Edgar Filing: ISRAMCO INC

isramco10k123110.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

Mark one:
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010

r	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.)

2425 West Loop South, Suite 810, Houston Texas 77027

(Address of Principal Executive Offices)

713-621-3882

(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 r No x

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 r No x

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. x Yes r 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.r

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

Large accelerated filer r Accelerated filer x Non-accelerated filer r Smaller Reporting Company o

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

As of March 11, 2011, there were 2,717,691 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 June 30, 2010, based on the last sale price of such equity reported on the Nasdaq market, was approximately $128 million.

DOCUMENTS INCORPORATED BY REFERENCE

Information required by Part III, Items 10, 11, 12, 13 and 14, is incorporated by reference to portions of the registrant’s definitive proxy statement for its 2010 annual meeting of stockholders, which will be filed on or before April 30, 2011.

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ISRAMCO, INC.

2010 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

		Page
PART I

ITEM 1.	BUSINESS	4
ITEM 1A.	RISK FACTORS	11
ITEM 1B.	UNRESOLVED STAFF COMMENTS	21
ITEM 2.	PROPERTIES	21
ITEM 3.	LEGAL PROCEEDINGS	21
ITEM 4.	REMOVED AND RESERVED

PART II

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	22
ITEM 6.	SELECTED FINANCIAL DATA	22
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	32
ITEM 8.	CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	33
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	33
ITEM 9A.	CONTROLS AND PROCEDURES	33
ITEM 9B.	OTHER INFORMATION	33

PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 11.	EXECUTIVE COMPENSATION
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENTAND RELATED STOCKHOLDER MATTERS
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
ITEM 14.	PRINCIPAL ACCOUNTING FEES & SERVICES

PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	35

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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 volatility in commodity prices for oil and natural gas, including continued declines in prices;

·	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;

·	environmental risks;

·	drilling and operating risks;

·	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;

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

·	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 conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that the current economic recession in the United States will be severe and prolonged, which could adversely affect the demand for oil and natural gas and make it difficult, if not impossible, to access financial markets;

·	other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our business, operations or pricing.

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., a Delaware corporation incorporated in 1982 (hereinafter, “we”, the “Company” or “Isramco”), together with its wholly-owned subsidiaries, Isramco Energy LLC (“Isramco Energy”), Isramco Resources, LLC (“Isramco Resources”), Jay Petroleum, LLC ("Jay Petroleum"), Jay Management Company, LLC ("Jay Management") and Field Trucking and Services, LLC (”FTS”) (collectively “Isramco” or the “Company”), explore for, develop and produce natural gas and crude oil and operate oil and gas properties in the United States. Isramco's principal producing and exploring areas are further described in "Exploration, Development and Production" below.

At December 31, 2010, our estimated total proved oil, natural gas reserves and natural gas liquids, as prepared by our independent reserve engineering firm, Cawley, Gillespie & Associates, Inc., were approximately 9,031 thousand barrels of oil equivalent (“MBOE”), consisting of 3,318 thousand barrels (Bbls) of oil, and 23,701 million cubic feet (Mcf) of natural gas and 1,763 thousand barrels (Bbls) natural gas liquids. Approximately 97% of our proved reserves were classified as proved developed producing (See Note 16 Supplemental Oil and Gas Information to Consolidated Financial Statements to our consolidated financial statements). We maintain operational control of approximately 77% of our proved reserves. Full year 2010 production averaged 2.3 MBOE/d compared to 2.42 MBOE/d in 2009.

Our business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs, acquiring strategic oil and gas properties and improving of existing oil and gas properties. Over the course of 2010, we have expanded our activities in the United States through continued development of existing proved properties. An additional important goal for implementing our business strategy is to maintain the lowest possible operating cost structure, among other things, by serving as operator of a substantial portion of our oil and natural gas properties.

Exploration, Development and Production

United States

We, through our wholly-owned subsidiaries, are involved in oil and gas exploration, developing, 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 589 wells located mainly in Texas and New Mexico. The following is a summary of significant developments during 2010 through the present, including certain 2011 plans.

Acquisitions: On March 27, 2008, we purchased from GFB Acquisition - I, L.P. (“GFB”) and Trans Republic Resources, Ltd. (“Trans Republic,” and, together with GFB, the “Sellers”) interests in certain oil and gas properties located in Texas, New Mexico, Utah, Colorado and Oklahoma for an aggregate purchase price of approximately $102 million. The transaction included mainly operated oil and gas properties in approximately 40 fields (approximately 490 Leases) in East Texas, Texas Gulf Coast, Permian, Anadarko and San Juan Basins. Significant fields are the Alabama Ferry Field in East Texas, the Bagley Field in West Texas and New Mexico, and the Esperson Dome Field on the Texas Gulf Coast.

On March 2, 2007, we purchased certain oil and gas properties located in Texas and New Mexico from Five States Energy Company, LLC (“Five States”) for a purchase price of $92 million.

Divestiture: In December, 2010, we completed the sale of our interests in certain properties located in Wise and Parker Counties, Texas, for approximately $2.2 million in cash. As of December 31, 2009, we had approximately 5 MBOE of proved reserves associated with these properties. Production from these properties as of the sale date was approximately 0.029 MBOE /d.

Israel

In 2007 we closed our branch office in Israel in order to focus on our expanding presence in the United States. However, we retained certain interests in various oil and gas leases, which are discussed below.

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Tamar and Dalit Leases- We own an overriding royalty interest of 1.5375% in the Tamar and Dalit gas Leases, located offshore Israel, which will increase to 2.7375% after payout. In January 2009, Noble Energy Mediterranean Ltd. (“Noble”), the operator of the Leases, completed the Tamar # 1 (“Tamar”) well at a depth of 16,076 feet and in approximately 5,500 feet of water.

Following the Tamar #1 well Noble and its other partners drilled two additional wells. One was an exploration well, the Dalit # 1 well that was spudded on March 6, 2009. The second well was an appraisal well known as the Tamar #2 that was drilled to further define the resources available in the Tamar structure and to obtain information that will be important in the planning of the development for this field. On April 15, 2009, Noble announced flow test results from the Dalit natural gas discovery in the Michal license. The tests, which yielded a flow rate of 33 Mmcf/d of natural gas, were limited by the testing equipment available on the drilling rig.

On July 7, 2009, Noble announced the results from its Tamar #2 appraisal well. This well was, drilled to a total depth of 16,880 feet in 5,530 feet of water and is located approximately 3.5 miles northeast of the original discovery, Tamar #1. It was drilled on the flank of the structure with the intent of confirming reservoir quality and continuity, the appraisal well was also designed to confirm the projected gas/water contact.

According to the public documents filed by Noble, specifically, its Form 10-Q Quarterly Report filed July 30, 2009, the results of these operations were successful.

The government of Israel is currently considering proposals to impose a tax or charge upon oil and gas revenues, including revenues from oil and gas produced from the Tamar well. As currently proposed, such oil and gas revenues would be subject to a sliding scale of taxation, beginning with the imposition of a 20% charge on oil and gas revenues at such time as total revenues received equal 1.5 times the costs expended and increasing in steps to a 50% charge imposed at such time as revenues received equal 1.5 times the costs expended. The current proposal provides some relief for oil and gas revenues received from reservoirs developed before January 2014 by delaying the imposition of the charges; i.e. the 20% charge would become effective at such time as total revenues received equal 2 times the costs expended and the maximum 50% charge would not become effective until revenues received equaled 2.8 times costs expended.

Isramco’s overriding royalty would be subject to the above taxation at such time, and at the same rates, as the revenues attributable to the operating interest. Obviously the imposition of such charges would significantly decrease the amount of any revenues ultimately received as a result of the Corporation’s Israeli oil and gas interests.

The Israeli Petroleum Commissioner granted the partners two leases that are to expire on December 2038, covering Tamar and Dalit gas fields

Med Yavne Lease. Based on the gas finds known as "Or 1", a 30 year lease covering 53 square kilometers (approximately 13,100 acres) offshore Israel, was granted in June 2000 (the "Med Yavne Lease"). The original operator of the Med Yavne Lease was BG International Limited, a member of the British Gas Group ("BG"). BG resigned as the operator of the Lease and relinquished of its working interests in the Med Yavne Lease, and the partners appointed I.O.C - Israel Oil Company Ltd ("IOC") as the successor operator.

The operator performed a 3D seismic survey in the area of the Med Yavne lease. In January 2008 and in January 2009, IOC received an opinion from a consulting firm in the United States that performed a techno-economic examination of the development of the Or 1 reserve. This opinion indicates that, under certain assumptions, development of the Or 1 reserves by connection to a nearby platform (at a distance of seven miles) and from there via an existing transportation pipeline to the coast of Israel may be economically feasible. It is the intention of the partners in Med Yavne Lease to cooperate with independent third parties to jointly develop Or 1 reserves with the third party gas reserves.

Our participation interest of the Med Yavne Lease is 0.7052 %

All oil and gas assets in Israel are subject to a 12.5% Overriding Royalty payable to the Government of Israel under the Israeli Petroleum Law.

The expiration date of any Lease is subject to the fulfillment of applicable provisions of the Israel Petroleum Law and Regulations and the conditions and work obligations of each of the above leases.

Overriding Royalties. We hold Overriding Royalties in certain oil and gas assets. Additionally, we are entitled to receive from certain participants in the Med Yavne Lease overriding royalties equal to 2% of each such participant's rights to any oil/gas produced within those leases. The table below sets forth the Overriding Royalties held by us:

	Before Payout			After Payout
Overriding Interest in the Med Yavne Lease (1)		0.1	%		1.3	%
Overriding Interest in the Michal & Matan Licenses		1.5375	%		2.7375	%

(1) A 30-year lease covering an area of approximately 53 square kilometers (including the area of the gas discovery) was granted in June 2000.

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Derivative Instruments and Hedging Activities

We 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 generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next 48 and 15 months, respectively. 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. Our results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivative contracts.

As of December 31, 2010 we had swap contracts for a volume of 523,209 barrels of crude oil during 48 months, commencing January 2010, and swap contracts for a volume of 939,042 MMBTU of natural gas during 15 months commencing January 2010.

Hereunder are the open swap contracts positions as of December 31, 2010:

	Swap Contracts
	Natural Gas				Crude Oil
	Volume (MMBTU) (*)		Weighted Average Price ($/MMBTU)		Volume (Bbl)		Weighted Average Price ($/Bbl)
2011		764,820		8.22		240,336		86.55
2012		174,222		8.65		127,473		82.37
2013		-		-		89,400		85.15
2014		-		-		66,000		86.95

(*) Mcf = MMBTU

On March 9, 2011, pursuant to an agreement with Wells Fargo, the derivative contracts between Isramco and Wells Fargo were terminated and the Company signed new swap contracts with Macquarie Bank, N.A. for an aggregate volume of 336,780 barrels of crude oil during the 46 month period commencing March 2011.

During the second quarter of 2009, we made the decision to mitigate a portion of our interest rate risk with interest rate swaps. These swap instruments reduce our exposure to market rate fluctuations by converting variable interest rates to fixed interest rates.

Under these swaps, we make payments to, or receive payments from, the counterparties based upon the differential between a specified fixed price and a price related to the three-month LIBOR. These interest rate swaps convert a portion of our variable rate interest on our Scotia debt (as defined in Note 6, “Long-term Debt and Interest Expense”) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. We have elected to designate these positions for hedge accounting and therefore the unrealized gains and losses are recorded in accumulated other comprehensive loss. The Company measures hedge effectiveness by assessing the changes in the fair value or expected future cash flows of the hedged item.

Our open interest rate positions, as described above, are as follows:

Notional amount (in thousands)		Start Date	Maturity Date	Weighted-Average Interest Rate
	2,000	April 2010	February 2011		3.63	%
	6,000	April 2010	February 2011		2.90	%

Competitive Conditions in the Business

The oil and natural gas industry is highly competitive and we compete with a substantial number of 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. 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. 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. 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.

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Markets and Major Customers

Through our wholly-owned subsidiary Jay Management Company, LLC ("Jay Management"), we operate a substantial portion of our 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. Isramco’s 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 oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. The Company has not experienced any significant losses from uncollectible accounts. 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.

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.

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 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 and results of operations. For further discussion on risks, see Item 1A. Risk Factors.

Regulations

We do not have any offshore operations in the US. 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 is to potentially limit the amount of oil and natural gas that we can produce from our wells and to 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.

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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 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.

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.

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 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.

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.

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The Clean Water Act, wastewater and storm water discharges

The oil and gas industry, and our operations, 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 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.

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 not heretofore engaged in extensive hydraulic fracturing or other well stimulation services on the wells for which we are the operator and when we do we engage third parties to conduct these operations on our behalf. On June 9, 2009, legislation entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act of 2010 was introduced in the United States Senate (Senate Bill number 1215) and House of Representatives (House Bill number 2766). Sponsors of this legislation assert that chemicals used in the fracturing process may adversely affect drinking water supplies. This legislation would repeal the existing exemption for hydraulic fracturing in the SDWA and could require the EPA to promulgate regulations to establish a permit procedure and to implement potential new restrictions applicable to hydraulic fracturing. This could, in turn, require state regulatory agencies in states with programs delegated under the SDWA to impose additional requirements on hydraulic fracturing operations. The current proposal would require persons using hydraulic fracturing to disclose the chemical constituents of their fracturing fluids to a regulatory agency, which would then make the information public via the internet. This could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process are impairing or could impair groundwater or cause other damage. This legislation, if adopted, would establish an additional level of regulation at the federal or state level and could lead to operational delays and/or increased operating costs, all of which would increase our regulatory burdens, make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business Certain states have adopted and are considering laws that require the disclosure of the chemical constituents in hydraulic fracturing fluids. In addition, in 2010, the EPA announced that it would be conducting a study on the environmental effects of hydraulic fracturing. The study is expected to be completed in 2012. Additional disclosure requirements could result in increased regulation, operational delays, and increased operating costs that could make it more difficult to perform hydraulic fracturing.

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 are 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.

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Certain of our operations, or the operations of service companies engaged by us, may be subject to permits and restrictions under these statutes for emissions of air pollutants. In this regard, the EPA proposed in a consent decree, which has not been approved by a federal court, that by January 31, 2011 it will issue a proposal to revise its national emissions standards for hazardous air pollution for crude oil and natural gas production, as well as gas transmission and storage as well as new source performance standards for oil and gas production.

Climate change legislation and greenhouse gas regulation

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. Additionally, the United States Supreme Court has ruled, in Massachusetts, et al. v. EPA, that the EPA abused its discretion under the Clean Air Act by refusing to regulate carbon dioxide emissions from mobile sources. As a result of the Supreme Court decision and the change in presidential administrations, on December 7, 2009, the EPA issued a finding that many believe serves as the foundation under the Clean Air Act to issue other rules that could result in the promulgation of federal greenhouse gas regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, on September 22, 2009, the EPA also issued a greenhouse gas monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their greenhouse gas emissions, including methane and carbon dioxide, to the EPA. These emissions will be published on a register to be made available on the Internet. These regulations could apply to our operations. The EPA has proposed two other rules that would regulate greenhouse gas emissions, one of which would regulate greenhouse gases from stationary sources, and might affect sources in the oil and natural gas exploration and production industry and the pipeline industry. The EPA has issued two other rules that would regulate GHGs, one of which regulates GHGs from stationary sources, and one which requires sources in the oil and natural gas exploration and production industry and the pipeline industry to report GHG emissions. The EPA’s findings, the greenhouse gas reporting rule, and the proposed rules to regulate the emissions of greenhouse gases would result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry.

On June 26, 2009, the United States House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey Cap-and-Trade Legislation” or “ACESA.” On November 5, 2009 the Senate Committee on Environment and Public Works approved the “Clean Energy Jobs and American Power Act of 2009,” authored by John Kerry and Barbara Boxer, that is similar in many ways to ACESA. One of the purposes of these bills is to control and reduce emissions of greenhouse gases in the United States. These bills would establish an economy-wide cap on emissions of greenhouse gases in the United States and would require an overall reduction in greenhouse gas emissions of 17% to 20% (from 2005 levels) by 2020, and by over 80% by 2050. Under these bills, most sources of greenhouse gas emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet the overall emission reduction goals of the bills. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of these bills would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. President Obama has indicated that he is in support of the adoption of legislation such as the two bills discussed above, and the White House is expending significant efforts to push for the legislation.

In two recent court decisions, one before the United States Second Circuit Court of Appeals and one before the United States Fifth Circuit Court of Appeals (The Fifth Circuit), the Court has allowed cases filed to require the imposition of greenhouse gas regulations to proceed. In the first case, Connecticut v. American Electric Power, the Second Circuit ruled that several states and other plaintiffs could continue their suit to impose greenhouse gas reductions on several utility defendants, concluding that a political question and standing objections of the defendants did not prohibit the suit from going forward. The Fifth Circuit, in Comer v. Murphy Oil, ruled that plaintiffs could similarly pursue a damage suit and the political question did not prohibit the suit. The Comer v. Murphy Oil case involves claims by plaintiffs who suffered damages from Hurricane Katrina and are seeking to recover damages from certain greenhouse gas emitters, asserting their emissions contributed to their increased damages. In another case filed in the Texas District Court in Austin on October 6, 2009, a citizens group sued the Texas Commission on Environmental Quality (“TCEQ”) asserting that the agency was required to regulate carbon dioxide emissions from parties applying for permits under the Texas Clean Air Act. This lawsuit could result in additional regulation of our operations, if the Texas courts require the TCEQ to regulate carbon dioxide and perhaps other greenhouse gases, such as methane.

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.

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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.

Employees

As of December 31, 2010, we had 29 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

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. The public can obtain any document we file with the SEC at www.sec.gov.

ITEM 1A. RISK FACTORS

In 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.

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

Prices for 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. For example, in recent years market prices for natural gas in the United States have declined substantially from the highs achieved in 2008 and the rapid development of shale plays throughout North America has contributed significantly to this trend. Factors influencing the prices of oil, natural gas and NGLs are beyond our control. These factors include, among others:

·	the worldwide military and political environment, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities or further acts of terrorism in the United States, or elsewhere;
·	worldwide and domestic supplies of crude oil and natural gas;
·	actions taken by foreign oil and gas producing nations;
·	the level of global crude oil and natural gas inventories;
·	the price and level of foreign imports of oil, natural gas and NGLs;

·	the effect of worldwide energy conservation efforts;
·	the price and availability of alternative and competing fuels;
·	the availability of pipeline capacity and infrastructure;
·	the availability of crude oil transportation and refining capacity;
·	weather conditions;
·	electricity dispatch;
·	domestic and foreign governmental regulations and taxes; and
·	the overall economic environment.

The 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:

·	limiting our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;
·	reducing the amount of oil, natural gas and NGLs that we can produce economically;
·	causing us to delay or postpone some of our capital projects;
·	reducing our revenues, operating income and cash flows;

·	reducing the carrying value of our crude oil and natural gas properties;
·	reducing the amounts of our estimated proved oil and natural-gas reserves;
·	reducing the standardized measure of discounted future net cash flows relating to oil and natural-gas reserves; and
·	limiting our access to sources of capital, such as equity and long-term debt.

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Our domestic operations are subject to governmental risks that 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 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. In the recently concluded session of Congress, climate-change legislation establishing a “cap-and-trade” plan for green-house gases (GHGs) was approved by the U.S. House of Representatives.. The U.S. Environmental Protection Agency (EPA) has also taken recent action related to GHGs. EPA has made findings and issued regulations that require the establishment and reporting of an inventory of greenhouse gas emissions and that could lead to the imposition of restrictions on greenhouse gas emissions from stationary sources such as ours. While it is not possible at this time to predict whether or when the Congress may act on climate-change legislation, legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the natural gas and oil that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas and oil.

Taxes. The U.S. President’s Fiscal Year 2012 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural-gas exploration and development, and (iii) implementing certain international tax reforms.

Hydraulic Fracturing. In the recently concluded session of Congress, legislation amending the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural-gas industry in the hydraulic-fracturing process was considered. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. It is not possible at this time to predict whether or when the current session of Congress may act on hydraulic-fracturing legislation. Such legislation, if adopted, could establish an additional level of regulation and permitting at the federal level.

The recent adoption of derivatives legislation by the U.S. Congress 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.

The U.S. Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission (the CFTC) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the new legislation, the CFTC has proposed regulations to set 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 would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation 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 be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through 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. If the Company reduces its use of derivatives as a result of the legislation and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the legislation 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.

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Oil and gas drilling is a speculative activity and risky.

We are engaged in the business of oil and natural gas exploration, production and operations and the development of productive oil and gas wells. Our growth will be materially dependent upon the success of our future drilling program. Drilling for oil and gas involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs or crews and the delivery of equipment. Although we believe that the use of 3-D seismic data and other advanced technology should increase the probability of success of our wells and should reduce average finding costs through elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic data and other traditional methods, drilling remains an inexact and speculative activity. In addition, the use of 3-D seismic data and such technologies requires greater pre-drilling expenditures than traditional drilling strategies and we could incur losses because of such expenditures. Our future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse effect on our future results of operations and financial condition. Although we may discuss drilling prospects that have been identified or budgeted for, we may ultimately not lease or drill these prospects within the expected time frame, or at all. We may identify prospects through a number of methods, some of which do not include interpretation of 3-D or other seismic data. The drilling and results for these prospects may be particularly uncertain. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including (i) the results of exploration efforts and the acquisition, review and analysis of the seismic data, (ii) the availability of sufficient capital resources and the other participants for the drilling of the prospects, (iii) the approval of the prospects by other participants after additional data has been compiled, (iv) economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews, (v) our financial resources and results (vi) the availability of leases and permits on reasonable terms for the prospects and (vii) the payment of royalties to lessors. There can be no assurance that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas. There are numerous uncertainties in estimating quantities of proved reserves, including many factors beyond our control.

Failure to fund continued capital expenditures could adversely affect our properties.

Our acquisition, exploration, and development activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations and loans from commercial banks and related parties. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of crude oil and natural gas, and our success in finding, developing and producing new reserves. If revenues were to decrease as a result of lower crude oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves, resulting in a decrease in production over time. If our cash flows from operations are not sufficient to meet our obligations and fund our capital budget, we may not be able to access debt, 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 expenditures, interests in some properties might be reduced or forfeited as a result.

Poor general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy.

These factors, combined with volatile oil, natural-gas and NGLs prices, declining business and consumer confidence, and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, or if an economic recovery is slow or prolonged, demand for petroleum products could continue to 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.

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Estimates of proved oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.

This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

At December 31, 2010, 100% of our estimated reserves were classified as proved developed.

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our financial condition, results of operations and cash flows.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration activities. Thus, our future oil and natural gas production and, therefore, our cash flow and income are highly dependent upon our level of success in finding or acquiring additional reserves. However, we cannot assure you that our future acquisition, development and exploration activities will result in any specific amount of additional proved reserves or that we will be able to drill productive wells at acceptable costs.

The successful acquisition of producing properties requires an assessment of a number of factors. These factors include recoverable reserves, future oil and natural gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. Such assessments are inexact and their accuracy is inherently uncertain. In connection with such assessments, we perform a review of the subject properties that we believe is thorough. However, there is no assurance that such a review will reveal all existing or potential problems or allow us to fully assess the deficiencies and capabilities of such properties. We cannot assure you that we will be able to acquire properties at acceptable prices because the competition for producing oil and natural gas properties is intense and many of our competitors have financial and other resources that are substantially greater than those available to us.

There is a possibility that we will lose the leases to our oil and gas properties.

Our oil and gas revenues are generated through oil and gas leases. These leases are conditioned on the performance of certain obligations, primarily the obligation to produce oil and/or gas or engage in operations designed to result in the production of oil and gas. If production ceases and operations are not commenced within a specified time, the lease may be lost. The loss of our leases may have a material impact on our revenues.

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In the 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 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 could eliminate our interests and may have a material impact on our revenues.

Our business is highly competitive.

The oil and natural gas industry is highly competitive in many respects, including identification of attractive oil and natural gas properties for acquisition, drilling and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities. In seeking suitable opportunities, we compete with a number of other companies, including large oil and natural gas companies and other independent operators with greater financial resources, larger numbers of personnel and facilities, and with more expertise. There can be no assurance that we will be able to compete effectively with these entities.

Our business may be affected by oil and gas price volatility.

Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing oil and natural gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we will be able to borrow under our Senior Credit Agreements will be subject to periodic redetermination based in part on current oil and natural gas prices and on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our properties.

Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility are:

·	the domestic and foreign supply of, and demand for oil and natural gas;

·	the ability of members of the Organization of Petroleum Exporting Countries (OPEC) and other producing countries to agree upon and maintain oil prices and production levels;

·	political instability, armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;

·	the growth of consumer product demand in emerging markets, such as India and China;

·	labor unrest in oil and natural gas producing regions;

·	weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;

·	the price and availability of alternative and competing fuels;

·	the price and level of foreign imports of oil, natural gas and NGLs; and

·	worldwide economic conditions.

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Our commercial lenders have liens on substantially all of our oil and gas assets in the United States and could foreclose in the event that we default under our credit facilities.

Under the terms of our credit facilities with our commercial lenders, our lenders have a first priority lien on substantially all of our oil and gas assets in the United States. If we default under the credit facility, our lender would be entitled to, among other things, foreclose on our assets in order to satisfy our obligations under a credit facility.

Our hedging activities may prevent us from benefiting fully from price increases and may expose us to other risks.

In order to manage our exposure to price risks in the marketing of our oil and natural gas production, we have entered 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:

·	our actual production is less than hedged volumes;

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

·	the counterparties to our hedging agreements fail to perform under the contracts.

·	a sudden unexpected event materially impacts oil and natural-gas prices.

The credit risk of financial institutions could adversely affect us.

We 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.

We have no means to market our oil and gas production without the assistance of third parties.

The marketability of our production depends 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 of new wells or the delay or discontinuance of development plans for properties. 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.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies and/or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production in response to strong prices of oil and natural gas may increase the demand for oilfield services, and the costs of these services may increase, while the quality of these services may suffer.

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Our oil and natural gas activities are subject to various risks that are beyond our control.

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and natural gas. Although we may take precautionary measures, many of 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, the ability of certain of our wells to produce oil and natural gas in commercial quantities, the rate of production and the economics of the development of, and our investment in the prospects in which we have or will acquire an interest. Any of these risks and hazards could materially and adversely affect our financial condition, results of operations and cash flows. Such risks and hazards include:

·	human error, 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;

·	blowouts, fires, hurricanes, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;

·	unavailability of materials and equipment;

·	engineering and construction delays;

·	unanticipated transportation costs and delays;

·	unfavorable weather conditions;

·	hazards resulting from unusual or unexpected geological or environmental conditions;

·	environmental regulations and requirements;

·	accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids, into the environment;

·	changes in laws and regulations, including laws and regulations applicable to oil and natural gas activities or markets for the oil and natural gas produced;

·	fluctuations in supply and demand for oil and natural gas causing variations of the prices we receive for our oil and natural gas production; and

·	the availability of alternative fuels and the price at which they become available.

We do not insure against all potential losses and could be materially and adversely affected by unexpected liabilities.

The exploration for, and production of, natural gas and crude oil can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, fires and loss of well control, which can damage or destroy wells or production facilities, injure or kill people, and damage property and the environment. Moreover, our onshore operations are subject to customary perils, including hurricanes and other adverse weather conditions. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. The occurrence of any of these events and any costs or liabilities incurred as a result of such events would reduce the funds available to us for our exploration, development and production activities and could, in turn, have a material adverse effect on our business, financial condition and results of operations.

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Governmental and environmental regulations could adversely affect our business.

Our business is subject to federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing of oil and natural gas and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste, unitization and pooling of properties and other matters. These laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and natural gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our revenues.

Our operations are also subject to complex environmental laws and regulations adopted by the various jurisdictions in which we have or expect to have oil and natural gas operations. We could incur liability to governments or third parties for any unlawful discharge of oil, natural gas or other pollutants into the air, soil or water, including responsibility for remedial costs. We could potentially discharge these materials into the environment in any of the following ways:

·	from a well or drilling equipment at a drill site;

·	from gathering systems, pipelines, transportation facilities and storage tanks;

·	damage to oil and natural gas wells resulting from accidents during normal operations; and

·	blowouts, hurricanes and explosions.

Assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our growth is primarily due to acquisitions of producing properties and underdeveloped leaseholds. We expect acquisitions may also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise in the future. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. Because of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

Our ability to sell our natural-gas and crude-oil production could be materially harmed if we fail to obtain adequate services such as transportation.

The marketability of our production depends in part upon the availability, proximity and capacity of pipeline facilities and tanker transportation. If any of the pipelines or tankers become unavailable, we would be required to find a suitable alternative to transport the gas and oil, which could increase our costs and/or reduce the revenues we might obtain from the sale of the gas and oil.

Title to the properties in which we have an interest may be impaired by title defects.

We generally conduct due diligence to review title on significant properties that we drill or acquire. However, there is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is due to title defects is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

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

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.

We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.

Our 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 the 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 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 in Israel may be adversely affected by economic and political developments.

We have interests in oil and gas leases and in oil and gas licenses in the waters off Israel. These interests may be adversely affected by political and economic developments, including the following:

·	war, terrorist acts and civil disturbances,

·	changes in taxation policies,

·	laws and policies of the US and Israel affecting foreign investment, taxation, trade and business conduct,

·	foreign exchange restrictions,

·	international monetary fluctuations and changes in the value of the US dollar, such as the decline of the US dollar and

·	other hazards arising out of Israeli governmental sovereignty over areas in which we own oil and gas interests.

Members of Isramco’s management team own a significant amount of common stock, giving them influence or control in corporate transactions and other matters, and the interests of these individuals could differ from those other shareholders.

Members of our management team beneficially own approximately 60.6% of our outstanding shares of common stock as of March 11, 2011. As a result, these shareholders are 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 other significant corporate transactions.

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

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Oil and Gas Exploration and Production - Properties and Reserves

Reserve Information. For estimates of Isramco's net proved reserves of natural gas, crude oil and natural gas liquids, see Note 16 to Consolidated Financial Statements, Supplemental Oil and Gas Information,.

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 16 to Consolidated Financial Statements, Supplemental Oil and Gas Information, represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas, crude oil and condensate and natural 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.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for us to conduct business in the future.

ITEM 3. LEGAL PROCEEDINGS

We disclosed information in our quarterly report for the three months ended September 30, 2010 relating to two putative shareholder derivative petitions that were filed by individual shareholders of the Company in the District Court of Harris County, Texas. These petitions each named certain of our officers and directors as defendants. Each of these suits claims that the shareholders were damaged as a result of various breaches of fiduciary duty, self dealing and other wrongdoing in connection with the Restated Agreement between the Company and Goodrich, primarily on the part of the Company’s Chairman and Chief Executive Officer, Haim Tsuff, and Jackob Maimon. On or about April 6, 2010, a third complaint was filed in the 295th District Court of Harris County, Texas by Yuval Ran, who claimed to be a shareholder, against certain of our officers and directors and several corporate parties controlled by Haim Tsuff. As with the prior suits, this complaint alleged various breaches of duty, self dealing and other wrongdoing in connection with the Restated Agreement between the Company and Goodrich, primarily on the part of the Company’s Chairman and Chief Executive Officer, Haim Tsuff, and Jackob Maimon (Jackob Maimon is a former President and a director who resigned from all positions held with us on June 29, 2010). In addition, this suit alleged claims relating to other transactions between the Company and entities controlled by Haim Tsuff, including but not limited to the loan transactions between the Company and related parties, the lease and sale of a cruise ship, and the closure of the Company’s Israel branch office. The third complaint was transferred to the 55th Judicial District Court of Harris County, Texas, by order signed April 20, 2010, and consolidated with the above-referenced first and second complaints by order signed May 21, 2010, into a single case, called “Lead Cause No. 2009-34535; In Re Isramco, Inc. Shareholder Derivative Litigation; In the 55th Judicial District Court of Harris County, Texas (the “Derivative Litigation”).

Subsequently, on or about September 7, 2010, the plaintiffs in the first two actions jointly filed an amended petition, which included some, but not all, of the claims alleged in the third complaint; and on or about October 4, 2010, the Court granted the motion to withdraw as plaintiff filed by the plaintiff in the third complaint On October 6, 2010, the parties attempted to mediate the case but no settlement was immediately forthcoming. Although the Company disputes the allegations of the plaintiffs and believes them to be without merit, subsequently, the derivative plaintiffs, the Company and the other defendants reached a tentative settlement of this litigation. This settlement, which requires court approval, is pending.

We also disclosed information in our quarterly report for the three months ended September 30, 2010 relating to an additional putative shareholder derivative complaint that was filed by an individual shareholder, Yuval Lapiner, on July 7, 2010 in the Delaware Chancery Court in Wilmington, Delaware, naming certain of our officers and directors as defendants. The claims asserted in this case are essentially the same damage claims as asserted in the lawsuit filed in April 2010 and described above. The Company filed motions in the Chancery Court to Dismiss or Stay the lawsuit and, by order dated October 20, 2010, the case was dismissed. The plaintiff did not appeal.

From time to time, we are involved in disputes and other legal actions arising in the ordinary course of business. In management's opinion, none of these other disputes and legal actions is expected to have a material impact on our consolidated financial position or results of operations.

ITEM 4. (Removed and Reserved)

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

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 8, 2011, there were approximately 277 holders of record of our common stock.

	High			Low
2010
First Quarter		$	80.10		$	49.00
Second Quarter			70.50			45.05
Third Quarter			61.12			45.56
Fourth Quarter			90.36			55.96

2009
First Quarter		$	66.10		$	28.00
Second Quarter			124.86			32.00
Third Quarter			171.18			114.22
Fourth Quarter			132.42			67.05

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.

ITEM 6. SELECTED FINANCIAL DATA

Not applicable

ITEM 7. MANAGEMENT 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 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.

Overview

We are 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. Our properties are primarily located in Texas, New Mexico and Oklahoma. We act as the operator of certain 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.

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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 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.

At December 31, 2010, our estimated total proved oil, natural gas reserves and natural gas liquids, as prepared by our independent reserve engineering firm, Cawley, Gillespie & Associates, Inc., were approximately 9,031 thousand barrels of oil equivalent (“MBOE”), consisting of 3,318 thousand barrels (Bbls) of oil, and 23,701 million cubic feet (Mcf) of natural gas and 1,763 thousand barrels (Bbls) natural gas liquids. Approximately 97% of our proved reserves were classified as proved developed producing (See Note 16 to Consolidated Financial Statements, Supplemental Oil and Gas Information). We maintain operational control of approximately 77% of our proved reserves. Full year 2010 production averaged 2.3 MBOE/d compared to 2.42 MBOE/d in 2009.

Critical accounting policies

The discussion and analysis of 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.

Oil and Natural Gas Activities

Accounting for oil and natural gas activities is subject to unique rules. Two generally accepted methods of accounting for oil and natural gas activities are available - successful efforts and full cost. The most significant differences between these two methods are the treatment of unsuccessful exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed as they are incurred upon a determination that the well is uneconomical, while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and natural gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using period-end prices and costs and a 10% discount rate. We account for our natural gas and crude oil exploration and production activities under the successful efforts method of accounting.

Proved Oil and Natural Gas Reserves

Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization and impairment expense. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir will also result in revisions to the amount of our estimated proved reserves.

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Our policies and procedures regarding internal controls over the recording of our oil and natural gas reserves are structured to objectively and accurately estimate our oil and natural gas reserve quantities and present values in compliance with both accounting principles generally accepted in the United States and the SEC’s regulations. Compliance with these rules and regulations is the responsibility of our senior engineer, who is also our principal engineer.

Our controls over reserve estimates include retention of Cawley, Gillespie & Associates, Inc as our independent petroleum engineers. We provide Cawley, Gillespie & Associates, Inc. information concerning our oil and natural gas properties, including production profiles, prices and costs, and they prepare their independent estimates of the oil and natural gas reserves attributable to our properties. All of the information regarding reserves in this annual report on Form 10–K is derived from the report of Cawley, Gillespie & Associates, Inc, which is included as an exhibit to this annual report.

We maintain an internal staff of petroleum engineers and an attorney experienced in petroleum land titles who work closely with Cawley Gillespie to ensure the integrity, accuracy and timeliness of the data furnished to Cawley, Gillespie & Associates, Inc for their reserves estimation process. Our senior engineer reviews and approves the reserve information compiled by our internal staff. Our technical teams and representatives of Cawley, Gillespie & Associates, Inc also jointly review our properties and discuss the methods and assumptions used by Cawley, Gillespie & Associates, Inc in the preparation of their year end reserve estimates.

Depreciation, Depletion and Amortization

Our rate of recording depreciation, depletion and amortization expense (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.

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 Obligations

We have significant obligations to remove tangible equipment and facilities associated with our oil and gas wells and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are most often associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations we have will be take effect in the future. Additionally, these operations are subject to private contracts and government regulations that often have vague descriptions of what is required. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate removal cost amounts, inflation factors, credit adjusted discount rates, timing of obligations and changes in the legal, regulatory, environmental and political environments.

Accounting for Derivative Instruments and Hedging Activities

Income Taxes

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.

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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.

Liquidity and Capital Resources

Our primary historical sources of capital and liquidity are internally generated cash flows from operations, availability under our senior credit agreements with our unrelated bank lenders with Bank of Nova Scotia and Wells Fargo (“Senior Credit Agreements”) and loans from various related party lenders (“Related Party Loans”) and asset dispositions. 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.

Note 6 to our Consolidated Financial Statements, Long-Term Debt and Interest Expense, describes the Senior Credit Agreements and Related Party Loans. Our Senior Credit Agreements originally provided a total $300 million in credit facilities. As of December 31, 2010, the combined total credit available borrowing base available for was approximately $45 million. On March 3, the Company terminated its relationship with Wells Fargo and paid its debt to Wells Fargo, further reducing the total credit available to approximately $4.5 million at that date. The borrowing base which relates to our oil and natural gas properties is redetermined on a semi-annual basis (with the Company and the lenders each having the right to one unscheduled redetermination per year) and adjusted based on our oil and natural gas properties, reserves, other indebtedness and other relevant factors. See Note 6 to Consolidated Financial Statements, Long-Term Debt and Interest Expense.

Our ability to utilize the full amount of our borrowing capacity is influenced by a variety of factors, including redeterminations of our borrowing base and covenants under our Senior Credit Agreements. Our Senior Credit Agreements contain customary financial and other covenants, including minimum working capital levels of not less than 1.0 to 1.0, leverage ratio of not greater than 3.5 to 1.0 and minimum coverage of interest of not less than 2.5 to 1.0. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, changes of control, asset sales, and liens on properties. At December 31, 2010, the Company was in compliance with all of its debt covenants under the Senior Credit Agreements.

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 capital resources available and the success in finding and acquiring additional reserves. We expect to fund our future capital requirements through internally generated cash flows and borrowings under our Senior Credit Agreements. Long-term cash flows are subject to a number of variables, including the level of production and prices and our commodity price hedging activities as well as various economic conditions that have historically affected the oil and natural gas industry.

Debt

	As of December 31,
	2010			2009			2008
	(In thousands except percentage)
Senior Credit Facilities	$	22,725		$	32,950		$	43,200
Long – term debt – related party		76,354			79,354			80,354
Short – term debt – related party		-			-			-
Current maturities of long-term debt, short-term debt and bank overdraft		17,350			12,366			22,544
Total debt		116,429			124,670			146,098

Stockholders’ equity		18,537			13,733			25,034

Debt to capital ratio		86	%		90	%		85	%

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At year-end 2010, our total debt was $116,429,000, compared to total debt of $124,670,000 at year-end 2009 and $146,098,000 at year-end 2008. As of December 31, 2010, current debt included $14,350,000 as current maturities of the Senior Credit Facilities. However, the Company is not obligated to repay the facilities prior to the due date, except for such payments as may be required under the Senior Credit Agreements in the event of a redetermination and reduction of the borrowing base. As of December 31, 2010, the $4,900,000 included as current maturities was due to the decision by management to continue reducing our debt below the borrowing base. As of December 31, 2009, current debt included $12,000,000 as current maturities, which again was due to management’s decision to continue payments to reduce debt below the borrowing base.

On March 3, 2011, the Company entered into a Loan Agreement with IOC pursuant to which it borrowed the sum of $11 million. The loan bears interest at a rate of 10% per annum and is payable in quarterly payments of interest only until March 3, 2012, when all accrued interest and principal is due and payable. The loan may be prepaid at any time without penalty. The loan is unsecured. The purpose of the loan was to provide funds to Isramco for the payment of amounts due under the Wells Fargo Senior Credit Facility at maturity. On March 3, 2011 Isramco paid the outstanding principal balance due under the Wells Fargo Senior Credit Agreement. Subsequently, on March 9, 2011, pursuant to an agreement with Wells Fargo, the derivative contracts between Isramco and Wells Fargo were terminated at a cost to the Company of approximately $7,000,000. Concurrently, the Company entered into new derivative contracts for 336,780 barrels of crude oil during the 46 month period commencing March 2011 with Macquarie Bank, N.A.

Off-Balance Sheet Arrangements

At December 31, 2010, we did not have any off-balance sheet arrangements.

Cash Flow

Our primary source of cash in 2010 and 2009 was from operating activities. Our primary sources of cash in 2008 were from operating and financing activities. In 2010 and 2009, cash received from operations was offset by repayments of borrowings under our Senior Credit Agreements and cash used in payments on addition to oil and gas properties, net of any divestiture activities. In 2008, Proceeds from loans obtained from related parties, proceeds from the Senior Credit Agreements and cash received from operations were offset by repayments of our Senior Credit Agreements, repayments of loans from related parties and cash used in investing activities to fund continued enhancement of operations acquisition activities.

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.

	Years Ended December 31,
	2010				2009				2008
	(In thousands)
Cash flows provided by operating activities		$	12,063			$	21,519			$	18,886
Cash flows used in investing activities			(1,437	)			(332	)			(97,753	)
Cash flows provided by (used in) financing activities			(7,876	)			(21,421	)			80,796
Net increase (decrease) in cash		$	2,750			$	(234	)		$	1,929

Operating Activities, Net cash flows provided by operating activities were $12,063,000, $21,519,000 and $18,886,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Key drivers of net operating cash flows are commodity prices, production volumes, hedging activities and operating cost.

Net cash provided by operating activities decreased in 2010 compared to 2009 primarily due to a reduction in working capital of $4,549,000, higher lease operating expenses and expenses related to our well plugging and abandonment obligations. The reduction in net cash proceeds from our commodity price hedging activities of $8,308,000 was offset by increased oil and natural gas revenues of $8,561,000. The increase in revenues was primarily attributable to higher average oil and gas prices for the year ended December 31, 2010 of $77.26/bbl and $4.71/mcf, compared to $58.52/bbl and $3.48/mcf for the year ended December 31, 2009. However, we are unable to predict future production levels or future commodity prices, and, therefore, we cannot predict future levels of net cash provided by operating activities.

Net cash provided by operating activities increased in 2009 compared to 2008 primarily due to an 8% increase in our average daily production volumes and gain from net cash received on settled derivative contracts which was partially offset by the 58%, 40% and 31% decrease in natural gas, oil and natural gas liquids prices, respectively.

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Investing Activities, The primary driver of cash used in investing activities in 2010 and 2009 is capital spending. The primary component of cash used in investing activities in 2008 was capital spending for acquisitions and development. Cash used in investing activities was $1,437,000, $332,000 and $97,753,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

In 2010, we spent an additional $3,454,000 on capital expenditures. We spent an additional $157,000 on other property and equipment during 2010. We participated in the drilling of 3 gross wells in 2010. In December, 2010, we completed the sale of our interests in certain properties in Wise and Parker Counties, Texas, for approximately $2.2 million.

In 2009, we spent an additional $645,000 on capital expenditures and other property and equipment.

In 2008, we spent $98,673,000 on acquisition of oil and gas properties and capital expenditures. We participated in the drilling of 3 gross wells in 2008. We spent an additional $369,000 on other property and equipment during 2008.

Financing Activities, The primary component of cash used in financing activities in 2010 and 2009 was payment on long-term debt ($7,875,000) and ($21,250,000). In 2008, the primary component of cash provided by financing activities was proceeds from long-term loans obtained from related parties ($43,773,000) and Senior Credit Agreements ($54,000,000), offset by repayments of long-term loans and repayments of Senior Credit Agreements ($16,800,000). Net cash flows provided by financing activities were ($7,876,000), ($21,421,000) and $80,796,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

Results of Continuing Operations

Selected Data

	Years Ended December 31,
	2010			2009			2008
	(In thousands except per share and MBOE amounts)
Financial Results
Oil and Gas sales	$	39,329		$	30,768			$	51,832
Other		2,871			956				365
Total revenues and other		42,200			31,724				52,197

Cost and expenses		41,059			42,024				63,619
Other expense (income)		5,784			13,369				(15,028	)
Income tax expense (benefit)		(1,856	)		(10,090	)			377
Net Income (loss)		(2,787	)		(13,579	)			3,229
Earnings per common share – basic and diluted	$	(1.03	)	$	(5.00	)		$	1.19
Weighted average number of shares outstanding-basic and diluted		2,717,691			2,717,691				2,717,691
Operating Results
Adjusted EBITDAX (1)	$	22,472		$	26,796			$	22,548
Total proved reserves (MBOE)		9,031			8,565				8,213
Annual sales volumes (MBOE)		841			886				821

Average cost per MBOE:
Production (excluding transportation and taxes)	$	18.32		$	12.99			$	17.59
General and administrative	$	6.09		$	4.64			$	3.31
Depletion	$	14.44		$	17.34			$	21.59

(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.

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Financial Results

Net Income (loss) Our net loss for 2010 totaled ($2,787,000) a, or ($1.03) per share, compared to a net loss for 2009 of ($13,579,000), or ($5.00) per share. The decrease in net loss was primarily due to higher natural gas, oil and NGLs sales revenues due to higher prices, the impact of derivatives, lower depreciation, depletion and amortization expenses and lower interest expense. This was partially offset by a decrease in sales volumes of natural gas, oil and natural gas liquids (“NGLs”) caused by adverse weather conditions in Texas that restricted our ability to access, repair and maintain our wells in the first quarter of 2010, along with the natural decline in production, and higher lease operating expenses. Our net loss for 2009 totaled ($13,579,000), or ($5.00) per share, compared to net income for 2008 of $3,229,000, or $1.19 per share. This decrease was primarily due to sustained lower natural gas, oil and NGLs sales revenues due to lower prices and impact of derivatives, which were partially offset by increases in sales volumes of natural gas, oil and natural gas liquids (“NGL”), lower lease operating expenses, lower depreciation, depletion, amortization and impairment expenses and tax benefit.

Revenues, Volumes and Average Prices

Sales Revenues

	Years Ended December 31,
In thousands except percentages	2010			2009			D vs. 2010			2008			D vs. 2009
Gas sales		$	11,157		$	9,124		22	%		$	20,747		(56)	%
Oil sales			22,405			17,147		31				25,049		(32)
Natural gas liquid sales			5,767			4,497		28				6,036		(25)
Total		$	39,329		$	30,768		28	%		$	51,832		(41)	%

Our sales revenues for the year ended December 31, 2010 increased by 28% when compared to same period of 2009, mainly due to higher natural gas, oil and condensate and NGLs commodity prices. Our sales revenues for the year ended December 31, 2009 decreased by 41% when compared to same period of 2008, mainly due to lower natural gas, oil and condensate and NGLs commodity prices.

Volumes and Average Prices

	Years Ended December 31,
	2010		2009		D vs. 2010			2008		D vs. 2009
Natural Gas
Sales volumes Mmcf		2,368		2,623		(10)	%		2,507		5	%
Price per Mcf	$	4.71	$	3.48		35		$	8.28		(58)
Total gas sales revenues (thousands)	$	11,157	$	9,124		22	%	$	20,747		(56)	%

Crude Oil
Sales volumes MBbl		290		293		(1)	%		258		14	%
Price per Bbl	$	77.26	$	58.52		32		$	97.1		(40)
Total oil sales revenues (thousands)	$	22,405	$	17,147		31	%	$	25,049		(32)	%

Natural gas liquids
Sales volumes MBbl		156		156		0	%		145		8	%
Price per Bbl	$	36.97	$	28.83		28		$	41.6		(31)
Total natural gas liquids sales revenues (thousands)	$	5,767	$	4,497		28	%	$	6,036		(25)	%

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The Company’s natural gas sale volumes decreased by 10%, crude oil sale volumes by 1% and natural gas liquid sale volumes by 0% in 2010 compared to 2009. This decrease was primarily caused by adverse weather conditions in Texas that restricted our ability to access, repair and maintain our wells in the first quarter of 2010, along with the natural decline in production. The Company’s natural gas sales volumes increased by 5%, crude oil sales volumes by 14% and natural gas liquids sales volumes by 8% in 2009 compared to 2008, primarily due to fact that in 2008 we recorded 9 months of production associated with the properties acquired in the GFB acquisition, which in turn was partially offset by the natural decline in our production.

Our average natural gas price for 2010 increased by 35% or $1.23 per Mcf, when compared to 2009 and decreased by 58%, or $4.80, when 2009 is compared to 2008. Our average crude oil price for 2010 increased by 32% or $18.74 per Bbl, when compared to 2009 and decreased by 40%, or $38.58, when 2009 is compared to 2008. Our average natural gas liquids price for 2010 increased by 28%, or $8.14 per Bbl, when compared to 2009 and decreased by 31%, or $12.77 per Bbl, when 2009 is compared to 2008.

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 sales revenues for the year ended December 31, 2010 compared to 2009 and 2008.

In thousands	Natural Gas			Oil			Natural gas liquids
2008 sales revenues	$	20,747		$	25,049		$	6,036
Changes associated with sales volumes		960			3,398			458
Changes in prices		(12,583	)		(11,300	)		(1,997	)
2009 sales revenues		9,124			17,147			4,497
Changes associated with sales volumes		(887	)		(176	)		-
Changes in prices		2,920			5,434			1,270
2010 sales revenues	$	11,157		$	22,405		$	5,767

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. 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.

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.

	Years Ended December 31,
In thousands except percentages	2010			2009			2008
Income from operations before income taxes	$	(4,643	)	$	(23,669	)	$	3,606
Depreciation, depletion, amortization and impairment expense		13,893			21,119			39,816
Interest expense		7,646			9,219			9,855
Unrealized gain on derivative contract		4,727			19,298			(32,657	)
Accretion Expenses		849			829			847
Other nonrecurring items - amortization of Inventory		-			-			1,081
Consolidated Adjusted EBITDAX	$	22,472		$	26,796		$	22,548

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Operating Expenses

	Years Ended December 31,
In thousands except percentages	2010		2009		D vs. 2010			2008		D vs. 2009
Lease operating expense, transportation and taxes	$	19,894	$	15,651		27	%	$	20,242		(23	)%
Depreciation, depletion and amortization		12,142		15,368		(21	)		17,723		(13	)
Impairments of oil and gas assets		1,751		5,751		(70	)		22,093		(74	)
Accretion expense		849		829		2			847		(2	)
Loss from plug and abandonment		1,300		312		317			-		-
General and administrative		5,123		4,113		25			2,714		52
	$	41,059	$	42,024		(2	)%	$	63,619		(34)	%

During 2010, our operating expenses decreased by 2% when compared to 2009 due to the following factors:

Lease operating expense, transportation cost and taxes increased by 27%, or $4,243,000, in 2010 when compared to 2009. This increase was the result of the costs associated with a plan we initiated in January 2010 to workover a number of our wells, along with the incremental costs involved in operating older, more mature fields that require additional repair and maintenance as well as the increasing costs of environmental remediation expenditures. Finally, the higher oil and gas sale prices we received had the effect of increasing the taxes paid during 2010. On a per unit basis, lease operating expenses (excluding transportation and taxes) increased by $5.33 per MBOE to $18.32 per MBOE in 2010, from $12.99 per MBOE in 2009.

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 to these factors may cause our composite DD&A rate and expense to fluctuate from period to period. Our DD&A decreased by 21%, or $3,226,000, in 2010 when compared to 2009 primarily due to higher prices (per MBOE) that impacted our estimated total reserves, which are the basis for the depletion calculation and the impact of a 2009 impairment of $5,751,000 on the depletable base used to calculate DD&A. On a per unit basis, depletion expense decreased by $2.90 per MBOE to $14.44 per MBOE in 2010 from $17.34 per MBOE in 2009.

·	Impairments of oil and gas assets of $1,751,000 in 2010 were primarily a result of lower natural gas prices in general and the low volume of gas produced in a few of our Central Texas fields.

·	General and administrative expenses increased by 25%, or $1,010,000, in 2010 when compared to 2009, primarily due to attorney’s fees and expenses related to certain derivative litigation pending in Harris County, Texas.

During 2009, our operating expenses decreased by 34% when compared to 2008 due to the following factors:

Lease operating expense, transportation and taxes decreased by 23%, or $4,591,000, in 2009 when compared to 2008 primarily as a result of cost savings programs initiated in response to the reduction in oil and gas prices experienced from 2008 into 2009. Cost savings were achieved through operating efficiencies, deferral of certain workovers and vendor negotiations. Additional reductions were due to lower commodity prices that affected the taxes paid during 2009. This decrease was partially offset by the fact that, in 2008, we recorded only 9 months of operating expense, transportation and taxes associated with the properties acquired in GFB acquisition, compared to 12 months during 2009. On a per unit basis, lease operating expenses (excluding transportation and taxes) decreased by $4.60 per MBOE to $12.99 per MBOE in 2009 from $17.59 per MBOE in 2008.

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 to these factors may cause our composite DD&A rate and expense to fluctuate from period to period. DD&A decreased by 13%, or $2,355,000, in 2009 when compared to 2008 primarily due to higher prices (per MBOE) that impacted our estimated total reserves, which are the basis for the depletion calculation, and the impact of a 2008 impairment of $22,093,000 on the depletable base used to calculate DD&A, which was partially offset by higher production. On a per unit basis, depletion expense decreased by $4.25 per MBOE to $17.34 per MBOE in 2009 from $21.59 per MBOE in 2008.

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·	Impairments of oil and gas assets of $5,751,000 in 2009 were primarily a result of lower natural gas prices in general and the low volume of gas produced in a few of our Central Texas fields.

General and administrative expenses increased by 52%, or $1,399,000, in 2009 when compared to 2008, primarily due to increases in compensation and benefit expenses associated with hiring additional employees required as a result of the GFB acquisition and assuming operation of approximately 350 additional wells in October 2008. The GFB acquisition also increased the volume of the activities and, as a result, the indirect expenses of the activities. In addition, the Company incurred increased legal expenses in 2009 due to a number of factors. The Company was required to pay an award of $288,000 in attorney’s fees as a result of an adverse court decision in a case filed by the Company in 2001. The Company was the subject of two derivative lawsuits filed in 2009. Also in 2009 the Company instituted lawsuits against several entities to recover damages relating to its investments in Barnett Shale operations and to the operation of the properties acquired in the Five States acquisition.

Other expenses (income)

	Years Ended December 31,
In thousands except percentages	2010			2009			D vs. 2010			2008			D vs. 2009
Interest expense net	$	7,646		$	9,219			(17	)%	$	9,855			(6	)%
Realized gain on sale of investment and other		-			(250	)		(100	)		(145	)		72
Net loss (gain) on derivative contracts		(1,862	)		4,400			(142	)		(24,738	)		(118	)
	$	5,784		$	13,369			(57	)%	$	(15,028	)		(189	)%

Interest expense. Isramco’s interest expense decreased by 17%, or $1,573,000, for the year ended December 31, 2010 compared to the same period of 2009. This decrease is primarily due to the lower average outstanding balance of the loans which we obtained to fund the Five States acquisition in 2007 and the GFB acquisition in 2008, and to decreases in average LIBOR rates during 2010. The decrease was partially offset by the payments on interest rate swaps. Isramco’s interest expense decreased by 6%, or $636,000, for the year ended December 31, 2009 compared to the same period of 2008. This decrease is primarily due to the lower average outstanding balance of the loans which we obtained to fund the Five States acquisition in 2007 and the GFB acquisition in 2008, and to decreases in average LIBOR rates in 2009. The decrease was partially offset by the payments on interest rate swaps.

Net loss (gain) on derivative contracts. We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with the prior year, we have elected not to designate any positions as cash flow hedges for accounting purposes. Accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statement of operations.

At December 31, 2010, the Company had a $2.5 million derivative asset, of which $2.2 million was classified as current and a $3.5 million derivative liability, of which $1.1 million was classified as current. For the year ended December 31, 2010, the Company recorded a net derivative gain of $1.86 million (a $4.7 million unrealized loss offset by a $6.6 million gain from net cash received on settled contracts).

At December 31, 2009, the Company had a $5.6 million derivative asset, of which $3.4 million was classified as current and a $1.8 million derivative liability, of which $0.1 million was classified as current. For the year ended December 31, 2009, the Company recorded a net derivative loss of $4.4 million (a $19.3 million unrealized loss partially offset by a $14.9 million gain from net cash received on settled contracts).

At December 31, 2008, the Company had a $23 million derivative asset, of which $12 million was classified as current. For the year ended December 31, 2008, the Company recorded a net derivative gain of $24.7 million (a $32.6 million unrealized gain partially offset by a $7.9 million loss from net cash payments on settled contracts).

Income Tax

Income tax benefit for the year ended December 31, 2010 decreased by $9 million from the prior year. The decreased in our income tax benefit from the prior year was primarily due to our pre-tax loss of $4.6 million for the year ended December 31, 2010 compared to our pre-tax loss of $23.7 million in 2009. The effective tax rates for the years ended December 31, 2010, 2009 and 2008 were 40%, 42.6% and 10.5%, respectively.

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Recently Issued Accounting Pronouncements

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivative Instruments and Hedging Activity

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.

We are 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. Each of the counterparties to our derivative contracts is a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement. Please refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Derivatives and Hedging Activities" for additional information.

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. 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. At December 31, 2010, we had two open positions that convert a portion of our variable rate interest of our Scotia debt (as defined in Item 8. Consolidated Financial Statements and Supplementary Data—Note 6, “Long-term Debt and Interest Expenses”) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. 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.

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. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Derivatives and Hedging Activities" for more details.

Fair Market Value of Financial Instruments

The 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 Supplementary Data—Note 7, "Fair Value of Financial Instruments" for additional information.

Interest Sensitivity

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk results primarily from fluctuations in short-term rates, which are LIBOR based, that may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our obligations.

At December 31, 2010, total debt was $116,429,000.This debt bears interest at floating or market interest rates. The interest rate applicable to approximately 32% of this debt is based upon either the prime rate or LIBOR, at our option. Fluctuations in market interest rates will cause our annual interest costs to fluctuate.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information called for by this Item 8 is included following the "Index to Financial Statements" contained in this Annual Report on Form 10-K.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

MANAGEMENT’S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES.

In accordance with Rules 13a-15(f) and 15d-15(f), of the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial 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 Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2010 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 and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management has assessed, and our independent registered public accounting firm, MaloneBailey, LLP, has audited, our internal control over financial reporting as of December 31, 2010. The unqualified reports of management and MaloneBailey, LLP thereon are included in Item 8 of this Annual Report on Form 10-K and are incorporated by reference herein.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There has been no change in our internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, during the three months ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None

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PART III

The information called for by items 10, 11, 12 13 and 14 will be contained in the Company's definitive proxy statement which the Company intends to file within 120 days after the end of the Company's fiscal year ended December 31, 2010 and such information is incorporated herein by reference.

GLOSSARY

"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.

"Overriding Royalty" means a percentage interest over and above the base royalty and is free of all costs of exploration and production, which costs are borne by the Grantor of the Overriding Royalty Interest and which is related to a particular Petroleum License.

"Payout" means the defined point at which one party has recovered its prior costs.

"Petroleum" means any petroleum fluid, 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 Petroleum Law"

The Company's 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.

The following 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.

The holder of a preliminary permit 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.

Drilling for 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.

The Company, 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 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.

As 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.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Exhibits

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 with all amendments, filed as an Exhibit to the S-l Registration Statement, File No. 2-83570.

4.1		First Amended and Restated Promissory Note dated as of February 27, 2007, issued to NAPHTHA ISRAEL PETROLEUM CORP., LTD. in the principal amount of $18,500,000 filed as an Exhibit to the 10-K for the year ended December 31, 2009 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, 2009 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, 2009 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, 2009 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.


10.6		CREDIT AGREEMENT dated as of March 2, 2007 among ISRAMCO ENERGY, L.L.C., each of the lenders that is a signatory hereto or which becomes a signatory hereto; and WELLS FARGO BANK, N. A., a national banking association, as agent for the Lenders., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.

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10.7		GUARANTY AGREEMENT, dated as of March 2, 2007 by ISRAMCO, Inc. in favor of Wells Fargo Bank, N.A., as administrative agent (the "ADMINISTRATIVE AGENT") for the lenders that are or become parties to the Credit Agreement referred to in Item 10.6., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.

10.8		PLEDGE AGREEMENT, dated as of March 2, 2007 by Isramco, Inc. in favor of Wells Fargo Bank, N.A., as administrative agent for itself and the lenders (the "LENDERS") which are parties to the Credit Agreement referred to in Item 10.6, filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.

10.9		Employment Agreement dated as of September 1, 2007 between Isramco Inc. and Edy Francis, filed as an Exhibit to the 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference.+

10.10		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.

10.11		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.

10.12		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, 2009 and incorporated herein by reference.

10.13		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, 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.($18.5 million)

10.15		First Amendment to Loan Agreement dated as of February 1, 2009, between Isramco, Inc, and Naphtha Israel Petroleum Corp., Ltd.($11.5 million)

10.16		Loan Agreement dated as of July 14, 2009 between Isramco, Inc. and I.O.C. – Israel Oil Company, Ltd.($6.0 million)

10.17		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)

10.18*		Loan Agreement dated as of March 3, 2011 between Isramco, Inc. and I.O.C. – Israel Oil Company, Ltd.($11.0 million)

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

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

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

31.2*		Certification of Chief Financial 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 Chief Financial 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. Reserve Report

__________________________

* Filed Herewith.

+ Management Agreement

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SIGNATURES

Pursuant to Section 13 or 15(d) 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.

/S/ HAIM TSUFF

HAIM TSUFF,

CHAIRMAN OF THE BOARD,

CHIEF EXECUTIVE OFFICER

(PRINCIPAL EXECUTIVE OFFICER)

Date: March 11, 2011

/S/ EDY FRANCIS

EDY FRANCIS,

CHIEF FINANCIAL OFFICER

(PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)

Date: March 11, 2011

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 11, 2011
Haim Tsuff	Chief Executive Officer

/s/ Josef From	Director	March 11, 2011
Josef From

/s/ Max Pridgeon	Director	March 11, 2011
Max Pridgeon

/s/ Mark Kalton	Director	March 11, 2011
Mark Kalton

/s/ Asaf Yarkoni	Director	March 11, 2011
Asaf Yarkoni

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INDEX TO FINANCIAL STATEMENTS

	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, 2010 and 2009	F-3
Consolidated Statements of Operations for the years ended December 31,2010, 2009 and 2008	F-4
Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 2010, 2009 and 2008	F-5
Consolidated Statements of Cash Flows for the years ended December 31,2010, 2009 and 2008	F-6
Notes to Consolidated Financial Statements	F-7

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Isramco, Inc. (the “Company”), including the Company’s Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. The Company’s internal control system was designed to provide reasonable assurance to the Company’s Management and Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the company’s internal control over financial reporting was effective as of December 31, 2010.

Malone-Bailey, LLP, the Company’s independent registered public accounting firm, has issued an attestation report on the effectiveness on our internal control over financial reporting as of December 31, 2010.

/s/ Haim Tsuff /s/ Edy Francis

Haim Tsuff Edy Francis

Chief Executive Officer Chief Financial Officer

Houston, Texas

March 11, 2011

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Isramco, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Isramco, Inc. (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the three years ended December 31, 2010. We also have audited the Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Isramco, Inc as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ MALONE BAILEY, LLP

www.malone-bailey.com

Houston, Texas

March 11, 2011

F-2

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ISRAMCO INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

As of December 31	2010			2009
ASSETS
Current Assets:
Cash and cash equivalents	$	5,657		$	2,907
Accounts receivable, net		6,110			7,424
Restricted and designated cash		889			827
Deferred tax assets		3,368			3,644
Derivative asset		2,156			3,421
Prepaid expenses and other current assets		715			656
Total Current Assets		18,895			18,879

Property and Equipment, at cost – successful efforts method:
Oil and Gas properties		222,122			220,138
Other		922			672
Total Property and Equipment		223,044			220,810
Accumulated depreciation, depletion and amortization		(91,208	)		(77,315	)
Net Property and Equipment		131,836			143,495

Marketable securities, at market		16,099			4,713
Debt cost		70			322
Derivative asset		343			2,158
Deferred tax assets and other		4,635			6,751
Total assets	$	171,878		$	176,318

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	9,316		$	9,798
Short term debt and bank overdraft		335			336
Current maturities of long-term debt		14,350			12,000
Derivative liability		1,133			693
Accrued interest and due to related party		9,371			4,677
Total current liabilities		34,505			27,504

Long-term debt		22,725			32,950
Accrued interest - related party		778			4,832
Long-term debt - related party		76,354			79,354

Other Long-term Liabilities:
Asset retirement obligations		16,577			16,248
Derivative liability – non-current		2,402			1,697
Total other long-term liabilities		18,979			17,945

Commitments and contingencies (Note 13)

Shareholders’ equity:
Common stock $0.0l par value; authorized 7,500,000 shares; issued 2,746,958 shares; outstanding 2,717,691 shares		27			27
Additional paid-in capital		23,194			23,194
Retained earnings (accumulated deficit)		(14,149	)		(11,362	)
Accumulated other comprehensive income		9,629			2,038
Treasury stock, 29,267 shares at cost		(164	)		(164	)
Total shareholders’ equity		18,537			13,733

Total liabilities and shareholders’ equity

171,878

176,318

See notes to the consolidated financial statements.

F-3

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ISRAMCO INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share amounts)

Year Ended December 31	2010			2009			2008

Revenues
Oil and gas sales	$	39,329		$	30,768		$	51,832
Office services to other		655			845			191
Gains on divestitures and other		2,216			111			174
Total revenues		42,200			31,724			52,197

Operating expenses
Lease operating expense, transportation and taxes		19,894			15,651			20,242
Depreciation, depletion and amortization		12,142			15,368			17,723
Impairments of oil and gas assets		1,751			5,751			22,093
Accretion expense		849			829			847
Loss from plug and abandonment		1,300			312			-
General and administrative		5,123			4,113			2,714
Total operating expenses		41,059			42,024			63,619
Operating income (loss)		1,141			(10,300	)		(11,422	)

Other expenses (income)
Interest expense, net		7,646			9,219			9,855
Realized gain on sale of investment and other		-			(250	)		(145	)
Net loss (gain) on derivative contracts		(1,862	)		4,400			(24,738	)
Total other expenses (income)		5,784			13,369			(15,028	)

Income (loss) from continuing operations before income taxes		(4,643	)		(23,669	)		3,606
Income tax benefit (expense)		1,856			10,090			(377	)

Net income (loss)	$	(2,787	)	$	(13,579	)	$	3,229

Earnings (loss) per share – basic and diluted:	$	(1.03	)	$	(5.00	)	$	1.19

Weighted average number of shares outstanding-basic and diluted		2,717,691			2,717,691			2,717,691

See notes to the consolidated financial statements.

F-4

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ISRAMCO INC.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 and 2008

	Common stock
	Number of shares	Amount		Additional Paid-In Capital		Accumulated other comprehensive income (loss)			Retained Earnings (Accumulated Deficit)			Treasury stock			Total Shareholders’Equity
				$ in thousands, except share amounts
Balances at January 1, 2008	2,717,691		27		23,194		3,426		$	(1,012	)		(164	)		25,471

Net income										3,229						3,229
Net unrealized loss on available for sale marketable securities, net of taxes of $1,568							(3,044	)								(3,044	)
Net gain (loss) on derivative contracts, net of taxes $321							(622	)								(622	)
Total comprehensive loss																(437	)

Balance of December 31, 2008	2,717,691	$	27	$	23,194	$	(240	)	$	2,217		$	(164	)	$	25,034

Net loss										(13,579	)					(13,579	)
Net unrealized gain on available for sale marketable securities, net of taxes of $1,035							2,011									2,011
Net gain (loss) on derivative contracts, net of taxes $138							267									267
Total comprehensive loss																2,278

Balance of December 31, 2009	2,717,691	$	27	$	23,194	$	2,038		$	(11,362	)		(164	)		13,733

Net loss										(2,787	)					(2,787	)
Net unrealized gain on available for sale marketable securities, net of taxes of $3,965							7,258									7,258
Net gain (loss) on derivative contracts, net of taxes $171							333									333
Total comprehensive gain																7,591

Balance of December 31, 2010	2,717,691	$	27	$	23,194	$	9,629		$	(14,149	)		(164	)		18,537

See notes to consolidated financial statements.

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ISRAMCO INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

Year Ended December 31	2010			2009			2008

Cash Flows From Operating Activities:
Net income (loss)	$	(2,787	)	$	(13,579	)	$	3,229
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion, amortization and impairment		13,893			21,119			39,816
Accretion expense		849			829			847
Unrealized and realized gain on marketable securities					(250	)		(76	)
Changes in deferred taxes		(1,856	)		(9,841	)		468
Net unrealized loss (gain) on derivative contracts		4,727			19,298			(32,657	)
Amortization of debt cost		252			252			189
Realized gain on sale of investment and capital gain		(2,160	)		(3	)		(68	)
Changes in components of working capital and other assets and liabilities
Accounts receivable		1,314			(2,008	)		1,179
Prepaid expenses and other current assets		(59	)		(167	)		408
Due to related party		(592	)		305			288
Increase (decrease) in accrued interest - related party		(1,768	)		3,561			1,885
Accounts payable and accrued expenses		250			2,003			3,378
Net cash provided by operating activities		12,063			21,519			18,886

Cash flows from investing activities:
Addition to property and equipment		(3,611	)		(645	)		(99,042	)
Proceeds from sale of oil and gas properties		2,236			1			68
Decreased (increased) in restricted deposit, net		(62	)		(70	)		745
Purchase of marketable securities					(370	)		-
Proceeds from sale of marketable securities					752			476
Net cash used in investing activities		(1,437	)		(332	)		(97,753	)

Cash flows from financing activities:
Payments on loans – related parties, net		-			(963	)		43,773
Proceeds from long-term debt		-			2,000			54,000
Repayment of long-term debt		(7,875	)		(21,250	)		(16,800	)
Payments for financing cost		-			-			(1,015	)
Borrowings (repayments) of short - term debt, net		(1	)		(1,208	)		838
Net cash provided by (used in) financing activities		(7,876	)		(21,421	)		80,796

Net increase (decrease) in cash and cash equivalents		2,750			(234)			1,929
Cash and cash equivalents at beginning of year		2,907			3,141			1,212
Cash and cash equivalents at end of year	$	5,657		$	2,907		$	3,141

See notes to the consolidated financial statements.

F-6

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ISRAMCO INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

Isramco, Inc. and its subsidiaries (“Isramco” or the “Company”) are primarily engaged in the acquisition, development, production and exploration of onshore oil and natural gas properties located in the United States of America (“United States”). The Company operates in one segment, oil and natural gas exploration and exploitation. The Company’s consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. All intercompany accounts and transactions have been eliminated. The Company has evaluated events or transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.

Cash and Cash Equivalents.

Isramco records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.

Allowance for Doubtful Accounts

The Company establishes provisions for losses on accounts receivable if it determines that it will not collect all or part of the outstanding balance. The Company regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. There is no significant allowance for doubtful accounts as of December 31, 2010 or 2009.

Oil and Gas Operations.

The Company applies the successful efforts method of accounting for oil and gas properties. Under the successful efforts method, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Acquisition costs and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated.

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Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Amortization rates are updated to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.

The Company reviews its property and equipment in accordance with Accounting Standard Codification (ASC) 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company 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 the Company would recognize an impairment loss for the difference between the carrying amount and the discounted cash flow.

In 2010, 2009 and 2008, we reported an impairment charge of $1,751,000, $5,751,000 and $22,093,000, respectively, relating to our oil and gas properties.

Property, Plant and Equipment Other than Oil and Natural Gas Properties

Other operating property and equipment are stated at the lower of cost or fair market value. Provision for depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the respective assets. The cost of normal maintenance and repairs is charged to operating expense as incurred. Material expenditures, which increase the life of an asset, are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of properties sold, or otherwise disposed of, and the related accumulated depreciation or amortization are removed from the accounts and any gains or losses are reflected in current operations.

Marketable Securities

The Company may invest a portion of its cash in money market mutual funds which are highly liquid marketable securities. The Company accounts for marketable securities in accordance with Financial Accounting Standards Board’s (FASB) ASC 320, Investments—Debt and Equity Securities, (ASC 320) and classifies marketable securities as trading, available-for-sale, or held-to-maturity. The appropriate classification of its marketable securities is determined at the time of purchase and reevaluated at each balance sheet date.

Trading and available-for-sale securities are recorded at fair market value. Isramco holds no held-to-maturity securities. Unrealized holding gains and losses on trading securities are included in earnings. Unrealized holding gains or losses, net of the related tax effects, on available-for-sale securities are excluded from earnings and are reported net of applicable taxes as accumulated other comprehensive income, a separate component of shareholders' equity, until realized.

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. Additional retirement obligations increase the liability associated with new oil and natural gas wells as these obligations are incurred.

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Concentrations of Credit Risk

The Company through its wholly-owned subsidiary Jay Management Company, LLC ("Jay Management") operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s 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 also be adversely affected.

In 2010, one individual purchaser of the Company's production accounted for 23% of the Company’s total sales and an additional three individual purchasers of the Company's production accounted for approximately 27% of its total sales (approximately 9% each), collectively representing 50% of the Company's total sales. In 2009, two individual purchasers of the Company's production each accounted for in excess of 10% of the Company’s total sales and an additional three individual purchasers of the Company's production accounted for approximately 25.5% of its total sales (approximately 8.5% each), collectively representing 50% of the Company's total sales. In 2008, one individual purchaser of the Company's production accounted for 11% of the Company’s total sales and four additional individual purchasers of the Company's production each accounted for in excess of 8% of its total sales, collectively representing 46% of the Company's total sales.

Revenue Recognition

Revenues from the sale of oil and natural gas are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectibility of the revenue is reasonably assured. The Company follows the entitlement method of accounting for recording oil and gas revenues. Under this method, any revenues received in excess of the Company’s interest in production are treated as a liability. If revenues received are less than Company's interest in production, the deficiency is recorded as an asset. The Company's imbalance position was not significant in terms of volumes or values at December 31, 2010 and 2009.

Price Risk Management Activities

The Company follows ASC 815, Derivatives and Hedging. From time to time, the Company may hedge a portion of its forecasted oil and natural gas production. 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 to not 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 gain (loss) on derivative contracts” on the Company’s consolidated statements of operations.

In 2010, 2009 and 2008, we recorded gain (loss) of $1.9 million, ($4.4) million and $24.7 million, respectively, related to our derivative instruments. Fair values are derived principally from market quoted and other independent third-party quotes.

During the second quarter of 2008, we made the decision to mitigate a portion of our interest rate risk with interest rate swaps. These swap instruments reduce our exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. These interest rate swaps convert a portion of our variable rate interest of our Scotia debt (as defined in Note 6, “Long-term Debt and Interest Expense”) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. We have elected to designate these positions for hedge accounting and therefore the unrealized gains and losses are recorded in accumulated other comprehensive loss. The Company measures hedge effectiveness by assessing the changes in the fair value or expected future cash flows of the hedged item.

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Income Taxes

The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

The Company follows ASC 740, Income Taxes, (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements.

The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

Generally, the Company's tax years subsequent to 2006 are either currently under audit or remain open and subject to examination by federal tax authorities and the tax authorities in Louisiana, New Mexico, Oklahoma and Texas, which are the jurisdictions in which the Company has had its principal operations. In certain of these jurisdictions, the Company operates through more than one legal entity, each of which may have different open years subject to examination. It is important to note that years are technically open for examination until the statute of limitations in each respective jurisdiction expires.

Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates.

Translation of Foreign Currencies

Foreign currency is translated in accordance with ASC 830-10, Foreign Currency Translation, which provides the criteria for determining the functional currency for entities operating in foreign countries. Isramco has determined its functional currency is the United States (U.S.) dollar since all of its contracts are in U.S. dollars. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income in shareholders’ equity. Foreign currency transaction gains and losses are included in current income. The functional currency of our Israeli subsidiaries is the New Israeli Shekel.

Legal Contingencies

The Company is subject to legal proceedings, claims and liabilities which arise in the ordinary course of its business. The Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These estimates are adjusted as additional information becomes available or circumstances change.

Earnings per Share

The Company’s basic earnings per share (EPS) amounts have been computed based on the average number of shares of common stock outstanding for the period and include the effect of any participating securities as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units and performance-based stock awards if the inclusion of these items is dilutive.

For the year ended December 31, 2010, Isramco's stock options were anti-dilutive.

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Environmental

The Company accrues for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations are recognized no later than the time of the completion of the remediation feasibility study or remediation plan. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value.

Recently Issued Accounting Pronouncements

In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting (ASC 2010-3), which amended the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, and added a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which was eliminated. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by Release No. 33-8995 are now required to price proved oil and gas reserves using the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 was effective for financial statements with fiscal years ending on or after December 31, 2009. The Company adopted SEC Release No. 33-8995 effective December 31, 2009. The impact on the Company's operating results, financial position and cash flows has been recorded in the financial statements and additional disclosures were added to the accompanying notes to the consolidated financial statements for the Company's supplemental oil and gas disclosure. See Supplemental Oil and Gas Information for more details.

In January 2010, the Financial Accounting Standards Board (FASB) issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimation and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-3. As discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Company adopted ASU 2010-03 effective December 31, 2009. See Supplemental Oil and Gas Information for more details.

In January 2010, the FASB issued ASU No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not impact the Company's operating results, financial position or cash flows, but did impact the Company's disclosures on fair value measurements. See Note 7, " Fair Value of Financial Instruments of Financial Instruments".

In April 2010, the FASB issued ASU No. 2010-12, Accounting for Certain Tax Effects of the 2010 Health Care Reform Acts (ASU 2010-12). This update clarifies questions surrounding the accounting implications of the different signing dates of the Health Care and Education Reconciliation Act (signed March 30, 2010) and the Patient Protection and Affordable Care Act (signed March 23, 2010) (collectively , the “Acts”). ASU 2010-12 states that the FASB and the Office of the Chief Accountant at the Securities and Exchange Commission (“SEC”) would not be opposed to view the two Acts together for accounting purposes. The adoption of ASU 2010-12 did not impact the Company's operating results, financial position, cash flows or disclosures.

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In December 2010, the FASB issued ASU No. 2010-28, When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts (ASU 2010-28). This codification update modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts and requires reporting units with such carrying amounts to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. ASU 2010-28 is effective for fiscal years and interim periods beginning after December 15, 2010 and early adoption is not permitted. The Company will adopt the provisions of this update in its Quarterly Report on Form 10-Q for the three months ended March 31, 2011. The Companydoes not expect a material impact if any, as a result of the adoption.

In December 2010, the FASB issued ASU No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (ASU 2010-29). ASU 2010-29 requires a public entity who discloses comparative pro forma information for business combinations that occurred in the current reporting period to disclose revenue and earnings of the combined entity as though the business combination(s) occurred as of the beginning of the comparable prior annual period only. This update also expands the supplemental pro forma disclosures required to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010 and early adoption is permitted. The Company will adopt the provisions of this update for any business combinations that occur after January 1, 2011. The Company does not expect a material impact, if any, as a result of the adoption.

2. Acquisitions

GFB Acquisition

On March 27, 2008, we purchased interests in certain oil and gas properties located in Texas, New Mexico, Utah, Colorado and Oklahoma from GFB Acquisition - I, L.P. (“GFB”) and Trans Republic Resources, Ltd. (“Trans Republic,” and, together with GFB, the “Sellers”) for an aggregate purchase price of approximately $102 million. The transaction included mainly operated oil and gas properties in approximately 40 fields (approximately 490 Leases) in East Texas and the Texas Gulf Coast and the Permian, Anadarko and San Juan Basins.

The following table summarizes the preliminary estimated fair values of assets that we acquired and the liabilities assumed in connection with the acquisition of these properties:

As of December 31	2008
	(In thousands)
Oil and gas properties (after adjustments)	$	105,982
Asset retirement obligation		(8,480	)

Net asset acquired	$	97,502

Five States Acquisition

On March 2, 2007, Isramco purchased certain oil and gas properties located in Texas and New Mexico from Five States Energy Company, LLC for an aggregate preliminary purchase price of $92 million (before adjustments as defined in the purchase agreement). Although the acquisition was closed on March 2, 2007, the effective date of the purchase was October 1, 2006 (the “Effective Date”). Accordingly, the Company is entitled to the net revenues, less direct operating expenses, of the acquired properties from the Effective Date through the Acquisition Date. This resulted in an adjustment to the preliminary purchase price. These financial statements reflect the assets acquired and operations related to those assets from the Acquisition Date through December 31, 2007. According to an engineering report prepared by an independent consulting company relating to the properties purchased, the estimated proved developed producing reserves were 1,447,161 net barrels of oil and 20,078,174 net MMCF's of natural gas and 1,305,705 net of liquid products. Pursuant to an agreement between Sigma Energy Corporation ("Sigma"), an unrelated party that originated the transaction with Five States, on March 2, 2007 Isramco and Isramco Energy, Isramco Energy paid Sigma, $300,000 and after Payout (as defined in the Agreement with Sigma), Isramco Energy will be required to assign Sigma a direct ownership interests equal to 3.75% of the interests acquired by Isramco Energy under the Purchase Agreement.

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3. Transactions with Affiliates and Related Parties

There were no active oil and gas operations conducted by the Company with related companies in Israel or anywhere else in 2010, 2009 or 2008.

On November 17, 2008, the Company and Goodrich Global, Ltd. (“Goodrich”) entered into an Amended and Restated Agreement, as subsequently amended on November 24, 2008 (“Restated Agreement”). The Restated Agreement replaced the consulting agreement originally entered into in May 1996. Under the the Restated Agreement, the Company pays to Goodrich, which is owned and controlled by Haim Tsuff, the Chairman of the Board of Directors and Chief Executive Officer of Isramco, $360,000 per annum in installments of $30,000 per month, in addition to reimbursing Goodrich for all reasonable expenses incurred in connection with services rendered on behalf of the Company. Goodrich is entitled to receive, with respect to each completed fiscal year beginning with the fiscal year ended on December 31, 2008, an amount in cash equal to five percent (5%) of the Company’s pre-tax recorded profit calculated without reference to gain or loss in derivative transactions (the “Supplemental Payment”). The Supplemental payment is to be made within ten (10) business days after the filing with the Securities and Exchange Commission of the Company’s Annual Report on Form 10-K for such fiscal year. For purposes of the Supplemental Payment in the Restated Agreement, “profit” means the pre – tax recorded profit as specified in the Company’s annual report on Form 10-K, but excluding unrealized gain or loss on derivative transactions. The Restated Agreement has an initial term through May 31, 2011; provided that the term of the Restated Agreement will be deemed to have been automatically extended for an additional three year period unless the Company furnishes Goodrich, by March 3, 2011, with written notice of its election to not extend the term of such agreement. The Company did not furnish notice of termination, and the Restated Agreement was accordingly extended. The Restated Agreement contains certain customary confidentiality and non-compete provisions. If the Restated Agreement is terminated by the Company other than for cause, then Goodrich is entitled to receive the equivalent of payments due through the then remaining term of the agreement. For the year ended December 31, 2010, 2009 and 2008 we paid Goodrich the total amount of $360,000, $360,000 and $310,000, respectively. The conditions precedent for Supplemental Payments were not met and no Supplemental Payments have been made. In addition, in connection with the tentative settlement of the Derivative Litigation, the parties to the Restated Agreement have agreed to amend the Restated Agreement to eliminate the provisions providing for Supplemental Payment.

In November 1999, we entered into a consulting agreement with Worldtech Inc., a Mauritus company of which Jackob Maimon is the President. Jackob Maimon is a former director of Isramco. Pursuant to this consulting agreement, we paid the consultant $240,000 per annum in installments of $20,000 per month plus expenses in consideration of the services provided to the Company. This agreement expired in May 2008.

4. Marketable Securities

For the year ended December 31, 2010, 2009 and 2008, we had zero net unrealized gains on marketable securities. Sales of marketable securities resulted in realized gains of $0, $250,000 and $52,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

Available-for-sale securities, which are primarily traded on the Tel-Aviv Stock Exchange and on the National Association of Securities Dealers Automated Quotation (“NASDAQ”), consist of the following (in thousands):

As of December 31	2010				2009
	Cost		Market Value		Cost		Market Value
	$	1,200	$	16,099	$	1,087	$	4,713

5. Derivative and Hedging Activities

The Company enters into derivative commodity contracts to economically hedge its exposure to price fluctuations on a portion of its anticipated oil and natural gas production. It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to the Company’s derivative contracts is a lender in the Company’s Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement.

At December 31, 2010, the Company has entered into swaps agreements. A swap requires the Company to make a payment to, or receive receipts from, the counterparty based upon the differential between a specified fixed price and a price related to those quoted on the New York Mercantile Exchange (NYMEX) for each respective period.

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As of December 31, 2010 we had swap contracts for volume of 523,209 barrels of crude oil during 48 months, commencing January 2011, and swap contracts for volume of 939,042 MMBTU of natural gas during 15 months commencing January 2011. Derivative commodity contracts settle based on NYMEX West Texas Intermediate and Henry Hub prices, which may differ from the actual price received by the Company. During 2010, 2009 and 2008 the Company did not elect to designate any positions as cash flow hedges for accounting purposes, and accordingly, recorded the net change in the mark-to-market valuation of these contracts, as well as all payments and receipts on settled contracts, in current earnings as a component of other income and expenses on the consolidated statements of operations.

At December 31, 2010, the Company had a $2.5 million derivative asset, of which $2.2 million was classified as current and a $3.5 million derivative liability, of which $1.1 million was classified as current. For the year ended December 31, 2010, the Company recorded a net derivative gain of $1.86 million (a $4.7 million unrealized loss partially offset by a $6.6 million gain from net cash received on settled contracts).

Natural Gas

At December 31, 2010, the Company had the following natural gas swap positions:

Period	Swaps
	Volume in MMbtu’s		Price / Price Range		Weighted Average Price
January 2011 – December 2011		764,820		8.22		8.22
January 2012 – March 2012		174,222		8.65		8.65

Crude Oil

At December 31, 2010, the Company had the following crude oil swap positions:

Period	Swaps
	Volume in Bbls		Price / Price Range		Weighted Average Price
January 2011 – December 2011		240,336		79.50-91.05		86.55
January 2012 – December 2012		127,473		80.20-88.20		82.37
January 2013 – December 2013		89,400		85.15		85.15
January 2014 – December 2014		66,000		86.95		86.95

At March 10, 2010, the Company had the following crude oil swap positions:

Period	Swaps
	Volume in Bbls		Price / Price Range		Weighted Average Price
March 2011 – December 2011		223,164		88.55-103.51		94.31
January 2012 – December 2012		127,473		88.20-103.51		99.67
January 2013 – December 2013		89,400		103.51		103.51
January 2014 – December 2014		66,000		103.51		103.51

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Under these swaps, the Company makes payments to, or receives payments from, the counterparties based upon the differential between a specified fixed price and a price related to the one-month London Interbank Offered Rate (“LIBOR”). These interest rate swaps convert a portion of the variable rate interest of our Scotia Senior Credit Facility (as defined in Note 6, “Long-term Debt and Interest Expenses”) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. We have elected to designate these positions for hedge accounting and therefore the unrealized gains and losses are recorded in accumulated other comprehensive loss. The Company measures hedge effectiveness by assessing the changes in the fair value or expected future cash flows of the hedged item.

The Company’s open interest rate positions, as described above, are as follows:

Notional amount (in thousands):		Start Date	Maturity Date	Weighted-Average Interest Rate
	2,000	April 2010	February 2011		3.63	%
	6,000	April 2010	February 2011		2.90	%

6. Long-Term Debt and Interest Expense

Long-Term Debt as December 31 consisted of the following (in thousands):

	2010		2009
Libor + 2% Bank Revolving Credit Facility due 2011	9,450		14,950
Libor + 2% Bank Revolving Credit Facility due 2012	27,625		30,000
Libor + 6% Related party Debt	12,000		12,000
Libor + 5.5% Related party Debt	954		954
Libor + 6% Related party Debt	11,500		11,500
Libor + 6% Related party Debt	6,000		6,000
Libor + 6% Related party Debt	48,900		48,900
	116,429		124,304
Less: Current Portion of Long-Term Debt	(17,350	)	(12,000	)
Total	99,079		112,304

Senior Revolving Credit Facilities

The Company entered into a Senior Secured Revolving Credit Agreement, dated as of March 27, 2008 and Amended and Restated as of December 19, 2008 (the “Scotia Senior Credit Agreement”), with each of the lenders from time to time party thereto (the “Lenders”). The Bank of Nova Scotia is the administrative agent for the Lenders and Capital One, N.A. is the syndication agent for the Lenders. The Scotia Senior Credit Agreement originally provided for a $150 million facility due in 2012 with a borrowing base of $54 million that is redetermined from time to time and adjusted based on the Company’s oil and gas properties, reserves, other indebtedness and other relevant factors. During the first quarter of 2011, the Lenders reduced the borrowing base to $28 million.

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Amounts outstanding under the Scotia Senior Credit Agreement bear interest at specified margins over the LIBOR of 1.25% to 2.00% for LIBOR loans or at specified margins over the Base Rate (as defined in the agreement) of 0.25% to 1.25% for base rate loans. Such margins fluctuate based on the utilization of the borrowing base. Borrowings under the Scotia Senior Credit Agreement are secured by first lien and security interest on the real and personal property of Isramco Resources.

The Scotia Senior Credit Agreement contains customary financial and other covenants, including minimum working capital levels of not less than 1.0 to 1.0, leverage ratio of not greater than 3.5 to 1.0 and minimum coverage of interest of not less than 2.5 to 1.0. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, changes of control, asset sales, and liens on properties. At December 31, 2010, the Company was in compliance with all of its debt covenants under the Scotia Senior Credit Agreement.

The Company entered into a Senior Secured Revolving Credit Agreement, dated as of March 2, 2007 as Amended and Restated as of June 15, 2007 (the “Wells Fargo Senior Credit Agreement”), with the lenders from time to time party thereto (the “Lenders”) and Wells Fargo Bank, N.A, as administrative agent for the Lenders. The Wells Fargo Senior Credit Agreement originally provided for a $150 million facility due in March, 2011 with a borrowing base of $35.3 million that is redetermined from time to time and adjusted based on the Company’s oil and gas properties, reserves, other indebtedness and other relevant factors.

Amounts outstanding under this Wells Fargo Senior Credit Agreement bore interest at specified margins over the LIBOR of 1.25% to 2.00% for LIBOR loans or at specified margins over the Base Rate (as defined in the agreement) of 0.25% to 1.25% for base rate loans. Such margins fluctuated based on the utilization of the borrowing base. Borrowings under the Wells Fargo Senior Credit Agreement were secured by a guarantee from Isramco and a pledge by Isramco of the shares of Isramco Energy.

The Wells Fargo Senior Credit Agreement contained customary financial and other covenants, including minimum working capital levels of not less than 1.0 to 1.0, leverage ratio of not greater than 3.5 to 1.0 and minimum coverage of interest of not less than 2.5 to 1.0. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, changes of control, asset sales, and liens on properties. At December 31, 2010, the Company was in compliance with all of its debt covenants under the Wells Fargo Senior Credit Agreement.

On or about March 3, 2011, the Corporation paid the outstanding principal balance of the Wells Fargo Senior Credit Facility. By agreement of the parties, the derivative contracts remained in place until March 9, 2011, when these contracts were novated and replaced by new derivative contracts, for the same volumes but at current market prices, with Macquarie Bank, N.A. In connection with this transaction, the Wells Fargo Senior Credit Facility was transferred to and assumed by Macquarie Bank, N.A. This facility currently has no outstanding principal or current availability. The credit facility was assigned and transferred to Macquarie Bank, N.A. in anticipation of the finalization of a successor credit facility pursuant to which all of the Corporation’s debt (including its related party debt) will be consolidated into a single facility at Macquarie Bank, N.A., or some other commercial lender. In the event the parties are not successful in finalizing this transaction the facility will be terminated and all collateral related thereto will be released. The Corporation is uncertain as to whether it will be successful in obtaining new replacement financing or, if is obtained, the timetable upon which such facility will be closed and other material terms and conditions.

Related Party Debt

In July 2009 the Company entered into a loan transaction with I.O.C. Israel Oil Company, Ltd. (“IOC”), related party, pursuant to which the Company borrowed $6 million (the “IOC Loan”). The purpose of the IOC Loan was to provide funds to Isramco Resources, LLC, which in turn paid this amount to Bank of Nova Scotia, as administrative agent, and Capital One, N.A., as a syndication agent, under the Scotia Senior Credit Agreement. This payment reduced the outstanding balance below the borrowing base and avoided the imposition of additional interest under the Scotia Senior Credit Agreement.

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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.

In connection with GFB Acquisition (see Note 2), we obtained the following financing from related parties:

Pursuant to a Loan Agreement dated as of February 26, 2007 Isramco obtained a loan from JOEL Jerusalem Oil Exploration Ltd, a related party ("JOEL"), a related party, in the principal amount of $7 million, repayable at the end of 3 months (that was extended until July 11, 2007). Interest accrues at a per annum rate of 5.36%.

On July 2007, the Company and JOEL reached an agreement to revise the period of the Loan to seven years and the interest rate to LIBOR plus 6%.

In February and March, 2008 we obtained loans from JOEL in the aggregate principal amount of $48.9 million, repayable at the end of 4 months at an interest rate of LIBOR plus 1.25% per annum. Pursuant to a loan agreement signed in June 2008, the maturity date of this loan was extended for an additional period of seven years. Interest accrues at a per annum rate of LIBOR plus 6%. Principal and interest are due and payable in four equal annual installments, commencing on June 30, 2012. At any time we can make prepayments without premium or penalty.

Mr. 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 Chief Executive Officer and Chairman, is a controlling shareholder of JOEL.

In connection with the Company’s purchase of certain oil and gas interests mainly in New Mexico and Texas in February 2007 (See Note 2), the Company obtained loans in the total principle amount of $42 million from Naphtha Israel Petroleum Corp. Ltd., (“Naphtha”) with terms and conditions as below:

Pursuant to a Loan Agreement dated as of February 27, 2007 (the "First Loan Agreement"), Isramco obtained a $18.5 million loan from Naphtha. The outstanding principal amount of the loan accrues interest at per annum rate equal to the London Inter-bank Offered Rate (LIBOR) plus 5.5%, not to exceed 11% per annum. Interest is payable at the end of each loan year. Principal plus any accrued and unpaid interest are due and payable on February 26, 2014. Interest after the maturity date accrues at the per annum rate of LIBOR plus 12% until paid in full. At any time, Isramco is entitled to prepay the outstanding amount of the loan without penalty or prepayment. To secure its obligations that may be incurred under the Loan Agreement, Jay Petroleum, LLC, a wholly – owned subsidiary of Isramco, agreed to guarantee the indebtedness. Naphtha can accelerate the loan and exercise 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, renewal, acceleration, maturity or otherwise) or fail to make any payment due under any hedge agreement entered into in connection with the transaction, (ii) Isramco's material breach of any of the representations or warranties made in the loan agreement or security instruments or any writing furnished pursuant thereto, (iii) Isramco's failure to observe any undertaking contained in transaction documents if such failure continues for 30 calendar days after notice, (iv) Isramco's insolvency or liquidation or a bankruptcy event or (v) Isramco's criminal indictment or conviction under any law pursuant to which such indictment or conviction can lead to a forfeiture by Isramco of any of the properties securing the loan.

Pursuant to a Loan Agreement dated as of February 27, 2007 (the "Second Loan Agreement") Isramco obtained a loan (the “Second Loan” , in the principal amount of $11.5 million 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, commencing 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 Second Loan is not secured. The other terms of the Second Loan Agreement are identical to the terms of the First Loan Agreement.

Pursuant to a Loan Agreement dated as of February 27, 2007 (the "Third Loan Agreement ") Isramco obtained a loan in the principal amount of $12 million (the “Third Loan”) from Naphtha, 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 Isramco can make prepayments without premium or penalty. The Third Loan is not secured. The other terms of the Third Loan Agreement are identical to the terms of the Loan Agreement.

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Effective February 1, 2009, each of the loans from IOC and Naphtha to the Company were amended and restated to extend all payment deadlines arising on and after February, 2009, by two years.

Mr. Haim Tsuff, Isramco's Chief Executive Officer and Chairman, is a controlling shareholder of Naphtha and IOC.

Debt Maturities

Aggregate maturities of long-term debt at December 31, 2010 are due in future years as follows (in thousands):

2011		17,350
2012		37,950
2013		18,100
2014		24,100
2015		15,100
Thereafter		3,829
Total	$	116,429

Interest Expense

The following table summarizes the amounts included in interest expense for the years ended December 31, 2010, 2009 and 2008:

	Years Ended December 31,
	2010			2009		2008
	(In thousands)
Current debt, long-term debt and other - banks	$	1,719	$	2,658	$	3,369
Long-term debt – related parties		5,927		6,561		6,486

	$	7,646	$	9,219	$	9,855

7. Fair Value of Financial Instruments

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 nonperformance 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 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.

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The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of December 31, 2010 and 2009. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for the years ended December 31, 2010 and 2009.

	December 31, 2010
	Level 1		Level 2		Level 3		Total
Assets
Marketable securities	$	16,099	$	—	$	—	$	16,099
Commodity derivatives		—		2,499		—		2,499

Total	$	16,099	$	2,499	$	—	$	18,598

Liabilities
Commodity derivatives	$	—	$	3,501	$	—	$	3,501
Interest rate derivatives		—		34		—		34

Total	$	—	$	3,535	$	—	$	3,535

	December 31, 2009
	Level 1		Level 2		Level 3		Total
Assets
Marketable securities	$	4,713	$	—	$	—	$	4,713
Commodity derivatives		—		5,579		—		5,579

Total	$	4,713	$	5,579	$	—	$	10,292

Liabilities
Commodity derivatives	$	—	$	1,852	$	—	$	1,852
Interest rate derivatives		—		538		—		538

Total	$	—	$	2,390	$	—	$	2,390

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Marketable securities listed above are carried at fair value. The Company is able to value its marketable securities based on quoted fair values for identical instruments, which resulted in the Company reporting its marketable securities as Level 1.

Derivatives listed above include swaps that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s consolidated statements of operations, in case of commodity derivatives, and in “Other comprehensive income”, in case of interest rate derivatives. The Company is able to value these assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves.

As of December 31, 2010 and 2009, the Company’s derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, while no assurance to this effect can be provided, the Company does not anticipate such nonperformance. Each of the counterparties to the Company’s derivative contracts is a lender in the Company’s Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreements.

8. Income Taxes

Isramco operates through its various subsidiaries in the United States (“U.S.”); accordingly, income taxes have been provided based upon the tax laws and federal and state income tax rates in the U.S. as they apply to Isramco’s current ownership structure.

Isramco accounts for income taxes pursuant to Accounting Standards Codification (ASC) 740, Accounting for Income Taxes, which requires recognition of deferred income tax liabilities and assets for the expected future tax consequences of events that have been recognized in Isramco’s financial statements or tax returns. Isramco provides for deferred taxes on temporary differences between the financial statements and tax bases of its assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse.

Isramco adopted Accounting Standards Codification (ASC) 740-10, effective January 1, 2007. Isramco recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations. There were no unrecognized tax benefits that if recognized would affect the tax rate. There were no interest or penalties recognized as of the date of adoption or for the twelve months ended December 31, 2010. The Company's tax years subsequent to 2006 are either currently under audit or remain open and subject to examination by federal tax authorities and the tax authorities in Louisiana, New Mexico, Oklahoma and Texas, which are the jurisdictions in which the Company has had its principal operations. In certain of these jurisdictions, the Company operates through more than one legal entity, each of which may have different open years subject to examination. It is important to note that years are technically open for examination until the statute of limitations in each respective jurisdiction expires.

The income tax provision differs from the amount of income tax determined by applying the Federal Income Tax Rate to pre-tax income from continuing operations due to the following items:

	Years Ended December 31,
	2010				2009			2008
	(In thousands)
Expected tax (benefit) expense	$	(1,632	)	$	(8,285)		$	1,262
State income taxes, net		18			4			(164	)
Foreign income taxes		-			-			(659)
Change in estimate of income tax basis (1)		-			(1,637	)		-
Other		(242	)		(172	)		(62	)
Total tax expense (benefit)	$	(1,856	)	$	(10,090	)	$	377

(1)	Changes in estimated income tax basis in connection with the preparation of 2006 and 2008 amended federal income tax returns.

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Deferred tax assets at December 31, 2010 and 2009 are comprised primarily of net operating loss carry forwards and book impairment from write downs of assets. Deferred tax liabilities consist primarily of the difference between book and tax basis depreciation, depletion and amortization (DD&A) and impairment. Book basis in excess of tax basis for oil and gas properties and equipment primarily results from differing methodologies for recording property costs and depreciation, depletion and amortization under accounting principles generally accepted in the United States and the applicable income tax statutes and regulations in the jurisdictions in which the Company operates. There is a net deferred tax asset and it is management’s opinion that a valuation allowance is not needed, as it is more likely than not based on objective evidence that realization of the deferred tax assets is reasonably assured.

The principal components of Isramco’s deferred tax assets and liabilities as of December 31 were as follows (in thousands):

	2010			2009
Deferred current tax assets:
Unrealized hedging transactions	$	385		$	242
Accrued interest		3,738			4,357
Deferred current tax assets	$	4,123		$	4,599

Deferred current tax liabilities:
Unrealized hedging transactions	$	(755	)	$	(955	)
	$	(755	)	$	(955	)

Net current deferred tax assets	$	3,368		$	3,644

Deferred noncurrent tax assets:
Unrealized hedging transactions	$	841		$	595
Book-tax differences in property basis					-
Net operating loss carry-forwards		12,154			10,324
Other		33			565
Deferred noncurrent tax assets	$	13,028		$	11,484


Deferred noncurrent tax liabilities:
Unrealized hedging transactions	$	(120	)	$	(754	)
Book-tax differences in property basis		(1,344	)		(1,196	)
Book-tax differences in marketable securities		(5,265	)		(1,232	)
Other		(1,664	)		(1,664	)
Deferred noncurrent tax liabilities	$	(8,393	)	$	(4,846	)

Net noncurrent deferred tax assets	$	4,635		$	6,638

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The principal components of Isramco's Income Tax Provision for the years indicated below were as follows (in thousands):

	2010			2009			2008
Current income tax:
Federal	$			$	-		$	276
Foreign					-			(659	)
State					-			114
Total current income tax	$			$	-		$	(269	)

Deferred income tax
Federal	$	(1,874	)	$	(10,094	)	$	884
Foreign					-			-
State		18			4			(238	)
Total deferred income tax	$	(1,856	)	$	(10,090	)	$	646
Provision for income tax	$	(1,856	)	$	(10,090	)	$	377

At December 31, 2010 the Company has U.S. tax loss carry forwards of approximately $34,729,000 which will expire in various amounts beginning in 2023 and ending in 2030. Utilization of such loss carry forwards could be limited to the extent Isramco has an ownership change that triggers the limitation under Section 382 of Internal Revenue Code of 1986, as amended.

9. Earnings Per Share

The following table sets forth the computation of Net Income (Loss) Per Share Available to Common Stockholders for the years ended December 31 (in thousands, except per share data):

	2010			2009			2008
Numerator for Basic and Diluted Earnings per Share -
Net Income (loss)	$	(2,787	)	$	(13,579	)	$	3,229


Denominator for Basic Earnings per Share -
Weighted Average Shares		2,717,691			2,717,691			2,717,691
Potential Dilutive Common Shares -		-			-			-
Adjusted Weighted Average Shares		2,717,691			2,717,691			2,717,691

Net Income (Loss) Per Share Available to Common Stockholders – Basic and Diluted	$	(1.03	)	$	(5.00	)	$	1.19

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10. Stock Options

The 1993 Stock Option Plan (the 1993 Plan) was approved at the annual meeting of shareholders held in August 1993. As of December 31, 2008, 20,050 shares of common stock were reserved for issuance under the 1993 Plan. Options granted under the 1993 Plan may be either incentive stock options under the Internal Revenue Code or options that do not qualify as incentive stock options. Options granted under the 1993 Plan may be exercised for a period of up to ten years from the grant date. The exercise price for an incentive stock option may not be less than 100% of the fair market value of Isramco's common stock on the date of grant. All the options granted under the 1993 Plan to date were fully vested on the date of grant. The administrator of the 1993 Plan may set the exercise price for a nonqualified stock option at less than 100% of the fair market value of Isramco's common stock on the date of grant.

No stock options were granted during 2010, 2009 and 2008. Shares of common stock reserved for future issuance under the 1993 plan are 20,050 shares. There are no granted stock options outstanding under the 1993 Plan as of balance sheet date.

11. Supplemental Cash Flow Information

Cash paid for interest and income taxes was as follows for the years ended December 31 (in thousands):

	2010		2009		2008
Interest	$	9,160	$	6,263	$	7,014

Income taxes	$	-	$	-	$	80

The consolidated statements of cash flows for the year ended December 31, 2010 exclude the following non-cash transactions:

·	Net unrealized gain on available for sale marketable securities of $7.258 million, net of taxes of $3.965 million

The consolidated statements of cash flows for the year ended December 31, 2008 exclude the following non-cash transactions:

·	Asset retirement obligation from acquired properties and additional revision to current properties of $12.3 million included in the oil and gas properties

12. Concentrations of Credit Risk

Financial instruments, which potentially expose Isramco to concentrations of credit risk, consist primarily of trade accounts receivable and oil and gas derivative assets. Isramco's customer base includes several of the major United States oil and gas operating and production companies. 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 December 31, 2010. The fair value of oil and gas derivatives contracts will be significantly impacted by the change in oil and gas future prices. Isramco continues to monitor and review credit exposure of its marketing counter-parties.

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.

A significant portion of Isramco's cash and cash equivalents is invested in marketable securities. Substantially all marketable securities owned by Isramco are held by banks in Israel and Switzerland.

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13. Commitments and Contingencies

Commitments

Isramco has a few immaterial lease agreements.

Contingencies

From time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. All known liabilities are accrued based on the Company’s best estimate of the potential loss. In the opinion of management, Isramco's ultimate liability, if any, in these pending actions would not have a material adverse effect on the financial position, operating results or liquidity of Isramco.

14. Asset Retirement Obligation

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, the Company records a liability (an asset retirement obligation or ARO) on the consolidated balance sheet and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.

The following table presents the reconciliation of the beginning and ending aggregate carrying amount legal obligations associated with the retirement of oil and gas properties at December 31 (in thousands):

	2010			2009			2008
Liability for asset retirement obligation at the beginning of the year	$	16,248		$	15,733		$	2,670
Liabilities Incurred		4			-			8,480
Liabilities settled and divested		(524	)		(314	)		(17	)
Accretion expense		849			829			847
Revisions (*)		-			-			3,753
Liability for asset retirement obligation at the end of the year	$	16,577		$	16,248		$	15,733

(*) In 2008, management revised the asset retirement obligation liabilities to reflect the increase the costs of fulfilling such obligations and the decrease in the estimated life of the wells.

15. Subsequent Events

The Company has evaluated subsequent events through March 11, 2011 which is the date the consolidated financial statements were issued.

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16. Supplementary Oil and Gas Information (Unaudited)

The following supplemental information regarding the oil and gas activities of Isramco for 2010, 2009 and 2008 is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission and SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." Capitalized costs relating to oil and gas activities and costs incurred in oil and gas property acquisition, exploration and development activities for each year are shown below.

CAPITALIZED COST OF OIL AND GAS PRODUCING ACTIVITIES (IN THOUSANDS)

As of December 31	2010			2009
	United States			United States
Unproved properties not being amortized	$	-		$	-
Proved property being amortized		222,122			220,138
Accumulated depreciation, depletion amortization and impairment		(90,752	)		(77,116	)
Net capitalized costs		131,370			143,022

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES (IN THOUSANDS)

As of December 31	2010		2009		2008
	United States
Property acquisition costs—proved and unproved properties	$	-	$	-	$	97,502
Exploration costs	$	-	$	-	$	-
Development costs	$	3,454	$	423	$	1,167

OIL AND GAS RESERVES

Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

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The following table illustrates the Company's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by our independent reserve engineering firm, Cawley, Gillespie & Associates, Inc. The oil and natural gas liquids prices as of December 31, 2010 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate spot price which equates to $79.43 per barrel. The oil and natural gas liquids prices as of December 31, 2009 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate posted price which equates to $57.65 per barrel. The oil and natural gas liquids price as of December 31, 2008 is based on the year-end West Texas Intermediate posted price of $41.00 per barrel. The oil and natural gas liquids prices were adjusted by lease or field for quality, transportation fees, and regional price differentials. The natural gas prices as of December 31, 2010 and 2009 are based on the respective 12-month unweighted average of the first of the month prices of the Henry Hub spot price which equates to $4.37 per Mmbtu and $3.87 per Mmbtu, respectively. The natural gas price as of December 31, 2008 is based on the year-end Henry Hub spot market price of $5.71 per Mmbtu. All prices are adjusted by lease or field for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States.

	Oil BBls			Gas Mcf			NGL BBls			Equivalent (BOE)
December 31, 2007		2,003,081			25,352,566			2,163,661			8,392,170

Revisions of previous estimates		(2,276,616	)		(15,011,339	)		(766,418	)		(5,544,924	)
Acquisition of minerals in place		3,210,496			17,862,776			-			6,187,625
Sales of minerals in place		-			-			-			-
Production		(257,967	)		(2,507,828	)		(145,240	)		(821,178	)
December 31, 2008		2,678,994			25,696,175			1,252,003			8,213,693

Revisions of previous estimates		616,674			1,378,468			391,115			1,237,534
Acquisition of minerals in place		-			-			-			-
Sales of minerals in place		-			-			-			-
Production		(293,601)			(2,622,389	)		(155,793	)		(886,459	)
December 31, 2009		3,002,067			24,452,254			1,487,325			8,564,768

Revisions of previous estimates		606,445			1,616,809			431,465			1,307,378
Acquisition of minerals in place		-			-			-			-
Sales of minerals in place		-			-			-			-
Production		(290,589	)		(2,368,158	)		(155,640	)		(840,922	)
December 31, 2010		3,317,923			23,700,905			1,763,150			9,031,224

Isramco's proved developed reserves are as follows:

	Developed
	Oil BBls		Gas Mcf		NGL BBls		Equivalent (BOE)
December 31, 2010		3,317,923		23,700,905		1,763,150	9,031,224
December 31, 2009		3,002,067		24,452,254		1,487,325	8,564,768
December 31, 2008		2,678,994		25,696,175		1,252,003	8,213,693
December 31, 2007		1,808,317		23,338,079		1,873,949	7,571,947

	Undeveloped
	Oil BBls		Gas Mcf		NGL BBls		Equivalent (BOE)
December 31, 2007		194,764		2,014,487		289,711	820,223

Revisions of Previous Estimates —

2010 — Proved reserves must be estimated using the assumption that prices and costs remain constant for the duration of the reservoir life. The upward Revisions of Previous Estimates was due to significantly higher average first-day of the month oil and gas prices calculated for the 12 months ended December 31, 2010 compared to prices as of December 31, 2009.

2009 — Proved reserves must be estimated using the assumption that prices and costs remain constant for the duration of the reservoir life. The upward Revisions of Previous Estimates was due to significantly higher average first-day of the month oil prices calculated for the 12 months ended December 31, 2009 compared to prices as of December 31, 2008 which partially offset by lower average first-day of the month gas prices calculated for the 12 months ended December 31, 2009 compared to prices as of December 31, 2008.

The SEC amended its definitions of oil and natural gas reserves effective December 31, 2009. Previous periods were not restated for the new rules. Key revisions include a change in pricing used to prepare reserve estimates to a 12-month unweighted average of the first-day-of-the-month prices, the inclusion of non-traditional resources in reserves, definitional changes, allowing the application of reliable technologies in determining proved reserves, and other new disclosures (Revised SEC rules).

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STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOW

The following Standardized Measure of Discounted Future Net Cash Flow information has been developed utilizing ASC 932, Extractive Activities —Oil and Gas, (ASC 932) procedures and based on oil and natural gas reserve and production volumes estimated by Cawley, Gillespie & Associates, Inc. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

•

future costs and selling prices will probably differ from those required to be used in these calculations;

•

due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

•

a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

•

future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure for the year ended December 31, 2008, the future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year-end prices were required. At December 31, 2010 and 2009, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts.

	2010			2009			2008
Future cash inflows	$	429,260,906		$	294,721,432		$	277,008,941
Future development costs		(740,588	)		(556,810	)		(511,810	)
Future production costs		(208,228,155	)		(147,470,220	)		(146,421,245	)
Future income tax expenses		(33,475,234	)		-			-	)
Future net cash flows before 10% discount		186,816,929			146,694,402			130,075,886
10%Annual discount for estimated timing of cash flows		(89,183,575	)		(68,284,971	)		(56,698,274	)

Standardized measure discounted future net cash flows	$	97,633,354		$	78,409,431		$	73,377,612

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CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Company’s proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2010

	2010			2009			2008
Beginning of the year	$	78,409,431		$	73,377,612		$	96,765,740
Sales and transfers of oil and gas produced, net of production costs		(19,435,256	)		(15,116,990	)		(31,469,183	)
Net changes in prices and production costs		28,652,935			4,638,711			(144,454,304	)
Net changes in income taxes		(17,494,664	)		-			28,376,801
Changes in estimated future development costs, net of current development costs		(2,930,885	)		211,024			(3,546,457	)
Purchase of minerals in place		-			-			124,894,615
Revision of previous estimates		17,549,795			11,948,600			(45,059,969	)
Accretion of discount		7,092,982			6,626,173			23,513,947
Change in production rates and other		5,789,016			(3,275,699	)		24,356,422

End of year	$	97,633,354		$	78,409,431		$	73,377,612

Unaudited Quarterly Financial Information

(In Thousands, Except Per Share Data)

Quarter Ended	March 31			June 30			September 30			December 31
2010
Total Revenues	$	10,165			9,527			9,928			12,580
Net Income (loss) before taxes	$	2,057			1,464			(3,802	)		(4,362	)
Net Income (loss)	$	1,357			966			(2,510	)		(2,600	)

Earnings (loss) per Common Share
-Basic and Diluted	$	0.50		$	0.36		$	(0.92	)	$	(0.96	)

2009
Total Revenues	$	7,007		$	7,399		$	7,810		$	9,508
Net Income (loss) before taxes	$	2,713		$	(12,223	)	$	(3,236	)	$	(10,923)
Net Income (loss)	$	1,790		$	(8,014	)	$	(2,018	)	$	(5,337	)

Earnings (loss) per Common Share
-Basic and Diluted	$	0.66		$	(2.95	)	$	(0.74	)	$	(1.96	)

2008
Total Revenues	$	7,730		$	18,873		$	17,866		$	7,728
Net Income (loss) before taxes	$	(11,586	)	$	(47,905	)	$	51,572		$	11,525
Net Income (loss)	$	(7,646	)	$	(32,186	)	$	34,488		$	8,573

Earnings (loss) per Common Share
-Basic and Diluted	$	(2.81	)	$	(11.84	)	$	12.69		$	3.15

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