovered energy-based plants. We currently conduct our business activities in two business segments:

We recently expanded our operations to include the provision of services in the demand response, energy management and energy storage markets. On March 15, 2017, we completed the acquisition of substantially all of the business and assets of Viridity Energy, Inc. (“VEI”), a Philadelphia-based company with nearly a decade of expertise and leadership in demand response, energy management and storage. The acquired business and assets are owned and operated by our wholly owned subsidiary Viridity Energy Solutions Inc. (“Viridity”). The acquisition enabled us to enter the growing energy storage and demand response markets. We intend to use Viridity to accelerate long-term growth, expand our market presence, and further develop our demand response VPower™ software platform and energy storage services. We plan to continue to provide services and products to existing customers of the acquired business, while expanding into new geographies and targeting a broader potential customer base.

Both our Electricity segment and Product segment operations are conducted in the United States and the rest of the world. Our current generating portfolio includes geothermal power plants in the United States, Guatemala, Kenya and Guadeloupe, as well as recovered energy generation power plants in the United States.

For the three months ended March 31, 2017, our total revenues increased by 25.3% (from $151.6 million to $189.9 million) over the corresponding period in 2016.

For the three months ended March 31, 2017, Electricity segment revenues were $115.8 million, compared to $107.9 million for the three months ended March 31, 2016, an increase of 7.3% from the prior year period. Product segment revenues for the three months ended March 31, 2017 were $74.1 million, compared to $43.7 million during the three months ended March 31, 2016, an increase of 69.5% from the prior year period.

During the three months ended March 31, 2017 and 2016, our consolidated power plants generated 1,427,704 megawatt hours (“MWh”) and 1,396,868 MWh, respectively, an increase of 2.2%.

For the three months ended March 31, 2017, our Electricity segment generated approximately 61.0% of our total revenues, while our Product segment generated approximately 39.0% of our total revenues. For the three months ended March 31, 2016, our Electricity segment generated approximately 71.2% of our total revenues, while our Product segment generated approximately 28.8% of our total revenues.

For the three months ended March 31, 2017, approximately 87.4% of our Electricity segment revenues were derived from PPAs with fixed energy rates which are not affected by fluctuations in energy commodity prices. We have variable price PPAs in California and Hawaii, which provide for payments based on the local utilities’ avoided cost, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others, as follows:

We recently reduced our economic exposure to fluctuations in the price of oil and natural gas from February 2017 until December 2017, and before that we reduced our economic exposure to fluctuations in the price of natural gas from March 31, 2015 and from June 1, 2015 until December 31, 2015 and from February 3, 2016 until December 29, 2016 by entering into derivatives transactions. For the three months ended March 31, 2017, we recorded a net loss of $0.2 million under Derivatives and foreign currency transaction gains.

To comply with obligations under their respective PPAs, certain of our project subsidiaries are structured as special purpose, bankruptcy remote entities and their assets and liabilities are ring-fenced. Such assets are not generally available to pay our debt, other than debt at the respective project subsidiary level. However, these project subsidiaries are allowed to pay dividends and make distributions of cash flows generated by their assets to us, subject in some cases to restrictions in debt instruments, as described below.

Electricity segment revenues are also subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under “Seasonality”.

Revenues attributable to our Product segment are based on the sale of equipment, engineering, procurement and construction (“EPC”) contracts and the provision of various services to our customers. Product segment revenues may vary from period to period because of the timing of our receipt of purchase orders and the progress of our equipment manufacturing and execution of the relevant project.

Our management assesses the performance of our two operating segments differently. In the case of our Electricity segment, when making decisions about potential acquisitions or the development of new projects, management typically focuses on the internal rate of return of the relevant investment, technical and geological matters and other business considerations. Management evaluates our operating power plants based on revenues, expenses, and EBITDA, and our projects that are under development based on costs attributable to each such project. Management evaluates the performance of our Product segment based on the timely delivery of our products, performance quality of our products, revenues and costs actually incurred to complete customer orders compared to the costs originally budgeted for such orders.

Recent Developments

The most significant developments in our company and business since January 1, 2017 are described below:

Trends and Uncertainties

Different trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee. However, we believe that our results of operations and financial condition for the foreseeable future will be primarily affected by the following trends, factors and uncertainties that are from time to time also subject to market cycles:

Revenues

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

Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 87.4% of our Electricity revenues for the three months ended March 31, 2017 were derived from PPAs with fixed price components, we have variable price PPAs in California and Hawaii. Our SO#4 PPAs totaling approximately 90 MWs in California are subject to the impact of fluctuations in natural gas prices whereas the prices paid for electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii is impacted by the price of oil as well as other commodities. Accordingly, our revenues from those power plants may fluctuate.

Our Electricity segment revenues are also subject to seasonal variations, as more fully described in “Seasonality” below.

Our PPAs generally provide for energy payments alone, or energy and capacity payments. Generally, capacity payments are payments calculated based on the amount of time that our power plants are available to generate electricity. Some of our PPAs provide for bonus payments in the event that we are able to exceed certain target capacity levels and the potential forfeiture of payments if we fail to meet certain minimum target capacity levels. Energy payments, on the other hand, are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser’s avoided costs. Our more recent PPAs generally provide for energy payments alone with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.

Revenues attributable to our Product segment fluctuate between periods, mainly based on our ability to receive customer orders, the status and timing of such orders, delivery of raw materials and the completion of manufacturing. Larger customer orders for our products are typically the result of our sales efforts, our participation in, and winning of, tenders or requests for proposals issued by potential customers in connection with projects they are developing as well as returning customers. Such projects often take a significant amount of time to design and develop and are subject to various contingencies, such as the customer’s ability to raise the necessary financing for a project. Consequently, we are generally unable to predict the timing of such orders for our products and may not be able to replace existing orders that we have completed with new ones. As a result, revenues from our Product segment fluctuate (sometimes, extensively) from period to period.

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

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

The contribution of our domestic and foreign operations within our Electricity segment and Product segment to combined pre-tax income differ in a number of ways.

Electricity Segment. Our Electricity segment domestic revenues were approximately 90% and 117% higher than our Electricity segment foreign revenues for the three months ended March 31, 2017 and 2016, respectively. However, domestic operations in our Electricity segment have higher costs of revenues and expenses than the foreign operations in our Electricity segment. Our foreign power plants are located in lower-cost regions, like Kenya, Guatemala and Guadeloupe, which favorably impact payroll and maintenance expenses among other items. They are also newer than most of our domestic power plants and therefore tend to have lower maintenance costs and higher availability factors than our domestic power plants.

Product Segment. Our Product segment foreign revenues were approximately 99% and 87% of our total Product segment revenues for the three months ended March 31, 2017 and 2016. Our Product segment foreign activity also benefits from lower costs of revenues and expenses than Product segment domestic activity such as labor and transportation costs. Accordingly, our Product segment foreign activity contributes more than our Product segment domestic activity to our pre-tax income from operations.

Relative Contributions. While our combined (domestic and foreign) Electricity segment revenues exceeded our combined Product segment revenues by approximately $42 million and $64 million, respectively, for the three months ended March 31, 2017 and 2016 (primarily foreign) Product segment revenues resulted in higher pre-tax income from foreign operations for both of those periods.

Seasonality

The prices paid for the electricity generated by some of our domestic power plants pursuant to our PPAs are subject to seasonal variations. The prices (mainly for capacity) paid for electricity under the PPAs with Southern California Edison and Pacific Gas & Electric in California for the Heber 2 power plant in the Heber complex, the Mammoth complex, the Ormesa complex, and the North Brawley power plant are higher in the months of June through September. As a result, we receive, and expect to continue to receive in the future, higher revenues from these power plants and complexes during such months. In the winter, our power plants produce more energy principally due to the lower ambient temperature, which has a favorable impact on the energy component of our Electricity revenues. The higher payments payable by Southern California Edison and Pacific Gas & Electric Company in the summer months offset the negative impact on our revenues from lower generation in the summer due to the higher ambient temperature.

        Breakdown of Cost of Revenues

Electricity Segment

The principal cost of revenues attributable to our operating power plants includes operation and maintenance expenses comprised of salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes, insurance and, for some of our projects, purchases of make-up water for use in our cooling towers and also depreciation and amortization. In our California power plants, our principal cost of revenues also includes transmission charges and scheduling charges. In some of our Nevada power plants, we also incur transmission and wheeling charges. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual power plants from quarter to quarter. Payments made to government agencies and private entities on account of site leases where plants are located are included in cost of revenues. Royalty payments, included in cost of revenues, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenues derived from the associated geothermal rights. Royalties constituted approximately 3.9% and 4.3% of Electricity segment revenues for the three months ended March 31, 2017 and March 31, 2016, respectively.

Product Segment

The principal cost of revenues attributable to our Product segment includes materials, salaries and related employee benefits, expenses related to subcontracting activities, and transportation expenses. Sales commissions to sales representatives are included in selling and marketing expenses. Some of the principal expenses attributable to our Product segment, such as a portion of the costs related to labor, utilities and other support services are fixed, while others, such as materials, construction, transportation and sales commissions, are variable and may fluctuate significantly depending on market conditions. As a result, the cost of revenues attributable to our Product segment, expressed as a percentage of total revenues, fluctuates. Another reason for such fluctuation is that in responding to bids for our products, we price our products and services in relation to existing competition and other prevailing market conditions, which may vary substantially from order to order.

Cash and Cash Equivalents

Our cash and cash equivalents decreased to $174.1 million as of March 31, 2017 from $230.2 million as of December 31, 2016. This decrease was principally due to: (i) our use of $52.9 million to fund capital expenditures; (ii) $35.3 million net cash paid for the acquisition of substantially all the business and assets of VEI; (iii) a net change in in restricted cash and cash equivalents of $25.6 million; (iv) an unconsolidated investment in Sarulla of $14.9 million; (v) net repayment of $13.4 million of long-term debt; (vi) $6.8 million cash paid to non-controlling interests; and (vii) a $8.4 million cash dividend paid. This decrease was partially offset by: (i) $71.5 million derived from operating activities during the three months ended March 31, 2017; and (ii) net proceeds of $30.0 million from our revolving credit lines with commercial banks. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of March 31, 2017 was $524.8 million, as described below in “Liquidity and Capital Resources”. As of March 31, 2017, we have utilized $350.6 million of our corporate borrowing capacity.

Critical Accounting Estimates and Assumptions

A comprehensive discussion of our critical accounting estimates and assumptions is included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our Annual Report on Form 10-K for the year ended December 31, 2016.

New Accounting Pronouncements

See Note 2 to our condensed consolidated financial statements set forth in Item 1 of this quarterly report for information regarding new accounting pronouncements.

Results of Operations

Our historical operating results in dollars and as a percentage of total revenues are presented below. A comparison of the different periods described below may be of limited utility primarily as a result of (i) our recent construction or disposition of new power plants and enhancement of acquired power plants; and (ii) fluctuation in revenues from our Product segment.