Quarterly Report (10-q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

Check One
☒	Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended March 31, 2018

	or

☐	Transition report under 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 or Organization)		I.R.S. Employer Number

1001 West Loop South, Suite 750, HOUSTON, TX 77027

(Address of Principal Executive Offices)

713-621-5946

(Registrant’s Telephone Number, Including Area Code)

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

Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definition 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 Exchange Act). Yes o No ☒

As of May 10, 2018, Isramco, Inc, had 2,717,648 outstanding shares of common stock, par value $0.01 per share.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (unaudited)	4
	Consolidated Balance Sheets at March 31, 2018 and December 31, 2017	4
	Consolidated Statements of Operations for the three months ended March 31, 2018 and 2017	5
	Consolidated Statements of Comprehensive Income for the three months ended March 31, 2018 and 2017	6
	Consolidated Statements of Cash Flows for the three months ended March 31, 2018 and 2017	7
	Notes to Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27
Item 4.	Controls and Procedures	27

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	28
Item 1A.	Risk Factors	28
Item 2.	Changes in Securities and Use of Proceeds and Issuer Purchases of Equity Securities	28
Item 3.	Defaults Upon Senior Securities	28
Item 4.	(Removed and Reserved)	28
Item 5.	Other Information	28
Item 6.	Exhibits	29
	Signatures	30

Forward Looking Statements

CERTAIN STATEMENTS MADE IN THIS QUARTERLY REPORT ON FORM 10-Q ARE “FORWARD-LOOKING STATEMENTS” WITHIN THE MEANING OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995. FORWARD-LOOKING STATEMENTS CAN BE IDENTIFIED BY TERMINOLOGY SUCH AS “MAY”, “WILL”, “SHOULD”, “EXPECTS”, “INTENDS”, “ANTICIPATES”, “BELIEVES”, “ESTIMATES”, “PREDICTS”, OR “CONTINUE” OR THE NEGATIVE OF THESE TERMS OR OTHER COMPARABLE TERMINOLOGY AND INCLUDE, WITHOUT LIMITATION, STATEMENTS BELOW REGARDING EXPLORATION AND DRILLING PLANS, FUTURE GENERAL AND ADMINISTRATIVE EXPENSES, FUTURE GROWTH, FUTURE EXPLORATION, FUTURE GEOPHYSICAL AND GEOLOGICAL DATA, GENERATION OF ADDITIONAL PROPERTIES, RESERVES, NEW PROSPECTS AND DRILLING LOCATIONS, FUTURE CAPITAL EXPENDITURES, SUFFICIENCY OF WORKING CAPITAL, ABILITY TO RAISE ADDITIONAL CAPITAL, PROJECTED CASH FLOWS FROM OPERATIONS, OUTCOME OF ANY LEGAL PROCEEDINGS, DRILLING PLANS, THE NUMBER, TIMING OR RESULTS OF ANY WELLS, INTERPRETATION AND RESULTS OF SEISMIC SURVEYS OR SEISMIC DATA, FUTURE PRODUCTION OR RESERVES, LEASE OPTIONS OR RIGHTS, PARTICIPATION OF OPERATING PARTNERS, CONTINUED RECEIPT OF ROYALTIES, AND ANY OTHER STATEMENTS REGARDING FUTURE OPERATIONS, FINANCIAL RESULTS, OPPORTUNITIES, GROWTH, BUSINESS PLANS AND STRATEGY. BECAUSE FORWARD-LOOKING STATEMENTS INVOLVE RISKS AND UNCERTAINTIES, THERE ARE IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE EXPRESSED OR IMPLIED BY THESE FORWARD-LOOKING STATEMENTS. ALTHOUGH THE COMPANY BELIEVES THAT EXPECTATIONS REFLECTED IN THE FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CANNOT GUARANTEE FUTURE RESULTS, PERFORMANCE OR ACHIEVEMENTS. MOREOVER, NEITHER THE COMPANY NOR ANY OTHER PERSON ASSUMES RESPONSIBILITY FOR THE ACCURACY AND COMPLETENESS OF THESE FORWARD-LOOKING STATEMENTS. THE COMPANY IS UNDER NO DUTY TO UPDATE ANY FORWARD-LOOKING STATEMENTS AFTER THE DATE OF THIS REPORT TO CONFORM SUCH STATEMENTS TO ACTUAL RESULTS.

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PART I - Financial Information

ITEM 1. Financial Statements

ISRAMCO INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)

	As of March 31, 2018			As of December 31, 2017
ASSETS
Current Assets:
Cash and cash equivalents	$	11,886		$	30,009
Accounts receivable, net of allowances for doubtful accounts of $2,241 and $2,431		14,037			12,549
Restricted and designated cash		703			802
Inventories		419			475
Prepaid expenses and other		2,115			2,711
Total Current Assets		29,160			46,546

Property and Equipment, at cost – successful efforts method:
Oil and Gas properties		243,974			243,812
Advanced payment for equipment		452			564
Production service equipment and other equipment and property		62,109			59,108
Total Property and Equipment		306,535			303,484
Accumulated depreciation, depletion, amortization and impairment		(252,594	)		(251,355	)
Net Property and Equipment		53,941			52,129

Derivative asset		837			187
Restricted cash – long term		26,519			9,674
Investments		261			261
Total Assets	$	110,718		$	108,797

LIABILITIES AND SHAREHOLDERS’ DEFICIT
Current Liabilities:
Accounts payable and accrued expenses	$	13,329		$	13,515
Short term debt and current maturities of long-term debt, net of discount of $834 and $828		21,639			18,517
Payables due to related party		50			60
Accrued interest		1,079			1,027
Derivative liability		47			457
Total Current Liabilities		36,144			33,576

Long term debt, net of discount of $1,934 and $2,131		71,866			77,369

Other Long-term Liabilities:
Asset retirement obligations		21,872			21,670
Total Liabilities		129,882			132,615

Commitments and contingencies

Shareholders’ Deficit:
Common stock $0.01 par value; authorized 7,500,000 shares; issued 2,746,915 shares; outstanding 2,717,648 shares		27			27
Additional paid-in capital		23,853			23,853
Accumulated deficit		(35,935	)		(40,970	)
Treasury stock, 29,267 shares at cost		(164	)		(164	)
Total Isramco, Inc. Shareholders’ Deficit		(12,219	)		(17,254	)
Non controlling interest		(6,945	)		(6,564	)
Total Deficit		(19,164	)		(23,818	)
Total Liabilities and Shareholders’ Deficit	$	110,718		$	108,797

See notes to the unaudited consolidated financial statements.

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ISRAMCO INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share and per share amounts)

(Unaudited)

	Three Months Ended March 31
	2018			2017
Revenues
Oil and gas sales	$	10,984		$	11,064
Production services		5,763			3,468
Office services		136			137
Gain on divestiture		472			-
Other		138			131
Total revenues		17,493			14,800

Operating expenses
Lease operating expense, transportation and taxes		2,300			2,186
Depreciation, depletion and amortization		1,291			1,504
Accretion expense		230			222
Production services		5,585			3,942
Loss from plug and abandonment		58			22
General and administrative		1,365			1,178
Total operating expenses		10,829			9,054
Operating income		6,664			5,746

Other expenses
Interest expense, net		1,217			1,188
Loss (gain) from derivative contracts, net		(865	)		131
Total other expenses		352			1,319

Income before income taxes		6,312			4,427
Income tax expense		1,658			1,706

Net income	$	4,654		$	2,721
Net loss attributable to non-controlling interests		(381	)		(447	)
Net income attributable to Isramco	$	5,035		$	3,168

Earnings per share – basic:	$	1.85		$	1.17

Earnings per share – diluted:	$	1.85		$	1.17

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

See notes to the unaudited consolidated financial statements.

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ISRAMCO INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

	Three Months Ended March 31
	2018			2017
Net income	$	4,654		$	2,721
Comprehensive income		4,654			2,721
Comprehensive loss attributable to non-controlling interests		(381	)		(447	)
Comprehensive income attributable to Isramco	$	5,035		$	3,168

See notes to the unaudited consolidated financial statements.

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ISRAMCO INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three months Ended March 31,
	2018			2017

Cash Flows From Operating Activities:
Net income	$	4,654		$	2,721
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		1,291			1,504
Bad debt expense		58			-
Accretion expense		230			222
Gain on divestiture		(472	)		-
Changes in deferred taxes		-			4
Net unrealized gain on derivative contracts		(1,060	)		(133	)
Amortization of debt cost		191			201
Changes in components of working capital and other assets and liabilities
Accounts receivable		(1,546	)		(1,530	)
Prepaid expenses, and other		596			361
Due to related party		(10	)		(18	)
Inventories		56			123
Accounts payable and accrued expenses		(255	)		(165	)
Net cash provided by operating activities		3,733			3,290

Cash flows from investing activities:
Addition to property and equipment, net		(2,992	)		(230	)
Proceeds from sale of oil and gas properties and equipment		454			-
Net cash used in investing activities		(2,538	)		(230	)

Cash flows from financing activities:
Repayment of long term debt		(2,400	)		(2,400	)
Borrowings of bank overdraft, net		-			17
Repayments of short - term debt, net		(172	)		(223	)
Net cash used in financing activities		(2,572	)		(2,606	)

Net increase (decrease) in cash, cash equivalents, and restricted cash		(1,377	)		454
Cash, cash equivalents, and restricted cash at beginning of period		40,485			33,913
Cash, cash equivalents, and restricted cash at end of period	$	39,108		$	34,367

See notes to the unaudited consolidated financial statements.

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Isramco Inc.

Notes to Consolidated Financial Statements

(Unaudited)

Note 1 - Financial Statement Presentation

Isramco, Inc. and its subsidiaries and affiliated companies (together referred to as “We”, “Our”, “Isramco” or the “Company”) is predominately an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas properties located onshore in the United States and ownership of various royalty interests in oil and gas concessions located offshore Israel. The Company also operates a production services company that provides well maintenance and workover services, well completion, and recompletion services.

The accompanying unaudited financial statements and notes of Isramco have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “Commission”). Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying financial statements and notes should be read in conjunction with the accompanying financial statements and notes included in Isramco’s Annual Report on Form 10-K for the year ended December 31, 2017.

The accompanying unaudited interim financial statements furnished in this report reflect all adjustments that are, in the opinion of management, necessary to fairly present Isramco’s results of operations and cash flows for the three month periods ended March 31, 2018 and 2017 and Isramco’s financial position as of March 31, 2018.

Use of Estimates

In preparing financial statements in accordance with accounting principles generally accepted in the United States, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to the value of properties and equipment; proved reserves; intangible assets; asset retirement obligations; litigation reserves; environmental liabilities; liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Consolidated interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these consolidated financial statements.

Concentrations of Credit Risk

Financial instruments, which potentially expose Isramco to concentrations of credit risk, consist primarily of interest rate swaps, cash equivalents, trade and joint interest accounts receivable. Isramco’s customer base includes several of the major United States oil and gas operating and production companies as well as major power companies in Israel. Although Isramco is directly affected by the well-being of the oil and gas production industry, management does not believe a significant credit risk existed as of March 31, 2018. Isramco continues to monitor and review credit exposure of its marketing counter-parties.

Tamar Royalties LLC, a wholly owned subsidiary of Isramco Inc., entered into certain swap and cap agreements with Deutsche Bank AG London Branch to hedge the risk of interest rate volatility. See Note 4 for details.

Our production services segment customers include major oil and natural gas production companies and independent oil and natural gas production companies. We perform ongoing credit evaluations of our customers and usually do not require material collateral. We maintain reserves for potential credit losses when necessary. Our results of operations and financial position should be considered in light of the fluctuations in demand experienced by oilfield service companies as changes in oil and gas producers’ expenditures and budgets occur. These fluctuations can impact our results of operations and financial position as supply and demand factors directly affect utilization and hours which are the primary determinants of our net cash provided by operating activities.

Isramco maintains deposits in banks, which may exceed the amount of federal deposit insurance available. Management periodically assesses the financial condition of the institutions and believes that any possible deposit loss is minimal.

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Risk Management Activities

The Company follows Accounting Standards Codification (ASC) 815, Derivatives and Hedging. From time to time, the Company may hedge a portion of its forecasted oil and natural gas production or may hedge interest rates on variable interest rate loans. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction. The Company has elected not to designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net loss (gain) on derivative contracts” in the consolidated statements of operations. Currently, the Company has no derivative contracts in place to hedge against fluctuations in oil and natural gas prices.

Fair Value

Fair value accounting applies to reported balances that are required or permitted to be measured at fair value under existing accounting pronouncements. Fair value measurements are determined based on the assumptions that market participants would use in pricing the asset or liability. As a basis for considering market participant assumptions in fair value measurements, these accounting requirements establish a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within Levels 1 and 2 of the hierarchy) and the reporting entity’s own assumptions about market participant assumptions (unobservable inputs classified within Level 3 of the hierarchy).

Level 1 inputs utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access.

Level 2 inputs are inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 inputs might include quoted prices for similar assets and liabilities in active markets, as well as inputs that are observable for the asset or liability (other than quoted prices), such as interest rates, foreign exchange rates, and yield curves that are observable at commonly quoted intervals.

Level 3 inputs are unobservable inputs for the asset or liability, and are typically based on an entity’s own assumptions, as there is little, if any, related market activity.

In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset or liability. We utilize the fair value hierarchy in our accounting for interest rate swaps (Level 2).

Consolidation

The consolidated financial statements include the accounts of Isramco and its subsidiaries. Inter-company balances and transactions have been eliminated in consolidation.

Cash, cash equivalents and restricted cash

The Company adopted the FASB accounting standard ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) on January 1, 2018 using a full retrospective approach. ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are included with cash and cash equivalents in reconciling the beginning-of-period and end-of-period total amounts shown on the Company’s consolidated statements of cash flows. We believe the adoption of ASU 2016-18 did not have a material impact on the Company’s Consolidated Financial Statements.

The Company considers highly liquid investments purchased with a maturity period of three months or less at the date of purchase to be cash equivalents. Restricted cash and restricted cash – long term are included with cash, cash equivalents, and restricted cash on the Company’s consolidated statements of cash flows.

Consolidated balance sheets amount included as cash, cash equivalents, and restricted cash on the Company’s consolidated statements of cash flows:

	As of March 31, 2018		As of December 31, 2017

Cash and cash equivalents	$	11,886	$	30,009
Restricted and designated cash		703		802
Restricted cash – long term		26,519		9,674
Total Current Assets	$	39,108	$	40,485

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Impairment

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 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.

Asset Retirement Obligation

ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records asset retirement obligations to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells and gas gathering systems. The Company estimates the expected cash flow associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment.

Gain on divestiture

In February 2018, the Company sold oil and gas property for a net gain of $472,000. The gain consists of $454,000 cash plus $19,000 in relieved asset retirement obligation offset by a net book value of $1,000.

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.

Aggregate maturities of contractual obligations at March 31, 2018 are due in future years as follows (in thousands):

Principal Payments on Long-term debt:

2018	$	16,500
2019		21,900
2020		17,100
2021		14,700
2022		14,400
2023		11,400
Total	$	96,000

Note 2 - Supplemental Cash Flow Information

The Israeli taxing authority withheld taxes of $1,658,000 and $1,707,000 during the three months ended March 31, 2018 and 2017 respectively.

Cash payments for interest were $1,027,000 and $974,000 for the three months ended March 31, 2018 and 2017 respectively.

The consolidated statement of cash flows for the three months ended March 31, 2018 excludes the following non-cash transactions:

●	Increase in property and equipment of $112,000 included in accounts payable.

●	Asset retirement obligation of $19,000 relieved in sale of oil and gas properties.

The consolidated statement of cash flows for the period ended March 31, 2017 excludes the following non-cash transaction:

●	Net refund of advance payment for property and equipment of $38,000 used to reduce accounts payable.

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Note 3 – Revenue from Contracts with Customers

Adoption of new revenue recognition and disclosure guidance

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity is required to record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer.

The Company adopted the new revenue recognition and presentation guidance on January 1, 2018, using a full retrospective transition approach. We believe that adoption of the new guidance had no cumulative effect impact on the Company’s retained earnings at January 1, 2018.

The new guidance does not have a material impact on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows.

Below is a discussion of the nature, timing, and presentation of revenues arising from the Company’s major revenue-generating arrangements:

Oil and Gas sales United Sates – Revenues on sales of oil, natural gas liquids (“NGLs”), gas and purchased oil and gas are recognized when control of the product is transferred to the purchaser and payment can be reasonably assured. Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, distance from the well to the pipeline or market, commodity quality and prevailing supply and demand conditions. As such, the prices of oil, NGLs and gas generally fluctuate based on the relevant market index rates. Sales under the Company’s oil contracts are generally considered performed when the Company sells oil production at the wellhead and receives an agreed-upon index price, net of any price differentials. The Company recognizes revenue when control transfers to the purchaser at the wellhead based on the net price received. Sales under the Company’s gas processing contracts are recognized when the Company delivers gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the gas and remits proceeds to the Company for the resulting sales of NGLs and gas. In many cases, the Company elects to take its NGLs and residue gas in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the products itself. When the Company elects to take-in-kind, it delivers NGLs and gas to a third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser.

Natural Gas sales Israel – 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 / 2.7375% after payout in the Tamar Field (collectively the “Tamar Royalty”) offshore Israel. 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.

Natural gas from the Tamar Field is currently sold 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’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.

Revenues from natural gas sales in Israel are recognized when control of the product is transferred to a purchaser and payment can reasonably be assured. The Company receives monthly overriding royalty payments from Isramco Negev 2 Limited Partnership, a related party. We generally receive payment two months after the hydrocarbons have been produced. The revenue is recognized in the month that the hydrocarbons are produced.

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Production Services – Our production services business earns revenues for well servicing, plugging services, workover and fluid hauling services pursuant to master services agreements based on purchase orders or other contractual arrangements with the client. Production services jobs are generally short-term (less than 30 days) and are charged at current market rates for the labor, equipment and materials necessary to complete the job. Production services jobs are varied in nature, but typically represent a single performance obligation, either for a particular job, a series of distinct jobs, or a period of time during which we stand ready to provide services as our client needs them. Revenue is recognized for these services over time, as the services are performed. We typically bill clients for our production servicing on an hourly basis for the period that the rig/truck is actively working. Generally, the Company accounts for production services as a single performance obligation satisfied over time. Revenue for certain jobs spanning multiple days is recognized over time upon the completion of each day’s work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and personnel. Additional revenue is generated through labor charges and the sale of consumable supplies that are incidental to the service being performed. Such amounts are recognized ratably over the period during which the corresponding goods and services are consumed.

Disaggregation of revenues (in thousands):

	Three Months Ended March 31,
	2018		2017
Oil and Gas sales
United States	$	3,775	$	3,950
Israel		7,209		7,114
Production Services		5,763		3,468
Total revenues from contracts with customers	$	16,747	$	14,532

Performance obligations

The Company satisfies the performance obligations under its crude oil and natural gas sales contracts upon delivery of its production and related transfer of title to customers. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts that correspond with the value of the production transferred. The Company satisfies the performance obligations under production services arrangements by completing the contracted job, at which time the Company as the right to receive consideration from its customers in agreed upon amounts.

All of the Company’s outstanding production services and crude oil sales contracts at March 31, 2018 are short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.

The majority of the Company’s operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts, whether for crude oil or natural gas, each unit of production delivered to a customer represents a separate performance obligation; therefore, future volumes to be delivered are wholly unsatisfied at period-end and disclosure of the transaction price allocated to remaining performance obligations is not applicable.

Contract balances

Under the Company’s crude oil and natural gas sales contracts or arrangements that give rise to service revenues, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts and service arrangements generally do not give rise to contract assets or contract liabilities under ASC Topic 606. Instead, the Company’s unconditional rights to receive consideration are presented as a receivable within “Accounts receivable, net of allowances for doubtful accounts”, in its condensed consolidated balance sheets.

Revenues from previously satisfied performance obligations

To record revenues for commodity sales in the United States and Israel, at the end of each period the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in our consolidated financial statements within the caption “Oil and gas sales”. Revenues recognized during the three months ended March 31, 2018 related to performance obligations satisfied in prior reporting periods were not material.

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To record revenues for un-billed production services, at the end of each period the Company estimates the services rendered. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month invoices are created and reflected in our consolidated financial statement with the caption “Production services”. Revenues recognized during the three months ended March 31, 2018 related to performance obligations satisfied in prior reporting periods were not material.

Note 4 - Financial Instruments and Fair Value

Pursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820) the Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s non-performance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company believes that it utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

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 entered into a $120,000,000 credit facility with Deutsche Bank, which facility is discussed further in Note 5 “Long-Term Debt and Interest Expense”. Under the terms of this facility, Tamar Royalties, is required to hedge at least seventy-five percent (75%) of the outstanding balance under this 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 and DBAG entered into the IRS Agreement whereby the Company hedged $119,250,000 of the $120,000,000 initial borrowing as follows:

(a) Tamar Royalties 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, 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.

As a result of these financial instruments, the Company recorded a net gain from derivative contracts in the amount of $865,000 consisting of $1,060,000 of unrealized gain and $195,000 loss in cash settlements for the three months ended March 31, 2018. The Company recorded a net loss from derivative contracts in the amount of $131,000 consisting of $133,000 of unrealized gain and $264,000 loss in cash settlements for the three months ended March 31, 2017.

Financial Instruments as of March 31, 2018 and December 31, 2017 consisted of the following (in thousands):

		March 31, 2018						December 31, 2017
Financial Instrument	Fair Value Input Level	Carrying			Fair			Carrying			Fair
		Value			Value			Value			Value

ST Liabilities:
Interest rate swaps	Level 2	$	(47	)	$	(47	)	$	(457	)	$	(457	)

LT Assets:
Interest rate swaps	Level 2		837			837			187			187

		$	790		$	790		$	(270	)	$	(270	)

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Level 2 Financial Instruments

Our interest rate swaps are measured at fair value using Level 2 inputs. The fair of our interest rate swaps is based on the net present value of expected future cash flows related to both variable and fixed-rate legs of the swap agreement. This measurement is computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input.

Note 5 - Long-Term Debt and Interest Expense

Long-term debt as of March 31, 2018 and December 31, 2017, consisted of the following (in thousands):

	As of March 31, 2018			As of December 31, 2017
Bank loan
Principal amount	$	96,000		$	98,400
Less: unamortized discount and debt costs		(2,768	)		(2,959	)
Total long-term debt		93,232			95,441
Less: current maturities, net of current unamortized discount		(21,366	)		(18,072	)

Long-term debt, net of current maturities	$	71,866		$	77,369

Bank Loan and Credit Facility

The Deutsche Bank Facility

On May 18, 2015, 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%, but is subject to increase to 2.7375% upon the Tamar project payout (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.

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’ obligations under the DB 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). The initial Required Reserve Amount was $4,680,000. In addition, Tamar Royalties is required under the DB Facility to hedge against fluctuations in LIBOR as reflected in Note 4 “Financial Instruments and Fair Value”.

On January 2, 2018, the Company made a payment in the amount of $3,427,000 consisting of $2,400,000 and $1,027,000 in principal and interest respectively.

On April 2, 2018, the Company made a payment in the amount of $6,479,000 consisting of $5,400,000 and $1,079,000 in principal and interest respectively.

The Company incurred debt costs in obtaining the facility in the amount of $2,011,000. Additionally the lenders retained $2,959,000 in fees. These costs, totaling $4,970,000, are recorded as a reduction of the principal loan balance and are being amortized over the life of the loan using the effective interest method. Amortization of these costs for the three-month period ended March 31, 2018 and 2017 totaled $191,000 and $201,000 respectively.

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As of March 31, 2018, Tamar Royalties was in compliance with the financial covenants required under the DB Facility.

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 tenor 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; and (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 March 31, 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, 2017 at which time the remaining balance totaling $299,000 was expensed.

Isramco 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.

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

Short-Term Debt

As of March 31, 2018, and December 31, 2017, outstanding debt from short-term insurance financing agreements totaled $273,000 and $445,000 respectively. During the three months ended March 31, 2018, the Company made cash payments totaling $172,000.

Interest Expense

The following table summarizes the amounts included in interest expense for the three months ended March 31, 2018, and 2017:

	Three Months Ended March 31,
	2018		2017
	(In thousands)
Current debt, long-term debt and other - banks	$	1,217	$	1,188

Note 6 - Tamar Field Proceeds

We own an overriding royalty interest of 1.5375% in the Tamar Field, which will increase to 2.7375% after payout (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. For additional information, please see the disclosure related to the Tamar Royalty set forth in the ITEM 1. BUSINESS section included in our Annual Report on Form 10-K for the year ended December 31, 2017, which disclosure is hereby incorporated herein by reference thereto.

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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, Isramco Negev 2-LP, Delek Drilling, Avner Oil & Gas, and Dor Gas (the “Tamar Consortium”), two leases (the “Leases”). 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. On March 31, 2013 the Tamar Field commenced its initial production of the natural gas.

Since Isramco’s interest in the Tamar Field is an overriding royalty interest, there are no amounts capitalized with respect to Tamar Field.

During the three months ended March 31, 2018, Tamar Field net sales attributable to Isramco amounted to 1,316,631 Mcf of natural gas and 1,669 Bbl of condensate with prices of $5.43 per Mcf and $58.53 per Bbl of condensate. Total revenues net of marketing and transportations expenses were $7,209,000. The Israeli Tax Authority withheld $1,658,000 of this revenue.

During the three months ended March 31, 2017, Tamar Field net sales attributable to Isramco amounted to 1,318,916 Mcf of natural gas and 1,749 Bbl of condensate with prices of $5.36 per Mcf and $46.33 per Bbl of condensate. Total revenues net of marketing and transportations expenses were $7,114,000. The Israeli Tax Authority withheld $1,707,000 of this revenue.

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 charges related to gathering and transportation infrastructure. The disagreements primarily 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 Company currently believes that the total scope of the claim asserted by Isramco Negev 2 Limited Partnership is approximately forty-five million dollars ($45,000,000) and the counterclaims asserted by the Company 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.

Note 7 - Segment Information

Isramco’s primary business segments are vertically integrated within the oil and gas industry. These segments are separately managed due to distinct operational differences, unique technology, distribution and marketing requirements. The Company’s two reporting segments are oil and gas exploration and production and production services. The oil and gas exploration and production segment explores for and produces natural gas, crude oil, condensate, and natural gas liquids (“NGLs”). The production services segment is engaged in rig-based and workover services, well completion and recompletion services, plugging and abandonment of wells and other ancillary oilfield services.

Oil and Gas Exploration and Production Segment

Our Oil and Gas segment is engaged in the exploration, development and production of oil and natural gas properties located onshore in the United States and ownership of various royalty interests in oil and gas concessions located offshore Israel. 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 in New Mexico.

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Production Services Segment

The Company began production services operations in October 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 Service . 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.

●

Fluid Services. We own and operate 42 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 for 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.

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We typically bill clients for our production servicing on an hourly basis for the period that the rig is actively working. As of March 31, 2018, our fleet of production servicing rigs totaled 33 rigs, which we operate through 5 locations in Texas and New Mexico.

(in thousands)	Oil and Gas Exploration & Production			Production Services			Eliminations			Total
Three Months Ended March 31, 2018:
Sales revenues
United States	$	3,775		$	5,763		$	-		$	9,538
Israel		7,209			-			-			7,209
Office services and other		776			-			(30	)		746

Total revenues and other		11,760			5,763			(30	)		17,493

Operating costs and expenses		3,775			5,793			(30	)		9,538
Depreciation, depletion, and amortization		470			821			-			1,291
Interest expenses, net		120			1,097			-			1,217
Gain on derivative contracts		(865	)		-			-			(865	)

Total expenses and other		3,500			7,711			(30	)		11,181

Income (loss) before income taxes	$	8,260		$	(1,948	)	$	-		$	6,312
Net Income (loss)		6,214			(1,560	)		-			4,654
Net loss attributable to noncontrolling interests		-			(381	)		-			(381	)
Net income (loss) attributable to Isramco		6,214			(1,179	)		-			5,035
Total Assets	$	67,768		$	42,950		$	-		$	110,718
Expenditures for Long-lived Assets	$	133		$	2,859		$	-		$	2,992

(in thousands)	Oil and Gas Exploration & Production		Production Services			Eliminations			Total
Three Months Ended March 31, 2017:
Sales revenues
United States	$	3,950	$	3,468		$	-		$	7,418
Israel		7,114		-			-			7,114
Office services and other		298		-			(30	)		268

Total revenues and other		11,362		3,468			(30	)		14,800

Operating costs and expenses		3,495		4,085			(30	)		7,550
Depreciation, depletion, and amortization		765		739			-			1,504
Interest expenses, net		303		885			-			1,188
Loss on derivative contracts		131		-			-			131

Total expenses and other		4,694		5,709			(30	)		10,373

Income (loss) before income taxes	$	6,668	$	(2,241	)	$	-		$	4,427
Net Income (loss)		4,334		(1,613	)		-			2,721
Net loss attributable to noncontrolling interests		-		(447	)		-			(447	)
Net income (loss) attributable to Isramco		4,334		(1,166	)		-			3,168
Total Assets	$	104,941	$	36,517		$	-		$	141,458
Expenditures for Long-lived Assets	$	96	$	134		$	-		$	230

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

THE FOLLOWING COMMENTARY SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES CONTAINED ELSEWHERE IN THIS REPORT ON FORM 10-Q. 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 REPORT ON FORM 10-Q. ISRAMCO INC. DISCLAIMS ANY OBLIGATION TO UPDATE SUCH FORWARD LOOKING STATEMENTS.

Overview

Isramco is predominately an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas properties located onshore in the United States and ownership of various royalty interests in oil and gas concessions located offshore Israel. The Company also operates a production services company that provides well maintenance, workover services, well completion and recompletion services. Our properties are primarily located in Texas, New Mexico and Oklahoma. We also act as the operator of a certain number of these properties. Historically, we have grown through acquisitions, with a focus on properties within our core operating areas that we believe have significant development and exploration opportunities and where we can apply our technical experience and economies of scale to increase production and proved reserves, while lowering lease operating costs.

As noted above in Note 6 to the Company’s consolidated financial statements, in 2009 two natural gas discoveries known as “Tamar” and “Dalit” were made within the area covered by the Michal and Matan Licenses respectively and are known as the Tamar Field. In December 2009 the Israeli Petroleum Commissioner granted Noble Energy, Inc. (“Noble”) and its partners, Isramco Negev 2-LP, Delek Drilling, Avner Oil & Gas, and Dor Gas (the “Tamar Consortium”), two leases (the “Leases”). The Leases are scheduled to expire in December 2038. 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. On March 31, 2013, the Tamar Field began its initial production of the natural gas.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the prices received 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 we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other 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. Our 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, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. To the extent these factors lead to reductions in our drilling plans and associated capital budgets in future periods, our financial position, cash flows and operating results could be adversely impacted.

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Concentrations of Credit Risk

Liquidity and Capital Resources

Our primary source of cash during the three months ended March 31, 2018 was 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.

Our future capital resources and liquidity 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 and continue growth. We expect to fund our future capital requirements through internally generated cash flows, borrowings under loans from related parties, and a future credit facility. 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.

On May 18, 2015, the Company entered into a term loan credit agreement with Deutsche Bank Trust Company Americas (“Deutsche Bank”) in the amount of $120,000,000 secured by the Company’s interest in the Tamar Field. Interest on the borrowing is variable. The Company entered into interest rate swap agreements in relation to this borrowing. The terms of the agreement and swaps are disclosed in Notes 4 and 5 to the Company’s consolidated financial statements.

During the three months ended March 31, 2018, our cash decreased by $1.4 million. Specifically, the net cash provided by operating activities of $3.7 million and cash received from divestiture of $0.5 million was offset by an investment of $3.0 million in production services equipment and oil and gas properties, $2.4 million in repayments of long term debt, and $0.2 million in repayments of short-term debt.

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Debt:

	As of March 31,			As of December 31,
In thousands	2018			2017
Long – term debt net of discount and bank fees	$	71,866		$	77,369

Current maturities of long-term debt, short-term debt and current portion of discount and debt cost		21,639			18,517
Total debt	$	93,505		$	95,886

Stockholders’ deficit	$	(19,164	)	$	(23,818	)

Debt to capital ratio		126	%		133	%

As of March 31, 2018, our total debt was $93,505,000 compared to total debt of $95,886,000 at December 31, 2017.

Contractual Obligations

Aggregate maturities of contractual obligations at March 31, 2018 are due in future years as follows (in thousands):

Principal Payments on Long-term debt:

2018	$	16,500
2019		21,900
2020		17,100
2021		14,700
2022		14,400
2023		11,400
Total	$	96,000

Cash Flow

Our primary source of cash during the three months ended March 31, 2018 was cash flow from operating activities. In the first three months of 2018, cash received from operations was primarily used for investments in production services equipment, oil and gas properties and repayment of short term and long term loans. In the first three months of 2017, cash received from operations and proceeds from sale of oil and gas properties was primarily used for repayment of long-term debt, short-term debt, and investments in equipment.

Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes 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 for oil and natural gas have historically 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.

	Three Months Ended March 31,
	2018			2017
	(In thousands)
Cash flows provided by operating activities	$	3,733		$	3,290
Cash flows used in investing activities		(2,538	)		(230	)
Cash flows used in financing activities		(2,572	)		(2,606	)
Net increase (decrease) in cash	$	(1,377	)	$	454

Operating Activities. During the three months ended March 31, 2018, compared to the same period in 2017, net cash flow provided by operating activities increased by $443,000 to $3,733,000. The increase was primarily attributable to increased revenues from our well services segment.

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Investing Activities. Net cash flows used in investing activities for the three months ended March 31, 2018 and 2017 were $2,538,000 and $230,000, respectively. During the first three months of 2018, the Company invested $133,000 in oil and gas properties and $2,859,000 in production services equipment. The Company also received $454,000 from divestiture of oil and gas assets. During the first three months of 2017, the Company invested $96,000 in oil and gas properties and $134,000 in production services equipment.

Financing Activities. Net cash flows used in financing activities were $2,572,000 and $2,606,000 for the three months ended March 31, 2018 and 2017, respectively. During the first three months of 2018 the Company made payments on long term debt of $2,400,000, made payments on short term debt in the amount of $172,000. During the first three months of 2018 the Company made payments on long term debt of $2,400,000, made payments on short term debt in the amount of $223,000 and increased bank overdraft in the amount of $17,000.

Results of Operations

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Selected Data
	Three Months Ended March 31,
	2018			2017
	(In thousands except per share and BOE amounts)
Financial Results
Oil and Gas sales
United States	$	3,775		$	3,950
Israel		7,209			7,114
Production Services		5,763			3,468
Gain on divestiture		472			-
Other		274			268
Total revenues and other		17,493			14,800

Cost and expenses		10,829			9,054
Other expenses		352			1,319
Income tax expense		1,658			1,706
Net income attributable to common shareholders		4,654			2,721
Net loss attributable to non-controlling interests		(381	)		(447	)
Net income attributable to Isramco		5,035			3,168
Earnings per common share – basic	$	1.85		$	1.17
Earnings per common share – diluted	$	1.85		$	1.17

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

Operating Results
Adjusted EBITDAX (1)	$	7,991		$	7,208
Sales volumes United States (MBOE)		100			122
Sales volumes Israel (MBOE)		221			222

Average cost per BOE United States: (2)
Production (excluding transportation and taxes)	$	18.32		$	14.05
General and administrative (oil and gas production segment)	$	11.82		$	8.74
Depletion	$	4.69		$	6.27

(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.

(2)	There are no costs associated with revenues from Israeli operations since the Company owns the Tamar Royalty, which is an overriding royalty free of operating expenses.

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Financial Results

Net income in the first quarter of 2018 was $5,035,000 or $1.85 per share. This compares to net income in the first quarter of 2017 of $3,168,000 or $1.17 per share.

This increase in income was primarily due to a gain on derivative contracts of $865,000 compared to a loss on derivative contracts for the first quarter of 2017 of $131,000, a gain on divestiture of $472,000, and an increase in revenues from production services.

Revenues, Volumes and Average Prices Oil and Gas Segment - Israel

Revenues, Volumes and Average Prices Oil and Gas Segment – United States

Sales Revenues

	Three Months Ended March 31,
In thousands except percentages	2018		2017		D vs. 2017
Gas sales	$	750	$	1,097		(32	)%
Oil sales		2,670		2,447		9
Natural gas liquid sales		355		406		(13	)
Total	$	3,775	$	3,950		(4	)%

The Company’s sales revenues from United States based oil and gas operations for the first quarter of 2018 decreased by 4% when compared to same period in 2017 due to a decrease in production volumes for crude oil, natural gas, and NGLs. This decrease was partially offset by higher prices for crude oil and NGLs in the United States.

Volumes and Average Prices

	Three Months Ended March 31,
	2018		2017		D vs. 2017
Natural Gas
Sales volumes Mmcf		262.4		332.5		(21	)%
Average Price per Mcf	$	2.86	$	3.30		(13	)
Total gas sales revenues (thousands)	$	750	$	1,097		(32	)%

Crude Oil
Sales volumes MBbl		43.0		49.1		(12	)%
Average Price per Bbl	$	62.06	$	49.80		25
Total oil sales revenues (thousands)	$	2,670	$	2,447		9	%

Natural gas liquids
Sales volumes MBbl		13.5		17.4		(22	)%
Average Price per Bbl	$	26.22	$	23.32		12
Total natural gas liquids sales revenues (thousands)	$	355	$	406		(13	)%

In the United States the Company’s natural gas sales volumes decreased by 21%, crude oil sales volumes decreased by 12%, and natural gas liquids sales volumes decreased by 22% for the first quarter of 2018 compared to the same period of 2017.

The Company’s average natural gas price received for the first quarter of 2018 decreased by 13%, or $0.44 per Mcf, when compared to the same period of 2017. The Company’s average crude oil price for the first quarter of 2018 increased by 25%, or $12.26 per Bbl, when compared to the same period of 2017. Our average natural gas liquids price for the first quarter of 2018 increased by 12%, or $2.90 per Bbl, when compared to the same period of 2017.

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Analysis of Oil and Gas Operations Sales Revenues

The following table provides a summary of the effects of changes in volumes and prices on Isramco’s United States sales revenues for the three months ended March 31, 2018 compared to the same period of 2017.

In thousands	Natural Gas			Oil			Natural gas liquids
2017 sales revenues	$	1,097		$	2,447		$	406
Changes associated with sales volumes		(231	)		(305	)		(90	)
Changes in prices		(116	)		528			39
2018 sales revenues	$	750		$	2,670		$	355

Operating Expenses (excluding production services segment)

	Three Months Ended March 31,
In thousands except percentages	2018		2017		D vs. 2017
Lease operating expense, transportation and taxes	$	2,300	$	2,186		5	%
Depreciation, depletion and amortization of oil and gas properties		470		765		(39	)
Accretion expense		230		222		4
Loss (gain) from plugging and abandonment of wells		58		22		164
General and administrative		1,186		1,066		11
	$	4,244	$	4,261		(0.4	)%

During the three months ended March 31, 2018, our operating expenses decreased by 0.4% when compared to the same period of 2017 due to the following factors:

Lease operating expense, transportation cost and taxes increased by 5%, or $114,000, in 2018 when compared to 2017 primarily due to increased repair work with increased economics. On a per unit basis, lease operating expenses (excluding transportation and taxes) increased by $4.27 per MBOE to $18.32 per MBOE in 2018 from $14.05 per MBOE in 2017.

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 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 39% in the first three months of 2018 as compared to the same period in 2017 as a result of a lower depletable base and lower production.

·	General and administrative expenses increased by 11% or $120,000, in 2018 when compared to 2017 as a result of increased professional fees, legal fees and wages.

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Production Services Segment

	Three Months Ended March 31,
In thousands except percentages	2018			2017			D vs. 2017
Production Services	$	5,763		$	3,468			66	%
Operating expenses		5,585			3,942			42
Depreciation		821			739			11
General and administrative		209			142			47
Operating loss	$	(852	)	$	(1,355	)		(37	)%

·	Our sales revenues from production services operations for the first quarter of 2018 increased by 66% or $2,295,000 when compared to same period in 2017 as a result of the increased demand for our services and related expansion in the market.

·	Operating expenses from production services operations for the first quarter of 2018 increased by 42% or $1,643,000 when compared to the same period in 2017 as a result increased operations and related payroll.

Production service equipment depreciation – the amounts represent depreciation of production services rigs and auxiliary equipment for our production services subsidiary. The depreciation expenses for the first quarter of 2018 totaled $821,000, an increase of $82,000 compared to the same period in 2017. This increase in depreciation is primarily a result of additional equipment purchases.

·	General and administrative expenses from production services operations for the first quarter of 2018 totaled $209,000, an increase of $67,000 compared to the same period in 2017 which was primarily related to increased legal fees and an increase in bad debt expense.

Other expenses

	Three Months Ended March 31,
In thousands except percentages	2018			2017		D vs. 2017
Interest expense, net	$	1,217		$	1,188		2	%
Loss (gain) on interest rate swap		(865	)		131		(760	)
	$	352		$	1,319		(73	)%

Interest expense. Isramco’s interest expense increased by 2%, or $29,000, for the three months ended March 31, 2018 compared to the same period of 2017. This increase was primarily due to a higher interest rate during the first quarter of 2018 compared to 2017, which was partially offset by lower outstanding principal for the period.

Unrealized loss on interest rate swaps. For the first quarter of 2018 we recorded a gain as a result of changes in fair value of the derivative in the amount of $865,000, comprised of a cash settlement loss of $195,000 and gain of $1,060,000 as a result of changes in the fair value. In the first quarter of 2018 we recorded a loss as a result of changes in fair value of the derivative in the amount of $131,000, comprised of a cash settlement loss of $264,000 and gain of $133,000 as a result of changes in the fair value.

Adjusted EBITDAX.

To 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. The Company believes that 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.

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However, Adjusted EBITDAX, as defined by Isramco, may not be comparable to similarly titled measures used by other companies. Therefore, Isramco’s consolidated Adjusted EBITDAX should be considered in conjunction with income (loss) from operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect income from continuing operations and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Isramco’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) from operations before income taxes.

	Three Months Ended March 31,
In thousands except percentages	2018			2017
Income from operations before income taxes	$	6,312		$	4,427
Depreciation, depletion and amortization expense		1,291			1,504
Unrealized gain on interest rate swap		(1,060	)		(133	)
Interest expense		1,217			1,188
Accretion expense		230			222
Consolidated Adjusted EBITDAX	$	7,990		$	7,208

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ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Derivative Instruments and Hedging Activity

We are exposed to various risks, including risks associated with energy commodity price. 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 allows 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. Currently, we have no open positions or contracts in place in relation to commodity prices.

When such contracts are in place, we are exposed to market risk on our open derivative contracts and counterparty performance risk with respect to our counterparties. However, we usually do not expect such non-performance because our contracts are usually with major financial institutions with investment grade credit ratings.

We are also exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. We 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. Periodically, we look to utilize interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates.

We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. The Company has elected not to designate any of its positions for hedge accounting. See Item 1. Consolidated Financial Statements .

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.

In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Co-Chief Executive Officers, our Chief Financial Officer, and our Chief Accounting Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Co-Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer concluded that our disclosure controls and procedures were effective as of March 31, 2018 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in the Company’s internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II - Other Information

ITEM 1. 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. 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 charges related to gathering and transportation infrastructure. The disagreements primarily 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 Company currently believes that the total scope of the claim asserted by Isramco Negev 2 Limited Partnership is approximately forty-five million dollars ($45,000,000) and the counterclaims asserted by the Company 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. 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, the case is still in its early stages. 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 1A. Risk Factors

None

ITEM 2. Change in Securities & Use of Proceeds

None

ITEM 3. Default Upon Senior Securities

None

ITEM 4. Removed and Reserved

None

ITEM 5. Other Information

None

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ITEM 6. Exhibits

Exhibits
31.1	Certification of Chief Executive Officer pursuant to Section 31 2 of Sarbanes-Oxley Act
31.2	Certification of Chief Financial Officer pursuant to Section 31 2 of Sarbanes-Oxley Act
31.3	Certification of Chief Accounting Officer pursuant to Section 31 2 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 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
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

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SIGNATURES

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

	ISRAMCO, INC

Date: MAY 10, 2018	By:	/s/ HAIM TSUFF
		HAIM TSUFF
		CO-CHIEF EXECUTIVE OFFICER
		(PRINCIPAL EXECUTIVE OFFICER)

Date: MAY 10, 2018	By:	/s/ EDY FRANCIS
		EDY FRANCIS
		CO-CHIEF EXECUTIVE OFFICER & CHIEF FINANCIAL OFFICER
		(PRINCIPAL FINANCIAL OFFICER)

Date: MAY 10, 2018	By:	/s/ ZEEV KOLTOVSKOY
		ZEEV KOLTOVSKOY
		CHIEF ACCOUNTING OFFICER
		(PRINCIPAL ACCOUNTING OFFICER)

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