UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

Mark one:
☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, ~~2017~~2018
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

COMMISSION FILE NUMBER: 0-12500

ISRAMCO, INC.

(Exact name of registrant as specified in its charter)

Delaware	13-3145265
(State or Other Jurisdiction of Incorporation)	(IRS Employer Identification No.)

1001 West Loop South, Suite 750, Houston Texas 77027

(Address of Principal Executive Offices)

713-621-6785

(Registrant’s Telephone Number, including Area Code)

Securities registered under Section 12(b) of the Exchange Act: None

Securities registered under Section 12(g) of the Exchange Act:

Common Stock, par value $0.01

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☐

Indicate by check mark whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 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 if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained in this Form, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or 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.

Large accelerated filer ☐

Accelerated filer ☒

Non-accelerated filer ☐

Smaller Reporting Company ☐

Emerging growth company ☐

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 Securities Exchange Act). Yes ☐ No ☒

As of March 1218, ~~2018~~2019, there were 2,717,648 shares of the Registrant’s common stock par value $0.01 per share (“Common Stock”) outstanding. The aggregate market value of the Common Stock held by non-affiliates of the Registrant at March 914, ~~2018~~2019, based on the last sale price of such equity reported on Nasdaq Market, was approximately $6977.4572 million.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for its ~~2017~~2018 Annual Meeting of Stockholders to be filed not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K are incorporated by reference into Part III of this Form 10-K.

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ISRAMCO, INC.

~~2017~~2018 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

		Page
PART I
ITEM 1.	BUSINESS	5
ITEM 1A.	RISK FACTORS	1415
ITEM 1B.	UNRESOLVED STAFF COMMENTS	27
ITEM 2.	PROPERTIES	2728
ITEM 3.	LEGAL PROCEEDINGS	29
ITEM 4.	MINE SAFETY DISCLOSURES	3029
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	3130
ITEM 6.	SELECTED FINANCIAL DATA	3130
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	3231
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	4946
ITEM 8.	CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA	5047
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	5047
ITEM 9A.	CONTROLS AND PROCEDURES	5047
ITEM 9B.	OTHER INFORMATION	5048
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	5149
ITEM 11.	EXECUTIVE COMPENSATION	5149
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	5149
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	5149
ITEM 14.	PRINCIPAL ACCOUNTING FEES & SERVICES	5149
PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	5351

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Special note regarding forward-looking statements

This report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number of anticipated wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. The actual results could differ materially from those anticipated in these forward-looking statements. One should consider carefully the statements under the “Risk Factors” section of this report and other sections of this report that describe factors that could cause our actual results to differ from those set forth in the forward-looking statements, including, but not limited to, the following factors:

•● the timing and extent of changes in prices for, and demand for, crude oil and condensate, NGLs, natural gas and related commodities; • the possibility that the industry may be subject to future regulatory or legislative actions (including any additional taxes and changes in environmental regulation); • the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs; • the possibility that production decline rates for some of our oil and gas producing properties are greater than we expect; • our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions; • the ability to replace oil and natural gas reserves; • our ability to retain skilled operations personnel whom we would need in the event of an upturn in the demand for our services; • environmental risks; • drilling and operating risks; • the loss of one or more of our larger customers; • our ability to implement price increases or maintain pricing on our core services; • exploration and development risks; • competition, including competition for acreage in oil and gas producing areas and for experienced personnel; • management’s ability to execute our plans to meet our goals; • technological advances affecting energy consumption and energy supply; • the collectability of our receivables;

●

the possibility that the industry may be subject to future regulatory or legislative actions (including any additional taxes and changes in environmental regulation);

●

the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

●

the possibility that production decline rates for some of our oil and gas producing properties are greater than we expect;

●

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;

●

the ability to replace oil and natural gas reserves;

●

our ability to retain skilled operations personnel whom we would need in the event of an upturn in the demand for our services;

●

environmental risks;

●

drilling and operating risks;

●

the loss of one or more of our larger customers;

●

our ability to implement price increases or maintain pricing on our core services;

●

exploration and development risks;

●

competition, including competition for acreage in oil and gas producing areas and for experienced personnel;

●

management’s ability to execute our plans to meet our goals;

●

technological advances affecting energy consumption and energy supply;

●

the collectability of our receivables;

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•● our ability to retain key members of senior management and key technical employees;

•● industry capacity;

•● employee turnover and our ability to replace or add qualified workers;

•● severe weather impacts on our business;

•● operating risks and the possibility that our insurance may not be adequate to cover all of our losses or liabilities;

•● our ability to repay our debt when due;

•● changes in domestic and global economic and business conditions that impact the demand for oil, natural gas liquids and natural gas;

•● changes in domestic and global supplies of oil, natural gas and natural gas liquids arising from economic and business conditions (including actions by the Organization of the Petroleum Exporting Countries);

•● our ability to obtain goods and services, such as drilling rigs and tubulars, and access to adequate gathering systems and pipeline take-away capacity, to execute our drilling and development programs;

•● general economic and regulatory conditions, whether internationally, nationally, or in the regional and local market areas in which we do business, may be less favorable than expected; and

•● other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our business, operations or commodity prices.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in the section entitled “Risk Factors” included in this report. All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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PART I

ITEM 1. BUSINESS

Overview

Isramco, Inc., (NASDAQ: ISRL) is a Delaware corporation incorporated in 1982 (hereinafter, “we”, the “Company” or “Isramco”). The Company together with its subsidiaries is an independent oil and natural gas company, engaged in the exploration, development and production of predominately oil and natural gas properties located onshore in the United States and offshore Israel. The Company also operates a production services company that provides a full range of onshore production services to oil companies and independent oil and natural gas production companies conducting operations in the United States.

We currently conduct our operations through two operating segments: our Exploration, Development and Production Segment and our Production Services Segment. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 1011, “Segment Information”, of the Notes to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplemental Data, of this Annual Report on Form 10-K.

Exploration, Development and Production Segment

At December 31, ~~2017~~2018, our estimated total proved oil, natural gas reserves and natural gas liquids, as prepared by our independent reserve engineering firms, Netherland, Sewell & Associates, Inc. and Cawley, Gillespie & Associates, Inc., were approximately 3840,~~653~~267 thousand barrels of oil equivalent (“MBOE”), consisting of 12,~~765~~125 thousand barrels (MBbls) of oil, ~~216~~223,~~451~~915 million cubic feet (MMcf) of natural gas and ~~813~~823 thousand barrels (MBbls) of natural gas liquids. Approximately 8667.02% of our proved reserves were classified as proved developed (See Note 1314, “Supplemental Oil and Gas Information”). Full year ~~2017~~2018 production averaged 3.7875 MBOE/d compared to 3.8078 MBOE/d in ~~2016~~2017. Tamar Field production share amounted to 2.4657 MBOE/d out of total 3.7875 MBOE/d compared to 2.3546 MBOE/d in ~~2016~~2017.

United States

We, through our wholly-owned subsidiaries, are involved in oil and gas exploration, including the development, production and operation of wells in the United States. We own varying working interests in oil and gas wells in Louisiana, Texas, New Mexico, Oklahoma, Wyoming, Utah and Colorado and currently serve as operator of approximately 422 producing wells located mainly in Texas and in New Mexico.

Israel

In 2007, we closed our branch in Israel in order to focus on our expanding presence in the United States. Despite the closure of that branch we retained certain overriding royalties in three oil and gas licenses located offshore Israel. These licenses granted by the government of Israel are known as the “Michal”, “Matan” and “Shimshon” Licenses.

In 2009, two natural gas discoveries, known as “Tamar” and “Dalit”, were made within the area covered by the Michal and Matan Licenses, respectively. In December 2009, the Israeli Petroleum Commissioner granted Noble Energy, Inc. (“Noble”) and its partners, (the “Tamar Consortium”), two leases (the “Tamar Lease” and the “Dalit Lease”). The Leases are scheduled to expire in December 2038 and cover the Tamar and Dalit gas fields (collectively the “Tamar Field”). The Tamar Field is approximately 95 kilometers off the coast of the Israel, in the Israel exclusive economic zone of the Eastern Mediterranean, with a water depth of approximately 1,700 meters.

We own all ownership units in Tamar Royalties LLC, a Delaware limited liability company. Tamar Royalties LLC owns an overriding royalty interest of 1.5375% before payout /which escalates to 2.7375% after payout in the Tamar Field (collectively the “Tamar Royalty”). An overriding royalty interest is an ownership interest in the oil and gas leasehold estate equating to a certain percentage of production or production revenues, calculated free of the costs of production and development of the underlying lease(s), but subject to its proportionate share of certain post production costs. An overriding royalty interest is a non-possessory interest in the oil and gas leasehold estate and, accordingly, we have no control over the operations, drilling, expenses, timing, production, sales, or any other aspect of development or production of the Tamar Field.

Production from the Tamar Field commenced in March 2013. The Tamar Field is now operational and delivering natural gas to Israel. The natural gas flows from the Tamar Field through the world’s longest subsea tieback, more than 90 miles to the Tamar platform, and then to the Ashdod onshore terminal (AOT).

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With regard to the payout of the Tamar Field, a disagreement between the Company and Isramco Negev 2 Limited Partnership has emerged as to what costs should be included in the calculation of payout. In addition to actual costs for the development of the Tamar Field, Isramco, Negev 2 Limited Partnership has asserted that the following costs should be included in the calculation of payout: (i) Isramco Negev 2 Limited Partnership’s financing costs; (ii) the general and administrative expenses of Isramco Negev 2 Limited Partnership; (iii) the expected decommissioning costs of the Tamar Field; and (iv) expected future payments to be made in respect of the “Sheshinsky Levy” under Israeli law. In addition to the claim asserted by Isramco Negev 2 Limited Partnership, the Company has asserted counterclaims related to Isramco Negev 2 Limited Partnership’s inclusion into the payout calculation of its expenses related to gathering and transportation infrastructure. The ~~disagreement~~disagreements primarily ~~stems~~stem from the fact that the agreements governing the creation of the Tamar Royalty were formulated in the 1980s and do not have a clear and unequivocal definition as to what costs should be included in the payout calculation. ~~The~~At ~~Company~~the ~~currently~~time ~~believes~~of initiating arbitration, the Company believed that the total scope of the ~~disagreement~~claim iswas approximately forty-five million dollars ($45,000,000); however, this amount increases each month based on Isramco Negev 2 Limited Partnership’s failure to pay the increased, post-payout overriding royalty to the Company. In addition, certain claims asserted by the Company related to post production costs and pipeline infrastructure have not been quantified. Under the terms of the agreements creating the Tamar Royalty, the dispute is subject to arbitration in Israel. The Company believes that the claims of Isramco Negev 2 Limited Partnership are erroneous and contrary to generally accepted industry practice. The Company expects that the matter will be favorably resolved through this arbitration process; however, the Company cannot be assured of a favorable result in this arbitration process.

The Tamar Consortium currently sells natural gas from the Tamar Field to the Israel Electric Corporation (“IEC”) and numerous other Israeli purchasers, including independent power producers, cogeneration facilities, local distribution companies and certain industrial companies. Currently, many of the Tamar Consortium’s gas purchase and sale agreements provide for sales at a 7 to 15 year term, while some contracts have extension options of up to 2 years. Depending on the specific contract, prices may vary and are based on an initial base price subject to price adjustment provisions, including price indexation and a price floor. The IEC contract provides for price reopeners (sometimes referred to as “price review” clauses) in the eighth and eleventh years of the contract, subject to limits on the amount of increase or decrease from the existing contractual price.

During year ended December 31, ~~2017~~2018, net sales from the Tamar Field attributable to the Company amounted to 5,~~343~~591,000 Mcf of natural gas and 67,~~990~~335 Bbl of condensate with prices of $5.3549 per Mcf and $4762.4695 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $2831,~~781~~036,000. The Israeli Tax Authority withheld $67,~~907~~138,000 of this revenue.

During year ended December 31, ~~2016~~2017, net sales from the Tamar Field attributable to the Company amounted to 5,~~102~~343,000 Mcf of natural gas and 6,~~882~~990 Bbl of condensate with prices of $5.3435 per Mcf and $3747.4846 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $2728,~~462~~781,000. The Israeli Tax Authority withheld $6,~~866~~907,000 of this revenue.

During year ended December 31, ~~2015~~2016, net sales from the Tamar Field attributable to the Company amounted to 45,~~505~~102,000 Mcf of natural gas and 6,~~074~~882 Bbl of condensate with prices of $5.5234 per Mcf and $4637.5348 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $2527,~~151~~462,000. The Israeli Tax Authority withheld $6,~~665~~866,000 of this revenue.

We have a third party reserve report from independent petroleum engineers, Netherland, Sewell & Associates, Inc. dated March 711, ~~2018~~2019 estimating reserves allocable to the Tamar Royalty as of December 31, ~~2017~~2018 (the “Tamar Reserve Report”). This reserve report estimates that by reason of the Company’s ownership of the Tamar Royalty, we have proven reserves estimated at ~~206~~213.45 million cubic feet of natural gas and ~~268~~278 thousand barrels of natural gas liquids. The Tamar Reserve Report indicates the undiscounted estimated future net revenue (after deduction of estimated production, ad valorem taxes and levy but before estimated income tax) for such reserves (paid out over time) to be $~~684~~703.39 million. The Tamar Reserve Report estimates the net present worth of such reserves, discounted at 10% annual discount rate factor, at $~~331~~321.79 million (See Note 1314 to our consolidated financial statements, “Supplemental Oil and Gas Information”). The gas price used to value the reserves in the Tamar Reserve Report is calculated in accordance with SEC rules based on the unweighted arithmetic price for each month within the 12-month period prior to December 31, ~~2017~~2018. The report indicates that there are no commercial oil deposits included as reserves.

The amount of proceeds we receive from the Tamar Royalty is contingent on a variety of factors including the timing of production and the price received. In the event of payout, the Tamar Royalty increases. Payout is the point when all the costs of leasing, drilling, producing and operating the leases have been recovered from lease production proceeds, as defined in the royalty agreements under which we acquired our interest.

As we do not control any of the factors affecting our rights to payments (time of production, price received, costs incurred) and as a result of the other risk factors as set forth below in “Risk Factors,” we cannot determine the amounts or timing of any payments we will receive or when payout is likely to occur, if ever. As discussed above, the determination of the occurrence of payout with respect to the Tamar Royalty is currently the subject of a disagreement with Isramco Negev 2 Limited Partnership. The Company believes that the disagreement will be resolved through a forthcoming arbitration process with Isramco Negev 2 Limited Partnership. Based on the reserves and anticipated production, the income from the Tamar Royalty is currently expected to be very significant to the Company for the foreseeable future.6

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~~Table~~As we do not control any of ~~Contents~~the factors affecting our rights to payments (time of production, price received, costs incurred) and as a result of the other risk factors as set forth below in “Risk Factors,” we cannot determine the amounts or timing of any payments we will receive or when payout is likely to occur, if ever. As discussed above, the determination of the occurrence of payout with respect to the Tamar Royalty is currently the subject of a disagreement with Isramco Negev 2 Limited Partnership. The Company believes that the disagreement will be resolved through a forthcoming arbitration process with Isramco Negev 2 Limited Partnership. Based on the reserves and anticipated production, the income from the Tamar Royalty is currently expected to be very significant to the Company for the foreseeable future.

Commercial production of the Tamar Field reserves is subject to numerous risks, including all of the typical risks associated with offshore oil and gas production. Commercial production of such reserves is also subject to additional risks that may be unique to the Tamar Field. These include:

● There has been no previous large -scale production of natural gas from offshore Israel. Therefore, there may be geological, geophysical, or other unforeseen problems unique to offshore Israel that could affect production. In addition, because of the lack of comparable production history for this part of offshore Israel, the length of time that large scale production from offshore Israel can be sustained is uncertain.

●

There has been significant political upheaval and unrest in the Middle East, particularly in Syria. In addition, there is considerable hostility between Israel and other countries in the region. Accordingly, there is significant risk that production from the Tamar Field may be delayed, diminished, or prevented by virtue of war, acts of terrorism, or other similar or dissimilar events of force majeure.

●

The market for natural gas in Israel exists, but the financial ability of customers of the Tamar Consortium to take and pay for material amounts of such natural gas remains unclear. It is uncertain that existing customers and markets are capable of buying all of the anticipated production from the Tamar Field.

●

The Israel Antitrust Authority continues to monitor the Israeli natural gas market, including Noble and the Tamar Consortium, and could impose additional regulations or requirements on the Noble or the Tamar Consortium which could include a requirement to divest of some or all of their ownership or require all or any of them to separately market their proportionate share of production.

As noted above, the Company owns an interest in the Shimshon license located offshore Israel. In April of 2012, a well was drilled in the area covered by the Shimshon license, which has been recognized as a commercial discovery by the Israeli government. The Shimshon partners submitted an application to convert the Shimshon license to a lease. Terms of the lease are in discussion with the Israeli government’s Ministry of Energy and Water Resources. ~~As of December 31, 2017 there were no estimated recoverable reserves.~~

Production Services Segment

The Company began production services operations in September 2011. Our production servicing rig and truck fleet provides a range of production services, including the completion of newly-drilled wells, maintenance and workover of existing wells, fluid transportation, related oilfield services and plugging and abandonment of wells at the end of their useful lives to a diverse group of oil and gas exploration and production companies.

●

Completion Services. Newly drilled wells require completion services to prepare the well for production. Production servicing rigs are frequently used to complete newly drilled wells to minimize the use of higher cost drilling rigs in the completion process. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or gas to flow into the well bore, stimulating and testing these zones, and installing the production string and other downhole equipment. The completion process typically ranges from a few days to several weeks, depending on the nature and type of the completion, and generally requires additional auxiliary equipment in addition to a production services rigs. The demand for completion services is directly related to drilling activity levels, which are sensitive to fluctuations in oil and gas prices.

●

Well-servicing/Maintenance Services. We provide maintenance services on the mechanical apparatus used to pump or lift oil from producing wells. These services include, among other activities, repairing and replacing pumps, sucker rods and tubing. We provide the rigs, equipment and crews for these tasks, which are performed on both oil and natural gas wells, but which are more commonly required on oil wells. Maintenance services typically take less than 48 hours to complete. Rigs generally are provided to customers on a call-out basis.

● Workover Services. Producing oil and natural gas wells occasionally require major repairs or modifications, called “workovers.” Workovers may be required to remedy failures, modify well depth and formation penetration to capture hydrocarbons from alternative formations, clean out and recomplete a well when production has declined, repair leaks or convert a depleted well to an injection well for secondary or enhanced recovery projects. Workovers normally are carried out with pumps and tanks for drilling fluids, blowout preventers, and other specialized equipment for servicing rigs. A workover may last anywhere from a few days to several weeks.7

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~~Table~~● ofWorkover ~~Contents~~Services. Producing oil and natural gas wells occasionally require major repairs or modifications, called “workovers.” Workovers may be required to remedy failures, modify well depth and formation penetration to capture hydrocarbons from alternative formations, clean out and recomplete a well when production has declined, repair leaks or convert a depleted well to an injection well for secondary or enhanced recovery projects. Workovers normally are carried out with pumps and tanks for drilling fluids, blowout preventers, and other specialized equipment for servicing rigs. A workover may last anywhere from a few days to several weeks.

● Fluid Services. At December 31, ~~2017~~2018, we owned and operated 2635 fluid service trucks equipped with an average fluid hauling capacity of up to 130 barrels a piece. Each fluid service truck is equipped to pump fluids from or into wells, pits, tanks and other storage facilities. The majority of our fluid service trucks are also used to transport water to fill frac tanks on well locations, to transport produced salt water to disposal wells, and to transport drilling and completion fluids to and from well locations.

●

Plugging Services. Production servicing rigs are also used in the process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Many well operators bid this work on a “turnkey” basis, requiring the service company to perform the entire job, including the sale or disposal of equipment salvaged from the well as part of the compensation received, and complying with state regulatory requirements. Plugging and abandonment work can provide favorable operating margins and is less sensitive to oil and gas pricing than drilling and workover activity since well operators must plug a well in accordance with state regulations when it is no longer productive. We perform plugging and abandonment work throughout our core areas of operation in conjunction with equipment provided by us or by other service companies.

We typically bill clients for our production servicing on an hourly basis for the period that the rig is actively working. As of December 31, ~~2017~~2018, our fleet of production servicing rigs totaled 33 rigs, which we operate through 45 locations in Texas and New Mexico. Our fleet is capable of working at depths from 14,000 to 25,000 feet, and as of December 31, ~~2017~~2018, our fleet consists of one 600 series rig, twenty -eight 550 series rigs, and four 300 series rigs.

Derivative Instruments and Hedging Activities

From time to time we utilize derivative contracts to hedge against the variability in cash flows associated with interest rate risk and/or the forecasted sale of our anticipated future oil and natural gas production. We may hedge a substantial, but varying, portion of our anticipated oil and natural gas production current and subsequent. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to derivative contracts, which would potentially allow us to not record the change in fair value of our derivative contracts in the consolidated statements of operations. We carry our derivatives at fair value on our consolidated balance sheets, with the changes in the fair value included in our consolidated statements of operations in the period in which the change occurs.

On June 16, 2015, Tamar Royalties LLC (“Tamar Royalties”), a wholly owned subsidiary of the Company, engaged in an interest rate swap agreement (“IRS Agreement”) with the Deutsche Bank AG London Branch (“DBAG”). An interest rate swap is an agreement between two parties (known as counterparties) where one stream of future interest payments is exchanged for another based on a specified notional principal amount. Interest rate swaps often exchange fixed interest payments for floating interest payments that are linked to interest rates.

As previously disclosed on the Company’s Form 8-K filed May 22, 2015, Tamar Royalties ~~LLC~~ entered into a $120,000,000 credit facility with Deutsche Bank, which facility is discussed further in Note 46 “Long-Term Debt and Interest Expense” to the Company’s consolidated financial statements,. Under the terms of this facility, Tamar Royalties ~~LLC~~, is required to hedge at least seventy-five percent (75%) of the outstanding balance under this ~~Facility~~facility against fluctuations in LIBOR, with at least thirty -seven and one-half percent (37.5%) of the outstanding balance being hedged through swaps. The notional value of these hedges corresponds to the amortization schedule covering the facility and previously disclosed in the aforementioned Form 8-K. Accordingly, on June 16, 2015, Tamar Royalties ~~LLC~~ and DBAG entered into the IRS Agreement whereby the ~~Tamar~~Company ~~Royalties LLC~~ hedged $119,250,000 of the $120,000,000 initial borrowing as follows:

(a) Tamar Royalties ~~LLC~~ hedged 37.5% of the perpetual outstanding balance under the facility, being an initial notional amount of $45,000,000, with a fixed rate swap whereby the Company will pay DBAG a fixed interest rate of 4.63%, and DBAG will pay the Company a monthly floating interest rate of USD-LIBOR-BBA plus a spread of 2.75%.

(b) Tamar Royalties hedged the remaining 62.5% of the perpetual outstanding balance less $750,000, being an initial notional amount of $74,250,000, against fluctuations in LIBOR by capping the fluctuations in LIBOR at 1.50%. Pursuant to the IRS ~~agreement~~Agreement, the Company will pay DBAG a fixed interest rate of 0.91%, and DBAG will pay the Company the greater of (i) USD-LIBOR-BBA minus a cap strike of 1.5% and (ii) zero.

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Competitive Conditions in the Business

The oil and natural gas industry is highly competitive and we compete with many other companies that have greater financial and other resources. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. There are also many production services companies that compete for the same customers as we compete. The primary areas in which we encounter substantial competition are in locating and acquiring attractive producing oil and natural gas properties, obtaining purchasers and transporters of the oil and natural gas we produce and hiring and retaining key employees during active times in the oil and gas industry. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States and in some instances individual states where we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.

Our production services customers include major oil companies and mid-range independent oil and natural gas production companies. The markets in which we operate are highly competitive. Competition is influenced by such factors as price, capacity, availability of work crews, and reputation and experience of the service provider. We believe that an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. We believe many of our large customers place increased emphasis on the safety, performance and quality of the crews, equipment and services provided by their contractors. Although we believe customers consider all of these factors, price is often the primary factor in determining which service provider is awarded the work. However, in several instances, we have secured and maintained work for large customers for which efficiency, safety, technology, size of fleet, and availability of other services are of equal importance to price.

Markets and Major Customers

Through our wholly-owned subsidiary, we operate a substantial portion of our domestic oil and natural gas properties. As the operator of a property, the Company makes full payment of the costs associated with each property and seeks reimbursement from the other working interest owners in the property for their share of those costs. Our joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general were adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected.

The purchasers of the Company’s United States based oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. During the year ended December 31, ~~2017~~2018 no purchaser, marketer, or major oil and gas or pipeline company accounted for 10% or more of our consolidated revenues. The Company has not experienced any significant losses from uncollectible accounts as to its sales of oil and gas production. The Company does not believe the loss of any one of its purchasers would materially affect the Company’s ability to sell the oil and natural gas it produces. The Company believes other purchasers are available in the Company’s areas of operations.

The Company’s overriding royalty interest in the Tamar field is paid monthly by Isramco Negev 2 Limited Partnership, a related party. During the twelve months ended December 31, ~~2017~~2018 income from this source accounted for 4438% of the Company’s consolidated revenues. If Isramco Negev 2 Limited Partnership were to stop receiving revenue from its working interest in the Tamar Field, we would not receive revenue from our overriding royalty interest (the Tamar Royalty). Loss of payments from this source would cause significant financial consequences to the Company.

Our production service subsidiary customers include major oil and natural gas production companies and independent oil and natural gas production companies. We perform credit evaluations of our customers and usually do not require collateral. We maintain reserves for potential credit losses when necessary. During the twelve months ended December 31, ~~2017~~2018, no one individual customer accounted for 10% or more of consolidated revenues. The Company believes the loss of one or more customers of our production service subsidiary would not have a significant effect on this Segment because the Company believes that it can employ its rigs with other existing customers or new customers to the extent it has in the past in such circumstances.

Seasonality of Business

Weather conditions affect the demand for, and prices of, natural gas and can disrupt our overall business plans. Demand for natural gas is typically higher in the fourth and first quarters resulting in higher natural gas prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

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Operational Risks

Oil and natural gas exploration and development involves a high degree of risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will discover or acquire additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other circumstances may cause accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids, into the environment, or cause significant injury to persons or property. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in loss of oil and natural gas properties.

We carry insurance against such hazards. However, as is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations. For further discussion on risks, see Item 1A. Risk Factors.

Regulations

We do not have any offshore operations in the United States. However, all of the jurisdictions in which we own or operate oil and natural gas properties regulate exploration for and production of oil and natural gas. These laws and regulations include provisions requiring permits to drill wells and requirements that we obtain and maintain a bond or other security as a condition to drilling or operating wells. Regulations also specify the permitted location of and method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells.

Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in a given area, and the unitization or pooling of oil and natural gas properties, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the establishment of maximum allowable rates of production from fields and individual wells. The effect of these regulations may limit the amount of oil and natural gas that we can produce from our wells and limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability.

Each state in which we operate also imposes some form of production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. We are liable for paying this tax on our production, and are also liable for various real and personal property taxes on our leases and facilities.

Environmental and Occupational Health and Safety Regulations

The oil and gas industry in the United States is subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Many governmental agencies, such as the United States Environmental Protection Agency (the “EPA”) have issued lengthy and comprehensive regulations to implement and enforce these laws. These laws and regulations often require difficult and costly compliance measures. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities.

In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of that person. We endeavor to fully comply with these regulatory requirements; however, compliance increases our costs and consequently affects our profitability.

As a part of the overall environmental regulatory policy, the permitting, construction and operations of certain oil and gas facilities are regulated. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Once operational, enforcement measures can include significant civil penalties for regulatory violations, regardless of intent. Under appropriate circumstances, an administrative agency can issue a cease and desist order to require termination of operations.

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Environmental regulation is becoming more comprehensive and additional programs, as well as increased obligations under existing programs, are anticipated. In this regard, we expect additional regulation of naturally occurring radioactive materials, oil and natural gas exploration and production operations, waste management, and underground injection of water and waste material. The adoption of additional regulations could have a material adverse effect on our financial condition and results of operations. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations.

Compliance with environmental laws and regulations increases the Company’s overall cost of business, but has not had, to date, a material adverse effect on its operations, financial condition or results of operations. It is not anticipated, based on current laws and regulations, that Isramco will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, given that such laws and regulations are subject to change, Isramco is unable to predict the ultimate cost of compliance or the ultimate effect on its operations, financial condition and results of operations.

Comprehensive Environmental Response, Compensation and Liability Act and Hazardous Substances

In 1980, the United States Congress enacted the federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or the Superfund law. This law, which has been amended since enactment, and comparable state laws impose strict liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of what are considered to be “hazardous substances” into the environment. These persons include the current or former owners or operators of the sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances released at the site. Under CERCLA, we may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment whether or not we are responsible for the release or even owned an interest in the site at the time of the release, as well as for damages to natural resources and for the costs of health studies. In addition, companies that incur liability frequently confront additional claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment in addition to a CERCLA claim.

The Solid Waste Disposal Act and Waste Management

The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as RCRA, regulates the disposal of solid waste but generally excludes most wastes generated by the exploration and production of oil and natural gas, such as drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies as non-hazardous wastes as long as these wastes are not commingled with regulated hazardous wastes. Moreover, in the ordinary course of our operations, other wastes generated in connection with our exploration and production activities may be regulated as hazardous waste under RCRA or hazardous substances under CERCLA. From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we have been and may be required to remove or remediate these materials or wastes. At this time, it is not possible to estimate the potential liabilities to which we may be subject from unknown, latent liability risks with respect to any properties where materials or wastes may have been released, but of which we have not been made aware.

The Clean Water Act, wastewater and storm water discharges

The oil and gas industry, generally, and our operations specifically, are also subject to the federal Clean Water Act and analogous state laws. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff and, as part of our overall evaluation of our current operations, we may apply for storm water discharge permit coverage and updating storm water discharge management practices at some of our facilities. We believe that we will be able to obtain, or be included under, these permits, where necessary, and be required make only minor modifications to existing facilities and operations that we believe would not have a material effect on us. The Clean Water Act and similar state acts regulate other discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages.

These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil. More specifically, we are required to develop and maintain a plan applicable to each of our properties at which any significant volume of crude oil or other substance is stored and to ensure the site has sufficient protections (such as berms, etc.) to ensure that any spill will be contained and not reach navigable waters.11

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~~Table~~These laws also require the preparation and implementation of ~~Contents~~Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil. More specifically, we are required to develop and maintain a plan applicable to each of our properties at which any significant volume of crude oil or other substance is stored and to ensure the site has sufficient protections (such as berms, etc.) to ensure that any spill will be contained and not reach navigable waters.

The Safe Drinking Water Act, groundwater protection, and the Underground Injection Control Program

The federal Safe Drinking Water Act (SWDA), the Underground Injection Control (UIC) program promulgated under the SWDA and state programs all regulate the drilling and operation of salt water disposal wells. EPA directly administers the UIC program in some states and in others the responsibility for the program has been delegated to the state. This program requires that a permit be obtained before drilling salt water disposal well. Monitoring the integrity of well casing must also be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Violation of these regulations and/or contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SWDA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

We have engaged in limited hydraulic fracturing or other well stimulation services on the wells for which we are the operator by engaging third parties to conduct these operations on our behalf. For non-operated properties, the operators have applied and may choose to apply in the future hydraulic-fracturing techniques on properties in which we share interest.

The Clean Air Act

The federal Clean Air Act, enacted in 1970, and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. The EPA has developed and continues to develop stringent regulations under the authority of the Clean Air Act governing emissions of toxic air pollutants from specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

Some of our operations may be located in areas designated as “non-attainment” areas, which are geographic areas that do not meet the federal air quality standards. Air emission controls and requirements in non-attainment areas are generally more stringent that those imposed in other areas, and the construction of new, or expansion of existing, sources may be restricted.

Climate change

The issue of “global warming” has attracted significant attention and many believe that emissions of certain gases contribute to this problem. Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, and the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are considered “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products.

In summary, we may be subject to EPA greenhouse gas monitoring and reporting rules, and potentially new EPA permitting rules if adopted, that would apply greenhouse gas permitting obligations and emissions limitations under the federal Clean Air Act. Whether or not any federal greenhouse gas regulations are enacted, more than one-third of the states have begun taking action on their own to control and/or reduce emissions of greenhouse gases. Several multi-state programs have been developed or are in the process of being developed, including the Regional Greenhouse Gas Initiative involving 10 Northeastern states, the Western Climate Initiative involving seven western states, and the Midwestern Greenhouse Gas Reduction Accord involving seven states. The latter two programs have several other states acting as observers and they may join one of the programs at a later date. Any of the climate change regulatory and legislative initiatives described above could have a material adverse effect on our business, financial condition, and results of operations.

Legislative initiatives and discussions to date have focused on the development of cap-and-trade and/or carbon tax programs. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Cap-and-trade programs could be relevant to us and our operations in several ways. First, the equipment we use to explore for, develop, produce and process oil and natural gas emits greenhouse gases. We could therefore be subject to caps, and penalties if emissions exceeded the caps. Second, the combustion of carbon-based fuels, such as the oil, gas and NGLs we sell, emits carbon dioxide and other greenhouse gases. Therefore, demand for our products could be reduced by imposition of caps and penalties on our customers. Carbon taxes could likewise affect us by being based on emissions from our equipment and/or emissions resulting from use of our products by our customers. Application of caps or taxes on companies such as Isramco, based on carbon content of produced oil and gas volumes rather than on consumer emissions, could lead to penalties, fees or tax assessments for which there are no mechanisms to pass them through the distribution and consumption chain where fuel use or conservation choices are made. Moreover, because oil and natural gas are used as chemical feedstocks and not solely as fossil fuel, the Company believes that applying a carbon tax to oil and gas at the production stage would be excessive with respect to actual carbon emissions from petroleum fuels.12

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~~Table~~Legislative initiatives and discussions to date have focused on the development of ~~Contents~~cap-and-trade and/or carbon tax programs. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Cap-and-trade programs could be relevant to us and our operations in several ways. First, the equipment we use to explore for, develop, produce and process oil and natural gas emits greenhouse gases. We could therefore be subject to caps, and penalties if emissions exceeded the caps. Second, the combustion of carbon-based fuels, such as the oil, gas and NGLs we sell, emits carbon dioxide and other greenhouse gases. Therefore, demand for our products could be reduced by imposition of caps and penalties on our customers. Carbon taxes could likewise affect us by being based on emissions from our equipment and/or emissions resulting from use of our products by our customers. Application of caps or taxes on companies such as Isramco, based on carbon content of produced oil and gas volumes rather than on consumer emissions, could lead to penalties, fees or tax assessments for which there are no mechanisms to pass them through the distribution and consumption chain where fuel use or conservation choices are made. Moreover, because oil and natural gas are used as chemical feedstocks and not solely as fossil fuel, the Company believes that applying a carbon tax to oil and gas at the production stage would be excessive with respect to actual carbon emissions from petroleum fuels.

The National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are potentially subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Threatened and endangered species, migratory birds, and natural resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties, may act to prevent oil and gas exploration activities or seek damages for harm to species, habitat, or natural resources resulting from drilling, construction or releases of oil, wastes, hazardous substances or other regulated materials, and may seek compensation for alleged natural resources damages and in some cases, criminal penalties.

Hazard communications and community right to know

We are subject to federal and state hazard communications and community right to know statutes, including, but not limited to, the federal Emergency Planning and Community Right-to-Know Act, and regulations. These regulations govern record keeping and reporting of the use and release of hazardous substances.

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act, commonly referred to as OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public.

Hydraulic Fracturing

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand or other proppant materials, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore.

As explained in more detail below, the hydraulic fracturing process is typically regulated by state oil and natural gas agencies, although the EPA, and the Bureau of Land Management of the United States Department of the Interior (“BLM”), and other federal regulatory agencies have taken steps to review or impose federal regulatory requirements. Certain states in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. Certain municipalities have already banned hydraulic fracturing, and courts have upheld those moratoria in some instances. In the past several years, dozens of states have approved or considered additional legislative mandates or administrative rules on hydraulic fracturing.13

AtTable ~~the federal level, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture~~ of air emissions released during hydraulic fracturing; finalized regulations in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; and issued in May 2014 an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands including, for example, notice to and pre-approval by BLM of the proposed hydraulic fracturing activities; development and pre-approval by BLM of a plan for managing and containing flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; and public disclosure of the chemicals used in the hydraulic fracturing fluid. The rule has been challenged in federal court and implementation has been stayed pending a final decision. Contents

13As explained in more detail below, the hydraulic fracturing process is typically regulated by state oil and natural gas agencies, although the EPA, and the Bureau of Land Management of the United States Department of the Interior (“BLM”), and other federal regulatory agencies have taken steps to review or impose federal regulatory requirements. Certain states in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. Certain municipalities have already banned hydraulic fracturing, and courts have upheld those moratoria in some instances. In the past several years, dozens of states have approved or considered additional legislative mandates or administrative rules on hydraulic fracturing.

~~Table~~At the federal level, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of ~~Contents~~air emissions released during hydraulic fracturing; finalized regulations in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; and issued in May 2014 an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands including, for example, notice to and pre-approval by BLM of the proposed hydraulic fracturing activities; development and pre-approval by BLM of a plan for managing and containing flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; and public disclosure of the chemicals used in the hydraulic fracturing fluid. The rule has been challenged in federal court and implementation has been stayed pending a final decision.

In addition, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. The adoption of new federal rules or regulations relating to hydraulic fracturing could lead to increased operating costs, delays and curtailment in the pursuit of exploration, development or production activities, which in turn could materially adversely affect our operations. Several governmental reviews are underway that focus on environmental aspects of hydraulic fracturing activities. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, we do not believe that this multi-year study report provides any basis for further regulation of hydraulic fracturing at the federal level.

Based on the foregoing, increased regulation and attention given to the hydraulic fracturing process from federal agencies, various states and local governments could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

Employees

As of December 31, ~~2017~~2018, we had approximately ~~193~~297 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees.

Available Information

We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Isramco, Inc., that file electronically with the SEC. Information about the Company can be found at our internet address: www.isramcousa.com The public can obtain any document we file with the SEC at www.sec.gov.

~~ITEM 1A. RISK FACTORS~~14

InTable addition to the other information contained in this Annual Report on Form 10-K, investors should consider carefully the following risk factors, which may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could be materially and adversely affected and the trading price of our common stock could decline.Contents

~~Oil,~~ITEM ~~natural-gas and NGLs prices are volatile~~1A. ARISK ~~substantial or extended decline in prices could adversely affect our financial condition and results of operations.~~FACTORS

~~Prices~~In ~~for~~addition ~~oil,~~to ~~natural~~the ~~gas~~other ~~and~~information ~~NGLs~~contained ~~(Natural~~in ~~Gas~~this ~~Liquids)~~Annual ~~can~~Report ~~fluctuate~~on ~~widely.~~Form ~~Our revenues~~10-K, ~~operating~~investors ~~results~~should ~~and~~consider ~~future~~carefully ~~growth~~the ~~rates~~following ~~are highly~~risk ~~dependent~~factors, onwhich ~~the~~may ~~prices~~not webe ~~receive~~the ~~for~~only ~~our~~risks ~~oil~~we face, ~~natural~~as ~~gas~~our business and ~~NGLs.~~operations ~~Historically,~~may ~~the~~also ~~markets~~be ~~for~~subject ~~oil,~~to ~~natural gas and~~risks ~~NGLs~~that ~~have~~we ~~been~~do ~~volatile~~not ~~and~~yet ~~may~~know ~~continue~~of, toor bethat ~~volatile~~we incurrently ~~the~~believe ~~future~~are immaterial. ~~For~~If ~~example,~~any inof ~~recent~~the ~~years~~events ~~market~~or ~~prices~~circumstances ~~for~~described ~~natural~~below ~~gas~~actually inoccurs, ~~the~~our ~~United~~business, ~~States~~financial ~~have~~condition ~~declined~~or ~~substantially~~results ~~from~~of ~~the~~operations ~~highs~~could ~~achieved~~be inmaterially ~~2008,~~and adversely affected and the ~~rapid~~trading ~~development~~price of ~~shale~~our ~~plays~~common ~~throughout~~stock ~~North~~could ~~America has contributed significantly to this trend~~decline.

14Oil, natural-gas and NGLs prices are volatile. A substantial or extended decline in prices could adversely affect our financial condition and results of operations.

~~Table~~Prices offor ~~Contents~~oil, natural gas and NGLs (Natural Gas Liquids) can fluctuate widely. Our revenues, operating results and future growth rates are highly dependent on the prices we receive for our oil, natural gas and NGLs. Historically, the markets for oil, natural gas and NGLs have been volatile and may continue to be volatile in the future.

AFactors ~~significant~~influencing ~~decline~~the ~~in crude oil~~ prices ~~started in October 2014, continued through 2015 and slightly rebounded towards the end~~ of ~~2016~~oil, ~~which~~natural ~~continued~~gas ~~through the end of 2017. As a result, we experienced decreases in crude oil revenues~~ and ~~recorded~~NGLs ~~asset~~are ~~impairment~~beyond ~~charges~~our ~~due to commodity price declines~~control. IfThese ~~crude~~factors ~~oil prices were continue to decline again~~include, ~~further~~among ~~operating asset impairment and our profitability will likely be negatively affected.~~others:

~~Factors~~● ~~influencing~~the worldwide military and political environment, uncertainty or instability resulting from the ~~prices~~escalation or additional outbreak of ~~oil,~~armed ~~natural~~hostilities ~~gas~~or ~~and~~further ~~NGLs~~acts ~~are~~of ~~beyond~~terrorism ~~our~~in ~~control.~~the ~~These~~United ~~factors~~States, ~~include~~or elsewhere, ~~among~~particularly ~~others:~~Israel;

● ~~the~~global ~~worldwide~~factors ~~military~~impacting ~~and~~supply ~~political~~quantities ~~environment,~~of ~~uncertainty~~crude oroil, ~~instability~~natural ~~resulting~~gas ~~from~~and ~~the~~NGLs, ~~escalation~~in orparticular, ~~additional~~US ~~outbreak~~crude ofoil ~~armed~~and ~~hostilities~~NGL orsupply ~~further~~growth ~~acts~~resulting offrom ~~terrorism~~shale inoil ~~the United States, or elsewhere, particularly Israel~~development;

● ~~global~~the ~~factors~~extent ~~impacting~~to ~~supply~~which ~~quantities~~US ofshale ~~crude~~producers ~~oil,~~become ~~natural~~swing ~~gas and NGLs~~producers, inyielding ~~particular,~~additional USnon-OPEC crude oil ~~and NGL~~ supply ~~growth resulting from shale oil development~~;

● ~~the~~political ~~extent~~conditions toand ~~which~~events US(including ~~shale~~instability ~~producers~~or ~~become~~armed ~~swing~~conflict) ~~producers,~~in ~~yielding additional non~~hydrocarbon-~~OPEC~~producing ~~crude oil supply~~regions;

● ~~political~~actions ~~conditions~~taken ~~and~~by ~~events~~foreign ~~(including~~oil ~~instability~~and orgas ~~armed conflict) in hydrocarbon-~~producing ~~regions~~nations;

● ~~actions~~the ~~taken~~level byof ~~foreign~~global crude oil and natural gas ~~producing nations~~inventories;

● ~~the~~further ~~level~~application of horizontal drilling techniques which could increase production and significantly impact both domestic and global supplies of crude oil, ~~and~~ natural gas, ~~inventories~~and NGLs;

● ~~further~~the ~~application~~price ~~of horizontal drilling techniques which could increase production~~ and ~~significantly~~level ~~impact~~of ~~both~~foreign ~~domestic~~imports ~~and global supplies~~ of ~~crude~~ oil, natural gas, and NGLs;

● the ~~price~~effect ~~and level~~ of ~~foreign~~worldwide ~~imports~~energy ofconservation ~~oil, natural gas and NGLs~~efforts;

● actions by the ~~effect~~Organization of ~~worldwide~~Petroleum ~~energy~~Exporting ~~conservation~~Countries, ~~efforts~~which we refer to as OPEC;

● ~~actions~~the byprice ~~the~~and ~~Organization~~availability of ~~Petroleum~~alternative ~~Exporting~~and ~~Countries,~~competing ~~which we refer to as OPEC~~fuels;

● ~~the~~technology ~~price~~advances ~~and~~that ~~availability~~increase ofcrude ~~alternative~~oil, natural gas and ~~competing~~NGL ~~fuels~~production, thereby increasing supply;

● ~~technology~~the ~~advances~~cost ~~that~~of ~~increase~~exploring ~~crude~~for, ~~oil~~developing, ~~natural~~producing, ~~gas~~transporting, and ~~NGL~~marketing ~~production~~oil, ~~thereby~~natural ~~increasing~~gas, ~~supply~~and NGLs;

● the ~~cost~~availability of ~~exploring~~pipeline ~~for,~~capacity ~~developing, producing, transporting,~~ and ~~marketing oil, natural gas, and NGLs~~infrastructure;

● the availability of ~~pipeline~~crude ~~capacity~~oil transportation and ~~infrastructure~~refining capacity;

● ~~the~~consumer ~~availability~~demand offor ~~crude~~ oil, ~~transportation~~gas and ~~refining capacity~~NGLs;

● the growth of consumer product demand ~~for~~in ~~oil~~emerging markets, ~~gas~~such as India and ~~NGLs~~China;

● ~~the~~fuel ~~growth~~efficiency ofregulations, ~~consumer~~such ~~product~~as ~~demand~~the inCorporate ~~emerging~~Average ~~markets~~Fuel Economy (CAFE) standards, ~~such~~and its impacts on crude oil demand as ~~India~~a ~~and~~transportation ~~China~~fuel;

● ~~fuel~~labor ~~efficiency~~unrest ~~regulations,~~in ~~such~~oil ~~as the Corporate Average Fuel Economy (CAFE) standards,~~ and ~~its~~natural ~~impacts~~gas onproducing ~~crude oil demand as a transportation fuel~~regions;

● ~~labor~~regional ~~unrest~~pricing ~~in oil and natural gas producing regions~~differentials;

● ~~regional~~weather ~~pricing differentials~~conditions;

● ~~weather~~electricity ~~conditions~~needs;

● ~~electricity~~the ~~needs~~nature and extent of domestic and foreign governmental regulation (including environmental regulation and regulation of derivatives transactions and hedging activities) and taxation; and

● the ~~nature~~overall ~~and~~economic ~~extent of domestic and foreign governmental regulation (including environmental regulation and regulation of derivatives transactions and hedging activities) and taxation; and~~environment.

~~● the overall economic environment.~~15

~~The~~Table ~~long-term effect~~ of ~~these and other factors on the prices of oil, natural gas and NGLs are uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:~~Contents

●The ~~adversely~~long-term ~~affecting~~effect ~~our~~of ~~financial~~these ~~condition,~~and ~~liquidity,~~other ~~ability~~factors toon ~~finance~~the ~~planned~~prices ~~capital~~of ~~expenditures~~oil, natural gas and ~~results~~NGLs ofare ~~operations;~~uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:

● ~~reducing~~adversely ~~the~~affecting ~~amount~~our offinancial ~~oil~~condition, ~~natural~~liquidity, ~~gas~~ability ~~and~~to ~~NGLs~~finance ~~that~~planned wecapital ~~can~~expenditures ~~produce~~and ~~economically~~results of operations;

● reducing ~~our~~the ~~revenues,~~amount ~~profit~~of ~~margins~~oil, ~~operating~~natural ~~income~~gas and ~~cash~~NGLs ~~flows~~that we can produce economically;

● ~~certain~~reducing ~~properties~~our inrevenues, ~~our~~profit ~~portfolio~~margins, ~~becoming~~operating ~~economically~~income ~~unviable~~and cash flows;

● ~~delay~~certain orproperties ~~postponement~~in ofour ~~some~~portfolio ofbecoming ~~our~~economically ~~capital projects~~unviable;

● ~~reducing~~delay ~~the~~or ~~carrying~~postponement ~~value~~of some of our ~~crude~~capital ~~oil and natural gas properties~~projects;

● reducing the ~~amounts~~carrying value of our ~~estimated~~crude ~~proved~~ oil and natural- gas ~~reserves~~properties;

● reducing the ~~standardized~~amounts ~~measure~~ of ~~discounted~~our ~~future~~estimated ~~net~~proved ~~cash flows relating to~~ oil and natural-gas reserves; ~~and~~

● ~~limiting~~reducing ~~our~~the ~~access~~standardized tomeasure ~~sources~~ of ~~capital,~~discounted ~~such~~future asnet ~~equity~~cash flows relating to oil and ~~long~~natural-~~term~~gas ~~debt~~reserves; and

● ~~additional~~limiting ~~counterparty~~our ~~credit~~access ~~risk~~to ~~exposure~~sources onof ~~commodity~~capital, ~~hedges.~~such as equity and long-term debt; and

● ~~asset~~additional ~~impairment~~counterparty ~~charges~~credit ~~resulting~~risk ~~from~~exposure ~~reductions~~on incommodity ~~the carrying values of our crude oil and natural gas properties at the date of assessment;~~hedges.

15● asset impairment charges resulting from reductions in the carrying values of our crude oil and natural gas properties at the date of assessment;

~~Table~~Depending on the market prices of ~~Contents~~oil and gas, oil and gas exploration and production companies may cancel or curtail their drilling programs and may lower production spending on existing wells, thereby reducing demand for our production services. Many factors beyond our control affect oil and gas prices, including:

~~Depending~~● on the ~~market~~cost ~~prices~~ of ~~oil~~exploring ~~and gas~~for, ~~oil~~producing and ~~gas~~delivering exploration and production companies may cancel or curtail their drilling programs and may lower production spending on existing wells, thereby reducing demand for our production services. Many factors beyond our control affect oil and gas ~~prices, including:~~;

● the ~~cost~~discovery rate of ~~exploring~~new ~~for, producing and delivering~~ oil and gas reserves;

● the ~~discovery~~ rate of decline of existing and new oil and gas reserves;

● the ~~rate~~ability of ~~decline~~oil ofand ~~existing~~gas exploration and ~~new~~production ~~oil~~companies ~~and~~to ~~gas~~raise ~~reserves~~capital;

● ~~the~~economic ~~ability~~conditions ofin ~~oil~~the ~~and~~United ~~gas~~States, ~~exploration~~Israel and ~~production companies to raise capital~~elsewhere;

● ~~economic~~the ~~conditions~~price inof ~~the~~foreign ~~United~~imports ~~States,~~of ~~Israel~~oil and ~~elsewhere;~~gas.

●Our ~~the~~domestic ~~price~~operations ofare ~~foreign~~subject ~~imports~~to ofgovernmental ~~oil~~risks ~~and~~that ~~gas~~may impact our operations.

Our domestic operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, tribal, local and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental ~~risks~~agencies, ~~that~~price or gathering-rate controls, hydraulic fracturing and environmental protection regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. We may ~~impact~~incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including environmental and tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, currently proposed federal legislation, that, if adopted, could adversely affect our business, financial condition and results of operations, includes the following:

Our domestic operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, tribal, local and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies, price or gathering-rate controls, hydraulic fracturing and environmental protection regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including environmental and tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, currently proposed federal legislation, that, if adopted, could adversely affect our business, financial condition and results of operations, includes the following:

●	Climate Change. A number of state and regional efforts have emerged that are aimed at tracking and/or reducing emissions of green-house gases (GHGs). In addition, the U.S. Environmental Protection Agency (EPA) has made findings that emissions of GHGs present a danger to public health and the environment and, based on these findings, has adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act. We may be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs.

●	Taxes. On December 22, 2017, the United States Congress enacted the Tax Cuts and Jobs Act (“Tax Reform Legislation”). The Tax Reform Legislation, among other things, (i) permanently reduces the US corporate income tax rate to 21% beginning in 2018, (ii) repeals the corporate alternative minimum tax (AMT) allowing for corresponding refunds of prior period AMT credits, (iii) provides for a five year period of 100% bonus depreciation followed by a phase-down of the bonus depreciation percentage, (iv) imposes a new limitation on the utilization of net operating losses generated in taxable years beginning after December 31, 2017, and (v) provides for more general changes to the taxation of corporations, including changes to the deductibility of interest expense, the adoption of a modified territorial tax system, assessing a repatriation tax or “toll-charge” on undistributed earnings and profits of US-owned foreign corporations, and introducing certain anti-base erosion provisions. The Tax Reform Legislation is complex and far-reaching and could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs. The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued, and our business and financial condition could be adversely affected.

● Climate Change. A number of state and regional efforts have emerged that are aimed at tracking and/or reducing emissions of green-house gases (GHGs). In addition, the U.S. Environmental Protection Agency (EPA) has made findings that emissions of GHGs present a danger to public health and the environment and, based on these findings, has adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act. We may be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs. ● Taxes. On December 22, 2017, the United States Congress enacted the Tax Cuts and Jobs Act (“Tax Reform Legislation”). The Tax Reform Legislation, among other things, (i) permanently reduces the US corporate income tax rate to 21% beginning in 2018, (ii) repeals the corporate alternative minimum tax (AMT) allowing for corresponding refunds of prior period AMT credits, (iii) provides for a five year period of 100% bonus depreciation followed by a phase-down of the bonus depreciation percentage, (iv) imposes a new limitation on the utilization of net operating losses generated in taxable years beginning after December 31, 2017, and (v) provides for more general changes to the taxation of corporations, including changes to the deductibility of interest expense, the adoption of a modified territorial tax system, assessing a repatriation tax or “toll-charge” on undistributed earnings and profits of US-owned foreign corporations, and introducing certain anti-base erosion provisions. The Tax Reform Legislation is complex and far-reaching and could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs. The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued, and our business and financial condition could be adversely affected. In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to US federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Reform Legislation, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future, or the timing of any such action. The elimination of such US federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-US taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition. ● Hydraulic Fracturing. This process is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. With regard to our non-operated properties, the operators may choose to apply hydraulic-fracturing techniques in many of our U.S. onshore oil and natural-gas drilling and completion programs. Hydraulic fracturing involves using water, sand or other proppant materials, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore.16

16Table of Contents

~~Table~~In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to US federal and state income tax laws, including (i) the elimination of ~~Contents~~the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Reform Legislation, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future, or the timing of any such action. The elimination of such US federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-US taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition.

As● ~~explained~~Hydraulic inFracturing. ~~more~~This ~~detail below, the hydraulic fracturing~~ process is ~~typically~~an ~~regulated~~essential ~~by state oil~~ and ~~natural~~common ~~gas~~practice ~~agencies, although the EPA, the BLM and other federal regulatory agencies have taken steps to review or impose federal regulatory requirements. Certain states~~ in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. Certain municipalities have already banned hydraulic fracturing, and courts have upheld those moratoria in some instances. In the past several years, dozens of states have approved or considered additional legislative mandates or administrative rules on hydraulic fracturing. At the federal level, the EPA has taken numerous actions, including the following: final federal Clean Air Act regulations in 2012 and, more recently, in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and ~~natural~~ gas ~~hydraulic~~industry ~~fracturing,~~used ~~leak~~to ~~detection,~~stimulate ~~and~~production ~~permitting; published in June 2016 an effluent limitation final rule prohibiting the discharge~~ of ~~wastewater from onshore unconventional oil and~~ natural gas ~~extraction facilities to publicly owned wastewater treatment plants;~~ and issued in May 2014 an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM finalized rules in March 2015 that impose new /or ~~more~~oil stringent standards for performing hydraulic fracturing on federal and American Indian lands including, for example, notice to and pre‑approval by BLM of the proposed hydraulic fracturing activities; development and pre‑approval by BLM of a plan for managing and containing flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from ~~hydraulic~~dense ~~fracturing~~subsurface ~~activities;~~rock ~~and public disclosure of the chemicals used in the hydraulic fracturing fluid~~formations. ~~Some~~With ofregard ~~these rules are subject~~ to pending challenges and, on March 28, 2017, an executive order was signed directing the EPA and the BLM to review their rules and, if appropriate, to initiate rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. Accordingly, the EPA and the BLM have taken actions to delay or rescind certain requirements related to hydraulic fracturing activities. In addition, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. The adoption of new federal rules or regulations relating to hydraulic fracturing could require us to obtain additional permits or approvals or to install expensive pollution control equipment for our ~~operations,~~non-operated ~~which in turn could lead to increased operating costs~~properties, ~~delays and curtailment in~~ the ~~pursuit~~operators of exploration, development or production activities, which in turn could materially adversely affect our operations. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may ~~impact~~choose ~~drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others~~ to ~~result~~apply in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic ~~fracturing itself and contamination of groundwater resources, we do not believe that this multi~~-~~year study report provides any basis for further regulation of hydraulic~~ fracturing at the federal level. Based on the foregoing, increased regulation and attention given to the hydraulic fracturing process from federal agencies, various states and local governments could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. ~~Additional legislation or regulation could also lead to operational delays or increased operating costs~~ in ~~the~~many ~~production~~ of ~~oil,~~our ~~natural gas and NGLs, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing~~U.S. ~~The~~onshore ~~adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new~~ oil and natural-gas ~~wells~~drilling and ~~increased~~completion ~~compliance costs and time, which could adversely affect our business, financial position, results of operations and cash flows~~programs. ●Hydraulic ~~The~~fracturing ~~federal~~involves ~~Clean~~using ~~Water Act~~water, assand ~~amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability Act,~~ or CERCLA, the Safe Drinking Water Act, or SDWA, the federal Outer Continental Shelf Lands Act, the Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes are the primary statutes that impose the requirements and provide for civil, criminal and administrative penalties and other ~~sanctions~~proppant for violation of their requirements. The OSHA hazard communication standard, the Environmental Protection Agency “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials ~~we use in our operations to employees~~, ~~state~~ and local government authorities and local citizens. In addition, CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain ~~classes~~chemicals of persons who are considered responsible for the release or threatened release of hazardous substances into the environment. These persons include the current owner or operator of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred, and companies that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of removal and remedial action as well as damages to ~~natural~~fracture ~~resources. Few defenses exist to~~ the ~~liability~~hydrocarbon-bearing ~~imposed~~rock byformation ~~environmental laws and regulations. It is also common for third parties~~ to ~~file~~allow ~~claims~~flow ~~for~~of ~~personal~~hydrocarbons ~~injury and property damage caused by substances released~~ into the ~~environment~~wellbore.

17As explained in more detail below, the hydraulic fracturing process is typically regulated by state oil and natural gas agencies, although the EPA, the BLM and other federal regulatory agencies have taken steps to review or impose federal regulatory requirements. Certain states in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. Certain municipalities have already banned hydraulic fracturing, and courts have upheld those moratoria in some instances. In the past several years, dozens of states have approved or considered additional legislative mandates or administrative rules on hydraulic fracturing. At the federal level, the EPA has taken numerous actions, including the following: final federal Clean Air Act regulations in 2012 and, more recently, in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting; published in June 2016 an effluent limitation final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; and issued in May 2014 an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands including, for example, notice to and pre-approval by BLM of the proposed hydraulic fracturing activities; development and pre-approval by BLM of a plan for managing and containing flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; and public disclosure of the chemicals used in the hydraulic fracturing fluid. Some of these rules are subject to pending challenges and, on March 28, 2017, an executive order was signed directing the EPA and the BLM to review their rules and, if appropriate, to initiate rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. Accordingly, the EPA and the BLM have taken actions to delay or rescind certain requirements related to hydraulic fracturing activities. In addition, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. The adoption of new federal rules or regulations relating to hydraulic fracturing could require us to obtain additional permits or approvals or to install expensive pollution control equipment for our operations, which in turn could lead to increased operating costs, delays and curtailment in the pursuit of exploration, development or production activities, which in turn could materially adversely affect our operations. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, we do not believe that this multi-year study report provides any basis for further regulation of hydraulic fracturing at the federal level. Based on the foregoing, increased regulation and attention given to the hydraulic fracturing process from federal agencies, various states and local governments could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil, natural gas and NGLs, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs and time, which could adversely affect our business, financial position, results of operations and cash flows.

~~Table of Contents~~17

~~The~~Table ~~enactment~~ of derivatives legislation could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity-price, interest-rate, and other risks associated with its business.Contents

● The ~~Dodd-Frank~~federal ~~Wall~~Clean ~~Street~~Water ~~Reform~~Act, ~~and~~as ~~Consumer~~amended ~~Protection~~by ~~Act~~the ~~(Dodd-Frank~~Oil Pollution Act), ~~enacted~~the ~~in 2010, establishes~~ federal ~~oversight~~Clean ~~and~~Air ~~regulation~~Act, of the ~~over-the-counter~~federal ~~derivatives~~Resource ~~market~~Conservation and ~~entities~~Recovery Act, ~~such as~~ the ~~Company,~~federal ~~that~~Comprehensive ~~participate~~Environmental inResponse, ~~that~~Compensation, ~~market.~~and ~~The~~Liability ~~Dodd-Frank~~ Act, ~~requires~~or ~~the~~CERCLA, ~~Commodities Futures Trading Commission (CFTC) and~~ the ~~SEC~~Safe toDrinking ~~promulgate~~Water ~~rules~~Act, ~~and~~or ~~regulations~~SDWA, ~~implementing~~ the ~~Dodd-Frank~~federal ~~Act.~~Outer InContinental ~~its~~Shelf ~~rulemaking~~Lands ~~under the Dodd-Frank~~ Act, the ~~CFTC~~Occupational ~~issued~~Safety ~~a final rule on position limits for certain futures~~ and ~~option~~Health ~~contracts~~Act, inor ~~the~~OSHA, ~~major energy markets~~ and ~~for swaps that are~~ their ~~economic~~state ~~equivalents.~~counterparts ~~Certain bona~~and ~~fide hedging~~similar ~~transactions~~statutes ~~or positions~~ are ~~exempt~~the ~~from~~primary ~~these~~statutes ~~position~~that ~~limits.~~impose ~~The position-limits rule was vacated by~~ the ~~U.S.~~requirements ~~District~~and ~~Court~~provide for ~~the~~civil, ~~District~~criminal ofand ~~Colombia~~administrative inpenalties ~~September 2012~~ and ~~the~~other ~~CFTC~~sanctions ~~recently~~for ~~stated~~violation ~~that~~of ittheir ~~will appeal the District Court’s decision~~requirements. The ~~CFTC~~OSHA ~~also~~hazard ~~finalized~~communication ~~other regulations~~standard, ~~including critical rulemakings on~~ the ~~definition~~Environmental ofProtection ~~“swap,”~~Agency “~~swap~~community ~~dealer,~~right-to-know” ~~and~~regulations ~~“major~~under ~~swap~~Title ~~participant.”~~III ~~Some~~of ~~regulations,~~the ~~however,~~federal ~~remain~~Superfund toAmendment ~~be finalized~~ and itReauthorization isAct ~~not~~and ~~possible~~comparable atstate ~~this~~statutes ~~time~~require us to ~~predict~~organize ~~when this will be accomplished. Depending on the Company’s classification~~ and ~~the~~report ~~particular~~information ~~nature~~about ~~of its derivative activities,~~ the ~~Dodd-Frank~~hazardous ~~Act~~materials ~~and~~we ~~regulations~~use ~~may~~in ~~require~~our ~~the~~operations ~~Company~~ to ~~comply~~employees, ~~with~~state ~~margin requirements~~ and ~~with~~local ~~certain~~government ~~clearing~~authorities and ~~trade-execution~~local ~~requirements~~citizens. inIn ~~connection~~addition, ~~with~~CERCLA, ~~its~~also ~~derivative~~known ~~activities.~~as ~~The~~the ~~Dodd-Frank~~“Superfund” ~~Act~~law, and ~~regulations~~similar ~~may~~state ~~also~~statutes ~~require~~impose ~~the~~strict ~~counterparties~~liability, towithout ~~the~~regard ~~Company’s derivative instruments~~ to ~~spin~~fault ~~off~~or ~~some~~the legality of ~~their~~the ~~derivatives~~original ~~activities~~conduct, toon ~~separate~~certain ~~entities,~~classes ~~which~~of ~~may~~persons ~~not~~who beare asconsidered ~~creditworthy~~responsible asfor the ~~current~~release ~~counterparties.~~or ~~The~~threatened ~~Dodd-Frank~~release ~~Act~~of ~~and~~hazardous ~~regulations~~substances ~~could~~into ~~significantly increase~~ the ~~cost~~environment. ofThese ~~derivative~~persons ~~contracts~~include ~~(including~~the ~~through~~current ~~requirements~~owner toor ~~post~~operator ~~collateral~~of ~~which~~a ~~could~~facility ~~adversely~~where ~~affect~~a ~~our~~release ~~available~~has ~~liquidity)~~occurred, ~~materially alter~~ the ~~terms~~owner ofor ~~derivative~~operator ~~contracts, reduce the availability~~ of ~~derivatives~~a tofacility ~~protect~~at ~~against risks~~ the ~~Company~~time ~~encounters,~~a ~~reduce~~release ~~the Company’s ability to monetize or restructure its existing derivative contracts~~occurred, and ~~increase~~companies ~~the~~that ~~Company’s~~disposed ~~exposure~~of toor ~~less-creditworthy~~arranged ~~counterparties.~~for If the ~~Company~~disposal ~~reduces~~of ~~its~~hazardous ~~use~~substances offound ~~derivatives~~at as a ~~result~~particular ofsite. ~~the~~This ~~Dodd-Frank~~liability ~~Act and regulations, the Company’s results of operations~~ may ~~become~~be ~~more~~joint ~~volatile~~ and ~~its~~several. ~~cash~~Such ~~flows may be less predictable~~liability, which ~~could~~may ~~adversely~~be ~~affect~~imposed for the ~~Company’s~~conduct ~~ability~~of toothers ~~plan~~and for ~~and~~conditions ~~fund~~others ~~capital~~have ~~expenditures. Finally~~caused, ~~the~~includes ~~Dodd-Frank Act was intended, in part, to reduce~~ the ~~volatility~~cost of ~~oil~~removal and ~~natural-gas~~remedial ~~prices,~~action ~~which~~as ~~some~~well ~~legislators~~as ~~attributed~~damages to ~~speculative trading in derivatives and commodity instruments related to oil and~~ natural ~~gas~~resources. ~~The~~Few ~~Company’s~~defenses ~~revenues~~exist ~~could~~to ~~therefore~~the beliability ~~adversely~~imposed ~~affected~~by ifenvironmental alaws ~~consequence of the Dodd-Frank Act~~ and regulations ~~is to lower commodity prices~~. ~~Any~~It ofis ~~these~~also ~~consequences~~common ~~could~~for ~~have~~third aparties ~~material~~to ~~adverse~~file ~~effect~~claims onfor ~~the~~personal ~~Company’s~~injury ~~consolidated~~and ~~financial~~property ~~position,~~damage ~~results~~caused ofby ~~operations,~~substances orreleased ~~cash~~into ~~flows~~the environment.

~~Drilling~~The ~~crude~~enactment ~~oil~~of ~~and~~derivatives ~~natural~~legislation ~~gas~~could ~~wells~~have isan aadverse ~~high-risk~~effect ~~activity~~on ~~and~~the ~~subjects~~Company’s usability to ause ~~variety~~derivative instruments to reduce the effect of commodity-price, interest-rate, and other risks ~~that~~associated wewith ~~cannot~~its ~~control~~business.

~~Drilling~~The ~~crude~~Dodd-Frank ~~oil~~Wall Street Reform and ~~natural~~Consumer ~~gas~~Protection ~~wells~~Act (Dodd-Frank Act), ~~including~~enacted ~~development~~in ~~wells~~2010, ~~involves~~establishes ~~numerous~~federal ~~risks~~oversight and regulation of the over-the-counter derivatives market and entities, ~~including~~such as the ~~risk~~Company, that weparticipate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions are exempt from these position limits. The position-limits rule was vacated by the U.S. District Court for the District of Colombia in September 2012 and the CFTC recently stated that it will appeal the District Court’s decision. The CFTC also finalized other regulations, including critical rulemakings on the definition of “swap,” “swap dealer,” and “major swap participant.” Some regulations, however, remain to be finalized and it is not possible at this time to predict when this will be accomplished. Depending on the Company’s classification and the particular nature of its derivative activities, the Dodd-Frank Act and regulations may require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities. The Dodd-Frank Act and regulations may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not ~~encounter~~be ~~commercially~~as ~~productive~~creditworthy ~~crude~~as ~~oil~~the current counterparties. The Dodd-Frank Act and ~~natural~~regulations ~~gas~~could ~~reserves~~significantly increase the cost of derivative contracts (including ~~“dry~~through ~~holes”~~requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less-creditworthy counterparties. AsIf the Company reduces its use of derivatives as a result of the Dodd-Frank Act and regulations, wethe Company’s results of operations may ~~not~~become ~~recover~~more ~~all~~volatile orand ~~any~~its ~~portion~~cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of ~~our~~oil ~~investment~~and natural-gas prices, which some legislators attributed to speculative trading in ~~new~~derivatives ~~wells~~and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

~~Specifically,~~Drilling wecrude ~~often~~oil ~~are uncertain as to the future cost or timing of drilling, completing~~ and ~~operating~~natural gas wells, ~~and~~is ~~our~~a ~~drilling operations and those of our third~~high-~~party~~risk ~~operators~~activity ~~may be curtailed, delayed or canceled, the cost of such operations may increase~~ and~~/or~~ ~~our~~subjects ~~results~~us ofto ~~operations and cash flows from such operations may be impacted, as~~ a ~~result~~variety of arisks ~~variety~~that ofwe ~~factors,~~cannot ~~including~~control.

●Drilling ~~unexpected~~crude ~~drilling~~oil ~~conditions;~~and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive crude oil and natural gas reserves (including “dry holes”). As a result, we may not recover all or any portion of our investment in new wells.

~~● title problems;~~18

●Table ~~pressure~~of ~~or irregularities in formations;~~Contents

●Specifically, ~~equipment~~we ~~failures~~often are uncertain as to the future cost or ~~accidents;~~timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled, the cost of such operations may increase and/or our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including

● ~~adverse~~unexpected ~~weather~~drilling conditions~~, such as winter storms, flooding and hurricanes, and changes in weather patterns~~;

● ~~compliance~~title with, or changes in, environmental laws and regulations relating to air emissions, hydraulic fracturing and disposal of produced water, drilling fluids and other wastes, laws and regulations imposing conditions and restrictions on drilling and completion operations and other laws and regulations, such as tax laws and regulationsproblems;

● ~~the~~pressure ~~availability~~or ~~and~~irregularities ~~timely~~in ~~issuance of required governmental permits and licenses~~formations;

● the availability of, costs associated with and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, rail cars, crude oil hauling trucks and qualified drivers and related facilities and equipment tofailures ~~gather,~~or ~~process, compress, transport and market crude oil, natural gas and related commodities~~accidents; ~~and~~

● ~~the~~adverse ~~costs~~weather ofconditions, orsuch ~~shortages~~as orwinter ~~delays in the availability of~~storms, ~~drilling~~flooding ~~rigs, hydraulic fracturing services, pressure pumping equipment~~ and ~~supplies~~hurricanes, ~~tubular materials, water, sand, disposal facilities, qualified personnel~~ and ~~other~~changes ~~necessary~~in ~~equipment,~~weather ~~materials, supplies and services.~~patterns;

~~Our~~● ~~failure~~compliance towith, ~~recover~~or ~~our~~changes ~~investment~~ in ~~wells~~, ~~increases~~environmental inlaws ~~the~~and ~~costs~~regulations ofrelating ~~our~~to ~~drilling~~air ~~operations~~emissions, orhydraulic ~~those~~fracturing ~~of our third-party operators,~~ and~~/or~~ ~~curtailments,~~disposal ~~delays or cancellations~~ of ~~our~~produced water, drilling ~~operations~~fluids orand ~~those of our third-party operators in each case due to any of the above factors or~~ other ~~factors~~wastes, ~~may~~laws ~~materially~~ and ~~adversely~~regulations ~~affect~~imposing ~~our~~conditions ~~business, financial condition~~ and ~~results~~restrictions ofon ~~operations.~~drilling ~~For related discussion of the risks~~ and ~~potential~~completion ~~losses~~operations and ~~liabilities~~other ~~inherent~~laws ~~in our crude oil~~ and ~~natural gas operations generally~~regulations, ~~see~~such ~~the~~as ~~immediately~~tax ~~following~~laws ~~risk~~and ~~factor.~~regulations;

18● the availability and timely issuance of required governmental permits and licenses;

~~Table~~● the availability of, ~~Contents~~costs associated with and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, rail cars, crude oil hauling trucks and qualified drivers and related facilities and equipment to gather, process, compress, transport and market crude oil, natural gas and related commodities; and

~~Our~~● ~~oil~~the ~~and~~costs ~~natural~~of, ~~gas~~or ~~activities~~shortages ~~are~~or ~~subject~~delays toin ~~various~~the ~~risks~~availability ~~that~~of, ~~are~~drilling ~~beyond~~rigs, ~~our~~hydraulic ~~control~~fracturing ~~and~~services, ~~expose~~pressure uspumping toequipment ~~potential losses~~ and ~~liabilities~~supplies, ~~and~~tubular ~~insurance~~materials, ~~may~~water, ~~not~~sand, ~~fully~~disposal ~~protect~~facilities, usqualified ~~against~~personnel ~~these~~and ~~risks~~other ~~and~~necessary ~~potential~~equipment, ~~losses~~materials, supplies and ~~liabilities~~services.

Our ~~operations~~failure ~~are~~to ~~subject~~recover toour ~~many~~investment ~~risks~~in ~~and~~wells, ~~hazards~~increases ~~incident~~in tothe ~~exploring~~costs ~~and~~of our drilling ~~for,~~operations ~~producing,~~or ~~transporting,~~those ~~marketing~~of ~~and~~our ~~selling~~third-party ~~oil~~operators, and/or ~~natural~~curtailments, ~~gas.~~delays ~~Although~~or wecancellations ~~may take precautionary measures, many~~ of ~~these~~our ~~risks~~drilling ~~and~~operations ~~hazards~~or ~~are~~those ~~beyond~~of our ~~control~~third-party ~~and~~operators ~~unavoidable~~in ~~under~~each ~~the~~case ~~circumstances.~~due ~~Many~~to any of ~~these~~the ~~risks~~above factors or ~~hazards~~other ~~could~~factors, may materially and adversely affect our ~~revenues and expenses~~business, ~~the~~financial ~~ability~~condition ~~of certain of our wells to produce oil~~ and ~~natural~~results ~~gas in commercial quantities, the rate~~ of ~~production~~operations. ~~and~~For ~~the~~related ~~economics~~discussion of the ~~development~~risks ~~of,~~ and ~~our~~potential ~~investment~~losses inand ~~the~~liabilities ~~prospects~~inherent in ~~which~~our wecrude ~~have~~oil ~~or will acquire an interest. Any of these risks~~ and ~~hazards~~natural ~~could~~gas ~~materially~~operations ~~and adversely affect our financial condition~~generally, ~~results~~see ofthe ~~operations~~immediately ~~and~~following ~~cash~~risk ~~flows~~factor. ~~Such risks and hazards include:~~

●Our ~~human~~oil ~~error,~~and ~~accidents,~~natural ~~labor~~gas ~~force~~activities ~~and~~are ~~other~~subject ~~factors~~to various risks that are beyond our control ~~that~~and ~~may~~expose ~~cause~~us ~~personal~~to ~~injuries~~potential orlosses ~~death~~and toliabilities, ~~persons~~ and ~~destruction~~insurance ormay ~~damage~~not tofully ~~equipment~~protect us against these risks and ~~facilities;~~potential losses and liabilities.

●Our ~~blowouts~~operations are subject to many risks and hazards incident to exploring and drilling for, ~~fires~~producing, ~~explosions~~transporting, ~~loss~~marketing and selling oil and natural gas. Although we may take precautionary measures, many of ~~well~~these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, ~~hurricanes~~the ability of certain of our wells to produce oil and natural gas in commercial quantities, ~~pollution~~the rate of production and ~~equipment~~the ~~failures~~economics ~~that~~of ~~may~~the ~~result~~development of, and our investment in ~~damage~~the toprospects in which we have or ~~destruction~~will acquire an interest. Any of ~~wells,~~these ~~producing~~risks ~~formations~~and hazards could materially and adversely affect our financial condition, ~~production~~results ~~facilities~~of operations and ~~equipment;~~cash flows. Such risks and hazards include:

● ~~unavailability~~human oferror, ~~materials~~accidents, labor force and other factors beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;

● ~~engineering~~blowouts, fires, explosions, loss of well control, hurricanes, pollution and ~~construction~~equipment ~~delays~~failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;

● ~~unanticipated~~unavailability ~~transportation~~of ~~costs~~materials and ~~delays~~equipment;

● ~~adverse~~engineering ~~weather conditions, such as winter storms, flooding~~ and ~~hurricanes,~~construction ~~and other natural disasters~~delays;

● ~~hazards~~unanticipated ~~resulting~~transportation ~~from~~costs ~~unusual~~and ~~or unexpected geological or environmental conditions~~delays;

● ~~environmental~~adverse ~~regulations~~weather conditions, such as winter storms, flooding and ~~requirements~~hurricanes, and other natural disasters;

● ~~accidental~~hazards ~~leakage~~resulting offrom ~~toxic~~unusual or ~~hazardous~~unexpected ~~materials,~~geological ~~such as petroleum liquids~~ or ~~drilling~~environmental ~~fluids, into the environment~~conditions;

● ~~changes~~environmental ~~in laws and~~ regulations, ~~including laws~~ and ~~regulations applicable to oil and natural gas activities or markets for the oil and natural gas produced~~requirements;

● ~~fluctuations~~accidental inleakage ~~supply~~of ~~and~~toxic ~~demand~~or ~~for~~hazardous ~~oil~~materials, ~~and~~such ~~natural~~as ~~gas~~petroleum ~~causing~~liquids ~~variations~~or ofdrilling ~~the~~fluids, ~~prices~~into wethe ~~receive for our oil and natural gas production~~environment;

● ~~hazards~~changes ~~resulting~~in ~~from~~laws ~~the~~and ~~presence~~regulations, ofincluding ~~hydrogen~~laws ~~sulfide~~and ~~(H2S)~~regulations orapplicable ~~other~~to ~~contaminants~~oil inand natural gas weactivities ~~produce~~or markets for the oil and natural gas produced;

● ~~the~~fluctuations ~~availability~~in ofsupply ~~alternative~~and ~~fuels~~demand for oil and natural gas causing variations of the ~~price~~prices atwe ~~which~~receive ~~they~~for ~~become~~our ~~available;~~oil and natural gas production;

● ~~terrorism,~~hazards ~~vandalism~~resulting ~~and~~from ~~physical,~~the ~~electronic~~presence ~~and~~of ~~cyber~~hydrogen ~~security~~sulfide ~~breaches.~~(H2S) or other contaminants in gas we produce;

To● ~~mitigate~~the ~~financial~~availability ~~losses~~of ~~resulting~~alternative ~~from~~fuels ~~these operating hazards, we maintain insurance coverage, including insurance coverage for certain physical damage, comprehensive general liability,~~ and ~~worker’s compensation and employer’s liability. However, our insurance coverage may not be sufficient to cover us against all of potential losses arising as a result of~~ the ~~foregoing,~~price ~~and~~at ~~for certain risks, such as political risk, business interruption, war, terrorism, and piracy, for~~ which wethey ~~have~~become ~~limited~~available; or no coverage. In addition, we are not insured against all risks in all aspects of our business. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.and

~~The~~● ~~high cost or unavailability of drilling rigs~~terrorism, ~~equipment,~~vandalism ~~supplies,~~and ~~personnel~~physical, ~~and~~electronic ~~other oilfield services could adversely affect our ability to execute our exploration~~ and ~~development~~cyber ~~plans~~security ~~on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations~~breaches.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, or qualified personnel. During these periods, the costs of rigs, equipment, supplies, and personnel are substantially greater and their availability to us may be limited. Additionally, these services may not be available on commercially reasonable terms. The high cost or unavailability of drilling rigs, equipment, supplies, personnel, and other oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations.19

ATable ~~portion~~ of ~~our crude oil and natural gas production may be subject to interruptions that could have a material and adverse effect on us.~~Contents

ATo ~~portion~~mitigate offinancial ~~our~~losses ~~crude~~resulting ~~oil~~from ~~and~~these ~~natural~~operating ~~gas~~hazards, ~~production~~we ~~may~~maintain beinsurance ~~interrupted~~coverage, orincluding ~~shut~~insurance ~~in,~~coverage ~~from~~for ~~time~~certain tophysical ~~time~~damage, ~~for~~comprehensive ~~various~~general ~~reasons~~liability, ~~including~~and worker’s compensation and employer’s liability. However, ~~but~~our insurance coverage may not ~~limited~~be sufficient to, cover us against all of potential losses arising as a result of ~~accidents~~the foregoing, ~~weather~~and ~~conditions~~for certain risks, ~~loss~~such ofas ~~gathering~~political risk, ~~processing~~business interruption, ~~compression~~war, orterrorism, ~~transportation~~and ~~facility~~piracy, ~~access~~for orwhich ~~field~~we ~~labor~~have ~~issues,~~limited or ~~intentionally~~no ascoverage. aIn ~~result~~addition, ofwe ~~market~~are ~~conditions~~not ~~such~~insured asagainst ~~crude~~all ~~oil~~risks orin ~~natural~~all ~~gas~~aspects ~~prices~~of ~~that~~our webusiness. ~~deem~~The ~~uneconomic. If~~occurrence of a ~~substantial~~significant ~~amount~~event ofagainst ~~our~~which ~~production~~we isare ~~interrupted,~~not ~~our~~fully ~~cash~~insured ~~flows~~could ~~and,~~have ina ~~turn,~~material adverse effect on our consolidated financial ~~condition~~position, ~~and~~ results of operations, ~~could~~or becash ~~materially and adversely affected~~flows.

19The high cost or unavailability of drilling rigs, equipment, supplies, personnel, and other oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations.

~~Table~~Our industry is cyclical and, from time to time, there is a shortage of ~~Contents~~drilling rigs, equipment, supplies, or qualified personnel. During these periods, the costs of rigs, equipment, supplies, and personnel are substantially greater and their availability to us may be limited. Additionally, these services may not be available on commercially reasonable terms. The high cost or unavailability of drilling rigs, equipment, supplies, personnel, and other oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations.

~~Failure~~A toportion ~~fund~~of ~~continued~~our ~~capital~~crude ~~expenditures~~oil and natural gas production may be subject to interruptions that could ~~adversely~~have ~~affect~~a ~~our~~material ~~properties~~and adverse effect on us.

~~Our~~A ~~acquisition,~~portion ~~exploration,~~of ~~and development activities require substantial capital expenditures. Historically, we have funded~~ our ~~capital~~crude ~~expenditures~~oil ~~through~~and anatural ~~combination~~gas ofproduction ~~cash~~may ~~flows~~be ~~from~~interrupted, ~~operations~~or ~~and~~shut ~~loans~~in, from ~~commercial~~time ~~banks~~to ~~and~~time ~~related~~for ~~parties.~~various ~~Future~~reasons, ~~cash~~including, ~~flows~~but ~~are~~not ~~subject~~limited to ~~a number of variables~~, ~~such~~ as ~~the~~a ~~level~~result of ~~production~~accidents, ~~from~~weather ~~existing wells~~conditions, ~~prices~~loss of ~~crude oil and natural gas~~gathering, ~~and our success in finding~~processing, ~~developing~~compression ~~and~~or ~~producing~~transportation ~~new~~facility ~~reserves.~~access Ifor ~~revenues~~field ~~were~~labor toissues, ~~decrease~~or intentionally as a result of ~~lower~~market conditions such as crude oil ~~and~~or natural gas prices orthat ~~decreased production, and our access to capital were limited,~~ we ~~would~~deem ~~have~~uneconomic. If a ~~reduced~~substantial ~~ability~~amount toof ~~replace~~ our ~~reserves, resulting in a decrease in~~ production ~~over~~is ~~time.~~interrupted, If our cash flows ~~from operations are not sufficient to meet our obligations~~ and ~~fund our capital budget~~, wein ~~may not be able to access debt~~turn, ~~equity or other methods of financing on an economic basis to meet these requirements, particularly in the current economic environment. If we are not able to fund~~ our ~~capital~~financial ~~expenditures,~~condition ~~interests~~and inresults ~~some~~of ~~properties~~operations ~~might~~could be ~~reduced~~materially orand ~~forfeited~~adversely ~~as a result~~affected.

~~Reserve~~Failure ~~estimates depend on many interpretations and assumptions that may turn out~~ to befund ~~inaccurate.~~continued ~~Any~~capital ~~significant~~expenditures ~~inaccuracies in these interpretations and assumptions~~ could ~~cause~~adversely ~~the~~affect ~~reported quantities and the value of~~ our ~~reserves to be materially misstated~~properties.

~~Estimating~~Our ~~quantities~~acquisition, ofexploration, ~~crude~~and ~~oil~~development activities require substantial capital expenditures. Historically, ~~NGLs~~we ~~and~~have ~~natural~~funded ~~gas~~our ~~reserves~~capital ~~and~~expenditures ~~future~~through ~~net~~a combination of cash flows from ~~such~~operations ~~reserves~~and isloans afrom ~~complex,~~commercial ~~inexact~~banks ~~process~~and related parties. ItFuture ~~requires~~cash ~~interpretations~~flows ofare ~~available~~subject ~~technical~~to ~~data~~a ~~and~~number ~~various~~of ~~assumptions~~variables, ~~including~~such ~~assumptions~~as ~~relating~~the tolevel ~~economic~~of ~~factors~~production from existing wells, ~~made~~prices byof ~~our~~crude ~~management~~oil and ~~our~~natural ~~independent~~gas, ~~reserve~~and ~~engineering~~our ~~firms;~~success ~~Netherland~~in finding, ~~Sewell~~developing &and ~~Associates,~~producing ~~Inc~~new reserves. If revenues were to decrease as a result of lower crude oil and ~~Cawley,~~natural ~~Gillespie &~~gas ~~Associates~~prices or decreased production, ~~Inc.~~and ~~Any~~our ~~significant~~access ~~inaccuracies~~to incapital ~~these~~were ~~interpretations~~limited, orwe ~~assumptions~~would ~~could~~have ~~cause~~a ~~the~~reduced ~~reported~~ability ~~quantities~~to ofreplace our reserves, ~~and~~resulting ~~future~~in ~~net~~a decrease in production over time. If our cash flows from ~~such~~operations ~~reserves~~are tonot besufficient ~~overstated~~to ormeet ~~understated.~~our ~~Also,~~obligations ~~the~~and ~~data~~fund ~~for~~our acapital ~~given~~budget, ~~reservoir~~we may ~~also~~not ~~change~~be ~~substantially~~able ~~over~~to ~~time~~access asdebt, aequity ~~result~~or ofother ~~numerous~~methods ~~factors~~of ~~including,~~financing ~~but~~on ~~not~~an ~~limited~~economic basis to, ~~additional~~meet ~~development~~these ~~activity~~requirements, ~~evolving~~particularly ~~production~~in ~~history~~the ~~and~~current ~~continual~~economic ~~reassessment~~environment. ofIf ~~the~~we ~~viability~~are ofnot ~~production~~able ~~under~~to ~~varying~~fund ~~economic~~our ~~conditions~~capital expenditures, interests in some properties might be reduced or forfeited as a result.

ToReserve ~~prepare~~ estimates ofdepend ~~our~~on ~~economically~~many ~~recoverable~~interpretations ~~crude oil, NGLs~~ and ~~natural~~assumptions ~~gas~~that ~~reserves~~may ~~and~~turn ~~future~~out ~~net~~to ~~cash~~be ~~flows from our reserves, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas~~inaccurate. WeAny ~~also~~significant ~~analyze~~inaccuracies ~~available~~in ~~geological,~~these ~~geophysical,~~interpretations ~~production~~ and ~~engineering~~assumptions ~~data,~~could ~~and~~cause the ~~extent,~~reported ~~quality~~quantities and ~~reliability~~the value of ~~this~~our ~~data~~reserves ~~can vary. The process also involves economic assumptions relating~~ to ~~commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, many of which factors are or may~~ be ~~beyond~~materially ~~our control~~misstated.

~~Estimates~~Estimating quantities of ~~reserves~~crude ~~based~~oil, onNGLs ~~risk of recovery~~ and ~~estimates~~natural ofgas ~~expected~~reserves and future net cash flows ~~prepared~~from bysuch ~~different~~reserves ~~engineers~~is a complex, orinexact byprocess. ~~the~~It ~~same~~requires ~~engineers~~interpretations atof ~~different~~available ~~times~~technical data and various assumptions, ~~may~~including ~~vary~~assumptions ~~substantially.~~relating ~~Actual~~to ~~production,~~economic ~~revenues~~factors, ~~and~~made ~~expenditures~~by ~~with~~our ~~respect~~management toand our ~~reserves~~independent ~~will~~reserve ~~likely~~engineering ~~vary~~firms; ~~from estimates~~Netherland, ~~and~~Sewell ~~the~~& ~~variance~~Associates, ~~may~~Inc. beand ~~material.~~Cawley, ~~The~~Gillespie & ~~discounted~~Associates, ~~cash~~Inc. ~~flows~~Any ~~included~~significant inaccuracies in ~~this~~these ~~report~~interpretations ~~should~~or ~~not~~assumptions becould ~~construed~~cause as the ~~fair~~reported ~~value~~quantities of ~~the~~our ~~estimated~~reserves ~~oil,~~and ~~natural-gas,~~future ~~and~~net ~~NGLs~~cash ~~reserves~~flows ~~attributable~~from tosuch ~~our~~reserves ~~properties.~~to ~~The~~be ~~estimated~~overstated ~~discounted~~or ~~future~~understated. ~~net~~Also, ~~cash~~the ~~flows~~data ~~from~~for ~~proved~~a ~~reserves~~given ~~are~~reservoir ~~based~~may onalso ~~average~~change ~~12-month~~substantially ~~sales~~over ~~prices~~time ~~using~~as ~~the~~a ~~average~~result ~~beginning-~~of~~-month~~ ~~price.~~numerous ~~Actual~~factors ~~future~~including, ~~prices~~but ~~and~~not ~~costs~~limited ~~may~~to, ~~differ~~additional ~~materially~~development ~~from~~activity, ~~the~~evolving ~~SEC~~production ~~regulation-compliant~~history ~~prices~~and ~~used~~continual ~~for~~reassessment ~~purposes~~ of ~~estimating~~the ~~future~~viability ~~discounted~~of ~~net~~production ~~cash~~under ~~flows~~varying ~~from~~economic ~~proved reserves~~conditions.

~~Discoveries~~To orprepare ~~Acquisitions~~estimates of ~~reserves~~our ~~are~~economically ~~needed~~recoverable tocrude ~~avoid~~oil, aNGLs ~~material~~and ~~decline~~natural ingas reserves and future net cash flows from our reserves, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, many of which factors are or may be beyond our control.

The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase, due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities or, through engineering studies, identify additional producing zones in existing wells, secondary or tertiary recovery techniques, or acquire additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.20

20Table of Contents

~~Table~~Estimates of ~~Contents~~reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues, and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The discounted cash flows included in this report should not be construed as the fair value of the estimated oil, natural-gas, and NGLs reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on average 12-month sales prices using the average beginning-of-month price. Actual future prices and costs may differ materially from the SEC regulation-compliant prices used for purposes of estimating future discounted net cash flows from proved reserves.

IfDiscoveries weor ~~acquire~~Acquisitions ~~crude~~of ~~oil~~reserves ~~and~~are ~~natural~~needed ~~gas properties, our failure~~ to ~~fully~~avoid ~~identify~~a ~~existing~~material ~~and~~decline ~~potential~~in ~~problems and liabilities, to accurately estimate~~ reserves, ~~production rates or costs, or to effectively integrate the acquired properties into our operations could materially~~ and ~~adversely affect our business, financial condition and results of operations~~production.

~~From~~The ~~time~~production torates ~~time,~~from ~~we seek to acquire crude~~ oil and ~~natural~~ gas properties. ~~Although~~generally wedecline ~~perform~~as ~~reviews~~reserves ofare ~~properties~~depleted, towhile berelated ~~acquired~~per inunit aproduction ~~manner~~costs ~~that~~generally weincrease, ~~believe~~due isto ~~duly~~decreasing ~~diligent~~reservoir pressures and ~~consistent~~other ~~with~~factors. ~~industry practices~~Therefore, ~~reviews~~our ofestimated ~~records~~proved reserves and ~~properties~~future ~~may not necessarily reveal existing or potential problems~~oil, ~~nor~~gas ~~may~~and ~~they~~NGL ~~permit~~production uswill todecline ~~become~~materially ~~sufficiently~~as ~~familiar~~reserves ~~with~~are ~~the~~produced ~~properties~~unless inwe ~~order~~conduct tosuccessful ~~assess~~exploration ~~fully their deficiencies~~ and ~~potential.~~development Weactivities ~~do not inspect every well. Even when we inspect a well~~or, wethrough doengineering ~~not always discover structural~~studies, ~~subsurface~~identify ~~and~~additional ~~environmental~~producing ~~problems~~zones ~~that may exist or arise~~ in ~~the~~existing ~~future.~~wells, ~~Even~~secondary ~~when~~or ~~problems~~tertiary ~~with~~recovery ~~a property are identified~~techniques, weor ~~often~~acquire ~~may~~additional ~~assume environmental and other risks and liabilities in connection with acquired~~ properties ~~pursuant~~containing toproved ~~the acquisition agreements~~reserves. ~~In addition~~Consequently, ~~there~~our ~~are~~future ~~numerous uncertainties inherent in estimating quantities of crude~~ oil, ~~and natural~~ gas ~~reserves~~and ~~(as~~NGL ~~discussed further above), actual future~~ production ~~rates~~ and ~~associated~~related ~~costs~~per ~~with~~unit ~~respect to acquired properties. Actual reserves,~~ production ~~rates and~~ costs ~~may~~are ~~vary~~highly ~~substantially~~dependent ~~from~~upon ~~those assumed in~~ our ~~estimates.~~level ~~In addition, an acquisition may have a material and adverse effect on our business and results~~ of ~~operations,~~success ~~particularly during the periods~~ in ~~which~~finding ~~the operations of the acquired properties are being integrated into our ongoing operations~~ or ifacquiring weadditional ~~are unable to effectively integrate the acquired properties into our ongoing operations~~reserves.

~~Title~~If we acquire crude oil and natural gas properties, our failure to fully identify existing and potential problems and liabilities, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties ininto ~~which~~our weoperations ~~have~~could anmaterially ~~interest~~and ~~may~~adversely beaffect ~~impaired~~our bybusiness, ~~title~~financial ~~defects~~condition and results of operations.

WeFrom ~~generally~~time ~~conduct~~to ~~due~~time, ~~diligence~~we seek to ~~review~~acquire ~~title~~crude onoil ~~significant~~and natural gas properties. Although we perform reviews of properties to be acquired in a manner that we ~~drill~~believe is duly diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or ~~acquire.~~potential ~~However~~problems, ~~there~~nor ismay nothey ~~assurance~~permit ~~that~~us weto ~~will~~become sufficiently familiar with the properties in order to assess fully their deficiencies and potential. We do not ~~suffer~~inspect every well. Even when we inspect a ~~monetary~~well, ~~loss~~we ~~from~~do ~~title~~not ~~defects~~always discover structural, subsurface and environmental problems that may exist or ~~title~~arise ~~failure~~in the future. ~~Additionally~~Even when problems with a property are identified, ~~undeveloped~~we ~~acreage~~often ~~has~~may ~~greater~~assume ~~risk~~environmental ofand ~~title~~other ~~defects~~risks ~~than~~and ~~developed~~liabilities ~~acreage~~in connection with acquired properties pursuant to the acquisition agreements. ~~Generally~~In addition, ~~under~~there ~~the~~are ~~terms~~numerous uncertainties inherent in estimating quantities of ~~the~~crude ~~operating~~oil ~~agreements~~and ~~affecting~~natural ~~our~~gas ~~properties~~reserves (as discussed further above), ~~any~~actual ~~monetary~~future ~~loss~~production isrates ~~due~~and toassociated ~~title~~costs ~~defects~~with isrespect to beacquired ~~borne~~properties. byActual ~~all~~reserves, ~~parties~~production torates ~~any~~and ~~such~~costs ~~agreement~~may invary ~~proportion~~substantially tofrom ~~their~~those ~~interests~~assumed in ~~such~~our ~~property~~estimates. IfIn ~~there~~addition, ~~are~~an ~~any~~acquisition ~~title~~may ~~defects~~have ora ~~defects~~material inand ~~assignment~~adverse effect on our business and results of ~~leasehold~~operations, ~~rights~~particularly induring ~~properties~~the periods in which wethe ~~hold~~operations anof ~~interest,~~the acquired properties are being integrated into our ongoing operations or if we ~~will~~are ~~suffer~~unable ato ~~financial~~effectively ~~loss~~integrate the acquired properties into our ongoing operations.

~~There~~Title isto athe ~~possibility~~properties ~~that~~in which we ~~will~~have ~~lose~~an ~~the~~interest ~~leases~~may tobe ~~our~~impaired ~~oil~~by ~~and~~title ~~gas properties~~defects.

~~Our~~We ~~oil~~generally ~~and~~conduct ~~gas~~due ~~revenues~~diligence ~~are~~to ~~generated~~review ~~through~~title ~~oil~~on ~~and~~significant ~~gas~~properties ~~leases~~that we drill or acquire. ~~These~~However, ~~leases~~there ~~are~~is ~~conditioned~~no onassurance ~~the~~that ~~performance~~we ofwill ~~certain~~not ~~obligations,~~suffer ~~primarily~~a ~~the~~monetary ~~obligation~~loss tofrom ~~produce~~title ~~oil~~defects ~~and/~~or ~~gas~~title orfailure. ~~engage~~Additionally, inundeveloped ~~operations~~acreage ~~designed~~has togreater ~~result~~risk inof title defects than developed acreage. Generally, under the ~~production~~terms of ~~oil~~the ~~and~~operating ~~gas.~~agreements Ifaffecting ~~production~~our ~~ceases~~properties, ~~and~~any ~~operations~~monetary ~~are~~loss ~~not~~is ~~commenced~~due ~~within~~to atitle ~~specified~~defects ~~time,~~is ~~the~~to ~~lease~~be ~~may~~borne beby ~~lost~~all parties to any such agreement in proportion to their interests in such property. ~~The~~If ~~loss~~there are any title defects or defects in assignment of ~~our~~leasehold ~~leases~~rights ~~may~~in ~~have~~properties ain ~~material~~which ~~and~~we ~~adverse~~hold ~~impact~~an oninterest, ~~our~~we ~~revenues~~will suffer a financial loss.

InThere ~~the~~is ~~case~~a ofpossibility ~~Israeli-based~~that ~~properties,~~ we ~~have~~will ~~interests~~lose inthe ~~licenses that, subject to certain conditions, may result in~~ leases ~~being granted. The leases are subject~~ to certain obligations and are renewable at the discretion of various governmental authorities. As such, if the parties responsible for operations are not able to fulfill their obligations under the leases, the leases may be modified, cancelled, not renewed, or renewed on terms different from the current leases. The modification or cancellation of our ~~leases~~oil ~~could eliminate our interests~~ and ~~may~~gas ~~have a material and adverse impact on our revenues~~properties.

WeOur oil and gas revenues are ~~subject~~generated through oil and gas leases. These leases are conditioned on the performance of certain obligations, primarily the obligation to ~~complex~~produce ~~laws~~oil and/or ~~regulations~~gas ~~relating~~or toengage ~~environmental~~in ~~protection~~operations ~~that~~designed ~~can~~to ~~adversely~~result ~~affect~~in the ~~cost,~~production ~~manner,~~of oil and ~~feasibility~~gas. If production ceases and operations are not commenced within a specified time, the lease may be lost. The loss of ~~doing~~our ~~business~~leases may have a material and adverse impact on our revenues.

~~Our~~In ~~operations~~the ~~and~~case of Israeli-based properties, we have interests in licenses that, subject to certain conditions, may result in leases being granted. The leases are subject to ~~numerous~~certain ~~federal~~obligations and are renewable at the discretion of various governmental authorities. As such, ~~regional~~if the parties responsible for operations are not able to fulfill their obligations under the leases, ~~state~~the leases may be modified, ~~tribal~~cancelled, ~~local~~not renewed, ~~and~~or ~~foreign~~renewed ~~laws~~on ~~and~~terms ~~regulations~~different ~~governing~~from the ~~release~~current ofleases. ~~pollutants~~The modification or ~~otherwise~~cancellation ~~relating~~of toour ~~environmental~~leases ~~protection.~~could ~~These~~eliminate ~~laws~~our interests and ~~regulations~~may ~~govern~~have ~~the~~a ~~following,~~material ~~among~~and ~~other~~adverse ~~things:~~impact on our revenues.

~~● issuance of permits in connection with exploration, drilling and production activities;~~21

●Table ~~protection~~ of ~~endangered species;~~Contents

●We ~~amounts~~are subject to complex laws and ~~types~~regulations ofrelating ~~emissions~~to environmental protection that can adversely affect the cost, manner, and ~~discharges;~~feasibility of doing business.

●Our ~~generation~~operations and properties are subject to numerous federal, ~~management~~regional, state, tribal, local, and ~~disposition~~foreign laws and regulations governing the release of ~~waste~~pollutants ~~materials;~~or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:

● ~~reclamation~~issuance ~~and~~of ~~abandonment~~permits ofin ~~wells~~connection ~~and~~with ~~facility~~exploration, ~~sites;~~drilling and production activities;

● ~~remediation~~protection of ~~contaminated~~endangered ~~sites.~~species;

In● ~~addition,~~amounts ~~these laws~~ and ~~regulations~~types ~~may impose substantial liabilities for our failure to comply or for any contamination resulting from our operations. Future environmental laws and regulations, such as the restriction against emission~~ of ~~pollutants~~emissions from previously unregulated activities or the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our industry. The cost of satisfying these requirements may have an adverse effect on our financial condition, results of operations, or cash flows or could result in limitations on our exploration and ~~production activities, which could have an adverse impact on our ability to develop and produce our reserves.~~discharges;

21● generation, management, and disposition of waste materials;

~~Table~~● reclamation and abandonment of ~~Contents~~wells and facility sites; and

We● ~~cannot~~remediation beof ~~certain~~contaminated ~~that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities~~sites.

WeIn ~~maintain~~addition, ~~general~~these laws and ~~excess~~regulations ~~liability~~may ~~policies,~~impose ~~which~~substantial weliabilities ~~consider~~for our failure to becomply ~~reasonable~~or for any contamination resulting from our operations. Future environmental laws and ~~consistent~~regulations, ~~with~~such ~~industry~~as ~~standards~~the restriction against emission of pollutants from previously unregulated activities or the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our industry. ~~These~~The ~~policies~~cost ~~generally~~of ~~cover:~~satisfying these requirements may have an adverse effect on our financial condition, results of operations, or cash flows or could result in limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce our reserves.

●We ~~personal~~cannot ~~injury;~~be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.

●We ~~bodily~~maintain ~~injury;~~general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:

● ~~third~~personal ~~party property damage~~injury;

● ~~medical~~bodily ~~expenses~~injury;

● ~~legal~~third ~~defense~~party ~~costs~~property damage;

● ~~pollution~~medical ~~in some cases~~expenses;

● ~~loss~~legal ordefense ~~damage to equipment~~costs;

● ~~well~~pollution ~~blowouts~~ in some cases; ~~and~~

● ~~worker’s~~loss ~~compensation.~~or damage to equipment;

As● iswell ~~common~~blowouts in ~~the~~some ~~oil~~cases; and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position, results of operations and cash flows. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover claims made against us in the future.

~~Reduced~~● ~~demand~~worker’s ~~for or excess capacity of production services could adversely affect our profitability~~compensation.

~~Our~~As ~~profitability~~is common in the ~~future~~oil ~~will~~and ~~depend~~natural ongas ~~many factors~~industry, ~~but~~we ~~largely~~will onnot ~~pricing~~insure ~~and~~fully ~~utilization~~against ~~rates~~all ~~for~~risks associated with our ~~production~~business ~~services.~~either Anbecause ~~increase~~such ininsurance ~~supply~~is ofnot ~~production~~available ~~servicing~~or ~~rigs~~because ~~and~~we ~~equipment,~~believe ~~without~~the premium costs are prohibitive. A loss not fully covered by insurance could have a ~~corresponding~~materially ~~increase~~adverse ineffect ~~demand~~on our financial position, orresults ~~decrease~~of inoperations ~~demand~~and ~~for~~cash ~~production~~flows. ~~servicing~~There ~~rigs~~can ~~and~~be ~~equipment~~no ~~could~~assurance ~~decrease~~that the ~~pricing~~insurance ~~and~~coverage ~~utilization~~that ~~rates~~we ofmaintain ~~our~~will ~~production~~be ~~services,~~sufficient ~~which~~to ~~would~~cover ~~adversely~~claims ~~affect~~made ~~our~~against ~~revenues~~us ~~and~~in ~~profitability~~the future.

~~Our~~Reduced ~~production~~demand ~~services~~for ~~business~~or ~~depends~~excess oncapacity ~~domestic~~of ~~spending~~production byservices ~~the~~could ~~oil and natural gas industry, and this spending and our business has been in the past, and may in the future be,~~ adversely ~~affected~~affect ~~by industry and financial market conditions that are beyond~~ our ~~control~~profitability.

WeOur profitability in the future will depend on ~~our~~many ~~customers’~~factors, ~~willingness~~but tolargely ~~make~~on ~~operating~~pricing and ~~capital~~utilization ~~expenditures~~rates tofor ~~explore~~our ~~for,~~production ~~develop~~services. ~~and~~An ~~produce~~increase ~~oil~~in ~~and~~supply ~~natural~~of ~~gas~~production inservicing ~~the~~rigs ~~United~~and ~~States.~~equipment, ~~Customers’~~without ~~expectations~~a ~~for~~corresponding ~~lower~~increase ~~market~~in ~~prices~~demand, ~~for~~or ~~oil~~decrease ~~and~~in ~~natural~~demand ~~gas,~~for asproduction ~~well~~servicing asrigs ~~the~~and ~~availability~~equipment ofcould ~~capital~~decrease ~~for~~the ~~operating~~pricing and ~~capital~~utilization ~~expenditures,~~rates ~~may~~of ~~cause~~our ~~them~~production ~~to curtail spending~~services, ~~thereby~~which ~~reducing~~would ~~demand~~adversely ~~for~~affect our ~~services~~revenues and ~~equipment~~profitability.

~~Industry~~Our ~~conditions~~production ~~are~~services ~~influenced~~business bydepends ~~numerous~~on ~~factors over which we have no control, such as the supply of and demand for oil and natural gas,~~ domestic ~~and~~spending ~~worldwide~~by ~~economic conditions, political instability in oil and natural gas producing countries and merger and divestiture activity among oil and gas producers. The volatility of~~ the oil and natural gas industry, and ~~the~~this ~~consequent~~spending ~~impact on exploration~~ and ~~production~~our ~~activity~~business ~~could~~has ~~adversely~~been ~~impact~~in the ~~level~~past, ~~of drilling~~ and ~~workover activity by some of our customers. This reduction~~ may ~~cause a decline~~ in the ~~demand~~future ~~for~~be, ~~our services or~~ adversely ~~affect~~affected ~~the~~by ~~price~~industry ~~of our services. In addition, reduced discovery rates of new oil~~ and ~~natural~~financial ~~gas reserves in our~~ market ~~areas~~conditions ~~also~~that ~~may~~are ~~have~~beyond ~~a negative long-term impact on~~ our ~~business, even in an environment of stronger oil and natural gas prices, to the extent existing production is not replaced and the number of producing wells for us to service declines~~control.

~~Deterioration~~We independ ~~the~~on ~~global~~our ~~economic~~customers’ ~~environment~~willingness ~~commencing~~to inmake ~~the~~operating ~~latter part of 2008~~ and ~~continuing~~capital ~~throughout~~expenditures ~~2009 caused the oilfield services industry~~ to ~~cycle~~explore ~~into~~for, adevelop ~~downturn~~and ~~due~~produce tooil ~~weakened demand. The industry returned to higher activity levels in 2011~~ and ~~remained higher during the first half of 2012, before another downturn in the second half of 2012, affecting~~ natural gas ~~prices~~ in ~~particular. The industry pricing remained relatively stable through~~ the ~~middle~~United ~~of 2014~~States. ~~However,~~Customers’ ~~beginning~~expectations infor ~~the~~lower ~~second~~market ~~half~~prices offor ~~2014~~oil ~~through the end of 2015~~ and ~~continued~~natural ~~at the beginning of 2016~~gas, ~~oil~~as ~~prices~~well ~~declined~~as ~~substantially from historical highs. Towards~~ the ~~end~~availability of ~~2016 and through 2017 we saw an increase in oil prices though they did not reach the same levels prior to the decline beginning in 2014. Any adverse changes in~~ capital ~~markets and declines in prices~~ for ~~oil~~operating and ~~natural~~capital ~~gas~~expenditures, ~~will~~may ~~likely~~ cause ~~oil~~them ~~and natural gas producers~~ to ~~announce~~curtail ~~reductions~~spending, inthereby ~~capital~~reducing ~~budgets~~demand for ~~future~~our ~~periods~~services and equipment.

Table of Contents

~~Limitations~~Industry onconditions ~~the~~are ~~availability~~influenced ofby ~~capital~~numerous factors over which we have no control, orsuch ~~higher~~as ~~costs~~the supply of ~~capital,~~and demand for ~~financing~~oil ~~expenditures~~and ~~may~~natural ~~cause~~gas, domestic and worldwide economic conditions, political instability in oil and natural gas ~~producers~~producing tocountries ~~make~~and ~~further~~merger ~~reductions~~and todivestiture ~~capital~~activity ~~budgets~~among inoil ~~the~~and ~~future~~gas ~~even~~producers. ifThe volatility of the oil orand natural gas ~~prices~~industry ~~increase~~and ~~from~~the ~~current~~consequent ~~levels.~~impact ~~Any~~on ~~such~~exploration ~~cuts~~and inproduction ~~spending~~activity ~~will~~could ~~curtail~~adversely impact the level of drilling ~~programs~~and asworkover ~~well~~activity asby ~~discretionary~~some ~~spending~~of onour ~~production~~customers. ~~services,~~This ~~which~~reduction may ~~result~~cause in a ~~reduction~~decline in the demand for our services, ~~the~~or ~~rates~~adversely weaffect ~~can~~the ~~charge~~price ~~and~~of our ~~utilization~~services. In addition, ~~certain~~reduced discovery rates of new oil and natural gas reserves in our ~~customers~~market ~~could~~areas ~~become~~also ~~unable~~may tohave ~~pay~~a ~~their~~negative ~~suppliers~~long-term impact on our business, ~~including~~even ~~us.~~in ~~Any~~an environment of ~~these~~stronger ~~conditions~~oil orand ~~events~~natural ~~could~~gas ~~adversely~~prices, ~~affect~~to ~~our~~the ~~operating~~extent ~~results~~existing production is not replaced and the number of producing wells for us to service declines.

IfLimitations on the availability of capital, or higher costs of capital, for financing expenditures may cause oil and natural gas ~~prices~~producers ~~remain~~to ~~volatile,~~make orfurther reductions to capital budgets in the future even if oil or natural gas prices ~~remain~~increase ~~low~~from orcurrent ~~decline~~levels. ~~further~~Any such cuts in spending will curtail drilling programs as well as discretionary spending on production services, which may result in a reduction in the demand for our ~~production~~ services, the rates we can charge and our utilization. In addition, certain of our customers could bebecome unable to pay their suppliers, including us. Any of these conditions or events could adversely ~~affected~~affect our operating results.

~~The~~If ~~demand for our services is primarily determined by current and anticipated~~ oil and natural gas prices ~~and~~remain ~~the~~volatile, ~~related general production spending and level of drilling activity in the areas in which we have operations. Volatility~~ or ~~weakness~~if in oil ~~prices~~ or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. This, in turn, could result in lower demand for our services and may cause lower rates and lower utilization of our production service equipment. If oil prices or natural gas prices continue to remain low or decline further, ~~or if there is a reduction in drilling activities,~~ the demand for our production services ~~and our results of operations~~ could be ~~materially and~~ adversely affected.

~~Competition~~The demand for our services is primarily determined by current and anticipated oil and natural gas prices and the related general production spending and level of drilling activity in the areas in which we have operations. Volatility or weakness in oil ~~and~~prices or natural gas ~~exploration~~prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production ~~industry~~spending ison ~~intense~~existing wells. This, in turn, could result in lower demand for our services and ~~many~~may cause lower rates and lower utilization of our ~~competitors~~production ~~have~~service ~~greater~~equipment. ~~resources~~If ~~than~~oil weprices ~~have~~or natural gas prices continue to remain low or decline further, or if there is a reduction in drilling activities, the demand for our services and our results of operations could be materially and adversely affected.

WeCompetition ~~compete~~in ~~with~~the ~~national~~ oil ~~companies, major integrated oil~~ and gas ~~companies,~~exploration ~~independent oil~~ and ~~gas~~production ~~companies~~industry ~~and~~is ~~other individual producers for the acquisition of licenses and leases~~intense, ~~properties~~ and ~~reserves~~many and the equipment, materials, services and employees and other contract personnel (including geologists, geophysicists, engineers and other specialists) required to explore, develop, produce and market crude oil and natural gas. Some of our competitors ~~may~~ have greater ~~and more diverse~~ resources ~~on which to draw~~ than we dohave. As a consequence, we may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights, acquisition of licenses and leases, properties and reserves or in acquiring necessary services, equipment, materials and personnel. If we are not successful in our competition for oil and gas reserves or in our marketing of production, our financial condition and results of operations may be adversely affected.

~~Poor~~We ~~general~~compete ~~economic~~with national oil companies, ~~business~~major integrated oil and gas companies, orindependent ~~industry~~oil ~~conditions~~and gas companies and other individual producers for the acquisition of licenses and leases, properties and reserves and the equipment, materials, services and employees and other contract personnel (including geologists, geophysicists, engineers and other specialists) required to explore, develop, produce and market crude oil and natural gas. Some of our competitors may have agreater ~~material~~and ~~adverse~~more ~~effect~~diverse resources on ~~our~~which ~~results~~to draw than we do. As a consequence, we may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights, acquisition of ~~operations~~licenses and leases, ~~liquidity~~properties and reserves or in acquiring necessary services, equipment, materials and personnel. If we are not successful in our competition for oil and gas reserves or in our marketing of production, our financial condition and results of operations may be adversely affected.

~~During~~Poor ~~the~~general ~~last few years~~economic, ~~concerns over inflation~~business, ~~energy~~or ~~costs,~~industry ~~geopolitical~~conditions ~~issues,~~may ~~the availability and cost of credit, the U.S. mortgage market, uncertainties with regard to European sovereign debt, and a declining real estate market in the United States~~ have ~~contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had~~ a ~~significant~~material adverse ~~impact~~effect on global financial markets and commodity prices. If the economic recovery in the United States or abroad remains prolonged, demand for petroleum products could diminish or stagnate, which could impact the price at which we can sell our ~~oil, natural gas, and NGLs, affect our vendors’, suppliers’ and customers’ ability to continue operations, and ultimately adversely impact our~~ results of operations, liquidity, and financial condition.

~~Our~~During ~~hedging~~the ~~activities~~last ~~may~~few ~~prevent~~years, usconcerns ~~from~~over ~~benefiting~~inflation, ~~fully~~energy ~~from~~costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market, uncertainties with regard to European sovereign debt, and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If the economic recovery in the United States or abroad remains prolonged, demand for petroleum products could diminish or stagnate, which could impact the price ~~increases~~at which we can sell our oil, natural gas, and ~~may~~NGLs, ~~expose~~affect usour vendors’, suppliers’ and customers’ ability to ~~other~~continue ~~risks~~operations, and ultimately adversely impact our results of operations, liquidity, and financial condition.

In order to manage our exposure to price risks in the marketing of our oil and natural gas production, we sometimes enter into oil and natural gas price hedging arrangements with respect to a portion of our anticipated production and we may enter into additional hedging transactions in the future. While intended to reduce the effects of volatile oil and natural gas prices, such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:23

●Table ~~our~~of ~~actual production is less than hedged volumes;~~Contents

●Our ~~there~~hedging isactivities amay ~~widening~~prevent ofus ~~price~~from ~~differentials~~benefiting ~~between~~fully ~~delivery~~from ~~points~~price ~~for~~increases ~~our production~~ and ~~the~~may ~~delivery~~expose ~~point~~us ~~assumed~~to inother ~~the hedge arrangement;~~risks.

●In order to manage our exposure to price risks in the ~~counterparties~~marketing of our oil and natural gas production, we sometimes enter into oil and natural gas price hedging arrangements with respect to a portion of our anticipated production and we may enter into additional hedging ~~agreements~~transactions ~~fail~~in the future. While intended to ~~perform~~reduce ~~under~~the effects of volatile oil and natural gas prices, such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the ~~contracts;~~price orestablished by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

● aour ~~sudden~~actual ~~unexpected~~production ~~event~~is ~~materially~~less ~~impacts~~than ~~oil~~hedged ~~and natural-gas prices.~~volumes;

23● there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

~~Table~~● ofthe ~~Contents~~counterparties to our hedging agreements fail to perform under the contracts; or

At● ~~the~~a ~~time~~sudden ofunexpected ~~this~~event ~~report,~~materially ~~the~~impacts ~~Company~~oil ~~had~~and nonatural-gas ~~commodity price hedging agreements in place~~prices.

~~The~~At ~~credit~~the ~~risk~~time of ~~financial~~this ~~institutions~~report, ~~could~~the ~~adversely~~Company ~~affect~~had usno commodity price hedging agreements in place.

WeThe have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, insurance companies and other institutions. These transactions expose us to credit risk ~~in the event~~ of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions through our derivative transactions. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility. Moreover, to the extent that purchasers of the Company’s production rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could ~~default~~adversely inaffect ~~their contractual obligations to the Company if such purchasers were unable to access the credit or equity markets for an extended period of time~~us.

We have noexposure ~~means~~to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, insurance companies and other institutions. These transactions expose us to ~~market~~credit risk in the event of default of our ~~oil~~counterparty. Deterioration in the credit markets may impact the credit ratings of our current and ~~gas~~potential ~~production~~counterparties ~~without~~and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions through our derivative transactions. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the ~~assistance~~aggregate amount of ~~third~~such ~~parties~~lender’s commitment under our credit facility. Moreover, to the extent that purchasers of the Company’s production rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the credit or equity markets for an extended period of time.

~~The~~We ~~marketability~~have ofno ~~our~~means ~~production~~to ~~depends~~market ~~upon the proximity of~~ our ~~reserves to, and the capacity of, facilities and third party services, including~~ oil and ~~natural~~ gas ~~gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or lack of capacity of such services and facilities could impair or delay the~~ production ofwithout ~~new wells or~~ the ~~delay~~assistance ~~or discontinuance~~ of ~~development~~third ~~plans for properties~~parties. A shut-in, delay or discontinuance could adversely affect our financial condition. In addition, regulation of oil and natural gas production transportation in the United States or in other countries may affect its ability to produce and market our oil and natural gas on a profitable basis.

~~Our~~The ~~exploration~~marketability of our production depends upon the proximity of our reserves to, and ~~development~~the ~~drilling~~capacity ~~efforts~~of, facilities and third party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or lack of capacity of such services and facilities could impair or delay the ~~operation~~production of ~~our~~new wells ~~may~~or ~~not~~the bedelay ~~profitable~~or discontinuance of development plans for properties. A shut-in, delay or ~~achieve~~discontinuance could adversely affect our ~~targeted~~financial ~~returns~~condition. In addition, regulation of oil and natural gas production transportation in the United States or in other countries may affect its ability to produce and market our oil and natural gas on a profitable basis.

WeOur ~~require~~exploration ~~significant~~and ~~amounts of undeveloped leasehold acreage to further our~~ development ~~efforts. Exploration, development,~~ drilling efforts and ~~production activities are subject to many risks, including~~ the ~~risk~~operation that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that our leasehold acreage will be profitably developed, that new wells drilled by us will be productive or that we will recover all or any portion of our ~~investment in such leasehold acreage or~~ wells. ~~Drilling for oil and natural gas~~ may ~~involve unprofitable efforts,~~ not ~~only~~be ~~from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are~~ profitable ~~may~~or ~~not~~ achieve our targeted ~~rate of return~~returns. Our ability to achieve our target results is dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

InWe ~~addition,~~require wesignificant ~~may~~amounts ~~not~~of beundeveloped ~~successful~~leasehold inacreage ~~controlling~~to further our development efforts. Exploration, development, drilling and production ~~costs~~activities are subject to ~~improve~~many ~~our~~risks, ~~overall~~including ~~return.~~the ~~The~~risk ~~cost~~that ofcommercially ~~drilling,~~productive ~~completing~~reservoirs ~~and~~will ~~operating~~not abe ~~well~~discovered. isWe ~~often~~invest ~~uncertain~~in ~~and~~property, ~~cost~~including ~~factors~~undeveloped ~~can~~leasehold ~~adversely~~acreage, ~~affect~~which ~~the~~we ~~economics~~believe ofwill aresult ~~project~~in projects that will add value over time. WeHowever, we cannot ~~predict~~guarantee ~~the~~that ~~cost~~our ofleasehold ~~drilling~~acreage ~~and~~will ~~completing~~be aprofitably ~~well~~developed, ~~and~~that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may beinvolve ~~forced~~unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to ~~limit~~return a profit after deducting operating and other costs. In addition, ~~delay~~wells orthat ~~cancel~~are ~~drilling~~profitable ~~operations~~may asnot aachieve ~~result~~our targeted rate of areturn. ~~variety~~Our ofability ~~factors~~to achieve our target results is dependent upon the current and future market prices for oil and natural gas, ~~including:~~costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

●In ~~unexpected~~addition, we may not be successful in controlling our drilling ~~conditions;~~and production costs to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling and completing a well, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:

● ~~pressure~~unexpected ordrilling ~~irregularities in formations~~conditions;

● ~~equipment~~pressure ~~failures~~ or ~~accidents~~irregularities ~~and shortages or delays~~ in ~~the availability of drilling and completion equipment and services~~formations;

● ~~adverse~~equipment ~~weather~~failures ~~conditions,~~or ~~including~~accidents ~~hurricanes;~~and shortages or delays in the availability of drilling and completion equipment and services;

● ~~compliance~~adverse ~~with~~weather ~~governmental~~conditions, ~~requirements.~~including hurricanes; and

We● ~~depend~~compliance onwith ~~the~~governmental ~~skill, ability and decisions of third party operators to a significant extent~~requirements.

The success of the drilling, development and production of the oil and natural gas properties in which we have or expect to have a non-operating working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of any third-party operator to make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and comply with laws, rules and regulations, including environmental laws and regulations in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could negatively affect our results of operations.24

24Table of Contents

~~Table~~We depend on the skill, ability and decisions of ~~Contents~~third party operators to a significant extent.

WeThe ~~depend~~success of the drilling, development and production of the oil and natural gas properties in which we have or expect to have a non-operating working interest is substantially ondependent upon the ~~continued~~decisions ~~presence~~of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of ~~key~~any ~~personnel~~third-party ~~for~~operator ~~critical~~to ~~management~~make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and ~~industry~~comply ~~contacts~~with laws, rules and regulations, including environmental laws and regulations in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could negatively affect our results of operations.

~~Our~~We ~~success~~depend ~~depends~~substantially ~~upon~~on the continued ~~contributions~~presence of ~~our executive officers and~~ key ~~employees,~~personnel ~~particularly~~for ~~with respect to providing the~~ critical management decisions and ~~contacts necessary to manage and maintain growth within a highly competitive~~ industry. ~~Competition for qualified personnel can be intense, particularly in the oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience~~contacts. Under these conditions, we could be unable to attract and retain these personnel. The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse effect on our business, operating results, financial condition and cash flows.

Our ~~operations~~success depends upon the continued contributions of our executive officers and key employees, particularly with respect to providing the critical management decisions and contacts necessary to manage and maintain growth within a highly competitive industry. Competition for qualified personnel can be intense, particularly in ~~Israel~~the ~~may~~oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience. Under these conditions, we could be ~~adversely~~unable ~~affected~~to byattract ~~unique~~and ~~economic~~retain these personnel. The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse effect on our business, ~~terrorist~~operating ~~activities~~results, financial condition and ~~political~~cash ~~developments~~flows.

WeOur ~~have~~operations ~~interests~~ in ~~oil and gas leases and in oil and gas licenses in the waters off~~ Israel. ~~These interests are a significant portion of our future production and cash flow and~~ may be adversely affected by ~~terrorist~~unique ~~activities~~economic, ~~political~~terrorist activities and ~~economic~~political developments~~, including the following:~~.

●We ~~war,~~have ~~terrorist~~interests ~~acts~~in oil and ~~civil~~gas ~~disturbances,~~leases and ~~other~~in oil and gas licenses in the waters off Israel. These interests are a significant portion of our future production and cash flow and may be adversely affected by terrorist activities, political ~~risks;~~and economic developments, including the following:

● ~~changes~~war, interrorist ~~taxation~~acts ~~policies~~and civil disturbances, and other political risks;

● ~~laws~~changes ~~and~~in ~~policies of the US and Israel affecting foreign investment,~~ taxation, ~~trade and business conduct~~policies;

● laws and policies of the US and Israel affecting foreign ~~exchange~~investment, ~~restrictions~~taxation, trade and business conduct;

● ~~international~~foreign ~~monetary~~exchange ~~fluctuations and changes in the value of the US dollar, such as the decline of the US dollar~~restrictions; ~~and~~

● ~~other~~international ~~hazards~~monetary ~~arising~~fluctuations ~~out~~and ofchanges ~~Israeli~~in ~~governmental~~the ~~sovereignty~~value ~~over~~of ~~areas~~the inUS ~~which~~dollar, wesuch ~~own~~as ~~oil~~the ~~and~~decline ~~gas~~of ~~interests.~~the US dollar; and

~~Oilfield~~● ~~service~~other ishazards aarising ~~highly~~out ~~competitive,~~of ~~fragmented~~Israeli ~~industry~~governmental sovereignty over areas in which ~~price~~we ~~competition~~own ~~could~~oil ~~reduce~~and ~~our~~gas ~~profitability~~interests.

WeOilfield ~~encounter substantial competition from other oilfield~~ service ~~companies.~~is ~~Our~~a ~~primary market areas are~~ highly ~~fragmented and~~ competitive., ~~The~~fragmented ~~fact that production services equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the~~ industry ~~and may result~~ in anwhich ~~oversupply~~price ~~of equipment in an area. Oilfield service companies compete primarily on a regional basis, and the intensity of~~ competition may vary significantly from region to region at any particular time. If demand for drilling or production services improves in a region where we operate, our competitors might respond by moving in suitable rigs and production services equipment from other regions. An influx of equipment from other regions could ~~rapidly intensify competition,~~ reduce ~~profitability~~our ~~and make any improvement in demand for production services short-lived~~profitability.

~~Most~~We encounter substantial competition from other oilfield service companies. Our primary market areas are highly fragmented and competitive. The fact that production services ~~contracts~~equipment are ~~awarded~~mobile onand ~~the~~can ~~basis~~be ofmoved ~~competitive~~from ~~bids,~~one ~~which~~market ~~also~~to ~~results~~another in ~~price~~response ~~competition.~~to Inmarket ~~addition~~conditions toheightens ~~pricing~~the competition in the industry and may result in an oversupply of equipment ~~availability,~~in wean ~~believe~~area. Oilfield service companies compete primarily on a regional basis, and the ~~following~~intensity ~~factors~~of ~~are~~competition ~~also~~may ~~important~~vary significantly from region to region at any particular time. If demand for drilling or production services improves in a region where we operate, our ~~clients~~competitors might respond by moving in ~~determining~~suitable ~~which~~rigs and production services ~~provider~~equipment tofrom ~~select:~~other regions. An influx of equipment from other regions could rapidly intensify competition, reduce profitability and make any improvement in demand for production services short-lived.

●Most production services contracts are awarded on the ~~type~~basis of competitive bids, which also results in price competition. In addition to pricing and ~~condition~~equipment ofavailability, ~~each~~we ofbelieve the ~~competing~~following factors are also important to our clients in determining which production ~~servicing~~services ~~rigs;~~provider to select:

● the ~~quality~~type ofand ~~service~~condition ~~and~~of ~~experience~~each of the ~~crews~~competing production servicing rigs;

● the ~~safety~~quality ~~record~~ of ~~the~~service ~~company~~and ~~providing~~experience of the ~~services~~crews; ~~and~~

● the ~~offering~~safety record of ~~ancillary~~the company providing the services.; and

We● ~~could~~the beoffering ~~adversely affected if shortages~~ of ~~equipment,~~ancillary ~~supplies or personnel occur~~services.

~~From~~We ~~time~~could tobe ~~time~~adversely ~~there~~affected ~~have~~if ~~been~~ shortages of ~~production services~~ equipment and supplies during periods of high demand which we believe could recur. Shortages could result in increased prices for production services equipment or supplies that we may be unable to pass on to clients. In addition, ~~during periods of shortages, the delivery times for equipment and~~ supplies ~~can be substantially longer. Any significant delays in our obtaining production services equipment~~ or ~~supplies~~personnel ~~could limit production services operations and jeopardize our relations with clients~~occur. In addition, shortages of production services equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

25From time to time there have been shortages of production services equipment and supplies during periods of high demand which we believe could recur. Shortages could result in increased prices for production services equipment or supplies that we may be unable to pass on to clients. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining production services equipment or supplies could limit production services operations and jeopardize our relations with clients. In addition, shortages of production services equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

~~Table of Contents~~25

~~Our~~Table ~~operations require the services~~ of employees having the technical training and experience necessary to achieve the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Shortages of qualified personnel have occurred in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. A significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material adverse effect on our financial condition and results of operations.Contents

~~There~~Our ~~are~~operations ~~limitations~~require the services of employees having the technical training and experience necessary to achieve the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Shortages of qualified personnel have occurred in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with ~~regard~~the requisite level of training and experience to ~~sales~~adequately operate our equipment, our operations could be materially and adversely affected. A significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of ~~Tamar~~either ~~Field~~of ~~Production~~these events for a significant period of time could have a material adverse effect on our financial condition and results of operations.

AsThere ~~noted~~are ~~above,~~limitations wewith ~~own~~regard an interest in the Tamar Field located offshore Israel. This interest in 2017 accounted for approximately 44% of our consolidated revenues and we expect the interest as a percentage of consolidated revenues to ~~increase~~sales ~~significantly if and when payout occurs. We note that the government~~ of ~~Israel allows the owners of~~ Tamar Field production to export fifty percent (50%) of the production that has not yet been committed to supply the Israel domestic market as of the date of the government’s decision in this regard. Accordingly, production from Tamar must first satisfy the minimum amount required to supply the Israeli economy. Production

IfAs ~~our~~noted ~~customers~~above, ~~delay~~we ~~paying~~own oran ~~fail~~interest toin ~~pay~~the aTamar ~~significant~~Field ~~amount~~located offshore Israel. This interest in 2018 accounted for approximately 38% of our ~~outstanding~~consolidated ~~receivables,~~revenues itand ~~could~~we ~~have~~expect the interest as a ~~material~~percentage ~~adverse~~of ~~effect~~consolidated onrevenues ~~our~~to ~~liquidity,~~increase ~~consolidated~~significantly ~~results~~if and when payout occurs. We note that the government of ~~operations~~Israel allows the owners of Tamar Field production to export fifty percent (50%) of the production that has not yet been committed to supply the Israel domestic market as of the date of the government’s decision in this regard. Accordingly, ~~and~~production ~~consolidated~~from ~~financial~~Tamar ~~condition~~must first satisfy the minimum amount required to supply the Israeli economy.

In most cases, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. In weak economic environments, we may experience increased delays and failures due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

WeIn most cases, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. In weak economic environments, we may beexperience ~~unable~~increased delays and failures due to, ~~implement~~among ~~price~~other ~~increases~~reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets. If our customers delay paying or ~~maintain~~fail ~~existing~~to ~~prices~~pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our ~~core~~liquidity, ~~services~~consolidated results of operations, and consolidated financial condition.

We ~~periodically~~may ~~seek~~be tounable ~~increase the prices of our services~~ to ~~offset~~implement ~~rising~~price ~~costs~~increases ~~and to generate higher returns for our stockholders. However, we operate in a very competitive industry and as a result, we are not always successful in raising,~~ or ~~maintaining~~maintain ~~our~~ existing prices. ~~Additionally, during periods of increased market demand, a significant amount of new service capacity, including new production services rigs may enter the market, which also puts pressure~~ on ~~the pricing of~~ our ~~services~~core ~~and limits our ability to increase or maintain prices. Furthermore, during periods of declining pricing for our~~ services~~, we may not be able to reduce our costs accordingly, which could further adversely affect our profitability~~.

~~Even~~We ~~when~~periodically weseek ~~are able~~ to increase ~~our~~the prices, weof ~~may~~our ~~not~~services ~~be able~~ to dooffset sorising atcosts aand ~~rate~~to ~~that~~generate ishigher ~~sufficient~~returns tofor ~~offset~~our ~~such~~stockholders. ~~rising~~However, ~~costs.~~we Inoperate ~~periods~~in ofa ~~high~~very ~~demand~~competitive ~~for~~industry ~~oilfield~~and ~~services,~~as a ~~tighter~~result, ~~labor~~we ~~market~~are ~~may~~not ~~result~~always successful in ~~higher~~raising, ~~labor~~or ~~costs.~~maintaining ~~During~~our ~~such~~existing ~~periods~~prices. Additionally, ~~our~~during ~~labor~~periods ~~costs~~of ~~could~~increased ~~increase~~market atdemand, a ~~greater~~significant ~~rate~~amount ~~than~~of ~~our~~new ~~ability~~service tocapacity, ~~raise~~including ~~prices~~new ~~for~~production ~~our~~ services. ~~Also,~~rigs we may ~~not~~enter bethe ~~able~~market, towhich ~~successfully~~also ~~increase~~puts ~~prices~~pressure ~~without~~on ~~adversely~~the ~~affecting~~pricing of our ~~activity~~services ~~levels.~~and ~~The~~limits ~~inability~~our ability to ~~maintain~~increase ~~our~~or maintain prices. orFurthermore, toduring ~~increase~~periods ~~our~~of ~~prices~~declining aspricing ~~costs~~for ~~increase~~our ~~could~~services, ~~have~~we amay ~~material~~not ~~adverse~~be ~~effect~~able onto reduce our ~~business~~costs accordingly, ~~financial~~which ~~position~~could ~~and~~further ~~results~~adversely ofaffect ~~operations~~our profitability.

AEven ~~member~~when ofwe ~~Isramco’s~~are ~~management~~able ~~team~~to ~~owns~~increase our prices, we may not be able to do so at a ~~significant~~rate ~~amount~~that is sufficient to offset such rising costs. In periods of ~~common~~high ~~stock~~demand for oilfield services, ~~giving~~a ~~him~~tighter ~~influence~~labor ormarket ~~control~~may result in ~~corporate~~higher ~~transactions~~labor ~~and~~costs. ~~other~~During ~~matters~~such periods, ~~and~~our ~~the~~labor ~~interests~~costs ofcould ~~these~~increase ~~individuals~~at a greater rate than our ability to raise prices for our services. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our prices or to increase our prices as costs increase could ~~differ~~have ~~from~~a ~~those~~material ~~other~~adverse ~~shareholders~~effect on our business, financial position and results of operations.

~~Haim~~A ~~Tsuff,~~member ~~the~~of ~~Company~~Isramco’s ~~President,~~management ~~Co-Chief~~team ~~Executive~~owns ~~Officer~~a ~~and~~significant ~~Chairman~~amount of ~~the Board of Directors, individually and through companies that he beneficially controls own over 73% of our outstanding shares of~~ common stock ~~as of March 12~~, ~~2018.~~giving Ashim ~~a result, Haim Tsuff is in a position to significantly~~ influence or control ~~the~~in ~~outcome~~corporate oftransactions ~~matters~~and ~~requiring~~other ~~a shareholder vote~~matters, ~~including~~and the ~~election~~interests of ~~directors,~~these ~~the~~individuals ~~adoption~~could ofdiffer anfrom ~~amendment~~those ~~to our certificate of incorporation or bylaws, and the approval of mergers and acquisitions, and~~ other ~~significant corporate transactions~~shareholders.

26Haim Tsuff, the Company’s President, Co-Chief Executive Officer and Chairman of the Board of Directors, individually and through companies that he beneficially controls own over 73% of our outstanding shares of common stock as of March 18, 2019. As a result, Haim Tsuff is in a position to significantly influence or control the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of an amendment to our certificate of incorporation or bylaws, and the approval of mergers and acquisitions, and other significant corporate transactions.

~~Table~~Our stock price is volatile, could continue to be volatile and has limited liquidity; Accordingly, investors may not be able to sell any significant number of ~~Contents~~shares of our stock at prevailing market prices.

~~Our~~Investor interest in our common stock may not lead to the development of an active or liquid trading market. The market price of our common stock has fluctuated in the past and is ~~volatile,~~likely ~~could~~to continue to be volatile and ~~has~~subject ~~limited~~to ~~liquidity;~~wide ~~Accordingly~~fluctuations. In addition, ~~investors~~the stock market has experienced extreme price and volume fluctuations. The stock prices and trading volumes for our stock has fluctuated widely and the average daily trading volume of our stock continues to be limited and may ~~not~~continue for reasons that may be ~~able~~unrelated to ~~sell~~business ~~any~~or ~~significant~~results ~~number~~of operations. General economic, market and political conditions could also materially and adversely affect the market price of our common stock and investors may be unable to resell their shares of ~~our~~common stock at ~~prevailing~~or above their purchase price. As a result of the limited trading in our stock, it may be difficult for investors to sell their shares in the public market at any given time at prevailing prices.

Investor interest in our common stock may not lead to the development of an active or liquid trading market. The market price of our common stock has fluctuated in the past and is likely to continue to be volatile and subject to wide fluctuations. In addition, the stock market has experienced extreme price and volume fluctuations. The stock prices and trading volumes for our stock has fluctuated widely and the average daily trading volume of our stock continues to be limited and may continue for reasons that may be unrelated to business or results of operations. General economic, market and political conditions could also materially and adversely affect the market price of our common stock and investors may be unable to resell their shares of common stock at or above their purchase price. As a result of the limited trading in our stock, it may be difficult for investors to sell their shares in the public market at any given time at prevailing prices.26

WeTable ~~have not paid dividends on our common stock and do not plan to declare dividends in the foreseeable future, and therefore only appreciation~~ of ~~the price of our common stock will provide a return to our shareholders.~~Contents

We have not paid ~~or declared any~~ dividends on our common stock and ~~currently~~do ~~intend~~not toplan ~~retain any earnings~~ to ~~fund~~declare ~~our~~dividends ~~working~~in ~~capital~~the ~~needs~~foreseeable future, ~~reduce debt~~ and ~~fund~~therefore ~~growth~~only ~~opportunities.~~appreciation ~~Any~~of ~~future dividends will be at~~ the ~~discretion~~price of our ~~board~~common ofstock ~~directors~~will ~~after~~provide ~~taking~~a ~~into~~return ~~account~~to ~~various factors it deems relevant, including~~ our ~~financial condition and performance, cash needs, income tax consequences and restrictions imposed by the Texas Business Organizations Code and other applicable laws~~shareholders.

~~The~~We ~~Company~~have ~~could~~not paid or declared any dividends on our common stock and currently intend to retain any earnings to fund our working capital needs, reduce debt and fund growth opportunities. Any future dividends will be ~~impacted~~at bythe ~~unfavorable~~discretion ~~results~~of our board of ~~legal~~directors ~~proceedings~~after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and restrictions imposed by the Texas Business Organizations Code and other applicable laws.

The Company iscould subject to various legal proceedings, disputes and claims that have not yet been fully resolved, and additional disputes and claims may arise in the future. Results of legal proceedings are subject to significant uncertainty and, regardless of the merit of the claims, these legal proceedings may be ~~expensive,~~impacted time-consuming, and disruptive to the Company’s operations and management. The Company may enter into arrangements to settle legal proceedings and other disputes in an attempt to mitigate against the foregoing risks. However, the Company cannot guarantee a favorable result with respect to any resolution of a legal proceeding, whether by ~~settlement~~unfavorable orresults ~~otherwise. If one or more~~ of ~~these~~ legal proceedings were resolved against the Company in a reporting period for amounts in excess of the Company’s expectations, such resolution could result in a material adverse effect on our business, financial position and results of operations.

~~ITEM~~The 1BCompany is subject to various legal proceedings, disputes and claims that have not yet been fully resolved, and additional disputes and claims may arise in the future. ~~UNRESOLVED~~Results ~~STAFF~~of ~~COMMENTS~~legal proceedings are subject to significant uncertainty and, regardless of the merit of the claims, these legal proceedings may be expensive, time-consuming, and disruptive to the Company’s operations and management. The Company may enter into arrangements to settle legal proceedings and other disputes in an attempt to mitigate against the foregoing risks. However, the Company cannot guarantee a favorable result with respect to any resolution of a legal proceeding, whether by settlement or otherwise. If one or more of these legal proceedings were resolved against the Company in a reporting period for amounts in excess of the Company’s expectations, such resolution could result in a material adverse effect on our business, financial position and results of operations.

~~None~~Uncertainty about the future of the London Interbank Offer Rate (LIBOR) may adversely affect our business and financial results.

~~ITEM~~LIBOR 2meaningfully influences market interest rates around the globe. ~~PROPERTIES~~In July 2017, the Chief Executive of the United Kingdom Financial Conduct Authority, which regulates LIBOR, announced its intent to stop persuading or compelling banks to submit rates for the calculation of LIBOR to the administrator of LIBOR after 2021. This announcement indicates that the continuation of LIBOR as currently constructed is not guaranteed after 2021. It is impossible to predict whether and to what extent banks will continue to provide LIBOR submissions to the administrator of LIBOR, whether any additional reforms to LIBOR may be enacted in the United Kingdom or elsewhere, and whether other rate or rates may become accepted alternatives to LIBOR.

~~Oil~~In 2014, the FRB and ~~Gas~~the ~~Exploration~~Federal Reserve Bank of New York convened the Alternative Reference Rates Committee (ARRC) to identify best practices for alternative reference rates, identify best practices for contract robustness, develop an adoption plan, and ~~Production~~create -an ~~Properties~~implementation plan with metrics of success and ~~Reserves~~a timeline. The ARRC accomplished its first set of objectives and has identified the Secured Overnight Financing Rate (SOFR) as the rate that represents best practice for use in certain new U.S. dollar derivatives and other financial contracts. The ARRC also published its Paced Transition Plan, with specific steps and timelines designed to encourage adoption of the SOFR. The ARRC was reconstituted in 2018 to help to ensure the successful implementation of the Paced Transition Plan and serve as a forum to coordinate and track planning across cash and derivatives products and market participants currently using LIBOR.

WeNo ~~own~~assurance ~~varying~~can ~~working~~be ~~interests~~provided inthat oil and gas wells in Louisiana, Texas, New Mexico, Oklahoma, Wyoming, Utah and Colorado. We currently serve as operator of approximately 422 producing wells most of which are located in Texas and New Mexico. Moreover, we own interests in properties operated by third party entities. In many instances, the ~~Company~~uncertainties ~~does~~around ~~not~~LIBOR ~~have, nor is it entitled to, information pertaining to certain matters such as (i) whether shut-in~~ or ~~temporarily~~their ~~abandoned~~resolution ~~wells~~will ~~operated~~not byadversely ~~these~~affect ~~third~~the ~~parties are mechanically capable of production~~use, ~~(ii) whether third party operators have obtained leases in which the Company would be contractually entitled to participate (being undeveloped acreage)~~level, and, involatility ~~some~~of ~~instances~~LIBOR or ~~(iii)~~other ~~the~~interest ~~gross~~rates ~~and~~or ~~net acreage maintained in~~ the ~~leases~~value ~~included~~of inLIBOR-based ~~the~~securities ~~contract~~or ~~area~~other ~~under~~securities ~~the~~or ~~operative~~financial ~~joint operating agreements~~arrangements. ~~Due~~Further, to the ~~nature~~viability of ~~some~~SOFR ~~third~~as ~~party~~an ~~operations~~alternative ~~(e.g.,~~reference ~~field~~rate ~~wide~~and ~~units), to~~ the ~~Company~~availability ~~cannot~~and ~~ascertain~~acceptance ~~the total number~~ of ~~wells~~other ~~drilled~~alternative ~~within~~reference arates ~~particular~~are ~~project~~unclear ~~area~~ and ~~whether~~also ~~each~~may ~~well~~have ~~within~~adverse ~~such~~effects ~~project~~on ~~area~~market isrates ~~productive. In some instances, third parties operate properties (e.g. field wide units and leases covering a large amount~~ of ~~acreage)~~interest ~~where production, revenue~~ and ~~expenses for~~ the ~~property~~value ~~are~~of ~~aggregated~~securities and ~~reported~~other asfinancial ~~a single property~~arrangements. ~~Accordingly~~These uncertainties, ~~well~~proposals ~~information~~and ~~with~~actions ~~regard~~ to ~~such~~resolve ~~properties is not always available to Isramco. In addition~~them, ~~most of the Company’s operated wells are legacy assets~~ and, ~~accordingly,~~their ~~were~~ultimate ~~drilled~~resolution ~~and~~also ~~operated~~could ~~for~~negatively ~~several~~impact ~~years by~~ our ~~predecessors~~funding ~~in title. Therefore~~costs, atloan ~~this time, the Company is conducting a review of the terms~~ and ~~conditions~~other ofasset ~~each~~values, ~~lease covering our operated assets to determine the acreage held by the underlying oil and gas leases and the Company is also examining shut~~asset-inliability ~~wells~~management ~~to ascertain whether these wells are mechanically capable of production in their current state. Moreover~~strategies, weand ~~are~~other ~~working~~aspects ~~with the operators~~ of our ~~non-operated~~business ~~assets~~and tofinancial ~~obtain similar information with regard to such properties~~results. ~~The Company expects to complete this review in the near future. Currently, we do not own any interest in undeveloped acreage.~~

27ITEM 1B. UNRESOLVED STAFF COMMENTS

~~Table of Contents~~None.

~~Drilling Activities~~27

~~During~~Table ~~the~~of ~~year ended December 31, 2015 we drilled and completed two development wells in North Texas. No new wells were drilled in 2017 or 2016.~~Contents

~~Reserve~~ITEM ~~Information~~2. ~~For estimates of Isramco’s net proved reserves of natural gas, crude oil and natural gas liquids, see Note 13 to Consolidated Financial Statements, “Supplemental Oil and Gas Information”.~~PROPERTIES

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Note 13 to Consolidated Financial Statements, “Supplemental Oil and Gas ~~Information”,~~Exploration ~~represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas, crude oil~~ and ~~condensate~~Production ~~and~~- ~~natural~~Properties ~~gas liquids that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount~~ and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. For related discussion, see ITEM 1A. Risk Factors.Reserves

We ~~believe~~own ~~that~~varying working interests in oil and gas wells in Louisiana, Texas, New Mexico, Oklahoma, Wyoming, Utah and Colorado. We currently serve as operator of approximately 422 producing wells most of which are located in Texas and New Mexico. Moreover, we own interests in properties operated by third party entities. In many instances, the Company does not have, ~~satisfactory~~nor ~~title~~is it entitled to, information pertaining to certain matters such as (i) whether shut-in or temporarily abandoned wells operated by these third parties are mechanically capable of production, (ii) whether third party operators have obtained leases in which the ~~properties~~Company ~~owned~~would be contractually entitled to participate (being undeveloped acreage), and, ~~used~~in some instances or (iii) the gross and net acreage maintained in ~~our~~the ~~business,~~leases ~~subject~~included in the contract area under the operative joint operating agreements. Due to ~~liens~~the ~~for~~nature ~~taxes~~of ~~not~~some ~~yet~~third ~~payable~~party operations (e.g., ~~liens~~field ~~incident~~wide units), to ~~minor~~the ~~encumbrances~~Company cannot ascertain the total number of wells drilled within a particular project area and whether each well within such project area is productive. In some instances, ~~liens~~third ~~for~~parties ~~credit~~operate ~~arrangements~~properties (e.g. field wide units and ~~easements~~leases covering a large amount of acreage) where production, revenue and ~~restrictions~~expenses ~~that~~for dothe property are aggregated and reported as a single property. Accordingly, well information with regard to such properties is not ~~materially~~always ~~detract~~available ~~from~~to ~~the~~Isramco. ~~value~~In addition, most of ~~these~~the ~~properties~~Company’s operated wells are legacy assets and, accordingly, were drilled and operated for several years by our ~~interests~~predecessors in ~~these~~title. ~~properties~~Therefore, orat this time, the ~~use~~Company is conducting a review of the terms and conditions of each lease covering our operated assets to determine the acreage held by the underlying oil and gas leases and the Company is also examining shut-in wells to ascertain whether these ~~properties~~wells are mechanically capable of production in ~~our~~their ~~business~~current state. WeMoreover, ~~believe~~we ~~that~~are working with the operators of our ~~properties~~non-operated ~~are~~assets ~~adequate~~to ~~and~~obtain ~~suitable~~similar ~~for~~information uswith regard to ~~conduct~~such ~~business~~properties. The Company expects to complete this review in the near future. Currently, we do not own any interest in undeveloped acreage.

~~Controls~~Drilling ~~Over Reserve Estimates~~Activities

~~The~~During ~~Company’s policies and practices regarding internal controls over~~ the ~~recording~~year ofended ~~reserves~~December ~~are~~31, ~~structured~~2015, towe ~~objectively~~drilled and ~~accurately~~completed ~~estimate~~two ~~our~~development ~~oil~~wells ~~and gas reserves quantities and present values~~ in ~~compliance~~North ~~with the SEC’s regulations and GAAP~~Texas. ~~The~~No ~~Company~~new ~~relies~~wells onwere ~~third~~drilled ~~party~~in ~~professionals to integrate geological~~2018, ~~geophysical~~2017, ~~engineering~~or ~~and economic data to produce the Company’s reserve reports, which are utilized for its filings with the Commission~~2016. ~~Our internal controls over reserves estimates include the following:~~

~~• A~~Reserve ~~reserve~~Information. ~~report~~For ~~covering~~estimates ~~100%~~ of ~~our~~Isramco’s net proved reserves inof ~~the~~natural ~~United~~gas, ~~States~~crude isoil ~~prepared~~and bynatural ~~Cawley,~~gas ~~Gillespie and Associates~~liquids, ~~Inc.,~~see aNote ~~third-party~~14 ~~petroleum~~to ~~consulting~~Consolidated ~~firm~~Financial Statements, on“Supplemental anOil ~~annual~~and ~~basis;~~Gas Information”.

~~• A~~There ~~reserve~~are ~~report~~numerous ~~covering~~uncertainties ~~100%~~inherent in estimating quantities of ~~our~~proved ~~interests~~reserves and in ~~Israel~~projecting isfuture ~~prepared~~rates byof ~~Netherland,~~production ~~Sewell~~and &timing ~~Associates~~of development expenditures, ~~Inc~~including many factors beyond the control of the producer. (The reserve data set forth in Note 14 to Consolidated Financial Statements, “~~NSAI~~Supplemental Oil and Gas Information”), represent only estimates. Reserve engineering is a ~~third-party~~subjective ~~petroleum~~process ~~consulting~~of ~~firm~~estimating underground accumulations of natural gas, oncrude oil and condensate and natural gas liquids that cannot be measured in an ~~annual~~exact ~~basis;~~manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. For related discussion, see ITEM 1A. Risk Factors.

~~• Senior~~We ~~Management~~believe ofthat we have satisfactory title to the ~~Company~~properties ~~reviews~~owned and ~~examines~~used ~~the~~in ~~reserve~~our ~~reports~~business, ~~generated~~subject byto ~~third~~liens ~~parties~~for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and ~~conducts~~easements anand ~~internal~~restrictions ~~evaluation~~that do not materially detract from the value of these properties, our interests in these properties, or the ~~assumptions~~use ~~underlying~~of ~~material~~these ~~changes~~properties in our business. We believe that our properties are adequate and suitable for us to ~~reserves~~conduct onbusiness anin ~~annual~~the ~~basis~~future.

~~The~~Controls ~~reserves~~Over ~~estimates~~Reserve shown for our U.S. properties have been independently evaluated by Cawley, Gillespie and Associates, Inc. The technical person at Cawley, Gillespie and Associates primarily responsible for preparing the estimates set forth in the reserves report incorporated herein is Mr. Todd Brooker, President. Mr. Brooker joined CG&A in October 1992 as a reservoir engineer. His responsibilities include reserves and economics evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. He is currently President of the firm and has managed the Austin office since its opening in 2002. Prior to joining CG&A, Todd worked in Gulf of Mexico drilling and production engineering at Chevron USA in New Orleans, Louisiana. He graduated Magna Cum Laude from the University of Texas at Austin in 1989 with a BS degree in Petroleum Engineering, and is a registered professional engineer in Texas.Estimates

28The Company’s policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and GAAP. The Company relies on third party professionals to integrate geological, geophysical, engineering and economic data to produce the Company’s reserve reports, which are utilized for its filings with the Commission. Our internal controls over reserves estimates include the following:

~~Table~~• A reserve report covering 100% of ~~Contents~~our proved reserves in the United States is prepared by Cawley, Gillespie and Associates, Inc., a third-party petroleum consulting firm, on an annual basis;

~~The~~• A ~~reserves~~reserve ~~estimates~~report ~~shown~~covering ~~for~~100% ~~overriding~~of ~~royalty~~our ~~interest~~interests in ~~the~~Israel ~~Tamar~~is ~~field~~prepared ~~have been independently evaluated~~ by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. Fthird-~~2699.~~party Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Richard B. Talley, Jr. and Mr. Zachary R. Long. Mr. Talley, a Licensed Professional Engineer in the State of Texas (No. 102425), has been practicing consulting petroleum engineering at NSAI since 2004 and has over 5 years of prior industry experience. He graduated from University of Oklahoma in 1998 with a Bachelor of Science Degree in Mechanical Engineering and from Tulane University in 2001 with a Master of Business Administration Degree. Mr. Long, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 11792), has been practicing consulting petroleum geoscience at NSAI since 2007 and has over 2 years of prior industry experience. He graduated from University of Louisiana at Lafayette in 2003 with a Bachelor of Science Degree in Geology and from Texas A&M University in 2005 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the educationfirm, ~~training,~~on ~~and~~an ~~experience~~annual ~~requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers~~basis; ~~both are proficient in judiciously applying industry standard practices to engineering~~ and ~~geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.~~

~~ITEM~~• Senior 3.Management ~~LEGAL~~of ~~PROCEEDINGS~~the Company reviews and examines the reserve reports generated by third parties and conducts an internal evaluation of the assumptions underlying material changes to reserves on an annual basis.

On or about September 21, 2011, the Company’s former Vice President and General Counsel, Dennis Holifield resigned. Mr. Holifield had been hired in March 2011. On or about October 12, 2011, Mr. Holifield submitted a “Summary Report” to the SEC (the “Summary Report”), in which made numerous factual allegations regarding Haim Tsuff, the Company’s Chief Executive Officer, Chairman, and President; Edy Francis, the Company’s Chief Financial Officer; Amir Sanker, the Company’s Asset Manager; and other Company personnel. In the Summary Report, Mr. Holifield characterized the alleged conduct as illegal or criminal. On November 3, 2011, the Company’s Board of Directors constituted a committee of independent directors consisting of Max Pridgeon and Asaf Yarkoni, referred to as the Special Investigative Committee of the Board of Directors (“SIC”) which was directed to investigate all of the Holifield allegations and report back to the full board and make any recommendations, if any, for corrective action. On January 7, 2013, SIC made their final report to the Board of Directors of the conclusions and results of the fourteen-month investigation into the allegations made by Mr. Holifield. The SIC determined that Mr. Holifield’s allegations were not supported by any available documentary evidence or by any statements made by former or current Isramco, Inc., directors, management, or employees interviewed by the SIC or its counsel. The SIC also determined that the Company had not engaged in wrongdoing of any sort including any unlawful or unethical business practices, any lapses in financial controls, or any governance issues that require redress or reform.28

OnTable ~~September 10, 2013, the Company filed suit against Mr. Holifield in Cause No. 201352927~~ of the 270th Judicial District Court of Harris County, Texas, to collect damages estimated in the amount of $1,000,000.00 owing to the Company by virtue of Mr. Holifield’s actions, which are alleged in the suit to include, but are not limited to, negligence, negligence per se, gross negligence, and breach of fiduciary duty owed to the Company. In response, in December 2013, Mr. Holifield filed a pro se answer which included counterclaims and a summary judgment motion. In his counterclaims. Mr. Holifield seeks to recover from the Company the following damages, inter alia: (i) over $2,000,000 for loss of income and failure to secure gainful employment arising from his constructive discharge or termination by the Company; (ii) over $2,000,000 for loss of earnings due to his alleged inability to obtain gainful employment by virtue of the damage caused to his professional reputation by alleged willful and deliberate acts of Haim Tsuff, Edy Francis, and Amir Sanker, (iii) over $2,000,000 due to the intentional infliction of emotional distress to Mr. Holifield; (iv) an amount estimated at $5,000,000 arising from Mr. Holifield’s claim that the Company violated the Racketeer Influenced Corrupt Organizations Act, by engaging in racketeering and conspiracy; (v) over $5,000,000 arising from the Company’s alleged fraudulent misrepresentation regarding Isramco’s purpose in hiring Mr. Holifield and (vi) other relief. The Company believes Mr. Holifield’s counter claims have no merit.Contents

~~Pursuant~~The toreserves aestimates ~~settlement~~shown ~~between~~for ~~the~~our ~~Company~~U.S. properties have been independently evaluated by Cawley, Gillespie and MrAssociates, Inc. ~~Holifield,~~The ~~the~~technical ~~parties~~person ~~agreed~~at toCawley, ~~release~~Gillespie and ~~dismiss~~Associates ~~all~~primarily ~~claims~~responsible ~~against~~for preparing the ~~other~~estimates set forth in the ~~above~~reserves ~~litigation,~~report ~~and~~incorporated toherein ~~file~~is aMr. ~~Joint~~Todd ~~Notice~~Brooker, ofPresident. ~~Nonsuit~~Mr. ~~with~~Brooker ~~Prejudice~~joined ~~with~~CG&A ~~the~~in ~~Court~~October ~~(the~~1992 ~~“Joint~~as ~~Notice”)~~a reservoir engineer. OnHis ~~October~~responsibilities 30include reserves and economics evaluations, ~~2017~~fair market valuations, infield ~~response~~studies, topipeline ~~the~~resource ~~Joint~~studies ~~Notice,~~and ~~the~~acquisition/divestiture ~~Court~~analysis. ~~entered~~His anreserve ~~order~~reports ~~dismissing~~are ~~all~~routinely ~~claims~~used ~~between~~for ~~the~~public ~~parties~~company ~~with~~SEC ~~prejudice~~disclosures. ~~Accordingly,~~His ~~the~~experience ~~lawsuit~~includes ~~between~~significant ~~Isramco~~projects in both conventional and ~~its~~unconventional ~~former~~resources ~~general~~in ~~counsel~~every major U.S. producing basin and abroad, ~~Dennis~~including ~~Holifield~~oil and gas shale plays, ~~has~~coalbed ~~settled.~~methane ~~After~~fields, Mrwaterfloods and complex, faulted structures. ~~Holifield~~He ~~reviewed~~is currently President of the ~~evidence,~~firm heand ~~came~~has tomanaged the ~~conclusion~~Austin ~~that~~office ~~there~~since isits noopening ~~basis~~in ~~for~~2002. ~~his~~Prior ~~accusations~~to ~~against~~joining ~~Isramco~~CG&A, ~~its~~Todd ~~directors,~~worked ~~its~~in ~~officers,~~Gulf of Mexico drilling and ~~its~~production ~~employees.~~engineering Mrat Chevron USA in New Orleans, Louisiana. ~~Holifield~~He ~~regrets~~graduated ~~any~~Magna ~~harm~~Cum ~~caused~~Laude tofrom ~~Isramco,~~the ~~Haim~~University ~~Tsuff,~~of ~~Edy~~Texas ~~Francis~~at Austin in 1989 with a BS degree in Petroleum Engineering, and ~~Amir~~is ~~Sanker~~a registered professional engineer in Texas.

29The reserves estimates shown for overriding royalty interest in the Tamar field have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Richard B. Talley, Jr. and Mr. Zachary R. Long. Mr. Talley, a Licensed Professional Engineer in the State of Texas (No. 102425), has been practicing consulting petroleum engineering at NSAI since 2004 and has over 5 years of prior industry experience. He graduated from University of Oklahoma in 1998 with a Bachelor of Science Degree in Mechanical Engineering and from Tulane University in 2001 with a Master of Business Administration Degree. Mr. Long, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 11792), has been practicing consulting petroleum geoscience at NSAI since 2007 and has over 2 years of prior industry experience. He graduated from University of Louisiana at Lafayette in 2003 with a Bachelor of Science Degree in Geology and from Texas A&M University in 2005 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

~~Table~~ITEM of3. ~~Contents~~LEGAL PROCEEDINGS

As noted above, the Company owns an overriding royalty interest of 1.5375% in the Tamar Field, which will increase to 2.7375% after payout (the “Tamar Royalty”). With regard to the payout of the Tamar Field, a disagreement between the Company and Isramco Negev 2 Limited Partnership has emerged as to what costs should be included in the calculation of payout. In addition to actual costs for the development of the Tamar Field, Isramco, Negev 2 Limited Partnership has asserted that the following costs should be included in the calculation of payout: (i) Isramco Negev 2 Limited Partnership’s financing costs; (ii) the general and administrative expenses of Isramco Negev 2 Limited Partnership; (iii) the expected decommissioning costs of the Tamar Field; and (iv) expected future payments to be made in respect of the “Sheshinsky Levy” under Israeli law. The disagreement primarily stems from the fact that the agreements governing the creation of the Tamar Royalty were formulated in the 1980s and do not have a clear and unequivocal definition as to what costs should be included in the payout calculation. ~~The~~At ~~Company~~the ~~currently~~time ~~believes~~of initiating arbitration, the Company believed that the total scope of the disagreement iswas approximately forty-five million dollars ($45,000,000); however, this amount increases each month based on Isramco Negev 2 Limited Partnership’s failure to pay the increased, post-payout overriding royalty of 2.7375%. Under the terms of the agreements creating the Tamar Royalty, the dispute is subject to arbitration in Israel. The Company believes that the claims of Isramco Negev 2 Limited Partnership are erroneous and contrary to generally accepted industry practice. The Company expects that the matter will be favorably resolved through this arbitration process; however, the Company cannot be assured of a favorable result in this arbitration process. On February 26, 2017, Isramco Negev 2 Limited Partnership reported the dispute concerning the Tamar Royalty in its filing with the stock exchange in Israel. As noted above, this dispute will be resolved through arbitration proceedings. The Company and Isramco Negev 2-LP have arranged to conduct the arbitration through the Center for Arbitration and Dispute Resolution (CADR) in Israel and have agreed upon the appointment of retired judge Itzhak Inbar to preside over the proceeding. The preliminary arbitration hearing in the matter occurred on August 13, 2017. On February 25, 2018, the Company submitted as Statement of Claim outlining the Company’s position with regard to the matter. ~~Accordingly~~Currently, the case is ~~still~~ in its early stages with the parties expected to complete the discovery process in the coming months. The next hearing before the arbitrator is scheduled for April 14, 2019. The Company believes that its interpretation of the agreements governing the creation of the Tamar Royalty is the correct interpretation and, accordingly, intends to vigorously pursue its case in the aforementioned arbitration proceedings.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

3029

Table of Contents

PART II

Our common stock is listed on the NASDAQ Capital Market under the symbol “ISRL”. The following table sets forth for the periods indicated, the reported high and low closing prices for our common stock. As of March 1218, ~~2018~~2019, there were approximately ~~139~~132 holders of record of our common stock.

	High		Low
2017
First Quarter	$	129.05	$	109.50
Second Quarter		120.10		101.75
Third Quarter		118.05		100.60
Fourth Quarter		124.90		104.65

We have never paid cash dividends on our common stock. We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future. Any future determination to pay dividends on common stock will be at the discretion of the board of directors and will be dependent upon then existing conditions, including other factors, as the board of directors deems relevant.

2016
First Quarter	$	88.11	$	72.43
Second Quarter		99.93		75.70
Third Quarter		85.00		78.00
Fourth Quarter		124.30		82.90

ITEM 6. SELECTED FINANCIAL DATA

WeThe ~~have~~table ~~never~~below ~~paid~~contains ~~cash~~selected ~~dividends~~consolidated onfinancial ~~our~~data ~~common~~derived ~~stock.~~from ~~We intend to retain earnings for use in the operation and expansion of~~ our ~~business~~Consolidated ~~and~~Financial ~~therefore~~Statements. doThe ~~not~~data ~~anticipate~~should ~~declaring~~be ~~cash~~read ~~dividends on our common stock~~ in ~~the~~conjunction ~~foreseeable~~with ~~future.~~“Management’s ~~Any~~Discussion ~~future~~and ~~determination~~Analysis toof ~~pay~~Financial ~~dividends~~Condition onand ~~common~~Results ~~stock will be at the discretion~~ of ~~the~~Operations” ~~board of directors~~ and ~~will~~our beConsolidated ~~dependent~~Financial ~~upon~~Statements ~~then~~and ~~existing~~the ~~conditions,~~related ~~including~~notes ~~other~~included ~~factors,~~elsewhere asin ~~the~~this ~~board of directors deems relevant~~report.

ITEM 6. SELECTED FINANCIAL DATA

	Year Ended December 31,
(thousands, except share and per share amounts)	2018		2017			2016		2015			2014
Revenues and Income (Loss)
Total Revenues		81,339		65,947			54,942		74,509			93,898
Net Income (Loss)		17,934		(24,310	)		6,745		(17,310	)		5,162
Per Share Data
Earnings (Loss) Per Share - Basic		6.60		(8.95	)		2.48		(6.37	)		1.90
Earnings (Loss) Per Share - Diluted		6.60		(8.95	)		2.48		(6.37	)		1.90
Cash Dividends Per Share		-		-			-		-			-
Year-End Stock Price Per Share		118.50		104.65			124.30		89.31			138.00
Weighted Average Shares Outstanding		2,717,648		2,717,648			2,717,648		2,717,648			2,717,648
Basic		2,717,648		2,717,648			2,717,648		2,717,648			2,717,648
Diluted		2,717,648		2,717,648			2,717,648		2,717,648			2,717,648
Total Assets		111,614		108,797			141,272		146,957			158,864
Long-term Obligations		78,365		99,039			116,289		124,567			92,674
Long-Term Debt & Long-Term Accrued Interest		56,193		77,369			95,441		104,252			72,628

The table below contains selected consolidated financial data derived from our Consolidated Financial Statements. The data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and the related notes included elsewhere in this report.30

	Year Ended December 31,
(thousands, except share and per share amounts)	2017			2016		2015			2014		2013
Revenues and Income (Loss)
Total Revenues		65,947			54,942		74,509			93,898		68,692
Net Income (Loss)		(24,310	)		6,745		(17,310	)		5,162		(6,710	)
Per Share Data
Earnings (Loss) Per Share - Basic		(8.95	)		2.48		(6.37	)		1.90		(2.47	)
Earnings (Loss) Per Share - Diluted		(8.95	)		2.48		(6.37	)		1.90		(2.47	)
Cash Dividends Per Share		-			-		-			-		-
Year-End Stock Price Per Share		104.65			124.30		89.31			138.00		127.05
Weighted Average Shares Outstanding		2,717,648			2,717,648		2,717,648			2,717,648		2,717,648
Basic		2,717,648			2,717,648		2,717,648			2,717,648		2,717,648
Diluted		2,717,648			2,717,648		2,717,648			2,717,648		2,717,648
Total Assets		108,797			141,272		146,957			158,864		157,913
Long-term Obligations		99,039			116,289		124,567			92,674		114,849
Long-Term Debt & Long-Term Accrued Interest		77,369			95,441		104,252			72,628		96,035

Table of Contents

31ITEM 7. MANAGEMENT DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Table~~THE ofFOLLOWING ~~Contents~~COMMENTARY SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES CONTAINED ELSEWHERE IN THIS FORM 10-K. THE DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS THAT INVOLVE RISKS AND UNCERTAINTIES. THESE STATEMENTS RELATE TO FUTURE EVENTS OR OUR FUTURE FINANCIAL PERFORMANCE. IN SOME CASES, YOU CAN IDENTIFY THESE FORWARD-LOOKING STATEMENTS BY TERMINOLOGY SUCH AS “MAY,” “WILL,” “SHOULD,” “EXPECT,” “PLAN,” “ANTICIPATE,” “BELIEVE,” “ESTIMATE,” “PREDICT,” “POTENTIAL,” “INTEND,” OR “CONTINUE,” AND SIMILAR EXPRESSIONS. THESE STATEMENTS ARE ONLY PREDICTIONS. OUR ACTUAL RESULTS MAY DIFFER MATERIALLY FROM THOSE ANTICIPATED IN THESE FORWARD-LOOKING STATEMENTS AS A RESULT OF A VARIETY OF FACTORS, INCLUDING, BUT NOT LIMITED TO, THOSE SET FORTH UNDER “RISK FACTORS” AND ELSEWHERE IN THIS FORM 10-K.

~~ITEM 7. MANAGEMENT DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~Overview

~~THE~~We ~~FOLLOWING~~are ~~COMMENTARY~~an ~~SHOULD~~independent BEoil ~~READ~~and INnatural ~~CONJUNCTION~~gas ~~WITH~~company ~~THE~~engaged ~~CONSOLIDATED~~in ~~FINANCIAL~~the ~~STATEMENTS~~exploration, ~~AND~~development, ~~RELATED~~and ~~NOTES~~production ~~CONTAINED~~of ~~ELSEWHERE~~oil INand ~~THIS~~natural ~~FORM~~gas ~~10-K~~properties located onshore in the United States and an owner of various royalty interests offshore Israel. ~~THE~~Our ~~DISCUSSION~~properties ~~CONTAINS~~are ~~FORWARD-LOOKING~~primarily ~~STATEMENTS~~located ~~THAT~~in ~~INVOLVE~~Texas, ~~RISKS~~New ~~AND~~Mexico ~~UNCERTAINTIES~~and Oklahoma. ~~THESE~~We ~~STATEMENTS~~act ~~RELATE~~as TOthe ~~FUTURE~~operator ~~EVENTS~~of ORmost ~~OUR~~of ~~FUTURE~~our ~~FINANCIAL~~U.S. ~~PERFORMANCE~~properties. INHistorically, ~~SOME~~we ~~CASES~~have grown through acquisitions, ~~YOU~~with ~~CAN~~a ~~IDENTIFY~~focus ~~THESE~~on ~~FORWARD-LOOKING~~properties ~~STATEMENTS~~within BYour ~~TERMINOLOGY~~core ~~SUCH~~operating ASareas ~~“MAY,”~~that ~~“WILL,”~~we ~~“SHOULD,”~~believe ~~“EXPECT,”~~have ~~“PLAN,”~~significant ~~“ANTICIPATE,”~~development ~~“BELIEVE,”~~and ~~“ESTIMATE,”~~exploration ~~“PREDICT,”~~opportunities ~~“POTENTIAL,”~~and ~~“INTEND,”~~where ORwe ~~“CONTINUE,”~~can ~~AND~~apply ~~SIMILAR~~our ~~EXPRESSIONS~~technical experience and economies of scale to increase production and proved reserves while lowering lease operating costs. ~~THESE~~In ~~STATEMENTS~~August, ~~ARE~~2011 ~~ONLY~~we ~~PREDICTIONS~~created a new production services subsidiary that began operations in October 2011. ~~OUR~~As ~~ACTUAL~~of ~~RESULTS~~December ~~MAY~~2018, ~~DIFFER~~the ~~MATERIALLY~~subsidiary ~~FROM~~had ~~THOSE~~33 ~~ANTICIPATED~~deployed INproduction ~~THESE~~services ~~FORWARD-LOOKING~~rigs ~~STATEMENTS~~and ASvarious Atrucks ~~RESULT~~that OFoperate Aprimarily ~~VARIETY~~in OFTexas ~~FACTORS,~~and ~~INCLUDING,~~New ~~BUT~~Mexico. ~~NOT~~The ~~LIMITED~~Company ~~TO,~~provides ~~THOSE~~a ~~SET~~full ~~FORTH~~range ~~UNDER~~of ~~“RISK~~production ~~FACTORS”~~services ~~AND~~such ~~ELSEWHERE~~as INwell ~~THIS~~completion ~~FORM~~and ~~10-K~~wellbore maintenance, workover, fluid transportation and plugging and abandonment services.

~~Overview~~Oil and Gas Exploration and Production Segment

WeOur financial results depend upon many factors, but are anlargely ~~independent~~driven by the volume of our oil and natural gas ~~company~~production ~~engaged~~and in the ~~exploration,~~price ~~development,~~that ~~and~~we receive for that production. ofOur ~~oil~~production ~~and~~volumes ~~natural~~will ~~gas~~decline ~~properties~~as ~~located~~reserves ~~onshore~~are indepleted ~~the~~unless ~~United~~we ~~States~~expend capital in successful development and anexploration ~~owner~~activities ofor ~~various~~acquire ~~royalty~~additional ~~interests~~properties ~~offshore~~with ~~Israel~~existing production. ~~Our~~The ~~properties~~amount ~~are~~we ~~primarily~~realize ~~located~~for inour ~~Texas~~production depends predominantly upon commodity prices, ~~New~~which ~~Mexico~~are ~~and~~affected ~~Oklahoma.~~by Wechanges ~~act~~in asmarket ~~the~~demand ~~operator~~and ofsupply, ~~most~~as ofimpacted ~~our~~by ~~U.S.~~overall ~~properties.~~economic ~~Historically~~activity, weweather, ~~have~~pipeline ~~grown~~capacity ~~through acquisitions~~constraints, ~~with~~inventory astorage ~~focus~~levels, onquality, ~~properties~~basis ~~within~~differentials ~~our~~and ~~core~~other ~~operating~~factors, ~~areas~~and ~~that~~secondarily weupon ~~believe~~our ~~have~~commodity ~~significant~~price ~~development~~hedging ~~and~~activities. ~~exploration~~Accordingly, ~~opportunities~~finding and ~~where~~developing weoil ~~can~~and ~~apply~~natural ~~our~~gas ~~technical~~reserves ~~experience~~at ~~and~~economical ~~economies~~costs ofis ~~scale~~critical to ~~increase~~our ~~production~~long-term ~~and~~success. ~~proved~~Our ~~reserves~~future ~~while~~drilling ~~lowering~~plans ~~lease~~are ~~operating~~subject ~~costs.~~to Inchange ~~August,~~based ~~2011~~upon wevarious ~~created~~factors, asome ~~new~~of ~~production~~which ~~services~~are ~~subsidiary~~beyond ~~that~~our ~~began~~control, ~~operations~~including indrilling ~~October~~results, ~~2011.~~oil Asand ofnatural ~~December~~gas ~~2017~~prices, the ~~subsidiary~~availability ~~had~~and 33cost ~~deployed~~of capital, drilling and production ~~services~~costs, ~~rigs~~availability of drilling services and ~~various~~equipment, ~~trucks~~gathering ~~that~~system ~~operate~~and ~~primarily~~pipeline intransportation ~~Texas~~constraints and ~~New~~regulatory ~~Mexico~~approvals. ~~The~~To ~~Company~~the ~~provides~~extent athese ~~full~~factors ~~range~~lead ofto ~~production~~reductions ~~services~~in ~~such~~our asdrilling ~~well~~plans ~~completion~~ and ~~wellbore~~associated ~~maintenance~~capital budgets in future periods, ~~workover~~our financial position, ~~fluid~~cash ~~transportation~~flows and ~~plugging~~operating ~~and~~results ~~abandonment~~could ~~services~~be adversely impacted.

~~Oil~~We own all ownership units in Tamar Royalties, LLC, which owns an overriding royalty interest of 1.5375% before payout which escalates to 2.7375% after payout in the Tamar Field (collectively the “Tamar Royalty”). An overriding royalty interest is an ownership interest in the oil and ~~Gas~~gas ~~Exploration~~leasehold estate equating to a certain percentage of production or production revenues, calculated free of the costs of production and ~~Production~~development ~~Segment~~of the underlying lease(s), but subject to its proportionate share of certain post production costs. An overriding royalty interest is a non-possessory interest in the oil and gas leasehold estate and, accordingly, we have no control over the operations, drilling, expenses, timing, production, sales, or any other aspect of development or production of the Tamar Field.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire additional properties with existing production. The ~~amount~~Tamar weField ~~realize~~project ~~for~~began ~~our~~ production ~~depends predominantly upon commodity prices, which are affected by changes~~ in ~~market~~March ~~demand~~2013 and ~~supply,~~is asnow ~~impacted~~operational ~~by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, quality, basis differentials~~ and ~~other~~delivering ~~factors, and secondarily upon our commodity price hedging activities. Accordingly, finding and developing oil and~~ natural gas ~~reserves at economical costs is critical~~ to ~~our long-term success~~Israel. ~~Our~~The ~~future drilling plans are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and~~ natural gas ~~prices,~~flows from the ~~availability~~Tamar ~~and~~Field ~~cost~~through ofthe ~~capital,~~world’s ~~drilling~~longest ~~and~~subsea ~~production costs~~tieback, ~~availability~~more ofthan ~~drilling~~90 ~~services~~miles ~~and~~to ~~equipment, gathering system and pipeline transportation constraints and regulatory approvals. To~~ the ~~extent~~Tamar ~~these factors lead to reductions in our drilling plans and associated capital budgets in future periods~~platform, ~~our financial position, cash flows~~ and ~~operating~~then ~~results~~to ~~could~~the beAshdod ~~adversely~~onshore ~~impacted~~terminal.

We own all ownership units in Tamar Royalties, LLC, which owns an overriding royalty interest of 1.5375% before payout / 2.7375% after payout in the Tamar Field (collectively the “Tamar Royalty”). An overriding royalty interest is an ownership interest in the oil and gas leasehold estate equating to a certain percentage of production or production revenues, calculated free of the costs of production and development of the underlying lease(s), but subject to its proportionate share of certain post production costs. An overriding royalty interest is a non-possessory interest in the oil and gas leasehold estate and, accordingly, we have no control over the operations, drilling, expenses, timing, production, sales, or any other aspect of development or production of the Tamar Field.31

~~The~~Table ~~Tamar~~of Field project began production in March 2013 and is now operational and delivering natural gas to Israel. The natural gas flows from the Tamar Field through the world’s longest subsea tieback, more than 90 miles to the Tamar platform, and then to the Ashdod onshore terminal.Contents

AsWith ~~noted above with~~ regard to the payout of the Tamar Field, a disagreement between the Company and Isramco Negev 2 Limited Partnership has emerged as to what costs should be included in the calculation of payout. In addition to actual costs for the development of the Tamar Field, Isramco, Negev 2 Limited Partnership has asserted that the following costs should be included in the calculation of payout: (i) Isramco Negev 2 Limited Partnership’s financing costs; (ii) the general and administrative expenses of Isramco Negev 2 Limited Partnership; (iii) the expected decommissioning costs of the Tamar Field; and (iv) expected future payments to be made in respect of the “Sheshinsky Levy” under Israeli law. In addition to the claim asserted by Isramco Negev 2 Limited Partnership, the Company has asserted counterclaims related to Isramco Negev 2 Limited Partnership’s inclusion into the payout calculation of its expenses related to gathering and transportation infrastructure. The ~~disagreement~~disagreements primarily ~~stems~~stem from the fact that the agreements governing the creation of the Tamar Royalty were formulated in the 1980s and do not have a clear and unequivocal definition as to what costs should be included in the payout calculation. ~~The~~At ~~Company~~the ~~currently~~time ~~believes~~of initiating arbitration, the Company believed that the total scope of the ~~disagreement~~claim iswas approximately forty-five million dollars ($45,000,000); however, this amount increases each month based on Isramco Negev 2 Limited Partnership’s failure to pay the increased, post-payout overriding royalty to the Company each month. In addition, certain claims asserted by the Company related to post production costs and pipeline infrastructure have not been quantified. Under the terms of the agreements creating the Tamar Royalty, the dispute is subject to arbitration in Israel. The Company believes that the claims of Isramco Negev 2 Limited Partnership are erroneous and contrary to generally accepted industry practice. The Company expects that the matter will be favorably resolved through this arbitration process; however, the Company cannot be assured of a favorable result in this arbitration process.

32During year ended December 31, 2018, net sales from the Tamar Field attributable to the Company amounted to 5,591,000 Mcf of natural gas and 7,335 Bbl of condensate with prices of $5.49 per Mcf and $62.95 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $31,036,000. The Israeli Tax Authority withheld $7,138,000 of this revenue.

~~Table~~During year ended December 31, 2017, net sales from the Tamar Field attributable to the Company amounted to 5,343,000 Mcf of ~~Contents~~natural gas and 6,990 Bbl of condensate with prices of $5.35 per Mcf and $47.46 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $28,781,000. The Israeli Tax Authority withheld $6,907,000 of this revenue.

During year ended December 31, ~~2017~~2016, net sales from the Tamar Field attributable to the Company amounted to 5,~~343~~102,000 Mcf of natural gas and 6,~~990~~882 Bbl of condensate with prices of $5.3534 per Mcf and $4737.4648 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $2827,~~781~~462,000. The Israeli Tax Authority withheld $6,~~907~~866,000 of this revenue.

~~During~~At ~~year~~December 31, ~~ended~~2018, ~~December~~our 31estimated total proved oil, ~~2016~~natural gas reserves and natural gas liquids, ~~net~~as ~~sales~~prepared ~~from~~by ~~the~~our ~~Tamar~~independent ~~Field~~reserve ~~attributable~~engineering tofirms, ~~Isramco~~Netherland, ~~amounted~~Sewell to& 5Associates,~~102~~ Inc. and Cawley,~~000~~ ~~Mcf~~Gillespie & Associates, Inc., were approximately 40,267 thousand barrels of oil equivalent (“MBOE”), consisting of 2,125 thousand barrels (MBbls) of oil, 223,915 million cubic feet (MMcf) of natural gas and ~~6,882~~823 ~~Bbl~~thousand barrels (MBbls) of ~~condensate~~natural ~~with~~gas ~~prices~~liquids. ofApproximately $567.342% ~~per~~of ~~Mcf~~our proved reserves were classified as proved developed (See Note 14, “Supplemental Oil and ~~$37~~Gas Information”).48 ~~per~~Full ~~Bbl~~year of2018 ~~condensate~~production averaged 3.75 ~~Total~~MBOE/d ~~revenues~~compared ~~net~~to of3.78 ~~marketing~~MBOE/d ~~and~~in ~~transportation~~2017. ~~expenses~~Tamar ~~were~~Field ~~$27,462,000.~~production ~~The~~share ~~Israeli~~amounted ~~Tax~~to ~~Authority~~2.57 ~~withheld~~MBOE/d ~~$6,866,000~~out of ~~this~~total ~~revenue~~3.75 MBOE/d compared to 2.46 MBOE/d in 2017.

~~During~~Production ~~the~~Services year ended December 31, 2015, net sales from the Tamar Field attributable to the Company amounted to 4,505,000 Mcf of natural gas and 6,074 Bbl of condensate with prices of $5.52 per Mcf and $46.53 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $25,151,000. The Israeli Tax Authority withheld $6,665,000 of this revenue.Segment

AtOur ~~December 31,~~core ~~2017,~~businesses depend on our ~~estimated~~customers’ ~~total~~willingness ~~proved~~to ~~oil~~make expenditures to produce, ~~natural~~develop ~~gas~~and ~~reserves~~explore for oil and natural gas ~~liquids,~~in asthe ~~prepared~~United byStates. ~~our~~Industry ~~independent~~conditions ~~reserve~~are ~~engineering~~influenced ~~firms,~~by ~~Netherland~~numerous factors, ~~Sewell~~such &as ~~Associates,~~the ~~Inc.~~supply of and ~~Cawley,~~demand ~~Gillespie &~~for ~~Associates,~~oil ~~Inc.~~and natural gas, ~~were~~domestic ~~approximately~~and 38worldwide economic conditions,~~653~~ ~~thousand~~political ~~barrels~~instability ofin oil ~~equivalent~~producing ~~(“MBOE”),~~countries ~~consisting~~and ofmerger ~~1,765~~and ~~thousand~~divestiture ~~barrels~~activity ~~(MBbls)~~among of oil, ~~216,451~~and ~~million~~natural ~~cubic~~gas ~~feet~~producers. ~~(MMcf)~~The volatility of the oil and natural gas industry, and ~~813~~the ~~thousand~~consequent ~~barrels~~impact ~~(MBbls)~~on ofexploration ~~natural~~and ~~gas~~production ~~liquids.~~activity, ~~Approximately~~could ~~86.0%~~adversely impact the level of ~~our~~workover ~~proved~~activity ~~reserves~~by ~~were~~some ~~classified~~of asour ~~proved~~customers. ~~developed~~This ~~(See~~volatility ~~Note~~also ~~13,~~affects ~~“Supplemental~~the ~~Oil~~demand for our services and ~~Gas~~the ~~Information”)~~price of our services. ~~Full~~In ~~year~~addition, ~~2017~~the ~~production~~discovery ~~averaged~~rate ~~3.78~~of ~~MBOE/d~~new ~~compared~~oil toand ~~3.80~~natural ~~MBOE/d~~gas reserves in ~~2016.~~our ~~Tamar~~market ~~Field~~areas ~~production~~also ~~share~~may ~~amounted~~have toan ~~2.46~~impact ~~MBOE/d~~on ~~out~~our ofbusiness, ~~total~~even ~~3.78~~in ~~MBOE/d~~an ~~compared~~environment toof ~~2.35~~stronger ~~MBOE/d~~oil inand ~~2016~~natural gas prices.

~~Production~~We ~~Services~~derive ~~Segment~~a majority of our revenues from services supporting production from existing oil and natural gas operations including in moderate oil and natural gas price environments, ongoing maintenance spending is generally required to sustain production. However, in a low commodity price environment our customers may reduce their budgets resulting in reduced demand for our services. As oil and natural gas prices reach higher levels, demand for all of our services generally increases as our customers engage in more well servicing activities relating to existing wells to maintain or increase oil and natural gas production from those wells. Because our services are required to support drilling and workover activities, our revenues will vary based on changes in capital spending by our customers as oil and natural gas prices increase or decrease.

Our core businesses depend on our customers’ willingness to make expenditures to produce, develop and explore for oil and natural gas in the United States. Industry conditions are influenced by numerous factors, such as the supply of and demand for oil and natural gas, domestic and worldwide economic conditions, political instability in oil producing countries and merger and divestiture activity among oil and natural gas producers. The volatility of the oil and natural gas industry, and the consequent impact on exploration and production activity, could adversely impact the level of workover activity by some of our customers. This volatility also affects the demand for our services and the price of our services. In addition, the discovery rate of new oil and natural gas reserves in our market areas also may have an impact on our business, even in an environment of stronger oil and natural gas prices.32

WeTable ~~derive a majority~~ of our revenues from services supporting production from existing oil and natural gas operations including in moderate oil and natural gas price environments, ongoing maintenance spending is generally required to sustain production. However, in a low commodity price environment our customers may reduce their budgets resulting in reduced demand for our services. As oil and natural gas prices reach higher levels, demand for all of our services generally increases as our customers engage in more well servicing activities relating to existing wells to maintain or increase oil and natural gas production from those wells. Because our services are required to support drilling and workover activities, our revenues will vary based on changes in capital spending by our customers as oil and natural gas prices increase or decrease.Contents

The production services market is highly competitive. Competition is influenced by such factors as price, capacity, availability of work crews, and reputation and experience of the service provider. We believe that an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. We believe many of our larger customers place increased emphasis on the safety, performance and quality of the crews, equipment and services provided by their contractors. Although we believe customers consider all of these factors, price is often the primary factor in determining which service provider is awarded the work. However, in numerous instances, we secure and maintain work from large customers for which efficiency, safety, technology, size of fleet and availability of other services are of equal importance to price.

The demand for our services fluctuates, primarily in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven primarily by the supply of, and demand for, oil and natural gas. Generally, as supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in a lower oil and natural gas price environment, demand for service and maintenance generally decreases as oil and natural gas producers decrease their activity. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work. Oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we may experience a more rapid decline in demand for well maintenance services compared with demand for other types of oilfield services. Further, in a low commodity price environment, fewer production services rigs are needed for completions, as these activities are generally associated with drilling activity. The plugging and abandonment work is less affected by prices and generally driven by state regulations and have smaller variations in demand.

The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of U.S. oil and natural gas exploration, development and production activity, as well as the equipment capacity in any particular region.

33Critical Accounting Policies

~~Table~~The discussion and analysis of ~~Contents~~our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the most significant estimates and assumptions we make in applying these policies.

~~Critical~~Oil ~~Accounting~~and ~~Policies~~Natural Gas Activities

~~The~~Accounting ~~discussion~~for oil and ~~analysis~~natural gas activities is subject to unique rules. Two generally accepted methods of ~~our~~accounting ~~financial~~for ~~condition~~oil and ~~results~~natural ofgas ~~operations~~activities are ~~based~~available - ~~upon~~successful ~~our~~efforts ~~consolidated~~and ~~financial~~full ~~statements,~~cost. ~~which~~The ~~have~~most ~~been~~significant ~~prepared~~differences inbetween ~~accordance~~these ~~with~~two ~~accounting~~methods ~~principles~~are ~~generally~~the ~~accepted~~treatment inof unsuccessful exploration costs and the ~~United~~manner ~~States.~~in ~~The~~which ~~preparation~~the carrying value of ~~our~~oil ~~consolidated~~and ~~financial~~natural ~~statements~~gas properties are amortized and evaluated for impairment. The successful efforts method requires usunsuccessful exploration costs to ~~make~~be ~~estimates~~expensed ~~and~~as ~~assumptions~~they are incurred upon a determination that ~~affect~~the ~~our~~well ~~reported~~is ~~results~~uneconomical, while the full cost method provides for the capitalization of ~~operations~~these ~~and~~costs. Both methods generally provide for the ~~amount~~periodic amortization of ~~reported~~capitalized ~~assets,~~costs ~~liabilities~~based ~~and~~on proved reserve quantities. Impairment of oil and natural gas ~~reserves.~~properties ~~Some~~under ~~accounting~~the ~~policies~~successful ~~involve~~efforts ~~judgments~~method ~~and~~is ~~uncertainties~~based toon ~~such~~ an ~~extent~~evaluation ~~that~~of ~~there~~the iscarrying ~~reasonable~~value ~~likelihood~~of ~~that~~individual ~~materially~~oil ~~different~~and ~~amounts~~natural ~~could~~gas ~~have~~properties ~~been~~against ~~reported~~their ~~under~~estimated ~~different~~fair ~~conditions~~value, orwhile ifimpairment ~~different~~under ~~assumptions~~the ~~had~~full ~~been~~cost ~~used.~~method ~~Actual~~requires ~~results~~an ~~may~~evaluation ~~differ~~of ~~from~~ the ~~estimates~~carrying ~~and~~value ~~assumptions~~of ~~used~~oil inand ~~the~~natural ~~preparation~~gas ofproperties ~~our~~included ~~consolidated~~in ~~financial~~a ~~statements.~~cost ~~Described~~center ~~below~~against ~~are~~ the ~~most~~net ~~significant~~present ~~policies~~value weof ~~apply~~future incash ~~preparing~~flows ~~our~~from ~~consolidated~~the ~~financial~~related ~~statements~~proved reserves, ~~some~~using ofperiod-end ~~which~~prices ~~are~~and ~~subject~~costs toand ~~alternative~~a ~~treatments~~10% ~~under~~discount ~~accounting~~rate. ~~principles~~We ~~generally~~account ~~accepted~~for inour ~~the~~natural ~~United~~gas ~~States.~~and Wecrude ~~also~~oil ~~describe~~exploration ~~the~~and ~~most~~production ~~significant~~activities ~~estimates~~under ~~and~~the ~~assumptions~~successful weefforts ~~make~~method inof ~~applying these policies~~accounting.

Proved Oil and Natural Gas ~~Activities~~Reserves

~~Accounting~~Isramco ~~for~~estimates ~~oil~~its ~~and~~proved ~~natural gas activities is subject to unique rules. Two generally accepted methods of accounting for~~ oil and ~~natural~~ gas ~~activities~~reserves ~~are~~as ~~available -~~defined ~~successful~~by ~~efforts and full cost. The most significant differences between these two methods are~~ the ~~treatment~~SEC ~~of unsuccessful exploration costs~~ and the ~~manner~~FASB. inThis ~~which~~definition ~~the~~includes ~~carrying~~crude ~~value of~~ oil, ~~and~~ natural gas, ~~properties are amortized~~ and ~~evaluated~~NGLs ~~for~~that ~~impairment.~~geological ~~The~~and ~~successful~~engineering ~~efforts~~data ~~method~~demonstrate ~~requires~~with ~~unsuccessful~~reasonable ~~exploration~~certainty ~~costs~~ to be ~~expensed~~economically asproducible ~~they~~in ~~are~~future ~~incurred~~periods ~~upon~~from aknown ~~determination~~reservoirs ~~that~~under ~~the~~existing ~~well~~economic ~~is uneconomical~~conditions, ~~while~~operating ~~the~~methods, ~~full~~government ~~cost~~regulations, ~~method provides for the capitalization of these costs~~etc., ~~Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities~~i.e., ~~Impairment~~at ofprices ~~oil~~ and ~~natural~~costs ~~gas~~as ~~properties under the successful efforts method is based on an evaluation~~ of the ~~carrying~~date ~~value of individual oil and natural gas properties against their estimated fair value, while impairment under~~ the ~~full~~estimates ~~cost~~are ~~method~~made. ~~requires~~Prices aninclude ~~evaluation~~consideration of ~~the~~price ~~carrying~~changes ~~value~~provided ofonly ~~oil~~by ~~and~~contractual ~~natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves~~arrangements, ~~using period-end prices~~ and ~~costs~~do ~~and~~not ainclude ~~10%~~adjustments ~~discount~~based ~~rate.~~upon Weexpected ~~account~~future ~~for our natural gas and crude oil exploration and production activities under the successful efforts method of accounting~~conditions.

~~Proved Oil and Natural Gas Reserves~~33

~~Isramco~~Table estimates its proved oil and gas reserves as defined by the SEC and the FASB. This definition includes crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, government regulations, etc., i.e., at prices and costs as of ~~the date the estimates are made. Prices include consideration of price changes provided only by contractual arrangements, and do not include adjustments based upon expected future conditions.~~Contents

The Company’s estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually by our independent reserve engineering firm, Cawley, Gillespie & Associates, Inc and Netherland, Sewell & Associates, Inc. and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions, and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization expense (DD&A) and could result in property impairments.

Depreciation, Depletion and Amortization

Our rate of recording DD&A is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it non-economic to drill for and produce higher cost reserves.

Our production services equipment and tools are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated depreciable lives of the assets using the straight-line method. We depreciate our operational assets over their depreciable lives to their salvage value, which is a fair value higher than the assets’ value as scrap. When we scrap an asset, we accelerate the depreciation of the asset down to its salvage value. When we dispose of an asset, a gain or loss is recognized.

34Impairment

~~Table~~We review our property and equipment in accordance with Accounting Standards Codification (ASC) 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires us to evaluate property and equipment as an event occurs or circumstances change that would more likely than not reduce the fair value of ~~Contents~~the property and equipment below the carrying amount. If the carrying amount of property and equipment is not recoverable from its undiscounted cash flows, then we would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, we evaluate the remaining useful lives of property and equipment at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods.

~~Impairment~~Asset Retirement Obligations

We ~~review~~have ~~our~~significant ~~property~~obligations ~~and~~to remove tangible equipment inand ~~accordance~~facilities associated with ~~Accounting~~our ~~Standards~~oil ~~Codification~~and ~~(ASC)~~gas ~~360,~~wells ~~Property,~~and ~~Plant,~~to restore land at the end of oil and ~~Equipment~~gas ~~(ASC~~production ~~360)~~operations. ~~ASC~~Our ~~360~~removal ~~requires~~and usrestoration toobligations ~~evaluate~~are ~~property~~most often associated with plugging and ~~equipment~~abandoning aswells. anEstimating ~~event~~the ~~occurs~~future orrestoration ~~circumstances~~and ~~change~~removal ~~that~~costs ~~would~~is ~~more~~difficult ~~likely~~and ~~than~~requires ~~not~~us ~~reduce~~to ~~the~~make ~~fair~~estimates ~~value~~and judgments because most of the ~~property~~removal ~~and~~obligations ~~equipment~~we ~~below~~have ~~the~~will ~~carrying~~be ~~amount.~~take Ifeffect in the ~~carrying~~future. ~~amount~~Additionally, ofthese ~~property~~operations ~~and~~are ~~equipment~~subject isto ~~not~~private ~~recoverable~~contracts ~~from~~and ~~its~~government ~~undiscounted~~regulations ~~cash~~that ~~flows,~~often ~~then~~have wevague ~~would~~descriptions ~~recognize~~of anwhat ~~impairment~~is ~~loss~~required. ~~for~~Asset ~~the~~removal ~~difference~~technologies ~~between~~and ~~the~~costs ~~carrying~~are ~~amount~~constantly ~~and~~changing, ~~the~~as ~~current~~are ~~fair~~regulatory, ~~value.~~political, ~~Further~~environmental, wesafety ~~evaluate~~and public relations considerations. Inherent in the ~~remaining~~present ~~useful~~value ~~lives~~calculations ofare ~~property~~numerous assumptions and ~~equipment~~judgments atincluding ~~each~~the ~~reporting~~ultimate ~~period~~removal tocost ~~determine~~amounts, ~~whether~~inflation ~~events~~factors, ~~and~~credit ~~circumstances~~adjusted ~~warrant~~discount arates, ~~revision~~timing toof obligations and changes in the ~~remaining~~legal, ~~depreciation~~regulatory, ~~periods~~environmental and political environments.

~~Asset~~Accounting ~~Retirement~~for ~~Obligations~~Derivative Instruments and Hedging Activities

We have ~~significant~~and ~~obligations~~may toutilize ~~remove~~derivative ~~tangible~~contracts ~~equipment~~to ~~and~~hedge ~~facilities~~against ~~associated~~the ~~with~~variability ~~our~~in ~~oil~~cash ~~and~~flows ~~gas~~associated ~~wells~~with ~~and~~the toforecasted ~~restore~~sale ~~land~~of atour ~~the~~anticipated ~~end~~future of oil and natural gas production ~~operations~~. ~~Our~~We ~~removal~~may ~~and~~generally ~~restoration~~hedge ~~obligations~~a ~~are~~substantial, ~~most~~but ~~often~~varying, ~~associated~~portion ~~with~~of ~~plugging~~our ~~and~~anticipated ~~abandoning~~oil ~~wells.~~and ~~Estimating~~natural ~~the~~gas ~~future~~production ~~restoration~~for ~~and~~the ~~removal~~next years. ~~costs~~We isdo ~~difficult~~not ~~and~~use ~~requires~~derivative usinstruments tofor ~~make~~trading ~~estimates~~purposes. ~~and~~We ~~judgments~~have ~~because~~elected ~~most~~not ofto ~~the~~apply ~~removal~~hedge ~~obligations~~accounting weto ~~have~~our ~~will~~derivative becontracts, ~~take~~which ~~effect~~would inpotentially ~~the~~allow ~~future.~~us ~~Additionally,~~to ~~these~~not ~~operations~~record ~~are~~the ~~subject~~change toin ~~private~~fair ~~contracts~~value ~~and~~of ~~government~~our ~~regulations~~derivative ~~that~~contracts ~~often~~in ~~have~~the ~~vague~~consolidated ~~descriptions~~statements of ~~what is required~~operations. ~~Asset~~We ~~removal~~carry ~~technologies~~our ~~and~~derivatives ~~costs~~at ~~are~~fair ~~constantly~~value ~~changing,~~on asour ~~are~~consolidated ~~regulatory,~~balance ~~political~~sheets, ~~environmental,~~with ~~safety~~the ~~and~~changes ~~public relations considerations. Inherent~~ in the ~~present~~fair value ~~calculations~~included ~~are~~in ~~numerous~~our ~~assumptions~~consolidated ~~and~~statements ~~judgments including the ultimate removal cost amounts, inflation factors, credit adjusted discount rates, timing~~ of ~~obligations~~operations ~~and changes~~ in the ~~legal,~~period ~~regulatory,~~in ~~environmental~~which ~~and~~the ~~political~~change ~~environments~~occurs.

~~Accounting for Derivative Instruments and Hedging Activities~~34

WeTable ~~have and may utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale~~ of our anticipated future oil and natural gas production. We may generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next years. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivative contracts, which would potentially allow us to not record the change in fair value of our derivative contracts in the consolidated statements of operations. We carry our derivatives at fair value on our consolidated balance sheets, with the changes in the fair value included in our consolidated statements of operations in the period in which the change occurs.Contents

Environmental Obligations, Litigation and Other Contingencies

Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental remediation, litigation, and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability is incurred and reasonable estimates of the liability can be made. Estimates of environmental liabilities are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change the Company’s estimate of environmental-remediation costs, such as changes in laws and regulations, changes in the interpretation or administration of laws and regulations, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment, and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental or other contingent matters and actual costs may vary significantly from the Company’s estimates. The Company’s in-house legal counsel regularly assesses these contingent liabilities and, in certain circumstances, consults with third-party legal counsel or consultants to assist in forming the Company’s conclusion.

Income Taxes and Impact of Tax Reform Legislation

The Company follows ASC 740, Income Taxes, (ASC 740), which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax assets and liabilities are computed using the liability method based on the differences between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

A valuation allowance is provided, if necessary, to reserve the amount of net operating loss and net deferred tax assets which the Company may not be able to use because of the expiration of maximum carryover periods allowed under applicable tax codes.

On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation), which made significant changes to US federal income tax law affecting us. See Note 56. Income Taxes.

35Liquidity and Capital Resources

~~Table~~Our primary source of ~~Contents~~cash during the year ended December 31, 2018, was net cash flow from operating activities. We continuously monitor our liquidity and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources and drilling success.

~~Liquidity~~Our future capital resources and ~~Capital~~liquidity ~~Resources~~may depend, in part, on our success in developing the leasehold interests that we have acquired. Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and gas industry. Future success in growing reserves and production will be highly dependent on the capital resources available and our success in finding and acquiring additional reserves. Our production services subsidiary also requires capital resources to acquire and maintain equipment. We expect to fund our future capital requirements through internally generated cash flows, and borrowings under loans and the credit facility described below. Long-term cash flows are subject to a number of variables, including the level of production, prices, amount of work orders received, and our commodity price hedging activities, as well as various economic conditions that have historically affected the oil and natural gas industry.

~~Our~~On ~~primary~~May ~~source~~18, of2015, ~~cash~~Tamar ~~during~~Royalties ~~the~~LLC ~~year~~(“Tamar ~~ended~~Royalties”), ~~December~~a 31newly formed, ~~2017~~wholly-owned, ~~was~~special ~~net~~purpose ~~cash~~subsidiary ~~flow~~of ~~from~~the ~~operating~~Company ~~activities. We~~entered ~~continuously~~into ~~monitor~~a ~~our~~term ~~liquidity~~loan ~~and~~credit ~~evaluate~~agreement ~~our~~(the ~~development~~“DB ~~plans~~Facility”) inwith ~~light~~Deutsche ofBank aTrust ~~variety~~Company Americas (“Deutsche Bank”) in the amount of ~~factors~~$120, ~~including~~000,000 ~~but~~secured ~~not~~by ~~limited~~the Company’s interest in the Tamar field. Interest on the borrowing is subject to, ~~our~~fluctuations ~~cash~~in ~~flows,~~LIBOR. ~~capital~~The ~~resources~~Company entered into interest rate swap agreements in relation to this borrowing. The terms of the agreement and ~~drilling~~swaps ~~success~~are disclosed in Notes 4 and 5.

~~Our~~On ~~future~~June ~~capital resources and liquidity may depend~~30, ~~in part~~2015, onthe ~~our~~Company ~~success~~obtained ina ~~developing~~credit facility (the ~~leasehold~~“SG ~~interests~~Facility”) ~~that~~with weThe ~~have~~Société ~~acquired~~Générale. ~~Cash~~The isSG ~~required~~facility toprovided ~~fund~~for ~~capital~~a ~~expenditures~~commitment ~~necessary~~by toThe ~~offset~~Société ~~inherent~~Générale ~~declines~~of ~~in production and proven reserves~~$150,000,000, ~~which~~subject isto ~~typical~~an ininitial ~~the~~borrowing ~~capital-intensive~~base ~~oil~~of ~~and gas industry~~$40,000,000. ~~Future~~ ~~success~~The intenure ~~growing~~of ~~reserves and production will be highly dependent on~~ the ~~capital~~SG ~~resources~~Facility ~~available~~was ~~and~~four ~~our~~(4) ~~success~~years ~~in finding~~ and ~~acquiring~~it ~~additional~~was ~~reserves.~~secured ~~Our~~by ~~production~~certain ~~services~~onshore ~~subsidiary~~United ~~also~~States ~~requires~~oil ~~capital resources to acquire~~ and ~~maintain~~gas ~~equipment~~properties. WeInterest ~~expect~~on toborrowing ~~fund~~was ~~our~~variable ~~future~~as ~~capital~~disclosed ~~requirements~~in ~~through~~Note ~~internally~~5 ~~generated cash flows, and borrowings under loans and the credit facility described below.~~ “Long-~~term~~Term ~~cash~~Debt ~~flows are subject to a number of variables, including the level of production, prices, amount of work orders received,~~ and ~~our~~Interest ~~commodity~~Expense”. ~~price~~On ~~hedging~~February ~~activities~~28, as2017 ~~well as various economic conditions that have historically affected~~ the ~~oil~~SG ~~and~~Facility ~~natural~~was ~~gas industry~~terminated.

OnDuring ~~May~~the ~~18,~~year ~~2015,~~ended ~~Tamar~~December ~~Royalties LLC (“Tamar Royalties”)~~31, ~~a newly formed~~2018, ~~wholly-owned,~~our ~~special~~cash ~~purpose subsidiary of the Company entered into a term loan credit agreement~~ (~~the~~including ~~“DB~~restricted ~~Facility”~~cash) ~~with~~decreased ~~Deutsche~~by ~~Bank~~$6,494,000. ~~Trust~~Specifically, ~~Company~~net ~~Americas~~cash ~~(“Deutsche~~from ~~Bank”)~~operating inactivities ~~the amount~~ of $~~120~~17,~~000~~167,000, ~~secured~~was offset by ~~the~~cash ~~Company’s~~used ~~interest~~ in ~~the~~investing ~~Tamar~~activities ~~field. Interest on the borrowing is subject to fluctuations in LIBOR. The Company entered into interest rate swap agreements in relation to this borrowing. The terms~~ of ~~the~~$7,394,000 ~~agreement~~ and ~~swaps~~cash ~~are~~used ~~disclosed~~ in ~~Notes~~financing 3activities ~~and~~of 4$16,267,000.

On(See ~~June~~Item ~~30,~~1A ~~2015, the Company obtained a credit facility (the~~ “SGRisk ~~Facility~~Factors”) ~~with The Société Générale~~. The SG facility provided for a commitment by The Société Générale of $150,000,000, subject to an initial borrowing base of $40,000,000. The tenure of the SG Facility was four (4) years and it was secured by certain onshore United States oil and gas properties. Interest on borrowing was variable as disclosed in Note 4 “Long-Term Debt and Interest Expense”. On February 28, 2017 the SG Facility was terminated.

During the year ended December 31, 2017, our cash increased by $3,919,000. Specifically, net cash from operating activities of $18,552,000, was offset by cash used in financing activities of $10,519,000 and cash used in investing activities of $4,114,000.35

~~(See~~Table ~~Item~~of ~~1A “Risk Factors”).~~ Contents

Commitments and Contingencies

As is common within the oil and natural gas industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and natural gas properties. It is our belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

Contractual Obligations: Aggregate maturities of contractual obligations at December 31, ~~2017~~2018 are due in future years as follows (in thousands):

Principal Payments on Long-term debt:

2018	$	18,900
2019	$	21,900
2019		21,900
2020		17,100
2021		14,700
2022		14,400
2023		11,400
Total	$	9879,~~400~~500

36Debt

Table of Contents

	As of December 31,
	2018			2017			2016
	(In thousands except percentage)
Long – term debt net of discount and bank fees		56,193			77,369			95,441

Short – term debt – related party (1)		3,671			-			-

Current maturities of long-term debt, short-term debt, net of current portion of discount and debt cost and bank overdraft		21,739			18,517			9,147
Total debt		81,603			95,886			104,588

Stockholders’ equity (deficit)		(7,359	)		(23,818	)		2,016

Debt to capital ratio		110	%		133	%		98	%

~~Debt~~(1) The amounts are inclusive of accrued interest due to related party.

	As of December 31,
	2017			2016			2015
	(In thousands except percentage)
Long – term debt net of discount and bank fees		77,369			95,441			104,252
Long – term debt – related party (1)		-			-			-
Current maturities of long-term debt, short-term debt, net of current portion of discount and debt cost and bank overdraft		18,517			9,147			9,952
Total debt		95,886			104,588			114,204
Stockholders’ equity (deficit)		(23,818	)		2,016			(2,868	)
Debt to capital ratio		133	%		98	%		103	%

At year-end 2018, our total debt was $81,603,000 compared to total debt of $95,886,000 at year-end 2017 and $104,588,000 at year-end 2016.

~~(1)~~Bank ~~The~~Loan ~~amounts~~and ~~are~~Credit ~~exclusive of accrued interest.~~Facility

AtThe ~~year-end~~Deutsche ~~2017,~~Bank ~~our total debt was $95,886,000 compared to total debt of $104,588,000 at year-end 2016 and $114,204,000 at year-end 2015.~~Facility

On May 18, 2015, Tamar Royalties LLC (“Tamar Royalties”), a newly formed, wholly-owned, special purpose subsidiary of the Company, entered into a term loan credit agreement (the “DB Facility”) with Deutsche Bank ~~Loan~~Trust Company Americas (“Deutsche Bank”), as facility agent for the lenders and ~~Credit~~as collateral agent for the secured parties, and with the lenders party thereto. The DB Facility provides for borrowings in the amount of $120,000,000 on a committed basis and is secured by, among other things, an overriding royalty interest in the Tamar Field, a natural gas field in the Mediterranean Sea, equal to 1.5375% before payout increasing to 2.7375% after payout in the Tamar Field (the “Royalty Interest”). In connection with the DB Facility, and pursuant to a royalties sale and contribution agreement, the Company contributed the Royalty Interest to Tamar Royalties in exchange for all of the ownership units of Tamar Royalties. Pursuant to the terms of its governing documents, Tamar Royalties will be managed by N.M.A. Energy Resources Ltd, a related party of the Company, and an independent manager, Donald J. Puglisi.

~~The Deutsche Bank Facility~~36

OnTable ~~May 18, 2015, Tamar Royalties LLC (“Tamar Royalties”), a newly formed, wholly-owned, special purpose subsidiary~~ of the Company, entered into a term loan credit agreement (the “DB Facility”) with Deutsche Bank Trust Company Americas (“Deutsche Bank”), as facility agent for the lenders and as collateral agent for the secured parties, and with the lenders party thereto. The DB Facility provides for borrowings in the amount of $120,000,000 on a committed basis and is secured by, among other things, an overriding royalty interest in the Tamar Field, a natural gas field in the Mediterranean Sea, equal to 1.5375% before payout / 2.7375% after payout in the Tamar Field (the “Royalty Interest”). In connection with the DB Facility, and pursuant to a royalties sale and contribution agreement, the Company contributed the Royalty Interest to Tamar Royalties in exchange for all of the ownership units of Tamar Royalties. Pursuant to the terms of its governing documents, Tamar Royalties will be managed by N.M.A. Energy Resources Ltd, a related party of the Company, and an independent manager, Donald J. Puglisi.Contents

Pursuant to the terms of the DB Facility, Tamar Royalties borrowed $120,000,000 in its initial borrowing under this facility. The initial borrowing under the DB Facility bears annual interest based on the LIBOR for a three-month interest period plus a spread of 2.75%. The $120,000,000 initial borrowing under the DB Facility will be repaid over eight (8) years commencing July 1, 2015, in accordance with an amortization profile based on projected cash flows from the Royalty Interest. Tamar Royalties’s obligations under the Facility are secured by a first ranking pledge of the shares of Tamar Royalties, first ranking pledge of all rights under the agreements creating the Royalty Interest, and a first priority security interest over the accounts created under the DB Facility.

So long as any amounts remain outstanding to the Lenders under the DB Facility, Tamar Royalties must, from and after the end of the Availability Period (as defined in the DB Facility), have a Historical Debt Service Coverage Ratio (as defined in the DB Facility) of not less than 1.00:1.00, a Loan Life Coverage Ratio (as defined in the DB Facility) of at least 1.1:1.00, and maintain a Required Reserve Amount (as defined in the DB Facility). In addition, Tamar Royalties is required under the DB facility to hedge against fluctuations in LIBOR as reflected in Note 34 “Financial Instruments and Fair Value”.

The amortization schedule under the DB Facility was based on the projection that the Investment Repayment Date (as defined therein) would occur at some point before the end of the first quarter of 2018 and therefore, commencing from the Payment Date occurring on 1st April 2018, the amounts to be repaid on each payment date under the credit agreement increase to reflect the expected increase in the Royalties Receivables (as defined therein) as a result of the increase in the royalty percentage following the Investment Repayment Date.

37As noted above with regard to the payout of the Tamar Field, a disagreement between Tamar Royalties and Isramco Negev 2 Limited Partnership has emerged as to whether certain items may be included in the calculation of payout. The disagreement largely stems from the fact that the agreements governing the creation of the Tamar Royalty were formulated in the 1980s and do not have a clear and unequivocal definition as to what costs should be included in the payout calculation. At the time of initiating arbitration, the Company believed that the total scope of the claim was approximately forty-five million dollars ($45,000,000); however, this amount increases each month based on Isramco Negev 2 Limited Partnership’s failure to pay the increased, post-payout overriding royalty to the Company. Under the terms of the agreements creating the Tamar Royalty, the dispute is subject to arbitration in Israel. The Company expects that the matter will be resolved through this arbitration process. However, the Company cannot be assured of a favorable result resulting from this arbitration process. Accordingly, the Company continues to receive royalty payments at the lower rates as if the Investment Repayment Date has not occurred.

~~Table~~Therefore, as a result of ~~Contents~~the dispute with the Isramco Negev 2, Tamar Royalties has a shortfall in its Royalties Receivables for the period (or part of the period) between 1st April 2018 and 1st April 2019, by which time, even if the Isramco Negev 2’s claims regarding the Investment Repayment Date are accepted, the Investment Repayment Date is expected to occur.

As ~~noted~~a ~~above~~result, ~~with regard to~~ the ~~payout~~Company ofbelieves ~~the~~ Tamar ~~Field, a disagreement between Tamar~~ Royalties ~~and~~required ~~Isramco~~an ~~Negev~~additional 2$15,600,000 ~~Limited~~USD ~~Partnership has emerged as~~ to ~~whether~~cover ~~certain~~payments ~~items may~~under ~~be included in~~ the ~~calculation~~amortization schedule of ~~payout.~~the ~~The~~DB ~~disagreement largely stems from~~ Facility (the ~~fact~~“Shortfall”), ~~that~~and the ~~agreements~~Company ~~governing~~believes ~~the~~that ~~creation~~curing of the ~~Tamar~~Shortfall ~~Royalty~~was ~~were formulated~~ in the ~~1980s~~best ~~and~~interest doof ~~not~~both ~~have~~Isramco aInc. ~~clear~~ and ~~unequivocal~~Tamar ~~definition~~Royalties. asTherefore, toIsramco ~~what~~Inc. ~~costs~~contributed ~~should~~the beexpected ~~included~~amount inof the ~~payout~~Shortfall, ~~calculation.~~being ~~The~~$15,600,000 ~~Company~~USD, ~~currently~~to ~~believes~~Tamar ~~that~~Royalties ~~the~~as ~~total~~an ~~scope~~additional ofcapital ~~the~~contribution ~~disagreement~~and issuch ~~approximately~~contribution ~~forty~~was ~~five~~made ~~million~~pursuant ~~dollars~~to ~~($45,000,000). Under~~ the terms ofand ~~the~~conditions ~~agreements~~of ~~creating~~that ~~the~~certain ~~Tamar~~Consent ~~Royalty,~~and ~~the~~Agreement ~~dispute~~dated isFebruary ~~subject~~27, to2018, ~~arbitration~~between inand ~~Israel.~~among ~~The~~Tamar ~~Company~~Royalties, ~~expects~~as ~~that~~Borrower, ~~the~~Deutsche ~~matter~~Bank ~~will~~Trust beCompany ~~resolved~~Americas, ~~through~~as ~~this~~Facility ~~arbitration~~Agent ~~process.~~and ~~However~~Collateral Agent, and the ~~Company~~Lenders ~~cannot~~party bethereto. As ~~assured of~~ a ~~favorable~~ result ~~resulting~~of ~~from~~the ~~this~~aforementioned ~~arbitration process. Accordingly~~contribution, together with the ~~Company~~terms ~~continues~~and toconditions ~~receive~~of ~~royalty~~the ~~payments~~aforementioned atconsent ~~the~~and ~~lower~~assignment, ~~rates~~Tamar asRoyalties ifremains ~~the~~in ~~Investment~~compliance ~~Repayment~~with ~~Date~~all ~~has~~covenants ~~not~~of ~~occurred~~the DB Facility.

~~Therefore,~~In as2015 athe ~~result~~Company ofincurred debt costs in obtaining the ~~dispute~~facility ~~with~~in the ~~Isramco~~amount ~~Negev~~of $2,011,000 ~~Tamar~~and ~~Royalties~~$2,959,000 ~~will~~in ~~have~~fees awere ~~shortfall~~retained inby ~~its~~the ~~Royalties~~lenders. ~~Receivables~~These ~~for~~costs ~~the~~totaling ~~period~~$4,970,000 ~~(or~~were ~~part~~recorded as a reduction of the ~~period)~~principal ~~between~~loan ~~1st~~balance ~~April~~and ~~2018~~are ~~and~~being ~~1st~~amortized ~~April~~over ~~2019,~~the bylife ~~which~~of ~~time,~~the ~~even~~loan ifusing the ~~Isramco~~effective ~~Negev~~interest ~~2’s~~method. ~~claims~~Amortization ~~regarding~~of these costs for the ~~Investment~~twelve ~~Repayment~~months ~~Date~~ended ~~are~~December ~~accepted~~31, ~~the~~2018, 2017, ~~Investment~~and ~~Repayment~~2016 ~~Date~~totaled is$828,000, ~~expected~~$789,000, toand ~~occur~~$820,000 respectively.

AsIn aconnection ~~result,~~with the ~~Company believes Tamar Royalites required an additional $15,600,000 USD to cover payments under the amortization schedule of the~~ DB Facility ~~(the “Shortfall”)~~, ~~and~~ the Company ~~believes~~and ~~that~~Tamar ~~curing~~Royalties ~~the~~entered ~~Shortfall~~into ~~was~~an inIntercompany ~~the~~Loan ~~best~~Agreement ~~interest~~dated ofMay ~~both~~18, ~~Isramco~~2015 ~~Inc.~~(the ~~and~~“Intercompany ~~Tamar~~Loan ~~Royalties~~Agreement”). ~~Therefore,~~ ~~Isramco~~Pursuant ~~Inc.~~to ~~contributed~~ the ~~expected~~terms ~~amount~~ of the ~~Shortfall,~~Intercompany ~~being~~Loan ~~$15~~Agreement,~~600,000~~ ~~USD, to~~ Tamar Royalties asLLC anprovided ~~additional~~a ~~capital~~loan ~~contribution and such contribution was made pursuant~~ to the ~~terms~~Company ~~and~~in ~~conditions~~an ofaggregate ~~that~~principal ~~certain~~amount ~~Consent~~of ~~and Agreement dated February 27~~$108, ~~2018~~000,000 ~~between~~USD. ~~and~~The ~~among~~purpose ~~Tamar~~of ~~Royalties,~~the asIntercompany ~~Borrower,~~Loan ~~Deutsche~~was ~~Bank~~to ~~Trust~~repay ~~Company~~indebtedness ~~Americas,~~owed asby ~~Facility~~the ~~Agent~~Company ~~and~~to ~~Collateral~~related ~~Agent~~parties, ~~and~~to ~~the~~enable ~~Lenders~~acquisitions ~~party~~and ~~thereto. As~~capital aexpenditures ~~result~~by of the ~~aforementioned contribution~~Company, ~~together with the terms~~ and ~~conditions~~for ofother ~~the~~general ~~aforementioned~~corporate ~~consent~~purposes ~~and assignment, Tamar Royalties remains in compliance with all covenants~~ of the ~~DB Facility~~Company.

InAs ~~2015 the Company incurred debt costs in obtaining the facility in the amount~~ of ~~$2,011,000~~December ~~and $2~~31,~~959,000~~ ~~in fees were retained by the lenders. These costs totaling $4~~2018,~~970,000~~ ~~were~~Tamar ~~recorded~~Royalties aswas ain ~~reduction~~compliance ofwith the ~~principal~~financial ~~loan~~covenants ~~balance~~required ~~and~~under ~~are being amortized over~~ the ~~life~~DB ~~of the loan using the effective interest method~~Facility. ~~Amortization of these costs for the twelve months ended December 31, 2017, 2016, and 2015 totaled $789,000, $820,000, and $402,000 respectively.~~

In connection with the DB Facility, the Company and Tamar Royalties entered into an Intercompany Loan Agreement dated May 18, 2015 (the “Intercompany Loan Agreement”). Pursuant to the terms of the Intercompany Loan Agreement, Tamar Royalties LLC provided a loan to the Company in an aggregate principal amount of $108,000,000 USD. The purpose of the Intercompany Loan was to repay indebtedness owed by the Company to related parties, to enable acquisitions and capital expenditures by the Company, and for other general corporate purposes of the Company.37

AsTable of ~~December 31, 2017, Tamar Royalties was in compliance with the financial covenants required under the DB Facility.~~Contents

The Société Générale Facility

On June 30, 2015, Isramco Onshore LLC (“Isramco Onshore”), a newly formed, wholly-owned, subsidiary of Isramco, Inc. (the “Company”), entered into a secured Credit Agreement (the “SG Facility”) with The Société Générale, as Administrative Agent and Issuing Lender, SG Americas Securities LLC, as Sole Bookrunner, Lead Arranger and Documentation Agent, and the lenders party thereto from time to time, as Lenders. The SG Facility provides for a commitment by The Société Générale of $150,000,000, subject to an initial borrowing base of $40,000,000. The tenure of the SG Facility was four (4) years and the SG Facility was secured by certain onshore United States oil and gas properties. Pricing under the SG Facility was as follows: (i) for EuroDollar Rate (as defined in the SG Facility) loans range from the EuroDollar rate plus 1.75% to the EuroDollar rate plus 2.75% depending on borrowing base utilization; and (ii) for Reference Rate (as defined in the SG Facility) loans ranges from the Reference Rate plus 0.75% to the Reference Rate Spread plus 1.75% based on borrowing base utilization; (iii) a quarterly commitment fee (as defined in the SG Facility) ranging from an annual rate of 0.38% to 0.5% of the undrawn borrowing base.

The SG Facility provided that Isramco Onshore hedge at least seventy-five percent (75%) of its crude oil production before borrowing under the SG Facility. As of December 31, ~~2017~~2018 and as of the date of issuance Isramco Onshore has not entered into such hedge agreements nor has it made a draw under the SG Facility. The Company incurred $478,000 of financing costs in relation to this credit facility which were capitalized as a long-term asset and amortized over the term on the agreement on a straight-line basis until December 31, 2016 at which time the remaining balance totaling $299,000 was expensed.

38Isramco Onshore had various financial and operating covenants required by the SG Facility, including, among other things, the requirement that, during the term of the SG Facility, Isramco Onshore must have a Minimum Current Ratio (as defined in the SG Facility) of not less than 1.00:1.00, a Maximum Leverage Ratio (as defined in the SG Facility) of not less than 4.00:1.00 and a Minimum Interest Coverage Ratio (as defined in the SG Facility) of at least 2.50:1.00. In addition, the SG Facility provided for customary events of default, including, but not limited to, payment defaults, breach of representations or covenants, bankruptcy events and change of control.

~~Table~~On August 18, 2016 as a result of ~~Contents~~semi-annual borrowing base redetermination the borrowing base under SG Facility was reduced to zero. On February 28, 2017 the SG Facility was terminated.

~~Isramco Onshore had various financial and operating covenants required by the SG Facility, including, among other things, the requirement that, during the~~ Short-term ofrelated ~~the~~party SG Facility, Isramco Onshore must have a Minimum Current Ratio (as defined in the SG Facility) of not less than 1.00:1.00, a Maximum Leverage Ratio (as defined in the SG Facility) of not less than 4.00:1.00 and a Minimum Interest Coverage Ratio (as defined in the SG Facility) of at least 2.50:1.00. In addition, the SG Facility provided for customary events of default, including, but not limited to, payment defaults, breach of representations or covenants, bankruptcy events and change of control.debt

OnIn ~~August~~September 182018 the Company issued an unsecured promissory note dated effective September 11, ~~2016~~2018, asto I.O.C - Israel Oil Company LTD (“IOC”) a ~~result~~related party in which the company may borrow up to $7,000,000 at a rate of ~~semi~~interest equal to seven and one-~~annual~~half ~~borrowing~~percent ~~base~~(7.5%) ~~redetermination~~and with a maturity date of September 2019. The company received $3,600,000 under this related party note in 2018 attendant with the ~~borrowing~~creation ~~base~~of a new subsidiary, Arrow Midstream LLC. Amounts received under SGthe ~~Facility~~aforementioned ~~was~~promissory ~~reduced~~note are dedicated to ~~zero.~~working Oncapital ~~February~~and 28the purchase of equipment for Arrow Midstream LLC, ~~2017~~a new wholly owned subsidiary of Isramco Inc. Arrow Midstream is focused on the SGtransportation ~~Facility~~of ~~was~~liquefied ~~terminated~~petroleum products including, but not limited to, butane, propane, and similar products.

~~Related~~Mr. ~~Party~~Haim ~~Debt~~Tsuff, Isramco’s Co-Chief Executive Officer and Chairman and is a controlling shareholder of IOC.

AIsramco ~~discussion~~also ofhad ~~the Company’s~~ related party ~~debt~~payables ~~previously outstanding in fiscal year 2015 is set forth below. On June 27, 2015 the Company used a portion~~ of ~~the proceeds secured from the DB Facility to repay the then-outstanding principal and interest balances of the related party debt discussed below. The final payment totaled~~ $~~101~~165,~~022,~~000 ~~which included loan principal payments totaling $93,395,000~~ and ~~interest payments totaling~~ $760,~~267,~~000. ~~The~~as ~~remaining portion~~ of ~~the~~December ~~payment~~31, ~~equal~~2018 toand ~~$360,000~~2017 ~~repaid~~respectively ~~related~~which ~~party~~are ~~payables.~~included Aswith ~~result,~~short ~~all~~term ~~such~~ related party debt ~~was~~on ~~repaid and~~ the ~~outstanding~~ balance ~~as of December 31, 2015, 2016 and 2017 was zero~~sheets.

~~I.O.C.~~Off-Balance ~~Israel~~Sheet ~~Oil Company, Ltd. (“IOC”)~~Arrangements

OnAt ~~February 27~~December 31, ~~2007~~2018, ~~Isramco~~we ~~obtained~~did anot ~~loan~~have in the principal amount of $12,000,000 from IOC, repayable at the end of five years. Interest accrues at a per annum rate of LIBOR plus 6%. Principal is due and payable in four equal annual installments, commencing on the second anniversary of the loan. Accrued interest is payable in equal annual installments. At any ~~time~~off-balance ~~Isramco~~sheet ~~can make prepayments without premium or penalty~~arrangements. ~~The loan is not secured.~~

InCash July 2009, the Company entered into a loan transaction with IOC, a related party, pursuant to which the Company borrowed $6 million (the “IOC Loan”). Amounts outstanding under the IOC Loan bear interest at LIBOR plus 6.0%. The IOC Loan matures in five years, with accrued interest payable annually on each anniversary date of the loan. The IOC Loan may be prepaid at any time without penalty.Flow

~~Effective~~Our ~~February~~primary 1,source ~~2009~~of cash in 2018 was cash flow from operating activities. In 2018, ~~the~~cash ~~loan~~received from ~~IOC~~operations ~~was~~and ~~amended~~proceeds from sale of oil and ~~restated~~gas toproperties ~~extend~~was ~~the~~primarily ~~payment~~used ~~deadlines~~for ~~arising~~repayment onof ~~and~~long-term ~~after~~debt, ~~February~~short-term ~~2009~~debt, byinvestments ~~two~~in ~~years~~equipment.

OnOur ~~March~~primary 3,source ~~2011,~~of ~~the~~cash ~~Company~~in ~~entered~~2017 ~~into~~was acash ~~Loan~~flow ~~Agreement~~from ~~with~~operating ~~IOC~~activities. ~~pursuant~~In ~~to which it borrowed the sum of $11~~2017,~~000,000.~~ ~~The~~cash ~~loan~~received ~~bears~~from ~~interest~~operations ~~at a rate of 10% per annum~~ and isproceeds ~~payable~~from insale ~~quarterly payments~~ of ~~interest~~oil ~~only until March 3, 2013, when all accrued interest~~ and ~~principal~~gas isproperties ~~due~~was ~~and~~primarily ~~payable.~~used ~~The~~for ~~loan~~repayment ~~may~~of belong-term ~~prepaid at any time without penalty. The loan is unsecured. During September 2011~~debt, ~~Isramco~~short-term ~~paid $4~~debt,~~544,000~~ ofinvestments ~~principal~~in ~~pursuant to this Loan agreement with IOC leaving outstanding principle of $6,456,000.~~equipment

Subsequently, in October 2011 the agreement with IOC, pertaining to the above mentioned loan in the outstanding principal amount of $6,456,000 was renegotiated. The payoff of principal amount was extended by 6 month to September 9, 2013. Interest accrued per annum was determined on LIBOR+5.5% from initial 10%.38

OnTable ~~March 29, 2012, the Company entered into a Loan Agreement with IOC pursuant to which it borrowed $3,500,000. The loan bears interest at a rate~~ of Libor + 5.5% per annum and matures on March 29, 2013, when all accrued interest and principal is due and payable. The loan may be prepaid at any time without penalty or premium. The loan was unsecured.Contents

OnOur ~~April~~primary ~~29,~~source ~~2012,~~of ~~the~~cash ~~Company~~in ~~entered~~2016 ~~into~~was ~~another~~cash ~~Loan~~flow ~~Agreement~~from ~~with~~operating ~~IOC,~~activities. ~~pursuant~~In ~~to which it borrowed $10~~2016,~~000,000.~~ ~~The~~cash ~~loan~~received ~~bears~~from ~~interest~~operations ~~of Libor+5.5% per annum~~ and ~~matures~~proceeds onfrom ~~April~~sale ~~30,~~of ~~2013,~~oil ~~when all accrued interest~~ and ~~principal~~gas isproperties ~~due and payable. The loan may be prepaid at any time without penalty or premium. The loan~~ was ~~funded~~primarily byused ~~IOC in three monthly installments starting April 2012. The loan is unsecured. The purpose of the loan was to provide funds to Isramco~~ for ~~the~~repayment ~~payment~~ of ~~amounts~~long-term ~~that~~debt, ~~were~~short-term ~~due~~debt, toinvestments ~~the Lenders under the Senior Credit Facility that was paid~~ in ~~full June 29, 2012~~equipment.

OnOperating ~~February~~cash ~~13,~~flow ~~2013,~~fluctuations ~~the~~were ~~Company~~substantially ~~entered~~driven ~~into~~by ~~another~~changes ~~Loan~~in ~~Agreement~~commodity ~~with~~prices ~~IOC,~~and ~~pursuant~~changes toin ~~which~~our itproduction ~~borrowed $1,500,000~~volumes. ~~The~~Working ~~loan~~capital ~~bears~~was ~~interest~~substantially ofinfluenced ~~Libor+6%~~by ~~per~~these ~~annum~~variables. Fluctuation in commodity prices and ~~matures~~our onoverall ~~February~~cash ~~13,~~flow ~~2018,~~may ~~when~~result ~~all~~in ~~accrued~~an ~~interest~~increase ~~and~~or ~~principal~~decrease isin ~~due~~our ~~and~~future ~~payable~~capital expenditures. ~~The~~Prices ~~loan~~for ~~may~~oil beand ~~prepaid~~natural atgas ~~any~~have ~~time~~historically ~~without~~been ~~penalty~~subject orto ~~premium.~~seasonal ~~The~~fluctuations ~~loan~~characterized isby ~~unsecured. The~~peak ~~purpose~~demand ofand higher prices in the ~~loan~~winter ~~was~~heating toseason; ~~provide~~however, ~~funds~~the toimpact ~~back~~of upother risks and uncertainties have influenced prices throughout recent years. See Results of Operations below for a ~~Letter~~review of ~~Credit~~the impact of prices and volumes on sales.

	Years Ended December 31,
	2018			2017			2016
	(In thousands)
Cash flows provided by operating activities	$	17,167		$	18,552		$	15,510
Cash flows (used in) investing activities		(7,394	)		(1,461	)		(250	)
Cash flows (used in) financing activities		(16,267	)		(10,519	)		(10,691	)
Net increase (decrease) in cash	$	(6,494	)	$	6,572		$	4,569

~~Table~~Operating Activities, Net cash flows provided by operating activities were $17,167,000, $18,552,000, and $15,510,000 for the years ended December 31, 2018, 2017 and 2016, respectively. Key drivers of ~~Contents~~net operating cash flows are commodity prices, production volumes, operating costs, proceeds from an overriding royalty interest in the Tamar Field and activities of our production services subsidiary.

OnDuring ~~March 1, 2013, all of~~ the ~~above-mentioned~~year ~~Loan~~ended agreements and notes with IOC except for the $1,500,000 loan agreement entered on February 13, 2013, were amended. The terms of all these loans and notes between the Company and IOC were amended extending the maturity to December 31, 2018., Incompared ~~addition~~to the ~~payment~~same ~~schedule~~period ~~was~~in ~~changed on the all of the loans and notes to require accrued interest only payments December 31, 2014, December 31, 2015, December 31, 2016, December 31,~~ 2017 ~~and final interest payment December 31~~, ~~2018~~net ~~with~~cash ~~outstanding~~flow ~~principal~~provided ~~paid~~by inoperating ~~four~~activities ~~equal~~decreased ~~installments~~by ~~with the first payment December 31~~$1,385,000 ~~2015~~to ~~and a similar payment made December 31 in each of the following three years until the final payment on December 31~~$17, ~~2018~~167,000. ~~The other terms of the loan agreements and notes remained unchanged.~~

AsDuring ~~noted~~the ~~above,~~year onended ~~June~~December 2731, ~~2015~~2017, ~~the~~compared ~~Company~~to ~~used a portion of~~ the ~~proceeds~~same ~~secured~~period ~~from~~in ~~the~~2016, DBnet ~~Facility~~cash toflow ~~repay~~provided ~~the~~by ~~then-outstanding~~operating ~~principal~~activities ~~and~~increased ~~interest~~by ~~balances of the related party debt. Accordingly~~$3,042,000 ~~the~~to ~~IOC debts have been paid in full~~$18,552,000.

~~Mr.~~We ~~Haim~~are ~~Tsuff~~unable to predict future production levels, ~~Isramco’s~~future ~~Co-Chief~~commodity ~~Executive~~prices, ~~Officer~~future ~~and~~proceeds ~~Chairman~~from our Tamar Field royalties, and isfuture arevenues ~~controlling~~generated ~~shareholder~~by our production services segment; therefore, we cannot predict future levels of ~~IOC~~net cash provided by operating activities.

~~Naphtha~~Investing ~~Israel~~Activities, ~~Petroleum~~Net ~~Corp.~~cash ~~Ltd~~flows used in investing activities for the twelve months ended December 31, 2018 and 2017 were $7,394,000 and $1,461,000, respectively. During 2018 and 2017 the Company invested in equipment and oil and gas properties in amounts equal to $8,997,000 (~~“Naphtha”~~$796,000 in oil and gas properties and $8,201,000 in production services equipment) and $4,184,000 ($615,000 in oil and gas properties and $3,569,000 in production services equipment) respectively. During 2018 the Company received $1,435,000 from the sale of oil and gas properties and received $168,000 from the sale of equipment.

InNet ~~connection~~cash ~~with~~flows used in investing activities for the twelve months ended December 31, 2017 and 2016 were $1,461,000 and $250,000, respectively. During 2017 and 2016 the Company’s ~~purchase~~invested ofin ~~certain~~equipment and oil and gas ~~interests~~properties ~~mainly~~in amounts equal to $4,184,000 ($615,000 in ~~New~~oil ~~Mexico~~and gas properties and ~~Texas~~$3,569,000 in ~~February~~production ~~2007~~services equipment) and $794,000 ($157,000 in oil and gas properties and $637,000 in production services equipment), respectively. During 2017 the Company ~~obtained~~received ~~loan~~$2,705,000 from ~~Naphtha,~~the asale ~~related~~of ~~party~~oil and gas properties, ~~with~~invested ~~terms~~$31,000 in a LLC, and ~~conditions~~received as$49,000 ~~below:~~from the sale of equipment.

OnFinancing ~~February 27~~Activities, ~~2007,~~Net ~~Isramco~~cash ~~obtained~~flows aused ~~loan,~~ in ~~the~~financing ~~principal~~activities ~~amount~~were of $1116,~~500~~267,000 ~~from Naphtha, repayable at the end of seven years. Interest accrues at a per annum rate of LIBOR plus 6%. Principal is due~~ and ~~payable in four equal installments~~$10,519,000 ~~commencing~~for on the fourth anniversary of the date of the loan. Interest is payable annually upon each anniversary date of this loan. At any time Isramco can make prepayments without premium or penalty. The loan is not secured. Interest is payable at the end of each loan year. ~~Principal~~ended ~~plus~~December 31, ~~any~~2018 ~~accrued~~ and ~~unpaid interest are due and payable on February 27~~2017, ~~2014~~respectively. ~~Interest~~In ~~after the maturity date accrues at the per annum rate of LIBOR plus 12% until paid in full. At any time~~2018, ~~Isramco is entitled to prepay~~ the ~~outstanding~~Company ~~amount~~made ~~of the loan without penalty or prepayment. To secure its obligations that may be incurred under the Loan Agreement~~$18, ~~Jay Petroleum~~900,000 ~~LLC,~~in aprincipal ~~wholly~~loan ~~owned subsidiary of Isramco, agreed to guarantee the indebtedness~~payments. ~~Naphtha~~The ~~can~~Company ~~accelerate~~also ~~the~~repaid ~~loan~~short-term ~~and~~insurance ~~exercise~~financing ~~its rights under the collateral upon the occurrence any one or more~~ of ~~the following events of default: (i) Isramco’s failure to pay any amount that may become due in connection with the loan within five (5) days of the due date (whether by extension~~$950, ~~renewal~~000, ~~acceleration,~~received ~~maturity or otherwise) or fail to make any payment due under any hedge agreement entered into in connection with the transaction~~$3,600,000 ~~(ii)~~from ~~Isramco’s~~related ~~material~~party ~~breach of any of the representations or warranties made in the loan agreement or security instruments or any writing furnished pursuant thereto~~financing, ~~(iii)~~and ~~Isramco’s~~paid ~~failure to observe any undertaking contained in transaction documents if such failure continues for 30 calendar days after notice~~$17,000 ~~(iv) Isramco’s insolvency or liquidation or a bankruptcy event or (v) Isramco’s criminal indictment or conviction under any law pursuant~~ to ~~which~~non-controlling ~~such indictment or conviction can lead to a forfeiture by Isramco of any of the properties securing the loan~~interests.

~~Effective~~Net ~~February~~cash 1flows used in financing activities were $10,519,000 ~~2009~~and $10,691,000 for the ~~loan~~year ~~from~~ended ~~Naphtha~~December 31, to2017 ~~the~~and ~~Company~~2016, ~~was~~respectively. ~~amended~~In ~~and~~2017, ~~restated~~the toCompany ~~extend~~made ~~all~~$9,600,000 ~~payment~~in ~~deadlines~~principal ~~arising~~loan onpayments. ~~and~~The ~~after~~Company ~~February~~also ~~2009,~~repaid byshort-term ~~two~~insurance ~~years~~financing of $911,000.

On March 1, 2013, the terms of the existing loan and note between the Company and Naphtha was amended extending the maturity to December 31, 2018. The payment schedule was changed on the Naphtha loan and note to require interest only payments December 31, 2013, December 31, 2014, December 31, 2015, December 31, 2016, December 31, 2017 and the final interest payment December 31, 2018 with principal outstanding paid in four equal installments with the first payment December 31, 2015 and a similar payment made December 31 in each of the following three years until the final payment on December 31, 2018. The other terms of the loan agreement and note remained unchanged. 39

~~Mr.~~Table ~~Haim Tsuff, Isramco’s Co-Chief Executive Officer and Chairman and is a controlling shareholder~~ of ~~Naphtha.~~Contents

40Results of Continuing Operations

~~Table~~Selected ~~of Contents~~Data

Jerusalem Oil Exploration Ltd (“JOEL”)

	Years Ended December 31,
	2018			2017			2016
	(In thousands except per share and MBOE amounts)
Financial Results
Oil and Gas sales
United States	$	15,932		$	15,109		$	12,947
Israel		31,036			28,781			27,462
Production services		31,825			18,265			12,752
Gain on divestiture		1,452			2,703			600
Other		1,094			1,089			1,181
Total revenues and other		81,339			65,947			54,942

Cost and expenses		53,426			41,321			40,875
Other expense		4,299			4,815			5,544
Income tax expense		7,138			45,637			3,634
Net income (loss) attributable to common shareholders		16,476			(25,826	)		4,889
Net loss attributable to noncontrolling interests		(1,458	)		(1,516	)		(1,856	)
Net income (loss) attributable to Isramco		17,934			(24,310	)		6,745
Earnings (loss) per common share – basic	$	6.60		$	(8.95	)	$	2.48
Earnings (loss) per common share –diluted	$	6.60		$	(8.95	)	$	2.48

Weighted average number of shares outstanding-basic		2,717,648			2,717,648			2,717,648
Weighted average number of shares outstanding- diluted		2,717,648			2,717,648			2,717,648

Operating Results
Adjusted EBITDAX (1)	$	35,319		$	31,970		$	24,847
Total proved reserves (MBOE)		40,267			38,653			34,582
Sales volumes United States (MBOE)		430			483			528
Sales volumes Israel (MBOE)		939			897			857

Average cost per BOE - United States:
Production (excluding transportation and taxes)	$	18.11		$	15.79		$	13.76
General and administrative	$	13.55		$	9.65		$	8.49
Depletion of oil and gas properties	$	4.39		$	5.08		$	6.58

In(1) ~~February~~See ~~and~~Adjusted ~~March,~~EBITDAX ~~2008~~for ~~the~~a ~~Company~~description ~~obtained loans from JOEL in the aggregate principal amount~~ of ~~$48.9~~Adjusted ~~million~~EBITDAX, ~~repayable~~which atis ~~the~~not ~~end of 4 months at an interest rate of LIBOR plus 1.25% per annum. Pursuant to~~ a ~~loan~~Generally ~~agreement~~Accepted ~~signed~~Accounting inPrinciples ~~June~~(GAAP) ~~2009~~measure, ~~the~~and ~~maturity date of this loan was extended for an additional period of seven years. Interest accrues at~~ a ~~per~~reconciliation ~~annum rate~~ of ~~LIBOR~~Adjusted ~~plus~~EBITDAX ~~6%.~~to ~~Principal~~income ~~and~~from ~~interest~~operations ~~are~~before ~~due~~income ~~and payable in four equal annual installments~~taxes, ~~commencing~~which onis ~~June~~presented ~~30,~~in ~~2013.~~accordance Atwith ~~any time, we can make prepayments without premium or penalty~~GAAP.

On June 30, 2013, the terms of an Amended and Restated Loan Agreement dated May 25, 2008, and note between the Company and Jerusalem Oil Exploration, Ltd. (“JOEL”) were amended to extend the maturity date to June 30, 2017. The payment schedule of the loan agreement and note was amended to require principal and accrued interest to be paid in three (3) installments in the amounts reflected in Promissory Note due on June 30th of each year commencing June 30, 2015. The other terms of the loan agreement and note remained unchanged.40

~~Mr.~~Table ~~Jackob Maimon, Isramco’s president at the time and a former director~~ of ~~the Company is a director of JOEL. Mr. Haim Tsuff, Isramco’s Co-Chief Executive Officer and Chairman, is a controlling shareholder of JOEL.~~Contents

AsFinancial noted above, on June 27, 2015 the Company used a portion of the proceeds secured from the DB Facility to repay the then-outstanding principal and interest balances of the related party debt. Accordingly, the JOEL debts have been paid in full.Results

~~Isramco~~Net ~~also~~Income ~~had related party payables of $60,000 and $90,000 as of December 31, 2017 and 2016 respectively which are included with short term related party debt on the balance sheets.~~(Loss)

~~Off-Balance~~In ~~Sheet~~2018 ~~Arrangements~~our net income was $17,934,000, or $6.60 per share. This compares to net loss of $(24,310,000), or $(8.95) per share for the year ended December 31, 2017.

AtIn ~~December 31~~2017 the Company had a one-time increase in allowance for foreign tax credit and deferred tax assets. We fully allowed for our accumulated future tax credit related to the taxes withheld by the Israeli taxing authorities. The valuation allowance amounted to $28,677,000. ~~2017~~Total foreign tax credit balance was written off in 2018 after the passing of new tax legislation in the United States which lowered the corporate tax rate to a level that eliminated the forecasted usage of the accumulated foreign tax credit. Likewise, we ~~did~~increased ~~not~~our ~~have~~allowance ~~any~~to ~~off-balance~~fully ~~sheet~~allow ~~arrangements~~for our deferred tax assets (see Note 6 – Income Tax to the Company’s consolidated financial statements). Net income comparatively increased in 2018 because we had no such increase in the allowance in 2018. In addition, the average commodity prices in 2018 were more than those of 2017, increasing our production revenues despite lower production volumes in the United States.

~~Cash~~In ~~Flow~~2017 our net loss was $(24,310,000), or $(8.95) per share. This compares to net income of $6,745,000, or $2.48 per share for the year ended December 31, 2016.

~~Our~~This ~~primary~~decrease ~~source~~in ofincome ~~cash~~is primarily due to the increase in ~~2017~~allowance ~~was~~for ~~cash~~foreign ~~flow~~tax ~~from~~credit ~~operating~~and ~~activities~~deferred tax assets. InWe ~~2017~~fully allowed for our accumulated future tax credit related to the taxes withheld by the Israeli taxing authorities. The valuation allowance amounted to $28,677,000. ~~cash~~Total ~~received~~foreign ~~from~~tax ~~operations~~credit ~~and~~balance ~~proceeds~~was ~~from~~written ~~sale~~off after the passing of ~~oil~~new ~~and~~tax ~~gas~~legislation ~~properties~~in ~~was~~the ~~primarily~~United ~~used~~States ~~for~~which ~~repayment~~lowered the corporate tax rate to a level that eliminated the forecasted usage of ~~long-term~~the ~~debt~~accumulated foreign tax credit. Likewise we increased our allowance to fully allow for our deferred tax assets (see Note 6 – Income Taxes to the Company’s consolidated financial statements). Income Tax. This increase in tax expense was partially offset by increased revenues from our United States based production operations, ~~short-term~~increased ~~debt~~revenues from the Tamar field, ~~investments~~increased inrevenues ~~equipment~~from production service activities, and an ~~increase~~increased in ~~restricted~~gain ~~cash~~on divestiture.

~~Our primary source of cash in 2016 was cash flow from operating activities. In 2016~~Revenues, ~~cash~~Volumes ~~received from operations~~ and ~~proceeds~~Average ~~from~~Prices ~~sale~~Oil ~~of oil~~ and ~~gas~~Gas ~~properties~~Segment ~~was primarily used for repayment of long~~-~~term~~ ~~debt, short-term debt, investments in equipment and an increase in restricted cash.~~Israel

~~Our~~During ~~primary~~year ~~source~~ended ofDecember ~~cash~~31, in2018, ~~2015~~net ~~was~~sales ~~cash flow~~ from ~~financing~~the ~~activities.~~Tamar InField ~~2015,~~attributable ~~net~~to ~~cash~~the ~~received~~Company ~~from~~amounted ~~bank~~to ~~loans~~5,591,000 ~~sales~~Mcf of ~~property,~~natural gas and ~~operating~~7,335 ~~activities~~Bbl ~~was~~of ~~primarily~~condensate ~~used~~with toprices ~~replay~~of ~~related~~$5.49 ~~party~~per ~~loans~~Mcf and ~~short-term~~$62.95 ~~debt,~~per ~~increase~~Bbl ~~restricted~~of ~~cash,~~condensate. Total revenues net of marketing and ~~investment~~transportation inexpenses ~~equipment~~were ~~for~~$31,036,000. ~~our~~The ~~production~~Israeli ~~services~~Tax ~~subsidiary~~Authority ~~and~~withheld ~~oil~~$7,138,000 ~~and~~of ~~gas~~this ~~properties~~revenue.

41During year ended December 31, 2017, net sales from the Tamar Field attributable to the Company amounted to 5,343,000 Mcf of natural gas and 6,990 Bbl of condensate with prices of $5.35 per Mcf and $47.46 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $28,781,000. The Israeli Tax Authority withheld $6,907,000 of this revenue.

~~Table~~During the year ended December 31, 2016, net sales from the Tamar Field attributable to the Company amounted to 5,102,000 Mcf of ~~Contents~~natural gas and 6,882 Bbl of condensate with prices of $5.34 per Mcf and $37.48 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $27,462,000. The Israeli Tax Authority withheld $6,866,000, of this revenue.

~~Operating~~Revenues, ~~cash~~Volumes ~~flow fluctuations were substantially driven by changes in commodity prices~~ and ~~changes~~Average in our production volumes. Working capital was substantially influenced by these variables. Fluctuation in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures. Prices Oil ~~for oil~~ and ~~natural~~Gas ~~gas~~Segment ~~have~~- ~~historically~~United been subject to seasonal fluctuations characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See Results of Operations below for a review of the impact of prices and volumes on sales.States

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Cash flows provided by operating activities	$	18,552		$	15,510		$	8,911
Cash flows (used in) investing activities		(4,114	)		(807	)		(4,680	)
Cash flows provided by (used in) financing activities		(10,519	)		(10,691	)		15,820
Net increase in cash	$	3,919		$	4,012		$	20,051

Sales Revenues

Operating Activities, Net cash flows provided by operating activities were $18,552,000, $15,510,000, and $8,911,000 for the years ended December 31, 2017, 2016 and 2015, respectively. Key drivers of net operating cash flows are commodity prices, production volumes, operating costs, proceeds from an overriding royalty interest in the Tamar Field and activities of our production services subsidiary.

	Years Ended December 31,
In thousands except percentages	2018		2017		Dvs. 2017			2016		D vs. 2016
Gas sales	$	3,133	$	3,955		(21	)%	$	3,209		23	%
Oil sales		11,195		9,558		17			8,506		12
Natural gas liquid sales		1,604		1,596		1			1,232		30
Total	$	15,932	$	15,109		5	%	$	12,947		17	%

~~During~~Our sales revenues for the year ended December 31, ~~2017,~~2018 increased by 5% when compared to the same period inof ~~2016~~2017, ~~net~~due ~~cash~~to ~~flow~~increase ~~provided~~in prices for crude oil and natural gas liquids partially offset by ~~operating~~reduced ~~activities~~production volumes and reduced prices for natural gas. Our sales revenues for the year ended December 31, 2017 increased by $317% when compared to the same period of 2016,~~042,000~~ primarily due to ~~$18~~increase in prices for natural gas,~~552~~ crude oil,~~000~~ and natural gas liquids partially offset by reduced production volumes.

~~During the year ended December 31, 2016, compared to the same period in 2015, net cash flow provided by operating activities increased by $6,599,000 to $15,510,000.~~41

WeTable are unable to predict future production levels, future commodity prices, future proceeds from our Tamar Field royalties, and future revenues generated by our production services segment; therefore, we cannot predict future levels of ~~net cash provided by operating activities.~~Contents

~~Investing~~Volumes ~~Activities, Net cash flows used in investing activities for the twelve months ended December 31, 2017~~ and ~~2016~~Average were $4,114,000 and $807,000, respectively. During 2017 and 2016 the Company invested in equipment and oil and gas properties in amounts equal to $4,184,000 ($615,000 in oil and gas properties and $3,569,000 in production services equipment) and $794,000 ($157,000 in oil and gas properties and $637,000 in production services equipment) respectively. During 2017 the Company increased restricted cash by $2,653,000, received $2,705,000 from the sale of oil and gas properties, invested $31,000 in a LLC, and received $49,000 from the sale of equipment.Prices

Net cash flows used in investing activities for the twelve months ended December 31, 2016 and 2015 were $807,000 and $4,680,000, respectively. During 2016 and 2015 the Company invested in equipment and oil and gas properties in amounts equal to $794,000 ($157,000 in oil and gas properties and $637,000 in production services equipment) and $4,883,000 ($2,292,000 in oil and gas properties and $2,591,000 in production services equipment) respectively. During 2016 the Company increased restricted cash by $557,000, received $600,000 from the sale of oil and gas properties, invested $133,000 in a LLC, and received $77,000 from the sale of equipment.

	Years Ended December 31,
	2018		2017		Dvs. 2017			2016		Dvs. 2016
Natural Gas
Sales volumes Mmcf		1,119		1,320		(15	)%		1,417		(7	)%
Price per Mcf	$	2.80	$	3.00		(7	)	$	2.26		33
Total gas sales revenues (thousands)	$	3,133	$	3,955		(21	)%	$	3,209		23	%

Crude Oil
Sales volumes MBbl		184		196		(6	)%		215		(9	)%
Price per Bbl	$	60.84	$	48.77		25		$	39.56		23
Total oil sales revenues (thousands)	$	11,195	$	9,558		17	%	$	8,506		12	%

Natural gas liquids
Sales volumes MBbl		59		67		(12	)%		77		(13	)%
Price per Bbl	$	27.19	$	23.82		14		$	16.00		49
Total natural gas liquids sales revenues (thousands)	$	1,604	$	1,596		1	%	$	1,232		30	%

~~Financing~~The ~~Activities,~~Company’s ~~Net~~natural ~~cash~~gas ~~flows~~sales ~~used~~volumes indecreased ~~financing~~by ~~activities were $10~~15%,~~519,000~~ ~~and~~crude ~~$10,691,000~~oil ~~for~~sales ~~the~~volumes ~~year~~decreased ~~ended~~by ~~December 31,~~6% ~~2017~~ and ~~2016,~~natural ~~respectively.~~gas Inliquids ~~2017,~~sales ~~the~~volumes ~~Company~~decreased ~~made~~by ~~$9,600,000~~12% infor ~~principal~~the ~~loan~~year ~~payments.~~ended ~~The~~December ~~Company~~31, ~~also~~2018 ~~repaid~~compared ~~short-term~~to ~~insurance~~the ~~financing~~same period of ~~$911,000~~2017.

~~Net~~Our ~~cash~~average ~~flows~~natural ~~provided~~gas byprice ~~(used~~for ~~in)~~the ~~financing~~year ~~activities~~ended ~~were~~December ~~($10~~31,~~691~~ 2018 decreased by 7%,~~000)~~ ~~and~~or $150.20 per Mcf,~~820,000~~ when compared to the same period of 2017. Our average crude oil price for the year ended December 31, ~~2016~~2018 ~~and~~increased ~~2015~~by 25%, ~~respectively~~or $12.07 Inper ~~2016~~Bbl, ~~the~~when ~~Company~~compared ~~made~~to ~~$9,000,000~~the insame ~~principal~~period ~~loan~~of ~~payments~~2017. ~~The~~Our ~~Company~~average ~~also~~natural ~~repaid~~gas ~~short-term~~liquids ~~insurance~~price ~~financing~~for ofthe ~~$1,341,000,~~year ~~and~~ended ~~decreased~~December ~~bank~~31, ~~overdraft~~2018 increased by 14%, or $~~350~~3.37 per Bbl,~~000~~ when compared to the same period of 2017.

42The Company’s natural gas sales volumes decreased by 7%, crude oil sales volumes decreased by 9% and natural gas liquids sales volumes decreased by 13% for the year ended December 31, 2017 compared to the same period of 2016.

~~Table~~Our average natural gas price for the year ended December 31, 2017 increased by 33%, or $0.74 per Mcf, when compared to the same period of ~~Contents~~2016. Our average crude oil price for the year ended December 31, 2017 increased by 23%, or $9.21 per Bbl, when compared to the same period of 2016. Our average natural gas liquids price for the year ended December 31, 2017 increased by 49%, or $7.82 per Bbl, when compared to the same period of 2016.

~~Results~~Analysis of ~~Continuing~~Oil and Gas Operations Sales Revenues

~~Selected~~The ~~Data~~following table provides a summary of the effects of changes in volumes and prices on Isramco’s sales revenues for the year ended December 31, 2018 compared to 2017 and 2016.

	Years Ended December 31,
In thousands	Natural Gas			Oil			Natural gas liquids
	2017			2016			2015
2016 sales revenues	$	3,209		$	8,506		$	1,232
	(In thousands except per share and MBOE amounts)
Changes associated with sales volumes		(220	)		(752	)		(160	)
Financial Results
Changes in prices		966			1,804	)		524
Oil and Gas sales
2017 sales revenues	$	3,955		$	9,558		$	1,596
United States	$	15,109		$	12,947		$	17,047
Changes associated with sales volumes		(602	)		(585	)		(191	)
Israel		28,781			27,462			25,151
Changes in prices		(220	)		2,222			199
Production services		18,265			12,752			22,465
2018 sales revenues	$	3,133		$	11,195		$	1,604
Gain on divestiture		2,703			600			8,378
Other		1,089			1,181			1,468
Total revenues and other		65,947			54,942			74,509
Cost and expenses		41,321			40,875			97,365
Other expense		4,815			5,544			7,383
Income tax expense (benefit)		45,637			3,634			(9,251	)
Net income (loss) attributable to common shareholders		(25,826	)		4,889			(20,988	)
Net income (loss) attributable to noncontrolling interests		(1,516	)		(1,856	)		(3,678	)
Net income (loss) attributable to Isramco		(24,310	)		6,745			(17,310	)
Earnings (loss) per common share – basic	$	(8.95	)	$	2.48		$	(6.37	)
Earnings (loss) per common share –diluted	$	(8.95	)	$	2.48		$	(6.37	)
Weighted average number of shares outstanding-basic		2,717,648			2,717,648			2,717,648
Weighted average number of shares outstanding- diluted		2,717,648			2,717,648			2,717,648
Operating Results
Adjusted EBITDAX (1)	$	31,970		$	24,847		$	31,177
Total proved reserves (MBOE)		38,653			34,582			36,220
Sales volumes United States (MBOE)		483			528			623
Sales volumes Israel (MBOE)		897			857			757
Average cost per BOE - United States:
Production (excluding transportation and taxes)	$	15.79		$	13.76		$	19.88
General and administrative	$	9.65		$	8.49		$	7.71
Depletion of oil and gas properties	$	5.08		$	6.58		$	9.77

(1) See Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a Generally Accepted Accounting Principles (GAAP) measure, and a reconciliation of Adjusted EBITDAX to income from operations before income taxes, which is presented in accordance with GAAP.42

~~Financial~~Table ~~Results~~of Contents

~~Net~~Operating ~~Income~~Expenses (~~Loss~~excluding production services segment)

In 2017 our net loss was $(24,310,000), or $(8.95) per share. This compares to net income of $6,745,000, or $2.48 per share for the year ended December 31, 2016.

	Years Ended December 31,
In thousands except percentages	2018		2017		D vs. 2017			2016			D vs. 2016
Lease operating expense, transportation and taxes	$	9,381	$	9,478		(1	)%	$	8,925			6	%
Depreciation, depletion and amortization of oil and gas properties		1,886		2,454		(23	)		3,474			(29	)
Impairments of oil and gas assets		1,252		1,682		(26	)		4,529			(63	)
Accretion expense		869		913		(5	)		897			2
Loss from plug and abandonment		281		26		NM			(3	)		NM
General and administrative		5,821		4,662		25			4,485			4
	$	19,490	$	19,215		1	%	$	22,307			(14	)%

~~This~~NM ~~decrease~~– inNot income is primarily due to the increase in allowance for foreign tax credit and deferred tax assets. We fully allowed for our accumulated future tax credit related to the taxes withheld by the Israeli taxing authorities. The valuation allowance amounted to $28,677,000. Total foreign tax credit balance was written off after the passing of new tax legislation of New Tax Reform in the United States which lowered the corporate tax rate to a level that eliminated the forecasted usage of the accumulated foreign tax credit. Likewise we increased our allowance to fully allow for our deferred tax assets see Item 5 Income Tax. This increase in tax expense was partially offset by increased revenues from our United States based production operations, increased revenues from the Tamar field, increased revenues from production service activities, and an increased in gain on divestiture.Meaningful

43During 2018, our operating expenses increased by 1% when compared to 2017 as highlighted below:

~~Table~~● Lease operating expense, transportation cost and taxes decreased by 1%, or $97,000 in 2018 when compared to 2017. On a per unit basis, lease operating expenses (excluding transportation and taxes) increased by $2.32 per MBOE to $18.11 per MBOE in 2018 from $15.79 per MBOE in 2017. The increase was a result of ~~Contents~~an increase in repair and maintenance activity.

In● ~~2016~~Depreciation, Depletion & Amortization (DD&A) of the cost of proved oil and gas properties is calculated using the unit-of-production method. Our DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact our ~~net~~composite ~~income~~DD&A ~~was~~rate $6and expense,~~745~~ including but not limited to field production profiles,~~000~~ drilling or acquisition of new wells, disposition of existing wells, and reserve revisions (upward or ~~$2.48~~downward) ~~per~~primarily ~~share~~related to well performance and commodity prices, and impairments. ~~This~~Changes ~~compares~~in these factors may cause our composite DD&A rate and expense to ~~net~~fluctuate ~~loss~~from ofperiod to period. DD&A decreased by 23%, or $~~(17~~568,~~310,~~000), orin 2018 when compared to 2017. On a per unit basis, depletion expenses decreased by $(60.~~37)~~69 per ~~share~~MBOE ~~for~~to ~~the~~$4.39 ~~year~~per ~~ended~~MBOE ~~December~~in ~~31,~~2018 ~~2015~~from $5.08 per MBOE in 2017 due to a lower beginning balance resulted from previous years impairments and lower production volumes compared to 2017.

~~This~~● ~~increase~~Impairments ~~was~~of ~~primarily~~oil ~~due to the decrease in impairment expense from $43,704,000 in 2015 to $4,529,000 in 2016. Additionally lease operating expenses decreased by $5,903,000 from $14,828,000 in 2015 to $8,925,000 in 2016~~ and ~~Tamar~~gas ~~Field~~assets ~~proceeds~~of ~~increased by~~ $21,~~311~~252,000 ~~from $25,151,000~~ in ~~2015~~2018 towere ~~$27,462,000~~primarily inthe ~~2016.~~result ~~This~~of ~~increase~~lower ~~was~~estimated ~~offset~~future ~~by decreased revenues from our US based oil and gas assets and~~ production ~~services subsidiary which was driven by decrease~~ in ~~natural~~several ~~gas~~fields ~~and crude oil prices~~ which ~~in turn~~ reduced ~~demand~~the ~~for~~projected ~~our~~value ~~production~~in ~~services;~~those ~~and~~fields ~~lower~~from ~~sales~~prior ~~volumes~~estimates ~~of oil, natural gas~~ and ~~NGLs.~~resulted ~~Additionally the increase~~ in ~~net~~a ~~income~~projected ~~was~~value ~~offset~~ lower ~~gain~~than onthe ~~divestiture,~~carrying ~~$600,000~~value inof ~~2016~~those asfields ~~compared~~which totriggered ~~$8,378,000 in 2015~~impairment.

~~Revenues,~~● ~~Volumes~~Loss from plugging and ~~Average~~abandonment ~~Prices~~expenses ~~Oil~~increased ~~and~~by ~~Gas~~$255,000 ~~Segment~~in 2018 when compared to 2017, primarily due to larger than planned costs to plug non-operated ~~Israel~~wells.

~~During~~● ~~year~~General ~~ended~~and ~~December~~administrative ~~31,~~expenses ~~2017,~~increased ~~net~~by ~~sales~~25% ~~from~~or ~~the Tamar Field attributable to the Company amounted to 5~~$1,~~343~~159,000 ~~Mcf~~primarily ofas ~~natural~~a ~~gas~~result ~~and 6,990 Bbl~~ of ~~condensate~~increased ~~with~~professional ~~prices~~fees ofin ~~$5.35~~2018 ~~per~~as ~~Mcf~~compared ~~and~~to ~~$47~~2017.~~46 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $28,781,000. The Israeli Tax Authority withheld $6,907,000 of this revenue.~~

During ~~the year ended December 31~~2017, ~~2016,~~our ~~net~~operating ~~sales~~expenses ~~from~~decreased ~~the~~by ~~Tamar~~14% ~~Field~~when ~~attributable~~compared to ~~the~~2016 ~~Company~~as ~~amounted~~highlighted to 5,102,000 Mcf of natural gas and 6,882 Bbl of condensate with prices of $5.34 per Mcf and $37.48 per Bbl of condensate. Total revenues net of marketing and transportation expenses were $27,462,000. The Israeli Tax Authority withheld $6,866,000, of this revenue.below:

~~During~~● ~~year~~Lease ~~ended~~operating ~~December 31~~expense, ~~2015,~~transportation ~~net~~cost ~~sales~~and ~~from~~taxes ~~the~~increased ~~Tamar~~by ~~Field~~6%, ~~attributable~~or to$553,000 ~~the~~in ~~Company~~2017 ~~amounted~~when compared to 42016. On a per unit basis,~~505,000~~ ~~Mcf~~lease ofoperating ~~natural~~expenses ~~gas~~(excluding transportation and ~~6,074~~taxes) ~~Bbl~~increased ofby ~~condensate~~$2.03 ~~with~~per ~~prices~~MBOE ofto $515.5279 per ~~Mcf~~MBOE ~~and~~in 2017 from $4613.5376 per ~~Bbl~~MBOE ofin ~~condensate~~2016. ~~Total~~The ~~revenues~~increase ~~net~~was a result of ~~marketing~~an ~~and~~increase ~~transportation~~in ~~expenses~~repair ~~were~~and ~~$25,151,000.~~maintenance ~~The~~activity ~~Israeli~~as ~~Tax~~oil, ~~Authority~~natural ~~withheld~~gas ~~$6,665,000~~and ofNGLs ~~this~~prices ~~revenue~~increased.

~~Revenues~~● Depreciation, ~~Volumes~~Depletion ~~and~~&Amortization ~~Average~~(DD&A) ~~Prices Oil~~of the cost of proved oil and ~~Gas~~gas ~~Segment~~properties is calculated using the unit-of-production ~~United~~method. ~~States~~Our DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact our composite DD&A rate and expense, including but not limited to field production profiles, drilling or acquisition of new wells, disposition of existing wells, and reserve revisions (upward or downward) primarily related to well performance and commodity prices, and impairments. Changes in these factors may cause our composite DD&A rate and expense to fluctuate from period to period. DD&A decreased by 29%, or $1,020,000, in 2017 when compared to 2016. On a per unit basis, depletion expenses decreased by $1.50 per MBOE to $5.08 per MBOE in 2017 from $6.58 per MBOE in 2016 due to a lower beginning balance resulted from previous years impairments and lower production volumes compared to 2016.

~~Sales Revenues~~43

	Years Ended December 31,
In thousands except percentages	2017		2016		Dvs. 2016			2015		D vs. 2015
Gas sales	$	3,955	$	3,209		23	%	$	3,935		(18	)%
Oil sales		9,558		8,506		12			11,677		(27	)
Natural gas liquid sales		1,596		1,232		30			1,435		(14	)
Total	$	15,109	$	12,947		17	%	$	17,047		(24	)%

Table of Contents

~~Our~~● ~~sales~~Impairments ~~revenues~~of ~~for~~oil ~~the~~and ~~year~~gas ~~ended~~assets ~~December~~of 31$1,682,000 in 2017 ~~increased~~were byprimarily ~~17% when compared to~~ the ~~same~~result ~~period~~ of ~~2016,~~lower ~~due~~estimated tofuture ~~increase~~production in ~~prices~~several ~~for~~fields ~~natural~~which ~~gas and crude oil and natural gas liquids partially offset by~~ reduced ~~production~~the ~~volumes.~~projected ~~Our~~value ~~sales~~in ~~revenues~~those ~~for~~fields ~~the~~from ~~year~~prior ~~ended~~estimates ~~December~~and ~~31,~~resulted ~~2016~~in ~~decreased~~a byprojected ~~24%~~value ~~when~~lower ~~compared~~than to the ~~same~~carrying ~~period~~value of ~~2015,~~those ~~primarily~~fields ~~due~~which totriggered ~~decrease in prices and production volumes for crude oil and natural gas~~impairment.

~~Volumes~~● Loss from plugging and ~~Average~~abandonment ~~Prices~~expenses increased by $29,000 in 2017 when compared to 2016, primarily due to an increase in the wells plugged in 2017.

	Years Ended December 31,
	2017		2016		D vs. 2016			2015		D vs. 2015
Natural Gas
Sales volumes Mmcf		1,320		1,417		(7	)%		1,640		(14	)%
Price per Mcf	$	3.00	$	2.26		33		$	2.40		(6	)
Total gas sales revenues (thousands)	$	3,955	$	3,209		23	%	$	3,935		(18	)%
Crude Oil
Sales volumes MBbl		196		215		(9	)%		257		(16	)%
Price per Bbl	$	48.77	$	39.56		23		$	45.44		(13	)
Total oil sales revenues (thousands)	$	9,558	$	8,506		12	%	$	11,677		(27	)%
Natural gas liquids
Sales volumes MBbl		67		77		(13	)%		93		(17	)%
Price per Bbl	$	23.82	$	16.00		49		$	15.43		4
Total natural gas liquids sales revenues (thousands)	$	1,596	$	1,232		30	%	$	1,435		(14	)%

●	General and administrative expenses increased as a result of increased professional fees. This increase was partially offset by a lesser increase in allowance for doubtful accounts and no write off of deferred financing costs as had occurred in 2016.

44Production Services Segment

Table of Contents

	Years Ended December 31,
In thousands except percentages	2018			2017			D vs. 2017			2016			D vs. 2016
Production Services (1)	$	32,164		$	18,265			76	%	$	12,752			43	%
Operating expenses		29,725			18,241			63			14,494			26
Depreciation		3,657			3,072			19			3,193			(4	)
General and administrative (1)		1,013			913			11			1,001			(9	)
Operating income	$	(2,231	)	$	(3,961	)		44	%	$	(5,936	)		33	%

~~The~~(1) Production ~~Company’s~~Services ~~natural~~revenue ~~gas~~includes ~~sales~~intersegment ~~volumes~~revenues ~~decreased by 7%, crude oil sales volumes decreased by 9%~~ and ~~natural gas liquids sales volumes decreased by 13% for the year ended December 31, 2017 compared to the same period of 2016~~expenses.

~~Our~~● ~~average~~The ~~natural~~revenues ~~gas~~from ~~price~~production ~~for~~services ~~the~~operations ~~year~~in ~~ended~~2018 ~~December 31, 2017~~ increased by 3376%, or $~~0.74 per Mcf~~13,899,000 when compared to ~~the~~2017 ~~same~~primarily ~~period~~due ofto ~~2016.~~a ~~Our~~continued ~~average~~rebound in crude oil ~~price~~prices ~~for~~which ~~the~~resulted ~~year~~in ~~ended~~growth ~~December~~in ~~31,~~our ~~2017~~trucking ~~increased~~services bythrough ~~23%,~~customer ~~or $9~~acquisition.21 ~~per~~The ~~Bbl,~~revenues ~~when~~from ~~compared~~production toservices ~~the~~operations ~~same~~in ~~period~~2017 ofincreased ~~2016.~~by ~~Our~~43% ~~average~~or ~~natural~~$5,513,000 ~~gas~~when ~~liquids~~compared ~~price~~to ~~for~~2016 ~~the~~primarily ~~year~~due ~~ended~~to ~~December~~a ~~31,~~rebound ~~2017~~in ~~increased~~crude byoil ~~49%,~~prices orwhich ~~$7.82~~resulted ~~per~~in ~~Bbl,~~growth ~~when~~in ~~compared~~our totrucking ~~the~~services ~~same~~through ~~period~~customer ~~of 2016~~acquisition.

~~The~~● ~~Company’s~~Operating ~~natural~~expenses ~~gas~~from ~~sales~~production ~~volumes~~services ~~decreased~~operations for the year ended December 31, 2018 has increased by 1463% or $11,484,000 ~~crude~~when ~~oil~~compared ~~sales~~to ~~volumes~~the ~~decreased~~same byperiod ~~16%~~in 2017. The increase was primarily associated with an increase in payroll, fuel, and ~~natural~~other ~~gas~~related ~~liquids~~expenses ~~sales~~as ~~volumes~~a ~~decreased~~result byof ~~17%~~increase in trucking services. Operating expenses from production services operations for the year ended December 31, ~~2016~~2017 has increased by 26% or $3,747,000 when compared to the same period in 2016. The increase was primarily associated with an increase in payroll, fuel, and other related expenses as a result of ~~2015~~increase in trucking services.

~~Our~~● ~~average~~Production ~~natural~~service ~~gas~~equipment ~~price~~depreciation ~~for~~– the ~~year~~amounts ~~ended~~represent ~~December~~depreciation ~~31,~~for ~~2016~~our ~~decreased~~production byservices ~~6%,~~rigs orand ~~$0.14~~auxiliary ~~per Mcf, when compared to the same period of 2015~~equipment. ~~Our~~The ~~average~~depreciation ~~crude~~expense ~~oil price~~ for the year ended December 31, ~~2016~~2018 ~~decreased~~increased by ~~13%, or~~ $~~5.88 per Bbl~~585,000 ~~when~~ compared to ~~the~~2017 ~~same~~as ~~period~~a result of ~~2015.~~increased ~~Our~~investment ~~average~~in ~~natural~~equipment. ~~gas~~The ~~liquids~~depreciation ~~price~~expense for the year ended December 31, ~~2016~~2017 ~~increased~~decreased by ~~4%, or~~ $~~0.57 per Bbl~~121,000 ~~when~~ compared to ~~the same period of 2015~~2016.

~~Analysis~~● For the year ended December 31, 2018 general and administrative expenses increased by 11% or $100,000 from 2017 primarily as a result of ~~Oil~~increased professional fees and ~~Gas~~increase ~~Operations~~in ~~Sales~~the ~~Revenues~~allowance for doubtful accounts partially offset by decreased legal fees. For the year ended December 31, 2017 general and administrative expenses decreased by 9% or $88,000 from 2016 primarily as a result of lesser increase in the allowance for doubtful accounts partially offset by increased legal fees.

~~The following table provides a summary of the effects of changes in volumes and prices on Isramco’s sales revenues for the year ended December 31, 2017 compared to 2016 and 2015.~~44

In thousands	Natural Gas			Oil			Natural gas liquids
2015 sales revenues	$	3,935		$	11,677		$	1,435
Changes associated with sales volumes		(535	)		(1,908	)		(247	)
Changes in prices		(191	)		(1,263	)		44
2016 sales revenues	$	3,209		$	8,506		$	1,232
Changes associated with sales volumes		(220	)		(752	)		(160	)
Changes in prices		966			1,804			524
2017 sales revenues	$	3,955		$	9,558		$	1,596

Table of Contents

~~Operating~~Other ~~Expenses (excluding production services segment)~~expenses

	Years Ended December 31,
In thousands except percentages	~~2017~~2018			~~2016~~2017			D vs. ~~2016~~2017			~~2015~~2016		D vs. ~~2015~~2016
Lease operating expense, transportation and taxes	$	9,478		$	8,925			6	%	$	14,828		(40	)%
Interest expense net	$	4,921		$	4,784			3	%	$	4,817		(1	)%
Depreciation, depletion and amortization of oil and gas properties		2,454			3,474			(29	)		6,091		(43	)
Interest expense – related party, net		71			-			NM			-		0
Impairments of oil and gas assets		1,682			4,529			(63	)		33,138		(86	)
Loss (gain) from derivative contracts, net		(680	)		176			486			657		(73	)
Accretion expense		913			897			2			856		5
Capital (gain) loss		(13	)		(145	)		(91	)		70		307
Loss from plug and abandonment		26			(3	)	NM				91		(103	)
	$	4,299		$	4,815			(11	)%	$	5,544		(13	)%
General and administrative		4,662			4,485			4			4,806		(7	)
	$	19,215		$	22,307			(14	)%	$	59,810		(63	)%

NM● –Net ~~Not~~interest ~~Meaningful~~expense. Isramco’s interest expense increased, by $208,000 for the twelve months ended December 31, 2018 compared to the same period of 2017 as indexed interest rate on the DB Facility increased with increased LIBOR rates. Also, the Company secured additional related party financing which increased the principal outstanding under the DB Facility. These increases were partially offset by the reduced principal balance on the DB Facility from principal payments.

45Net Interest expense. Isramco’s interest expense decreased only slightly, by $33,000 for the twelve months ended December 31, 2017 compared to the same period of 2016 as increased interest income from investment and the reduced principal balance on loans was partially offset by the increase in the indexed interest rate.

~~Table~~● Net loss on derivative contracts. During 2015 we entered into interest rate cap and swap agreements. These agreements are considered derivative and are accounted for with mark-to-market valuation. The loss in fair value of ~~Contents~~these contracts is recorded in the statement of operations. The loss from derivative contracts decreased from $657,000 in 2016 and to $176,000 in 2017 and turned to a gain of $680,000 in 2018 primarily as a result of an increase in the estimated future LIBOR rate which is a factor in determining the market value of the derivatives.

~~During~~Income ~~2017,~~Taxes ~~our~~and ~~operating~~Impact ~~expenses~~of ~~decreased~~Tax byReform ~~14% when compared to 2016 as highlighted below:~~Legislation

●Income ~~Lease~~tax ~~operating~~ expense, ~~transportation~~for ~~cost~~the ~~and~~year ~~taxes~~ended ~~increased by 6%~~December 31, or2018 was $~~553~~7,138,000 ~~in 2017 when compared to 2016~~. OnThe atax ~~per~~expense ~~unit~~was ~~basis,~~primarily ~~lease~~due ~~operating~~to ~~expenses~~the ~~(excluding~~tax ~~transportation~~withheld ~~and taxes) increased~~ by ~~$2.03~~the ~~per~~Israel ~~MBOE~~taxation toauthorities ~~$15.79~~on ~~per~~Tamar ~~MBOE~~Field ~~in 2017 from $13~~proceeds.~~76 per MBOE in 2016. The increase was a result of an increase in repair and maintenance activity as oil, natural gas and NGLs prices increased.~~

●Income ~~Depreciation~~tax expense for the year ended December 31, ~~Depletion~~2017 ~~&Amortization~~was ~~(DD&A)~~$45,637,000. ofThe tax expense was primarily due to the ~~cost~~full allowance of ~~proved~~amounts ~~oil~~previously ~~and~~in ~~gas~~deferred ~~properties~~tax isassets ~~calculated~~as ~~using~~future tax credits related to tax withheld by the ~~unit-of-production~~Israel ~~method.~~taxation ~~Our~~authorities ~~DD&A~~on ~~rate~~Tamar ~~and~~Field ~~expense~~proceeds ~~are~~and the ~~composite~~full allowance of ~~numerous~~other ~~individual~~deferred ~~field~~tax ~~calculations~~assets. ~~There~~On ~~are~~December ~~several~~22, ~~factors~~2017, ~~that~~the ~~can~~US ~~impact~~Congress ~~our~~enacted ~~composite~~the ~~DD&A~~Tax ~~rate~~Reform ~~and expense~~Legislation, ~~including~~which ~~but~~made ~~not~~significant ~~limited~~changes to ~~field~~US ~~production~~federal ~~profiles~~income tax law, ~~drilling~~including ora ~~acquisition~~reduction ofin ~~new~~the ~~wells~~federal corporate tax rate to 21% effective January 1, ~~disposition~~2018. ofUnder ~~existing~~US ~~wells~~GAAP, ~~and~~we ~~reserve~~are ~~revisions~~required ~~(upward~~to orrecognize ~~downward)~~the ~~primarily~~effect ~~related~~of toa ~~well~~rate ~~performance~~change ~~and~~on ~~commodity~~deferred ~~prices,~~tax assets and ~~impairments.~~liabilities ~~Changes~~in the period in ~~these~~which ~~factors~~the ~~may~~tax ~~cause~~rate ~~our~~change ~~composite~~is ~~DD&A~~enacted. At the lower tax rate, ~~and~~we ~~expense~~projected that we would not be able to ~~fluctuate~~recover ~~from~~accumulated ~~period~~foreign tax credits balance to ~~period.~~reduce ~~DD&A~~our ~~decreased~~future bytax ~~29%,~~burden orand therefore recorded a full valuation allowance of $131,~~020~~091,000. In addition, ina ~~2017~~full ~~when~~valuation ~~compared~~allowance was recorded to ~~2016.~~reduce Ondeferred atax ~~per~~assets ~~unit~~balances ~~basis~~as of December 31, ~~depletion~~2017 ~~expenses~~due ~~decreased~~to byuncertainty ~~$1.50~~in ~~per~~their ~~MBOE~~future torecoverability $5- see Note 6 Income Taxes.08 ~~per~~Our ~~MBOE~~pre-tax inincome of $19,811,000 for 2017 increased by $11,288,000 from pre-tax income in 2016 of $68,523,000.58 ~~per~~This ~~MBOE~~increase in ~~2016~~pre-tax ~~due~~income from 2016 to 2017 was primarily the result of a ~~lower~~$5,513,000 ~~beginning~~increase ~~balance~~in ~~resulted~~production services revenues, a $2,162,000 increase revenues from ~~previous~~United ~~years~~States ~~impairments~~based oil and ~~lower~~gas ~~production~~assets, ~~volumes~~a ~~compared~~$2,103,000 toincrease ~~2016~~in gain on divestiture, and a $1,319,000 increase in Tamar Field proceeds. This increase was partially offset by increased operating expenses.

●The ~~Impairments~~effective oftax ~~oil~~rates ~~and~~for ~~gas~~the ~~assets~~years ofended $1December 31,~~682~~ 2018,~~000~~ in 2017 ~~were~~and ~~primarily~~2016 ~~the~~were ~~result~~30.2%, of230.4% ~~lower estimated future production in several fields which reduced the projected value in those fields from prior estimates~~ and ~~resulted~~42.6%, ~~in a projected value lower than the carrying value of those fields which triggered impairment~~respectively.

~~● Loss from plugging and abandonment expenses increased by $29,000 in 2017 when compared to 2016, primarily due to an increase in the wells plugged in 2017.~~45

●Table ~~General and administrative expenses increased as a result~~ of ~~increased professional fees. This increase was partially offset by a lesser increase in allowance for doubtful accounts and no write off of deferred financing costs as had occurred in 2016.~~Contents

~~During~~Adjusted ~~2016, our operating expenses decreased by 63% when compared to 2015 as highlighted below:~~EBITDAX

●To ~~Lease~~assess the operating ~~expense~~results of Isramco, ~~transportation~~management ~~cost~~analyzes ~~and~~income ~~taxes~~from ~~decreased~~operations bybefore ~~40%~~income taxes, orinterest $5expense,~~903~~ exploration expense,~~000~~ inunrealized ~~2016~~gain ~~when~~(loss) ~~compared~~on toderivative ~~2015~~contracts and DD&A expense and impairments (“Adjusted EBITDAX”). OnAdjusted EBITDAX is not a ~~per~~GAAP ~~unit~~measure. ~~basis,~~Isramco’s ~~lease~~definition of Adjusted EBITDAX excludes exploration expense because exploration expense is not an indicator of operating ~~expenses~~efficiency ~~(excluding~~for ~~transportation~~a ~~and~~given ~~taxes)~~reporting ~~decreased~~period, but rather is monitored by ~~$6.12~~management ~~per~~as ~~MBOE~~a topart ~~$13.76~~of ~~per~~the ~~MBOE~~costs incurred in ~~2016~~exploration ~~from~~and ~~$19~~development activities.88 ~~per~~Similarly, ~~MBOE~~Isramco inexcludes ~~2015~~DD&A expense and impairments from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. The ~~decrease~~Company’s ~~was~~definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Isramco’s financing methods or capital structure. Adjusted EBITDAX is a ~~direct~~widely ~~result~~accepted financial indicator of a company’s ~~efforts~~ability to ~~reduce~~incur ~~costs~~and ~~through~~service ~~delaying~~debt, ~~well~~fund ~~repairs,~~capital ~~reducing~~expenditures ~~vendor~~and ~~prices,~~make payments on its long term loans. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and ~~reducing~~results ~~employee~~of ~~headcount/wages~~operations.

~~● Depreciation~~However, ~~Depletion~~Adjusted ~~&Amortization~~EBITDAX, ~~(DD&A)~~as ofdefined ~~the~~by ~~cost~~Isramco, ofmay ~~proved~~not ~~oil~~be ~~and~~comparable ~~gas~~to ~~properties~~similarly istitled ~~calculated~~measures ~~using~~used ~~the~~by ~~unit-of-production~~other ~~method~~companies. ~~Our~~Therefore, ~~DD&A~~Isramco’s ~~rate~~consolidated ~~and~~Adjusted ~~expense~~EBITDAX ~~are~~should ~~the~~be ~~composite~~considered ofin ~~numerous~~conjunction ~~individual~~with ~~field~~income ~~calculations.~~(loss) ~~There~~from ~~are~~operations ~~several~~and ~~factors~~other ~~that~~performance ~~can~~measures ~~impact~~prepared ~~our~~in ~~composite~~accordance ~~DD&A~~with ~~rate and expense~~GAAP, ~~including~~such ~~but~~as ~~not~~operating ~~limited~~income ~~to field production profiles, drilling~~ or ~~acquisition~~cash offlow ~~new~~from ~~wells,~~operating ~~disposition~~activities. ofAdjusted ~~existing~~EBITDAX ~~wells,~~has ~~and~~important ~~reserve~~limitations ~~revisions~~as ~~(upward~~an oranalytical ~~downward)~~tool ~~primarily~~because ~~related~~it toexcludes ~~well~~certain ~~performance~~items ~~and~~that ~~commodity~~affect ~~prices,~~income ~~and~~from ~~impairments.~~continuing ~~Changes~~operations ~~in these factors may cause our composite DD&A rate~~ and ~~expense~~net tocash ~~fluctuate~~provided ~~from~~by ~~period~~operating ~~to period~~activities. ~~DD&A~~Adjusted ~~decreased~~EBITDAX byshould ~~43%,~~not orbe ~~$2,617,000,~~considered in ~~2016~~isolation ~~when~~or ~~compared~~as ~~to 2015. On~~ a ~~per~~substitute ~~unit~~for ~~basis,~~an ~~depletion~~analysis ~~expenses~~of ~~decreased~~Isramco’s byresults ~~$3.19~~as ~~per~~reported ~~MBOE~~under ~~to $6~~GAAP.58 ~~per~~Below ~~MBOE~~is ina ~~2016~~reconciliation ~~from~~of ~~$9.77~~consolidated ~~per~~Adjusted ~~MBOE~~EBITDAX ~~in 2015 due~~ to aincome ~~decrease~~(loss) infrom ~~the~~operations ~~depletable~~before ~~base~~income ~~as a result of prior year impairments~~taxes.

● Impairments of oil and gas assets of $4,529,000 in 2016 were primarily the result of lower estimated future production in several fields which reduced the projected value in those fields from prior estimates and resulted in a projected value lower than the carrying value of those fields which triggered impairment.

	Years Ended December 31,
In thousands	2018			2017			2016
Income from operations before income taxes (1)	$	23,614		$	19,811		$	8,523
Depreciation, depletion, amortization and impairment expense		6,795			7,208			11,196
Interest expense, net		4,992			4,784			4,817
(Gain) on derivative contract		(951	)		(746	)		(586	)
Accretion Expenses		869			913			897
Consolidated Adjusted EBITDAX	$	35,319		$	31,970		$	24,847

●(1) ~~Loss~~Including ~~from~~net ~~plugging~~gain ~~and~~on ~~abandonment~~divestiture ~~expenses~~of ~~decreased~~$1,452,000 byin ~~103%~~2018, or $942,703,000 in ~~2016~~2017, ~~when~~and ~~compared to 2015~~$600,000 ~~primarily due to a decrease~~ in ~~the wells plugged in~~ 2016.

●Recently ~~The~~Issued ~~decrease~~Accounting ~~in general and administrative expenses was primarily due to decrease in bad debt expenses and professional fees partially offset by a 2016 write-off of $299,000 in deferred financing costs.~~Pronouncements

46We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplemental Data–Note 1, “Summary of Significant Accounting Policies.”

~~Table~~ITEM of7A. ~~Contents~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

~~Production~~Commodity ~~Services~~Price ~~Segment~~Risk and Derivative Instruments

	Years Ended December 31,
In thousands except percentages	2017			2016			D vs. 2016			2015			D vs. 2015
Production Services (1)	$	18,265		$	12,752			43	%	$	22,465			(43	)%
Operating expenses		18,241			14,494			26			21,802			(34	)
Depreciation		3,072			3,193			(4	)		3,853			(17	)
Impairment		-			-			0			10,566			(100	)
General and administrative (1)		913			1,001			(9	)		1,454			(31	)
Operating income	$	(3,961	)	$	(5,936	)		33	%	$	(15,210	)		61	%

We are exposed to various risks, including energy commodity price risk. If oil and natural gas prices decline significantly our ability to finance our capital budget and operations could be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have adopted a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The type of derivative instrument that we typically utilize is swaps. The total volumes which we hedge through the use of our derivative instruments vary from period to period.

~~(1)~~During ~~Production~~the ~~Services~~year ~~revenue~~ended ~~includes~~December ~~intersegment~~31, ~~revenues~~2015, Tamar Royalties LLC, a wholly owned subsidiary of the Company, entered into certain swap and ~~expenses~~cap agreements with Deutsche Bank AG London Branch to hedge the risk of interest rate volatility loan balances. See Note 4 “Financial Instruments and Fair Value” for details.

●We ~~The~~may ~~revenues~~be ~~from~~exposed ~~production services operations in 2017 increased by 43% or $5,513,000 when compared~~ to ~~2016~~market ~~primarily~~risk ~~due~~on toour aopen ~~rebound~~derivative incontracts ~~crude~~of ~~oil~~non-performance ~~prices~~by ~~which resulted in growth in~~ our ~~trucking services through customer acquisition~~counterparties. ~~The revenues from production services operations in 2016 decreased by 43% or $9~~However,~~713,000~~ ~~when~~we ~~compared~~do tonot ~~2015~~expect ~~primarily~~such ~~due~~non-performance tobecause aour ~~continued~~contracts ~~decrease~~are inwith ~~crude~~major ~~oil~~financial ~~and~~institutions ~~natural~~with ~~gas~~investment ~~prices~~grade ~~that~~credit ~~triggered a continued decrease in demand for our production services~~ratings.

● Operating expenses from production services operations for the year ended December 31, 2017 has increased by 26% or $3,747,000 when compared to the same period in 2016. The increase was primarily associated with an increase in payroll, fuel, and other related expenses as a result of increase in trucking services. Operating expenses from production services operations for the year ended December 31, 2016 has decreased by 34% or $7,308,000 when compared to the same period in 2015. The decrease was primarily associated with reduction in payroll, fuel, and other related expenses as a result of decrease in number of deployed rigs.46

●Table Production service equipment depreciation – the amounts represent depreciation for our production services rigs and auxiliary equipment. The depreciation expense for the year ended December 31, 2017 decreased by $121,000 compared to 2016. The decrease in depreciation expense for the year ended December 31, 2016 of ~~$660,000 is a result of a decrease in the depreciable base stemming from the impairment in 2015.~~Contents

●We ~~Impairment~~account offor ~~production~~our ~~service~~derivative ~~equipment~~activities –under ~~we analyze~~ the ~~potential~~provisions ~~impairment~~ of ~~property~~ASC ~~and~~815, ~~equipment~~Derivatives ~~annually~~and asHedging, of(ASC ~~December~~815). 31ASC or815 onestablishes anaccounting ~~interim~~and ~~basis~~reporting ~~if events or circumstances indicate~~ that ~~the~~every ~~fair~~derivative ~~values~~instrument ofbe ~~the~~recorded ~~assets~~on ~~have decreased below~~ the ~~carrying~~balance ~~value.~~sheet ~~Our~~as ~~analysis~~either ~~for~~an ~~potential~~asset ~~impairment~~or ofliability ~~property~~measured ~~and~~at ~~equipment~~fair ~~requires us to estimate undiscounted future cash flows~~value. ~~Actual~~Please ~~impairment~~refer ~~charges~~to ~~are~~Item ~~recorded using an estimate of discounted future cash flows~~8. ~~The~~Consolidated ~~determination~~Financial ofStatements ~~future cash flows requires us to estimate rates~~ and ~~utilization~~Supplemental inData—Note 4, ~~future~~“Financial ~~periods~~Instruments and ~~such~~Fair ~~estimates~~Value” ~~can~~for ~~change~~additional ~~based~~information. onAs ~~market~~of ~~conditions~~December 31, ~~technological~~2018 ~~advances~~and in2017 ~~industry~~we ordid ~~changes~~not inhave ~~regulations~~open ~~governing~~commodity ~~the~~derivative ~~industry~~positions.

AsInterest-Rate a result of the downturn which began in late 2014 and worsened through 2015, we performed impairment testing on our equipment as of December 31, 2015. Such testing indicated that the carrying value of our production services equipment was not recoverable and thus we recorded an impairment of $10,566,000 at December 31, 2015. No such impairment was recorded for the year ended December 31, 2017 and 2016.Risk

●We ~~For~~are ~~the~~exposed ~~year~~to ~~ended~~market ~~December~~risk ~~31,~~related ~~2017~~to ~~general~~adverse ~~and~~changes ~~administrative~~in ~~expenses~~interest ~~decreased~~rates. byOur interest 9%rate orrisk results ~~$88,000~~primarily from ~~2016~~fluctuations ~~primarily~~in asshort-term arates, ~~result~~which ofare LIBOR based. ~~lesser~~If interest rates increase, inour ~~the~~interest ~~allowance~~expense ~~for~~would ~~doubtful~~increase ~~accounts~~and ~~partially~~our ~~offset~~available bycash ~~increased~~flow ~~legal~~would ~~fees~~decrease. ~~General~~Periodically, ~~and~~we ~~administrative~~look ~~expenses~~to ~~from~~utilize ~~production~~interest ~~services~~rate ~~operations~~swaps ~~for~~to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. During the year ended December 31, ~~2016~~2015, ~~decreased~~Tamar byRoyalties ~~31%~~LLC, ora ~~$453~~wholly owned subsidiary of the Company,~~000~~ ~~from~~entered ~~2015~~into ~~primarily~~certain asswap aand ~~result~~cap ofagreements ~~lesser~~with ~~increase~~Deutsche inBank AG London Branch to hedge the ~~allowance~~risk ~~for~~of ~~doubtful~~interest ~~accounts~~rate volatility loan balances. See Note 4 “Financial Instruments and Fair Value” for details.

47We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

~~Table~~Fair Market Value of ~~Contents~~Financial Instruments

~~Other~~The ~~expenses~~estimated fair values for financial instruments under ASC 825, Financial Instruments, (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 8. Consolidated Financial Statements and Supplemental Data—Note 4 “Financial Instruments and Fair Value” for additional information.

	Years Ended December 31,
In thousands except percentages	2017			2016		D vs. 2016			2015		D vs. 2015
Interest expense net	$	4,784		$	4,817		(1	)%	$	2,432		98	%
Interest expense – related party, net		-			-		0			2,878		(100	)
Loss from derivative contracts, net		176			657		(73	)		1,988		(67	)
Capital (gain) loss		(145	)		70		307			85		(18	)
	$	4,815		$	5,544		(18	)%	$	7,383		(25	)%

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

●The ~~Net~~information ~~Interest~~called ~~expense.~~for ~~Isramco’s~~by ~~interest~~this ~~expense~~Item ~~decreased~~8 ~~only~~is ~~slightly,~~included byfollowing ~~$33,000 for~~ the ~~twelve~~“Index ~~months ended December 31, 2017 compared~~ to ~~the~~Financial ~~same~~Statements” ~~period~~contained ofin ~~2016~~this asAnnual ~~increased~~Report ~~interest income from investment and the reduced principal balance~~ on ~~loans~~Form ~~was partially offset by the increase in the indexed interest rate~~10-K.

~~Isramco’s~~ITEM ~~interest expense including related party interest expense decreased by~~ 9~~%, or $493,000, for the twelve months ended December 31, 2016 compared to the same period of 2015~~. ~~This~~CHANGES ~~decrease~~IN ~~was~~AND ~~primarily~~DISAGREEMENTS ~~due~~WITH toACCOUNTANTS ~~lower~~ON ~~interest~~ACCOUNTING ~~rates~~AND onFINANCIAL ~~the loans and lower average principal balance outstanding during the twelve months ended December 31, 2016.~~DISCLOSURE

● Net loss on derivative contracts. During 2015 we entered into interest rate cap and swap agreements. These agreements are considered derivative and are accounted for with mark-to-market valuation. The loss in fair value of these contracts is recorded in the statement of operations. The loss from derivative contracts decreased from $1,988,000 in 2015 to $657,000 in 2016 and to $176,000 in 2017 primarily as a result of an increase in the estimated future LIBOR rate which is a factor in determining the market value of the derivatives.None

~~Income~~ITEM ~~Taxes~~9A. ~~and~~CONTROLS ~~Impact~~AND ~~of Tax Reform Legislation~~PROCEDURES

~~Income~~DISCLOSURE ~~tax~~CONTROLS ~~expense~~AND ~~for the year ended December 31, 2017 was $45,637,000~~PROCEDURES. The tax expense was primarily due to the full allowance of amounts previously in deferred tax assets as future tax credits related to tax withheld by the Israel taxation authorities on Tamar Field proceeds and the full allowance of other deferred tax assets. On December 22, 2017, the US Congress enacted the Tax Reform Legislation, which made significant changes to US federal income tax law, including a reduction in the federal corporate tax rate to 21% effective January 1, 2018. Under US GAAP, we are required to recognize the effect of a rate change on deferred tax assets and liabilities in the period in which the tax rate change is enacted. At the lower tax rate, we projected that we would not be able to recover accumulated foreign tax credits balance to reduce our future tax burden and therefore recorded a full valuation allowance of $31,091,000. In addition, a full valuation allowance was recorded to reduce deferred tax assets balances as of December 31, 2017 due to uncertainty in their future recoverability - see Note 5 Income Taxes. Our pre-tax income of $19,811,000 for 2017 increased by $11,288,000 from pre-tax income in 2016 of $8,523,000. This increase in pre-tax income from 2016 to 2017 was primarily the result of a $5,513,000 increase in production services revenues, a $2,162,000 increase revenues from United States based oil and gas assets, a $2,103,000 increase in gain on divestiture, and a $1,319,000 increase in Tamar Field proceeds. This increase was partially offset by increased operating expenses.

~~Income~~We ~~tax~~have ~~expense~~established ~~for~~disclosure ~~the~~controls ~~year~~and ~~ended~~procedures ~~December 31,~~to ~~2016~~ensure ~~was~~that ~~$3,634,000.~~material ~~The~~information ~~tax~~relating ~~expense was primarily due~~ to ~~our~~Isramco, ~~pre-tax~~including ~~income~~its ofconsolidated $8subsidiaries,~~523,000~~ ~~which~~is ~~was~~made ~~primarily~~known ~~due~~ to the ~~decrease~~officers inwho ~~impairment~~certify ~~expense~~Isramco’s ~~from~~financial ~~$43,704,000~~reports ~~in 2015 to $4,529,000 in 2016. Additionally lease operating expenses decreased by $5,903,000 from $14,828,000 in 2015 to $8,925,000 in 2016~~ and ~~Tamar Field proceeds increased by $2,311,000 from $25,151,000 in 2015~~ to ~~$27,462,000~~other inmembers 2016. This increase was offset by decreased revenues from our US based oil and gas assets and production services subsidiary which was driven by decrease in natural gas and crude oil prices which in turn reduced demand for our production services; and lower sales volumes of ~~oil,~~senior ~~natural~~management ~~gas~~ and ~~NGLs. Additionally~~ the ~~increase~~Board inof ~~net income was offset lower gain on divestiture, $600,000 in 2016 as compared to $8,378,000 in 2015~~Directors.

~~The~~Based ~~effective~~on ~~tax~~their ~~rates~~evaluation, ~~for~~Isramco’s principal executive and principal financial officers have concluded that Isramco’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the ~~years~~Securities ~~ended~~Exchange Act of 1934) were effective as of December 31, ~~2017~~2018 to ensure that the information required to be disclosed by Isramco in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, ~~2016~~processed, summarized and ~~2015~~reported ~~were 230.4%,~~within ~~42.6%~~the time periods specified in the SEC rules and 30forms.~~6%, respectively.~~

~~Adjusted EBITDAX.~~47

ToTable ~~assess the operating results~~ of Isramco, management analyzes income from operations before income taxes, interest expense, exploration expense, unrealized gain (loss) on derivative contracts and DD&A expense and impairments (“Adjusted EBITDAX”). Adjusted EBITDAX is not a GAAP measure. Isramco’s definition of Adjusted EBITDAX excludes exploration expense because exploration expense is not an indicator of operating efficiency for a given reporting period, but rather is monitored by management as a part of the costs incurred in exploration and development activities. Similarly, Isramco excludes DD&A expense and impairments from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Isramco’s financing methods or capital structure. Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make payments on its long term loans. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations.Contents

48MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

~~Table~~Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as that term is defined in Rules 13a-15(f) and 15d-15(f) of ~~Contents~~the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

~~However,~~Because ~~Adjusted~~of ~~EBITDAX,~~its asinherent ~~defined by Isramco~~limitations, ~~may~~internal ~~not~~control beover ~~comparable~~financial toreporting ~~similarly~~may ~~titled~~not ~~measures~~prevent ~~used~~or bydetect ~~other companies~~misstatements. ~~Therefore~~Also, ~~Isramco’s~~projections ~~consolidated~~of ~~Adjusted~~any ~~EBITDAX~~evaluation ~~should~~of beeffectiveness ~~considered~~to infuture ~~conjunction~~periods ~~with~~are ~~income~~subject ~~(loss)~~to ~~from~~the ~~operations~~risk ~~and~~that ~~other~~controls ~~performance~~may ~~measures~~become ~~prepared~~inadequate ~~in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDAX has important limitations as an analytical tool~~ because itof ~~excludes~~changes ~~certain items that affect income from continuing operations and net cash provided by operating activities. Adjusted EBITDAX should not be considered~~ in ~~isolation~~conditions, or asthat athe ~~substitute~~degree ~~for an analysis~~ of ~~Isramco’s~~compliance ~~results~~with asthe ~~reported~~policies ~~under~~or ~~GAAP.~~procedures ~~Below~~may ~~is a reconciliation of consolidated Adjusted EBITDAX to income (loss) from operations before income taxes~~deteriorate.

	Years Ended December 31,
In thousands	2017			2016			2015
Income (loss) from operations before income taxes (1)	$	19,811		$	8,523		$	(30,239	)
Depreciation, depletion, amortization and impairment expense		7,208			11,196			53,648
Interest expense, net		4,784			4,817			5,310
Loss (gain) on derivative contract		(746	)		(586	)		1,602
Accretion Expenses		913			897			856
Consolidated Adjusted EBITDAX	$	31,970		$	24,847		$	31,177

Our management, under the supervision of and with the participation of our Co-Chief Executive Officer and Co-Chief Executive Officer / Chief Financial Officer, conducted an evaluation of our internal control over financial reporting as of December 31, 2017. In making this assessment, management used the criteria set forth in Internal Control − Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment using these criteria, our management determined that our internal control over financial reporting was effective as of December 31, 2018.

~~(1)~~The ~~Including~~effectiveness ~~net~~of ~~gain~~our oninternal ~~divestiture~~control ~~$2,703,000~~over infinancial ~~2017~~reporting as of December 31, ~~$600~~2018,~~000~~ inhas ~~2016~~been audited by MaloneBailey LLP, ~~and~~an $8independent registered public accounting firm,~~378,000~~ as stated in ~~2015~~their report which appears herein.

~~Recently~~CHANGES ~~Issued~~IN ~~Accounting~~INTERNAL ~~Pronouncements~~CONTROL OVER FINANCIAL REPORTING

WeThere ~~discuss~~was ~~recently~~no ~~adopted~~change ~~and~~in ~~issued~~Isramco’s ~~accounting~~internal ~~standards~~control inover ~~Item 8.~~financial ~~Consolidated~~reporting ~~Financial~~during ~~Statements~~the ~~and~~fourth ~~Supplemental~~quarter ~~Data–Note~~of 12018 that has materially affected, ~~“Summary~~or ofis ~~Significant~~reasonably ~~Accounting~~likely ~~Policies~~to materially affect, Isramco’s internal control over financial reporting.”

ITEM 7A9B. ~~QUANTITATIVE~~OTHER ~~AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~INFORMATION

~~Commodity Price Risk and Derivative Instruments~~None.

~~During~~Table ~~the year ended December 31, 2015, Tamar Royalties LLC, a wholly owned subsidiary~~ of the Company, entered into certain swap and cap agreements with Deutsche Bank AG London Branch to hedge the risk of interest rate volatility loan balances. See Note 3 “Financial Instruments and Fair Value” for details.Contents

WePART may be exposed to market risk on our open derivative contracts of non-performance by our counterparties. However, we do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings.III

We ~~account~~will ~~for~~file ~~our~~a ~~derivative~~definitive ~~activities~~Proxy ~~under~~Statement ~~the~~for ~~provisions~~our of2019 ~~ASC~~Annual ~~815,~~Meeting ~~Derivatives~~of ~~and~~Stockholders ~~Hedging,~~with ~~(ASC~~the ~~815).~~SEC, ~~ASC~~pursuant ~~815~~to ~~establishes~~Regulation ~~accounting~~14A, ~~and~~not ~~reporting~~later ~~that~~than ~~every~~120 ~~derivative~~days ~~instrument~~after ~~be recorded on~~ the ~~balance~~end ~~sheet~~of asour ~~either~~fiscal anyear. ~~asset~~Accordingly, orcertain ~~liability~~information ~~measured~~required atby ~~fair~~Part ~~value.~~III ~~Please~~has ~~refer~~been toomitted ~~Item 8.~~under ~~Consolidated~~General ~~Financial~~Instruction ~~Statements and Supplemental Data—Note~~ G(3,) ~~“Financial~~to ~~Instruments~~Form ~~and~~10-K. ~~Fair~~Only ~~Value”~~those ~~for~~sections ~~additional~~of ~~information.~~our Asdefinitive ofProxy ~~December~~Statement ~~31,~~that ~~2017~~specifically ~~and~~address ~~2016~~the weitems ~~did~~set ~~not~~forth ~~have~~herein ~~open~~are ~~commodity~~incorporated ~~derivative~~by ~~positions~~reference.

~~Interest-Rate~~Item ~~Risk~~10. Directors, Executive Officers and Corporate Governance

WeThe ~~are~~information ~~exposed~~required toby ~~market~~Item ~~risk~~10 ~~related~~is tohereby ~~adverse~~incorporated ~~changes~~by inreference ~~interest rates. Our interest rate risk results primarily~~ from ~~fluctuations in short-term rates, which are LIBOR based. If interest rates increase,~~ our ~~interest~~definitive ~~expense~~Proxy ~~would~~Statement ~~increase~~relating ~~and~~to our ~~available~~2019 ~~cash~~Annual ~~flow~~Meeting ~~would~~of ~~decrease. Periodically~~Stockholders, ~~we look~~ to ~~utilize~~be ~~interest~~filed ~~rate~~with ~~swaps to reduce~~ the ~~exposure~~Securities to market rate fluctuations by converting variable interest rates to fixed interest rates. During the year ended December 31, 2015, Tamar Royalties LLC, a wholly owned subsidiary of the Company, entered into certain swap and ~~cap~~Exchange ~~agreements~~Commission ~~with~~within ~~Deutsche~~120 ~~Bank~~days AGfollowing ~~London Branch to hedge~~ the ~~risk~~end of ~~interest~~our ~~rate~~fiscal ~~volatility loan balances~~year. ~~See Note 3 “Financial Instruments and Fair Value” for details.~~

WeItem ~~continue~~11. toExecutive ~~monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.~~ Compensation

49The information required by Item 11 is hereby incorporated by reference from our definitive Proxy Statement relating to our 2019 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days following the end of our fiscal year.

~~Table~~Item 12. Security Ownership of ~~Contents~~Certain Beneficial Owners and Management and Related Stockholder Matters

~~Fair~~The ~~Market~~information ~~Value~~required by Item 12 is hereby incorporated by reference from our definitive Proxy Statement relating to our 2019 Annual Meeting of ~~Financial~~Stockholders, ~~Instruments~~to be filed with the Securities and Exchange Commission within 120 days following the end of our fiscal year.

~~The~~Item ~~estimated fair values for financial instruments under ASC 825, Financial Instruments, (ASC 825) are determined at discrete points in time based on relevant market information~~13. ~~These~~Certain ~~estimates~~Relationships ~~involve uncertainties~~ and ~~cannot~~Related ~~be determined with precision. The estimated fair value of cash~~Transactions, ~~cash equivalents, accounts receivable~~ and ~~accounts~~Director payable approximates their carrying value due to their short-term nature. See Item 8. Consolidated Financial Statements and Supplemental Data—Note 3 “Financial Instruments and Fair Value” for additional information.Independence

~~ITEM~~The 8.information ~~FINANCIAL~~required ~~STATEMENTS~~by ~~AND~~Item ~~SUPPLEMENTAL~~13 ~~DATA~~is hereby incorporated by reference from our definitive Proxy Statement relating to our 2019 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days following the end of our fiscal year.

~~The information called for by this~~ Item 814. isPrincipal ~~included~~Accounting ~~following~~Fees ~~the~~and ~~“Index to Financial Statements” contained in this Annual Report on Form 10-K.~~Services

~~ITEM~~The 9.information ~~CHANGES~~required INby ~~AND~~Item ~~DISAGREEMENTS~~14 ~~WITH~~is ~~ACCOUNTANTS~~hereby ONincorporated ~~ACCOUNTING~~by ~~AND~~reference ~~FINANCIAL~~from ~~DISCLOSURE~~our definitive Proxy Statement relating to our 2019 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days following the end of our fiscal year.

~~None~~49

~~ITEM~~Table ~~9A.~~of ~~CONTROLS AND PROCEDURES~~Contents

~~DISCLOSURE CONTROLS AND PROCEDURES.~~GLOSSARY

We“Limited ~~have~~Partnership” ~~established~~means ~~disclosure~~Isramco ~~controls~~Negev ~~and~~2 ~~procedures~~Limited toPartnership, ~~ensure~~a ~~that~~Limited ~~material~~Partnership ~~information~~founded ~~relating~~pursuant to ~~Isramco~~a Limited Partnership Agreement made on the 2nd and 3rd days of March, ~~including~~1989 ~~its~~(as ~~consolidated~~amended ~~subsidiaries~~on September 7, is1989, ~~made~~July ~~known~~28, to1991, March 5, 1992 and June 11, 1992) between the ~~officers~~Trustee ~~who~~on ~~certify~~part ~~Isramco’s~~as ~~financial~~Limited ~~reports~~Partner and toIsramco ~~other~~Oil ~~members~~and ofGas ~~senior~~Ltd., ~~management~~as ~~and~~General ~~the~~Partner ~~Board~~on ofthe ~~Directors~~other part.

~~Based~~“Overriding onRoyalty” ~~their~~means ~~evaluation,~~a ~~Isramco’s~~percentage ~~principal~~interest ~~executive~~over and ~~principal~~above ~~financial~~the ~~officers~~base ~~have~~royalty ~~concluded that Isramco’s disclosure controls~~ and ~~procedures~~is ~~(as~~free ~~defined~~of inall ~~Rules~~costs ~~13a-15(e) and 15d-15(e) under the Securities Exchange Act~~ of ~~1934)~~exploration ~~were~~and ~~effective as of December 31~~production, ~~2017~~which tocosts ~~ensure~~are ~~that~~borne ~~the information required to be disclosed~~ by ~~Isramco in~~ the ~~reports~~Grantor ~~that~~of ~~it files or submits under~~ the ~~Securities~~Overriding ~~Exchange~~Royalty ~~Act~~Interest ofand ~~1934~~which is ~~recorded,~~related ~~processed,~~to ~~summarized~~a ~~and~~particular ~~reported~~Petroleum ~~within the time periods specified in the SEC rules and forms~~License.

~~MANAGEMENT’S~~“Payout” means ~~REPORT~~the ONpoint ~~INTERNAL~~at ~~CONTROL~~which ~~OVER~~all ~~FINANCIAL~~costs ~~REPORTING~~of leasing, exploring, drilling and operating have been recovered from production of a well or wells as defined by contractual agreement or otherwise.

~~Our~~“Petroleum” ~~management~~means isany ~~responsible~~petroleum ~~for~~fluid, ~~establishing~~whether ~~and~~liquid ~~maintaining~~or ~~adequate~~gaseous, ~~internal~~and ~~control~~includes ~~over~~oil, ~~financial~~natural ~~reporting~~gas, asnatural ~~that~~gasoline, ~~term~~condensates isand ~~defined~~related influid ~~Rules~~hydrocarbons, ~~13a-15(f)~~ and ~~15d-15(f)~~also ofasphalt ~~the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting~~ and ~~the~~other ~~preparation~~solid ofpetroleum ~~financial~~hydrocarbons ~~statements~~when ~~for~~dissolved ~~external purposes~~ in ~~accordance~~and producible with ~~generally~~fluid ~~accepted accounting principles~~petroleum.

~~Because~~“Israel ofPetroleum its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.Law”

~~Our~~The ~~management,~~Company’s ~~under~~business ~~the~~in ~~supervision~~Israel ofis ~~and~~subject ~~with~~to ~~the~~regulation ~~participation~~by ofthe ~~our~~State ~~Co-Chief Executive Officer and Co-Chief Executive Officer / Chief Financial Officer, conducted an evaluation~~ of ~~our~~Israel ~~internal~~pursuant ~~control~~to ~~over~~the ~~financial~~Petroleum ~~reporting as of December 31~~Law, ~~2017~~1952. InThe ~~making~~administration ~~this~~and ~~assessment,~~implementation ~~management~~of ~~used~~ the ~~criteria~~Petroleum ~~set~~Law ~~forth~~is vested in ~~Internal Control − Integrated Framework (2013) issued by~~ the ~~Committee~~Minister of ~~Sponsoring~~National ~~Organizations~~Infrastructure of (the ~~Treadway~~“Minister”) ~~Commission.~~and ~~Based~~an onAdvisory ~~this assessment using these criteria, our management determined that our internal control over financial reporting was effective as of December 31, 2017~~Council.

The ~~effectiveness~~following includes brief statements of ~~our~~certain ~~internal~~provisions ~~control~~of ~~over~~the ~~financial~~Petroleum ~~reporting~~Law asin effect at the date of ~~December~~this ~~31,~~Prospectus. ~~2017,~~Reference ~~has~~is ~~been~~made ~~audited~~to bythe ~~MaloneBailey~~copy ~~LLP,~~of the Petroleum Law filed as an ~~independent~~exhibit ~~registered~~to ~~public~~the ~~accounting~~Registration ~~firm,~~Statement asreferred ~~stated~~to inunder ~~their~~“Additional ~~report~~Information” and the description which ~~appears~~follows ~~herein~~is qualified in its entirety by such reference.

~~CHANGES~~The INholder ~~INTERNAL~~of ~~CONTROL~~a ~~OVER~~preliminary ~~FINANCIAL~~permit ~~REPORTING~~is entitled to carry out petroleum exploration, but not test drilling or petroleum production, within the permit areas. The Commissioner determines the term of a preliminary permit and it may not exceed eighteen (18) months. The Minister may grant the holder a priority right to receive licenses in the permit areas and for the duration of such priority right no other Party will be granted a license or lease in such areas.

~~There~~Drilling ~~was~~for nopetroleum ~~change~~is inpermitted ~~Isramco’s~~pursuant ~~internal~~to ~~control~~a ~~over~~license ~~financial~~issued ~~reporting~~by ~~during~~ the ~~fourth~~Commissioner. ~~quarter~~The term of ~~2017~~a ~~that~~license ~~has~~is ~~materially~~for ~~affected~~three (3) years, subject to extension under certain circumstances for an additional period up to four (4) years. A license holder is required to commence test drilling within two (2) years from the grant of a license (or earlier if required by the terms of the license) and not to interrupt operations between test drillings for more than four (4) months. If any well drilled by the Company is ~~reasonably~~determined ~~likely~~to be a Commercial discovery prior to ~~materially~~expiration ~~affect~~of the license, ~~Isramco’s~~the ~~internal~~Company ~~control~~will ~~over~~be ~~financial~~entitled ~~reporting~~to receive a Petroleum Lease granting it the exclusive right to explore for and produce petroleum in the lease area. The term of a lease is for thirty (30) years, subject to renewal for an additional term of twenty (20) years.

~~ITEM~~The 9BCompany, as a lessee, will be required to pay the State of Israel the royalty prescribed by the Petroleum Law which is presently, and at all times since 1952 has been, 12.5% ~~OTHER~~of ~~INFORMATION~~the petroleum produced from the leased area and saved, excluding the quantity of petroleum used in operating the leased area.

~~None~~The Minister may require a lessee to supply at the market price such quantity of petroleum as, in the Minister’s opinion, is required for domestic consumption, subject to certain limitations.

50As a lessee, the Company will also be required to commence drilling of a development well within six (6) months from the date on which the lease is granted and, thereafter, with due diligence to define the petroleum field, develop the leased area, produce petroleum therefore and seek markets for and market such petroleum.

~~Table of Contents~~50

~~PART~~Table ~~III~~of Contents

WePART will file a definitive Proxy Statement for our 2018 Annual Meeting of Stockholders with the SEC, pursuant to Regulation 14A, not later than 120 days after the end of our fiscal year. Accordingly, certain information required by Part III has been omitted under General Instruction G(3) to Form 10-K. Only those sections of our definitive Proxy Statement that specifically address the items set forth herein are incorporated by reference.IV

~~Item~~ITEM 1015. ~~Directors~~ EXHIBITS, ~~Executive~~FINANCIAL ~~Officers~~STATEMENT ~~and Corporate Governance~~SCHEDULES

~~The~~(a) information required by Item 10 is hereby incorporated by reference from our definitive Proxy Statement relating to our 2018 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days following the end of our fiscal year.Exhibits

Item 11. Executive Compensation

3.1		Certificate of Incorporation of Registrant with all amendments filed as an Exhibit to the S-l Registration Statement, File No. 2-83574.

3.2		Amendment to Certificate of Incorporation filed March 17, 1993, filed as an Exhibit with the S-l Registration Statement, File No. 33-57482.

3.3		By-laws of Registrant filed as Exhibit 3(ii) to the 8-K filed January 18, 2012 and incorporated herein by reference.

10.1		Purchase and Sale Agreement, dated as of February 16, 2007, among Five States Energy Company, L.L.C. and each of the other parties listed as a party “Seller” on the signature pages thereof and ISRAMCO, Inc., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.

10.17		2011 Stock Incentive Plan filed as an Exhibit to the 10-K for the year ended December 31, 2011 and incorporated herein by reference.

10.25		Employment Agreement dated effective November 3, 2017, between Isramco Inc. and Edy Francis, filed as an Exhibit to Form 8-K dated November 9, 2017 and incorporated herein by reference.

10.26		Consulting Agreement dated effective June 1, 2014, between Isramco Inc. and Goodrich Global Ltd., filed as an Exhibit to Form 8-K dated September 11, 2014 and incorporated herein by reference.

The information required by Item 11 is hereby incorporated by reference from our definitive Proxy Statement relating to our 2018 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days following the end of our fiscal year.

10.27		Credit Agreement dated as of May 18, 2015, by and among Tamar Royalties LLC, as Borrower, Deutsche Bank Trust Company Americas, as administrative agent, the lenders party thereto, as Lenders, and Deutsche Bank Trust Company Americas, as collateral agent filed as an Exhibit to 8-K filed by the Company on May 22, 2015 and incorporated herein by reference.

10.28		Royalties Sale and Contribution Agreement dated May 18, 2015, by and between Isramco, Inc., as Seller, and Tamar Royalties, LLC, as Borrower filed as an Exhibit to 8-K filed by the Company on May 22, 2015 and incorporated herein by reference.

10.29		Pledge, Assignment and Security Agreement dated as of May 18, 2015, by and between Tamar Royalties LLC, as Borrower, and Deutsche Bank Trust Company Americas, as collateral agent filed as an Exhibit to 8-K filed by the Company on May 22, 2015 and incorporated herein by reference.

10.30		Intercompany Loan Agreement dated as of May 18, 2015, by and between Isramco, Inc., as Payor, and Tamar Royalties, LLC, as Payee filed as an Exhibit to 8-K filed by the Company on May 22, 2015 and incorporated herein by reference.

10.31		Credit Agreement dated as of June 30, 2015, by and among Isramco Onshore LLC, as Borrower, Société Générale, as Administrative Agent and Issuing Lender, SG Americas Securities LLC, as Sole Bookrunner, Lead Arranger and Documentation Agent, and the lenders party thereto from time to time, as Lenders filed as an Exhibit to 8-K filed by the Company on July 6, 2015 and incorporated herein by reference.

14.1		Code of Ethics, filed as an Exhibit to Form 10-K for the year ended December 31, 2003.

~~Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters~~51

~~The~~Table ~~information required by Item 12 is hereby incorporated by reference from our definitive Proxy Statement relating to our 2018 Annual Meeting~~ of ~~Stockholders, to be filed with the Securities and Exchange Commission within 120 days following the end of our fiscal year.~~Contents

Item 13. Certain Relationships and Related Transactions, and Director Independence

23.1*		Consent of Cawley, Gillespie & Associates, Inc.

23.2*		Consent of Netherland, Sewell & Associates, Inc.

The information required by Item 13 is hereby incorporated by reference from our definitive Proxy Statement relating to our 2018 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days following the end of our fiscal year.

31.1*		Certification of Co-Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley Act.

31.2*		Certification of Co-Chief Executive Officer / Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley Act

31.3*		Certification of Chief Accounting Officer pursuant to Section 302 of Sarbanes-Oxley Act

32.1*		Certification of Chief Executive and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 Of the Sarbanes-Oxley act of 2002

32.2*		Certification of Co-Chief Executive Officer / Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 Of the Sarbanes-Oxley act of 2002

32.3*		Certification of Chief Accounting Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 Of the Sarbanes-Oxley act of 2002

99.1*		Cawley, Gillespie & Associates, Inc. Reserves Report

99.2*		Netherland, Sewell & Associates, Inc. Reserves Report

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema

101.CAL		XBRL Taxonomy Extension Calculation Linkbase

101.DEF		XBRL Taxonomy Extension Definition Linkbase

101.LAB		XBRL Taxonomy Extension Label Linkbase

101.PRE		XBRL Taxonomy Extension Presentation Linkbase

~~Item 14. Principal Accounting Fees and Services~~__________________________

~~The~~* ~~information~~Filed required by Item 14 is hereby incorporated by reference from our definitive Proxy Statement relating to our 2018 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days following the end of our fiscal yearHerewith.

51+ Management Agreement

~~Table of Contents~~52

~~GLOSSARY~~Table of Contents

“Limited Partnership” means Isramco Negev 2 Limited Partnership, a Limited Partnership founded pursuant to a Limited Partnership Agreement made on the 2nd and 3rd days of March, 1989 (as amended on September 7, 1989, July 28, 1991, March 5, 1992 and June 11, 1992) between the Trustee on part as Limited Partner and Isramco Oil and Gas Ltd., as General Partner on the other part.SIGNATURES

~~“Overriding~~Pursuant ~~Royalty”~~to ~~means~~Section a13 ~~percentage~~or ~~interest~~15(d) ~~over~~of ~~and above~~ the ~~base~~Securities ~~royalty~~Exchange ~~and~~Act ~~is free~~ of ~~all costs of exploration and production~~1934, ~~which~~the ~~costs~~registrant ~~are~~has ~~borne~~duly bycaused ~~the~~this ~~Grantor~~report ofto ~~the~~be ~~Overriding~~signed ~~Royalty~~on ~~Interest~~its ~~and~~behalf ~~which~~by isthe ~~related~~undersigned, tothereunto aduly ~~particular Petroleum License~~authorized.

~~“Payout” means~~/S/ ~~the~~HAIM ~~point at which all costs of leasing, exploring, drilling and operating have been recovered from production of a well or wells as defined by contractual agreement or otherwise.~~TSUFF

~~“Petroleum”~~HAIM ~~means any petroleum fluid~~TSUFF, whether liquid or gaseous, and includes oil, natural gas, natural gasoline, condensates and related fluid hydrocarbons, and also asphalt and other solid petroleum hydrocarbons when dissolved in and producible with fluid petroleum.

~~“Israel~~CHAIRMAN ~~Petroleum~~OF ~~Law”~~THE BOARD,

~~The~~CO-CHIEF ~~Company’s~~EXECUTIVE business in Israel is subject to regulation by the State of Israel pursuant to the Petroleum Law, 1952. The administration and implementation of the Petroleum Law is vested in the Minister of National Infrastructure (the “Minister”) and an Advisory Council.OFFICER

~~The~~(PRINCIPAL ~~following~~EXECUTIVE includes brief statements of certain provisions of the Petroleum Law in effect at the date of this Prospectus. Reference is made to the copy of the Petroleum Law filed as an exhibit to the Registration Statement referred to under “Additional Information” and the description which follows is qualified in its entirety by such reference.OFFICER)

~~The~~Date: ~~holder~~March ~~of a preliminary permit is entitled to carry out petroleum exploration~~18, but not test drilling or petroleum production, within the permit areas. The Commissioner determines the term of a preliminary permit and it may not exceed eighteen (18) months. The Minister may grant the holder a priority right to receive licenses in the permit areas and for the duration of such priority right no other Party will be granted a license or lease in such areas.2019

~~Drilling~~/S/ ~~for~~EDY petroleum is permitted pursuant to a license issued by the Commissioner. The term of a license is for three (3) years, subject to extension under certain circumstances for an additional period up to four (4) years. A license holder is required to commence test drilling within two (2) years from the grant of a license (or earlier if required by the terms of the license) and not to interrupt operations between test drillings for more than four (4) months. If any well drilled by the Company is determined to be a Commercial discovery prior to expiration of the license, the Company will be entitled to receive a Petroleum Lease granting it the exclusive right to explore for and produce petroleum in the lease area. The term of a lease is for thirty (30) years, subject to renewal for an additional term of twenty (20) years.FRANCIS

~~The~~EDY ~~Company~~FRANCIS, as a lessee, will be required to pay the State of Israel the royalty prescribed by the Petroleum Law which is presently, and at all times since 1952 has been, 12.5% of the petroleum produced from the leased area and saved, excluding the quantity of petroleum used in operating the leased area.

~~The~~CO-CHIEF ~~Minister~~EXECUTIVE ~~may~~OFFICER ~~require~~/ aCHIEF ~~lessee~~FINANCIAL ~~to supply at the market price such quantity of petroleum as, in the Minister’s opinion, is required for domestic consumption, subject to certain limitations.~~OFFICER

~~As a lessee, the Company will also be required to commence drilling of a development well within six~~ (6)PRINCIPAL ~~months~~FINANCIAL from the date on which the lease is granted and, thereafter, with due diligence to define the petroleum field, develop the leased area, produce petroleum therefore and seek markets for and market such petroleum.OFFICER)

52Date: March 18, 2019

~~Table~~/S/ ofZEEV ~~Contents~~KOLTOVSKOY

~~PART~~ZEEV IVKOLTOVSKOY,

~~ITEM~~CHIEF ~~15.~~ACCOUNTING ~~EXHIBITS, FINANCIAL STATEMENT SCHEDULES~~OFFICER

(a)PRINCIPAL ~~Exhibits~~ACCOUNTING OFFICER)

3.1		Certificate of Incorporation of Registrant with all amendments filed as an Exhibit to the S-l Registration Statement, File No. 2-83574.
3.2		Amendment to Certificate of Incorporation filed March 17, 1993, filed as an Exhibit with the S-l Registration Statement, File No. 33-57482.
3.3		By-laws of Registrant filed as Exhibit 3(ii) to the 8-K filed January 18, 2012 and incorporated herein by reference.
4.2		First Amended and Restated Promissory Note dated as of February 27, 2007, issued to NAPHTHA ISRAEL PETROLEUM CORP., LTD. in the principal amount of $11,500,000 filed as an Exhibit to the 10-K for the year ended December 31, 2008 and incorporated herein by reference.
4.3		First Amended and Restated Promissory Note dated as of February 27, 2007, issued to and I.O.C. ISRAEL OIL COMPANY, LTD. in the principal amount of $12,000,000 filed as an Exhibit to the 10-K for the year ended December 31, 2008 and incorporated herein by reference.
4.4		Promissory Note dated as of February 27, 2007, issued to and J.O.E.L JERUSALEM OIL EXPLORATION, LTD. in the principal amount of $7,000,000, filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
4.5		Promissory Note dated as of May 25, 2008, issued to and J.O.E.L JERUSALEM OIL EXPLORATION, LTD. in the principal amount of $48,900,000 filed as an Exhibit to the 10-K for the year ended December 31, 2008 and incorporated herein by reference.
10.1		Purchase and Sale Agreement, dated as of February 16, 2007, among Five States Energy Company, L.L.C. and each of the other parties listed as a party “Seller” on the signature pages thereof and ISRAMCO, Inc., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
10.2		LOAN AGREEMENT, dated as of February 27, 2007, between ISRAMCO, INC., and NAPHTHA ISRAEL PETROLEUM CORP., LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
10.3		LOAN AGREEMENT, dated as of February 27, 2007, between ISRAMCO, INC., and NAPHTHA ISRAEL PETROLEUM CORP., LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
10.4		LOAN AGREEMENT, dated as of February 27, 2007, Between ISRAMCO, INC., and I.O.C. ISRAEL OIL COMPANY, LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
10.5		LOAN AGREEMENT, dated as of February 26, 2007, between ISRAMCO, INC., and J.O.E.L JERUSALEM OIL EXPLORATION, LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.

Date: March 18, 2019

10.7		Agreement dated as of December 31, 2007 between Isramco Inc. and I.O.C. Israel Oil Company Ltd and addendum dated January 1, 2008, filed as an Exhibit to the 10-Q for the quarter ended March 31, 2008 and incorporated herein by reference.
10.8		Amended and restated credit agreement dated on April 28, 2008 between Isramco Resources, LLC and The Bank of Nova Scotia and Capital One, N.A., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2008 and incorporated herein by reference.

Pursuant to the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Haim Tsuff	Chairman of the Board &	March 18, 2019
Haim Tsuff	Co-Chief Executive Officer

/s/ Josef From	Director	March 18, 2019
Josef From

/s/ Max Pridgeon	Director	March 18, 2019
Max Pridgeon

/s/ Frans Sluiter	Director	March 18, 2019
Frans Sluiter

/s/ Nir Hasson	Director	March 18, 2019
Nir Hasson

/s/ Asaf Yarkoni	Director	March 18, 2019
Asaf Yarkoni

~~Table of Contents~~53

10.9		Amended and Restated Loan Agreement dated as of May 25, 2008 between Isramco Inc. and J.O.E.L. Jerusalem Oil Explorations Ltd. filed as an Exhibit to the 10-K for the year ended December 31, 2008 and incorporated herein by reference.
10.10		Amended and Restated Agreement dated as of November 17, 2008 between Isramco Inc. and Goodrich Global Ltd. filed as an Exhibit to the 10-K for the year ended December 31, 2008 and incorporated herein by reference.
10.11		First Amendment to Loan Agreement dated as of February 1, 2009, between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd.($18.5 million) filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
10.12		First Amendment to Loan Agreement dated as of February 1, 2009, between Isramco, Inc, and Naphtha Israel Petroleum Corp., Ltd.($11.5 million) filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
10.13		Loan Agreement dated as of July 14, 2009 between Isramco, Inc. and I.O.C. – Israel Oil Company, Ltd.($6.0 million) filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
10.14		First Amendment to Loan Agreement dated as of February 1, 2009 between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd.($12.0 million) filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
10.15		Loan Agreement dated as of March 3, 2011 between Isramco, Inc. and I.O.C. – Israel Oil Company, Ltd.($11.0 million) filed as an Exhibit to the 10-K for the year ended December 31, 2010 and incorporated herein by reference.
10.16		First Amendment to Loan Agreement dated as of October 1, 2011 between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd. ($11.0 million) filed as an Exhibit to the 10-K for the year ended December 31, 2011 and incorporated herein by reference.
10.17		2011 Stock Incentive Plan filed as an Exhibit to the 10-K for the year ended December 31, 2011 and incorporated herein by reference.
10.18		Loan Agreement dated as of February 13, 2013 between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd. (1.5 million) filed as an Exhibit to 10-K for the year ended December 2012 and incorporated herein by reference.
10.19		Amendment to Loan Agreement dated as of March 1, 2013 between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd. filed as an Exhibit to 10-K for the year ended December 2012 and incorporated herein by reference.
10.20		Amendment to Loan Agreement dated as of March 1, 2013 between Isramco, Inc. and NAPHTHA ISRAEL PETROLEUM CORP., LTD filed as an Exhibit to 10-K for the year ended December 2012 and incorporated herein by reference.
10.21		Amendment to Amended and Restated Loan Agreement and Note between Isramco Inc and J.O.E.L. Jerusalem Oil Exploration, Ltd dated June 30, 2013 filed as an Exhibit to 10-Q for the quarter ended June 2013 and incorporated herein by reference.
10.22		Promissory Note dated June 30, 2013, issued to and J.O.E.L JERUSALEM OIL EXPLORATION, LTD. in the principal amount of $43,700,921 filed as an Exhibit to 10-Q for the quarter ended June 2013 and incorporated herein by reference.
10.23		Loan Agreement dated as of March 29, 2012 between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd. ($3.5 million) filed as an Exhibit to 10K-A for the year ended December 2012 and incorporated herein by reference.
10.24		Loan Agreement dated as of April 29, 2012 between Isramco Inc. and I.O.C. Israel Oil Company, Ltd. ($10.0 million) filed as an Exhibit to 10-Q for the quarter ended June 30, 2012 and incorporated herein by reference.
10.25		Employment Agreement dated effective November 3, 2017, between Isramco Inc. and Edy Francis, filed as an Exhibit to Form 8-K dated November 9, 2017 and incorporated herein by reference.
10.26		Consulting Agreement dated effective June 1, 2014, between Isramco Inc. and Goodrich Global Ltd., filed as an Exhibit to Form 8-K dated September 11, 2014 and incorporated herein by reference.

Table of Contents

54INDEX TO FINANCIAL STATEMENTS

Table of Contents

	Page
Management’s Report on Internal Control Over Financial Reporting	F-1
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets at December 31, 2018 and 2017	F-3
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016	F-4
Consolidated Statements of Changes in Shareholders’ Equity (Deficit) for the years ended December 31, 2018, 2017 and 2016	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016	F-6
Notes to Consolidated Financial Statements	F-7

10.27		Credit Agreement dated as of May 18, 2015, by and among Tamar Royalties LLC, as Borrower, Deutsche Bank Trust Company Americas, as administrative agent, the lenders party thereto, as Lenders, and Deutsche Bank Trust Company Americas, as collateral agent filed as an Exhibit to 8-K filed by the Company on May 22, 2015 and incorporated herein by reference.
10.28		Royalties Sale and Contribution Agreement dated May 18, 2015, by and between Isramco, Inc., as Seller, and Tamar Royalties, LLC, as Borrower filed as an Exhibit to 8-K filed by the Company on May 22, 2015 and incorporated herein by reference.
10.29		Pledge, Assignment and Security Agreement dated as of May 18, 2015, by and between Tamar Royalties LLC, as Borrower, and Deutsche Bank Trust Company Americas, as collateral agent filed as an Exhibit to 8-K filed by the Company on May 22, 2015 and incorporated herein by reference.
10.30		Intercompany Loan Agreement dated as of May 18, 2015, by and between Isramco, Inc., as Payor, and Tamar Royalties, LLC, as Payee filed as an Exhibit to 8-K filed by the Company on May 22, 2015 and incorporated herein by reference.

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