Edgar Filing: ISRAMCO INC

isramco-10k12312008.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, 2008

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.)

4801 Woodway Drive Suite 100E Houston Texas 77056

(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 r Non-accelerated filer r Smaller Reporting Company x

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 20, 2009, 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, 2008, based on the last sale price of such equity reported on the Nasdaq market, was approximately $64.6 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 2009 annual meeting of stockholders, which will be filed on or before April 30, 2009.

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ISRAMCO, INC.

2008 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

		Page
PART I

ITEM 1.	BUSINESS	4
ITEM 1A.	RISK FACTORS	9
ITEM 1B.	UNRESOLVED STAFF COMMENTS	16
ITEM 2.	PROPERTIES	16
ITEM 3.	LEGAL PROCEEDINGS	16
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	16

PART II
		17
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	17
ITEM 6.	SELECTED FINANCIAL DATA	17
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25
ITEM 8.	CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	25
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	25
ITEM 9A.	CONTROLS AND PROCEDURES
ITEM 9B.	OTHER INFORMATION

PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORAT 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
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	29

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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 possibility that the United States economy is entering into a deflationary period, which would negatively impact the price of commodities, including oil and natural gas;

·	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 program;

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 operated 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, 2008, 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 8,213 thousand barrels of oil equivalent (“MBOE”), consisting of 2,679 thousand barrels (Bbls) of oil, and 25,696 million cubic feet (Mcf) of natural gas and 1,252 thousand barrels (Bbls) natural gas liquids. Approximately 97.6% of our proved reserves were classified as proved developed. (see "Supplemental Information to Consolidated Financial Statements").

Our business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs, acquiring of strategic oil and gas properties and improvement of existing oil and gas properties. Over the course of 2008, we have expanded our activities in the United States through a combination of strategic acquisitions and 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 620 wells located mainly in Texas and New Mexico. The following is a summary of significant developments during 2008 through the present, including certain 2009 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.

Israel

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

Matan License. In January 2009, Noble Energy, Inc. (“Noble”) completed the Tamar # 1 (“Tamar”) well at a depth of 16,076 feet and in approximately 5,500 feet of water depth. This well is located offshore Israel and is operated by Noble Energy, Inc. After analysis of all the post drilling and production test data, Noble estimates the gross mean resources potential of Tamar to be 5 trillion cubic feet of natural gas. Performance modeling indicates that the well can be ultimately completed to achieve a production rate of over 150 million cubic feet per day. We own an overriding royalty interest of 1.4375% in this well, which will increase to 2.7375% after payout.

Noble and its other partners have announced that they intend to retain the rights to the Atwood Hunter drilling rig in order to drill two additional wells, one of which is an exploration well, the Dalit # 1 well, which was spudded on March 6, 2009. The second well is an appraisal well (Tamar # 2) to be 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.

Med Yavne Lease. Based on the gas finds known as "Or 1" and "Or South", a 30 year lease, which covers 53 square kilometers (approximately 13,100 acres) offshore Israel, was granted to us in June 2000 (hereinafter: the "Med Yavne Lease"). The 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 Lease, and the partners appointed I.O.C Israel Oil Company as the successor operator.

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According to the operator's estimates, which are based on the results of the drillings in the Or 1, and on a 3D seismic survey performed in the area of the lease, the recoverable gas reserves of Or 1 reserve are estimated at 35 billion cubic feet. In January 2008 and in January 2009, Isramco received an opinion from a consulting firm in the United States that performed a techno-economic examination for the development of the Or 1 reserve. The opinion indicates that, under certain assumptions, development of the reserve by connection to a nearby platform (at a distance of seven miles) and from there via an existing transportation pipeline to the coast, 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 reserve with their gas reserve.

Our participation interest of the Med Yavne Lease is 0.7052 %

Hof Licenses. In February 2008 the Petroleum Commissionaire of Israel granted to us a license that covers 100,000 acres offshore Israel. According to the license terms the participants in the license need to drill one well in the license’s area by August 2009. We have sold 80% of the working interest in the license in return for a 20% carried working interest (up to investment of $4,000,000 in the license).

Med Ashdod 2. In February 2008 the Petroleum Commissionaire has granted us a license which covers 100,000 acres offshore Israel. According to the License terms the participants to the licenses need to sign a drilling contract by no later than November 2009. According to Israeli Petroleum law, the Petroleum Commissionaire sent a default notice in that notified us of the default and demanded that we cure the default within 60 days from the date of the notice. Pursuant to the Israeli Petroleum law, the operator has appealed this determination to the Minister of Infrastructure of Israel.

Our participation interest of the Med Ashdod Lease is 0.35%

The table below sets forth the working interests of Isramco and all related and unrelated participants in the lease and licenses in Israel, the total acreage and the expiration dates of each of the licenses and the lease as of December 31, 2008.

TABLE OF WORKING INTEREST

(% Interest of 100%)

Name of Participant	Med Yavne Lease		Med Ashdod 2 License		Hof License
Isramco (1)		0.7052		0.35		20.00

Related parties

Isramco Negev 2, Limited		49.863		21.05		30.00
Partnership

I.O.C.		14.7743		7.80		1.00

I.N.O.C. Dead Sea		--		5.05		5.00
Limited Partnership

Naphtha		1.80		--

Naphtha Explorations		3.5117		1.85		5.00
Limited Partnership

JOEL		4.4318		--		--

Equital		3.3291		--		--

Unrelated parties		23.3846		62.1		39.00

Total		100.00		100.00		100.00

Area (acres)		13,100		100,000		100,000

Expiration Date (2)	6/10/2030		2/14/2011		2/14/2011

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(1) All of the oil and gas assets are subject to a 12.5% Overriding Royalty due to the Government of Israel under the Israeli Petroleum Law.

(2) The expiration dates are 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 participant 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:

From the Limited Partnership, on the first 10% of the Limited Partnership's share of the following leases

	Before Payout			After Payout
Med Yavne Lease ,Michal ,Mathan Licenses from the first 10% working interests of Isramco Negev 2 LP (1)*		1	%		13	%
Michal & Matan Licenses 28.75% working interests of from Isramco Negev 2, LP		5.0	%		5.0	%

(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.

Acquisition Related Financing Activities

GFB Acquisition Financing.

To fund the oil and gas properties acquired in March 2008 from the Sellers we obtained loans in the aggregate principal amount of $102.9 million as described below:

In February and March, 2008 we obtained loans from J.O.E.L. Jerusalem Oil Exploration, Ltd. (“JOEL”), a related party, in the aggregate principal amount of $48.9 million, repayable at the end of 4 months at an interest rate of the London Interbank Offered Rate (LIBOR) plus 1.25% per annum. Pursuant to a loan agreement signed in June 2008, the maturity date of this loan was extended to June 30, 2015. 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 and director is a director of JOEL and Mr. Haim Tsuff, Isramco’s Chief Executive Officer and Chairman, is a controlling shareholder of JOEL.

We entered into a Senior Secured Revolving Credit Agreement, dated as of March 27, 2008, as subsequently amended, (the “Senior Credit Agreement”), with Bank of Nova Scotia, as administrative agent for the lenders form time to time (the “Lenders”) and Capital One, N.A as a syndication agent for the Lenders. The Senior Credit Agreement provides for a $150 million credit facility with an increased borrowing base of $54 million that will be re-determined from time to time, and adjusted based on the Company’s oil and gas properties, reserves, other indebtedness and other relevant factors. Owing to the general deterioration in economic conditions, during the fourth quarter of 2008, the lenders reduced the borrowing base to $45 million.

Amounts outstanding under the 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 Senior Credit Agreement) of 0.25% to 1.25% for base rate loans. Such margins will fluctuate based on the utilization of the borrowing base. Borrowings under the Senior Credit Agreement are secured by first lien and security interest on the real and personal property of Isramco Resources, one of our subsidiaries.

The 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, 2008, the Company was in compliance with all of its debt covenants under the Senior Credit Agreement.

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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 39 months. 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, 2008 we had swap contracts for volume of 771,724 barrels of crude oil during 39 months, commencing January 2009, and swap contracts for volume of 4,779,618 MMBTU of natural gas during 39 months commencing January 2009.

Hereunder are the open swap contracts positions as of December 31, 2008:

	Swap Contracts
	Natural Gas				Crude Oil
	Volume (MMBTU) (*)		Weighted Average Price ($/MMBTU)		Volume (Bbl)		Weighted Average Price ($/Bbl)
2009		2,054,928		8.25		274,596		81.00
2010		1,785,648		7.88		254,868		79.59
2011		764,820		8.22		210,307		87.53
2012		174,222		8.65		31,953		88.20

(*) Mef = MMBTU

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 of our Scotia debt (as defined in Note 8, “Long-term Debt”) 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:

National amount (in thousands)	Start Date	Maturity Date	Weighted-Average Interest Rate
32,000	April 2009	February 2011	3.63%
6,000	April 2009	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

Domestic exploration for and the production, sale and transportation of oil and natural gas are extensively regulated at the federal, state and local levels. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, extensive rules and regulations applicable to the oil and natural gas industry. Compliance with these regulations is costly. In addition, there are substantial penalties for failure to comply. To add to the difficulty in compliance, the interpretation and enforcement of these regulations is not always constant or uniform.

State regulatory authorities have established rules and regulations requiring permits for drilling operations, drilling bonds and reporting requirements applicable to exploration and production operations. All states in which we operate also have statutes and regulations concerning conservation matters, including the conditions and requirements applicable to the unitization or pooling of oil and natural gas properties, establishment of maximum rates of production from oil and natural gas wells and the number of wells which may be drilled in a certain area or formation. Production operations are also affected by changing tax and other laws.

As a member of the oil and gas industry, we are subject to extensive and evolving environmental laws and regulations. These regulations are administered by the United States Environmental Protection Agency and various other federal, state, and local environmental, zoning, health and safety agencies, many of which periodically examine our operations to monitor compliance with such laws and regulations. Among other subjects, these regulations address the release of waste materials into the environment and the transportation, storage and disposal of petroleum products and generally are designed to protect the environment and human, animal and plant health. Compliance with these regulatory requirements affects our operations and costs.

In recent years, environmental regulations have increasingly taken a cradle to grave approach to waste management, regulating and creating liabilities for the waste at its inception to final disposition. Our oil and natural gas exploration, development and production operations are subject to numerous environmental programs, including solid and hazardous waste management, water protection, air emission controls and situs controls affecting wetlands, coastal operations and antiquities. Further, each state in which we operate has its own unique laws and regulations governing solid waste disposal, water and air pollution, along with regulations governing the environmental effects of oil and natural gas exploration, development and production operations.

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Environmental regulatory programs typically focus on permitting, construction and operations of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Once a permit is received and a facility is operational, enforcement measures can result in the imposition of significant civil penalties for any regulatory violations regardless of intent or effort to comply. Under appropriate circumstances, an administrative agency can issue a cease and desist order requiring suspension of operations.

New programs and changes in existing programs are anticipated, some of which include naturally occurring radioactive materials (“NORM”), oil and natural gas exploration and production waste management, underground injection of waste material and emissions of certain gases, commonly referred to as “greenhouse gases” including carbon dioxide and methane, which according to recent studies may be contributing to the warming of the Earth’s atmosphere. In response to these studies, President Obama has expressed support for, and it is anticipated that the current session of Congress will consider, legislation to restrict or regulate emissions of greenhouse gases. Many states, either individually or through multi-state regional initiatives, have already begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Depending on the particular program, we could be required to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. In this regard, the Environmental Protection Agency may regulate greenhouse gas emissions even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.

We are also subject to federal and state Hazard Communications and Community Right to Know statutes and regulations. These regulations govern record keeping and reporting of the use and release of hazardous substances. We believe we are in compliance with these requirements in all material respects.

We may be required in the future to make substantial expenditures to comply with environmental laws and regulations. Other than to note that the regulation of the oil and gas industry and the cost of compliance are likely to increase in the future, the specific additional changes in operating procedures and expenditures required to comply with future laws dealing with the protection of the environment cannot be predicted.

Employees

As of December 31, 2008, we had 16 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.

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.

Crude oil and natural gas prices are volatile and a substantial reduction in these prices could adversely affect our results and the price of our common stock.

Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. The markets and prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:

·	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;

·	the price and availability of alternative 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.

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Significant declines in crude oil and natural gas prices for an extended period 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 crude oil and natural gas 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; or
·	limiting our access to sources of capital, such as equity and long-term debt.

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.

The current recession could have a material adverse impact on our financial position, results of operations and cash flows.

The oil and gas industry is cyclical in nature and tends to reflect general economic conditions. Economic analysts have stated that the U.S. and other world economies are in a recession that could last well into 2009 and beyond. The recession may lead to significant fluctuations in demand and pricing for our crude oil and natural gas production, such as the decline in commodity prices that occurred during 2008 and into 2009. Our profitability will likely be significantly affected by decreased demand and lower commodity prices. Due to lower commodity prices, we recorded asset impairment charges during fourth quarter 2008. If commodity prices continue to decline, there could be additional impairments of our operating assets. Our future access to capital, as well as that of our partners and contractors, could be limited due to tightening credit markets that could inhibit development of our property interests. Some of our longer-term projects require significant investment and may be delayed due to capital constraints. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or assumptions underlying our reserve estimates could cause the quantities and net present value of our reserves to be overstated or understated.

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There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated. The reserve information included or incorporated by reference in this report represents estimates prepared by our internal engineers. The procedures and methods for estimating the reserves by our internal engineers were reviewed by an independent petroleum engineering firm. Estimation of reserves is not an exact science. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, any of which may cause these estimates to vary considerably from actual results, such as:

·	historical production from an area compared with production from similar producing areas;

·	assumed effects of regulation by governmental agencies;

·	assumptions concerning future oil and natural gas prices, future operating costs and capital expenditures; and

·	estimates of future severance and excise taxes, workover and remedial costs.

Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared or

audited by different engineers, or by the same engineers at different times, may vary substantially. Actual

production, revenues and expenditures with respect to our reserves will likely vary from estimates, and the

variance may be material. The net present values referred to in this report should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower.

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 leases to the oil and gas properties. 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.

In the case of Israeli based properties, we have 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, we may not be able to fulfill our obligations under the leases, which may result in the modification, or cancellation of such leases or such leases may not be renewed or may be renewed on terms different from the current leases. The modification or cancellation of our leases 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.

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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.

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 the 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.

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The current economic crisis may have a negative impact on the liquidity of the counterparties to our hedging arrangements, which increases the risk of those counterparties failing to perform under those agreements. If those parties do fail to perform, we will be exposed to the price risks we had sought to mitigate and our operating results, financial position and cash flows may be materially and adversely affected. As of December 31, 2008 approximately 78%, 80%, 71% and 12% of our forecasted oil production and natural gas liquids hedged for 2009, 2010, 2011 and 2012 respectively and approximately 81%, 82%, 39% and 12% of our forecasted gas production hedged for the same time frame.

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.

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.

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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.

If we are unable to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, or our internal control over financial reporting is not effective, the reliability of our financial statements may be questioned and our share price may suffer.

Section 404 of the Sarbanes-Oxley Act requires any company subject to the reporting requirements of the U.S. securities laws to do a comprehensive evaluation of its internal control over financial reporting. To comply with this statute, we are required to document and test our internal controls over financial reporting and our management is required to issue a report concerning our internal controls over financial reporting in this Annual Report on Form 10-K for the effectiveness of our fiscal year ended December 31, 2008. Our independent auditors will be required to issue an opinion on the effectiveness of our internal controls over financial reporting for our annual report on Form 10-K for our fiscal year ending December 31, 2009. The rules governing the standards that must be met for management to assess our internal controls over financial reporting are complex and require significant documentation, testing and possible remediation to meet the detailed standards under the rules. We have discovered certain deficiencies in the design and/or operation of our internal controls that could adversely affect our ability to record, process, summarize and report financial data. We have invested and will continue to invest significant resources in this process. We are uncertain as to what impact this conclusion that deficiencies exist in our internal controls over financial reporting would have on the trading price of our common stock.

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 recent growth is due significantly 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.

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.

Rapid growth may place significant demands and resources.

We experienced rapid growth in operations occasioned by the purchase of approximately 650 producing oil and gas wells in March 2007 from Five States Energy Company, LLC and approximately 590 producing oil and gas wells from GFB and Trans Republic in March 2008. We expect that significant expansion of our operations will continue. The rapid growth has placed, and the anticipated future growth will continue to place, a significant demand on our managerial, operational and financial resources due to:

·	the need to manage relationships with various strategic partners and other third parties;

·	difficulties in hiring and retaining skilled personnel necessary to support our business;

·	the need to merge the operations of the acquired properties into our existing operations, accounting and management systems;

·	the need to train and manage a growing employee base; and

·	pressures for the continued development of our financial and information management systems.

If we have not made adequate allowances for the costs and risks associated with our expansion or if its systems, procedures or controls are not adequate to support our operations, our business could be adversely impacted.

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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 51.3% of our outstanding shares of common stock as of March 20, 2009. 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 articles 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.

ITEM 1B. Unresolved Staff Comments

Not applicable

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 Supplemental Information to Consolidated Financial Statements.

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 Supplemental Information to Consolidated Financial Statements 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.

ITEM 3. Legal proceedings

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. Submission of matters to a vote of security holders

No matters were submitted to a vote of our stockholders during the fourth quarter of the fiscal year ended December 31, 2008.

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PART II

ITEM 5. Market for registrant’s common equity and related stockholder matters

Approximately 342 stockholders of record as of December 31, 2008 held our common stock. In many instances, a registered stockholder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.

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.

	High			Low
2008
First Quarter		$	49.45		$	30.00
Second Quarter			50.00			31.06
Third Quarter			60.00			36.62
Fourth Quarter			46.47			19.20

2007
First Quarter		$	33.16		$	32.66
Second Quarter			42.91			42.73
Third Quarter			45.89			37.27
Fourth Quarter			47.47			47.37

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 an 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.

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, 2008, 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 8,213 thousand barrels of oil equivalent (MBOE), consisting of 2,679 thousand barrels (Bbls) of oil, and 25,696 million cubic feet (MMcf) of natural gas and 1,252 thousand barrels (Bbls) natural gas liquids. Approximately 97.6% of our proved reserves were classified as proved developed.

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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

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 also will result in revisions to the amount of our estimated proved reserves.

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 Statements of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS 144). SFAS 144 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

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 39 months. 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 statement of operations. We carry our derivatives at fair value on our consolidated balance sheets, with the changes in the fair value included in our 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.

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Income Taxes

The Company follows SFAS No. 109, Accounting for Income Taxes, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax assets and liabilities are computed using the liability method based on the differences between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

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

Liquidity and Capital Resources

Our primary sources of cash during 2008 were cash flows from operating activities, availability under our Senior Credit Agreement, and loans from related parties. The capital markets, as they relate to us, have been adversely impacted by the current financial crisis, concerns about overall deflation and its effect on commodity prices, the possibility of a deepening world recession that may extend for a long period into the future, a lack of liquidity in the banking system and the unavailability and cost of credit. Continued volatility in the capital markets could adversely impact our ability to replace our reserves, and eventually, our production levels.

Our future capital resources and liquidity may depend, in part, on our success in developing the leasehold interests that we 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 of 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, our commodity price hedging activities as well as various economic conditions that have historically affected the oil and natural gas industry. Oil and natural gas prices have continued to fall after December 31, 2008. If these prices hold for a prolonged period of time or continue to fall, our ability to fund capital expenditures, reduce debt, meet financial obligations and become profitable may be materially impacted.

Debt

	As of December 31,
	2008			2007			2006
	(In thousands except percentage)
Revolving Credit Facility	$	43,200		$	24,000		$	-
Long – term debt – related party		80,354			36,581			-
Short – term debt – related party		-			-			17,000
Current maturities of long-term debt, short-term debt and bank overdraft		22,544			3,706			347
Total debt		146,098			64,287			17,347

Stockholders’ equity		25,034			25,471			34,744

Debt to capital ratio		85	%		72	%		33	%

At year-end 2008, our total debt was $146,098 thousand compared to total debt of $64,287 thousand at year-end 2007 and $17,347 thousand at year-end 2006. As of December 31, 2008, current debt included $21,000 thousand as current maturities of the Revolving Credit Facility. However, the Company is not obligated to repay this facility prior to the due date, except for such payments as may be required under the Credit Agreement in the event of a redetermination and reduction of the borrowing base. As of December 31, 2008, $19,750 thousand of the $21,000 thousand was due to the decision of management to continue reducing the debt below the borrowing base. As of December 31, 2007, current debt included $3,000 thousand as current maturities, which again was due to management’s decision to continue payments to reduce debt below the borrowing base.

Cash Flow

Our primary sources of cash in 2008, 2007 and 2006 were from operating and financing activities. Proceeds from loans obtained from related parties, proceeds from Senior Credit Agreement and cash received from operations were offset by repayments of our Senior Credit Agreement, repayments of loans from related parties and cash used in investing activities to fund 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 or influence our ability to reduce our long-term loans. Prices for oil and natural gas have historically been subject to seasonal influences 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 Continuing Operations” below for a review of the impact of prices and volumes on sales.

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	Years Ended December 31,
	2008				2007				2006
	(In thousands)
Cash flows provided by operating activities		$	17,001			$	(662	)		$	7,233
Cash flows used in investing activities			(97,753	)			(63,656	)			(24,041	)
Cash flows provided by financing activities			82,681				64,957				16,181
Net increase (decrease) in cash		$	1,929			$	639			$	(627	)

Operating Activities, Net cash flows provided by (used in) operating activities were $17,001 thousands, ($662) thousands and $7,233 thousands for the years ended December 31, 2008, 2007 and 2006, respectively. Key drivers of net operating cash flows are commodity prices, increasing of production volumes primarily due to the two acquisitions we had during 2007 and 2008 and operating costs.

Because of significant declines in oil and natural gas prices, net cash flows provided by operating activities declined significantly in the fourth quarter 2008 compared to the third quarter.

Investing Activities, The primary component of cash used in investing activities is capital spending for the acquisitions in 2008 and 2007. Cash used in investing activities was $97,753 thousand, $63,656 thousand and $24,041 thousand for the years ended December 31, 2008, 2007 and 2006, respectively.

In 2008, we spent $98,673 thousand 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 thousand on other property and equipment during 2008.

In 2007, we spent $86,056 thousands on acquisition of oil and gas properties and capital expenditures. Our acquisitions were partially funded by the remaining restricted cash that we had deposited in 2006. We participated in the drilling of 2 gross wells in 2007. We spent an additional $67 thousand on other property and equipment during 2007.

In 2006, we spent $9,737 thousand on capital expenditures. We participated with XTO Energy, Inc, the operator, in drilling of 16 gross wells in 2006, mainly to the Barnett shale formation in Parker County, Texas.

Financing Activities, The primary component of cash provided by financing activities is proceeds from long-term loans obtained from related parties ($45,658) and Senior Credit

Agreements ($54,000) and offset by repayments of long-term loans and repayments of Senior Credit Agreements ($16,800). Net cash flows provided by financing activities were $82,681 thousands, $64,957 thousands and $16,181 thousands for the years ended December 31, 2008, 2007 and 2006, respectively.

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Results of Continuing Operations

Selected Data

	Years Ended December 31,
	2008			2007			2006
	(In thousands except per share and MBOE amounts)
Financial Results
Oil and Gas sales	$	51,832		$	20,827			$	2,167
Equity in earnings of unconsolidated affiliates		-			1,201				2,570
Other		365			728				825
Total revenues and other		52,197			22,756				5,562

Cost and expenses		63,619			21,183				4,777
Other expense (income)		(15,028	)		13,176				(6,510	)
Income tax expense (benefit)		377			(5,192	)			726
Income (loss) from continuing operations		3,229			(6,411	)			6,569
Earnings per common share – basic and diluted	$	1.19		$	(2.36	)		$	2.42
Weighted average number of shares outstanding-basic and diluted		2,717,691			2,717,691				2,717,691
Operating Results
Adjusted EBITDAX (*)	$	53,277		$	5,303			$	8,389
Total proved reserves (MBOE)		8,213			8,329				257
Annual sales volumes (MBOE)		821			455.5				48

Average cost per MBOE:
Production (including transportation and taxes)	$	24.66		$	16.47			$	23.31
General and administrative	$	3.31		$	6.37			$	41.85
Depletion	$	21.59		$	13.48			$	9.48

(*)Adjusted EBITDAX (earnings before interest, taxes, depreciation and amortization) 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 continuing operations before income taxes, which is presented in accordance with GAAP.

Financial Results

Income from continuing operations our net income from continuing operations for 2008 totaled $3,229 thousand, or $1.19 per share, compared to net loss from continuing operations for 2007 of $(6,411) thousands, or $(2.36) per share. We had income from continuing operations for 2006 of $6,569, or $2.42 per share. The increase in income from continuing operations for 2008 compared to 2007 was primarily due to GFB acquisition which result in an increase of natural gas, oil and natural gas liquids sales, higher commodity prices and gain on derivative contracts, partially offset by higher cost and expenses including impairment of oil and gas properties, higher interest expenses and income tax. The decrease in the net income in 2007 compared to 2006 is primarily attributable to an increase in net loss on derivative contracts ,an impairment as results of the sale of the land in Israel, increase of impairment of oil and gas assets due to low production of gas wells drilled to the Barnett Shale, an increase in interest expenses and compensation for legal settlement recorded in 2006, all of which partially offset by increasing of oil and gas operating income due to Five States acquisition, realized gain on sale of investment in High –Tech company and income tax benefit.

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Revenues, Volumes and Average Prices

Sales Revenues

	Years Ended December 31,
In thousands except percentages	2008			2007			D vs. 2008			2006			D vs. 2007
Gas sales		$	20,747		$	10,030		107	%		$	1,371		632	%
Oil sales			25,049			6,874		264				796		764
Natural gas liquid sales			6,036			3,923		54
Total		$	51,832		$	20,827		149	%		$	2,167		861	%

Our sales revenues for 2008 increased by 149% when compared to 2007 due to the GFB acquisition which resulted in higher sales volumes of natural gas, oil and natural gas liquids and due to higher oil, natural gas and natural gas liquids prices. The increase in 2007 compared to 2006 was primarily due to Five States acquisition and was additionally due to higher commodity prices.

Volumes and Average Prices

	Years Ended December 31,
	2008		2007		D vs. 2008			2006		D vs. 2007
Natural Gas
Sales volumes Mmcf		2,507		1,551		62	%		213		628	%
Price per Mcf	$	8.28	$	6.47		28		$	6.44		0.5
Total gas sales revenues (thousands)	$	20,747	$	10,030		107	%	$	1,371		632

Crude Oil
Sales volumes MBbl		258		96.7		167	%		13		644	%
Price per Bbl	$	97.1	$	71.1		37		$	61.2		16
Total oil sales revenues (thousands)	$	25,049	$	6,874		264	%	$	796		764	%

Natural gas liquids
Sales volumes MBbl		145		101		44	%		-
Price per Bbl	$	41.6	$	39		7		$	-
Total natural gas liquids sales revenues (thousands)	$	6,036	$	3,923		54	%	$	-

The company’s natural gas sales volumes increased by 62%, crude oil sales volumes by 167% and natural gas liquids sales volumes by 44% in 2008 compared to 2007 primarily due to GFB acquisition. The company’s natural gas sales volumes increased by 628%, crude oil sales volumes by 644% in 2007 compared to 2006 primarily due to Five States acquisition.

Our average natural gas price for 2008 increased by 28% or $1.81 per Mcf when compared to 2007 and increased by 0.5% or $0.03 when compared 2007 to 2006. Our average crude oil price for 2008 increased by 37% or $26 per Bbl when compared to 2007 and increased by 16% or $9.9 when compared 2007 to 2006. Our average natural gas liquids price for 2008 increased by 7% or $2.6 per Bbl when compared to 2007.

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Analysis of Oil and Gas Operations Sales Revenues

The following table provides a summary of the effects of changes in volumes and prices on Isramco’s sales revenues for the year ended December 31, 2008 compared to 2007 and 2006.

In thousands	Natural Gas		Oil		Natural gas liquids
2006 sales revenues	$	1,371	$	796	$	-
Changes associated with sales volumes		8,611		5,125		3,923
Changes in prices		48		953		-
2007 sales revenues		10,030		6,874		3,923
Changes associated with sales volumes		6,184		11,467		1,737
Changes in prices		4,533		6,708		376
2008 sales revenues	$	20,747	$	25,049	$	6,036

Operating Expenses

	Years Ended December 31,
In thousands except percentages	2008		2007		D vs. 2008			2006		D vs. 2007
Lease operating expense, transportation and taxes	$	20,242	$	7,500		170	%	$	1,119		570	%
Depreciation, depletion and amortization		17,723		6,139		189			455		1,249
Impairments of oil and gas assets		22,093		3,203		590			668		379
Impairments of other properties		-		928		-			-		-
Accretion expense		847		219		287			71		208
Exploration costs		-		292		-			125		134
Operator expense		-		-		-			330		-
General and administrative		2,714		2,902		(6	)		2,009		44
	$	63,619	$	21,183		200	%	$	4,777		343	%

During 2008, our operating expenses increased by 200% when compared to 2007 due to the following factors:

Lease operating expense, transportation and taxes increased by 170%, or $12,742 thousand, in 2008 when compared to 2007 due to approximately $10,800 thousand in additional operating expenses, transportation and taxes attributable to the properties acquired in the GFB acquisition. The remaining increase is attributable to higher commodity prices that affected the taxes paid during 2008 and to the fact that, in 2007, we recorded only 10 months of operating expense, transportation and taxes associated with the properties acquired in Five States acquisition, compared to 12 months during 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 year to year. DD&A increased by 189%, or $11,584 thousand, in 2008 when compared to 2007 primarily due to approximately $8,520 thousand DD&A which was related to the oil and gas properties acquired in GFB acquisition. The remaining increase is attributed to lower commodity prices at year-end 2008 that impacted the estimated total reserves, which are the basis for the depletion calculation.

Impairments of oil and gas assets of $22,093 thousand in 2008 were primarily a result of lower commodity prices in general and low volume of oil and gas produced in few of our North Texas fields and in the wells in which the Company participated in the Barnett Shale formation in Parker County, Texas, in particular. The impairments of $3,203 thousand in 2007 were primarily the result of the low volume of gas produced in the wells that the Company participated on the Barnett Shale formation in Parker County.

·	Impairment of other properties in 2007 of $928 thousand was attributed to undeveloped real estate located in Israel.

·	In 2007, we incurred $292 thousand in exploration costs mainly incurred for a 3D seismic survey covering the company’s leases in Wise County.

General and administrative expenses decreased by 6%, or $188 thousand, in 2008 when compared to 2007 primarily due to the closure of the Israeli branch on December 31, 2007. This decrease was partially offset by increases in compensation and benefit expenses associated with additional employees required in connection with the GFB acquisition. The GFB acquisition also increased the volume of the activities and, as a result, the indirect expenses of those activities.

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During 2007, our operating expenses increased by 343% when compared to 2006 due to the following factors:

Lease operating expense, transportation and taxes increased by 570%, or $6,381 thousand, in 2007 when compared to 2006 due to approximately $5,745 thousand in additional operating expenses, transportation and taxes attributable to the properties acquired in the Five States acquisition. The remaining increase is attributed to higher commodity prices that affected the taxes paid during 2007.

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 one or more of these factors may cause our composite DD&A rate and expense to fluctuate from year to year. DD&A increased by 1,249%, or $5,684 thousand, in 2007 when compared to 2006 primarily due to approximately $4,558 thousand DD&A which was related to the oil and gas properties acquired in Five States acquisition. The remaining increase is attributed to low volume of gas produced in wells in which the Company participated in the Barnett Shale formation in Parker County, which affected the estimated total reserves, which in turn are the basis for the depletion calculation.

·	The impairments of $3,203 thousand in 2007 were primarily the result of the low volume of gas produced in the wells that the Company participated on the Barnett Shale formation in Parker County.

·	Impairment of other properties in 2007 of $928 thousands was attributed to undeveloped real estate located in Israel.

·	In 2007, we incurred $292 thousand in exploration costs mainly incurred for a 3D seismic survey covering the company’s leases in Wise County, compared to $125 thousand in 2006, mainly incurred for geological and geophysical consulting relating to the operation in United States.

General and administrative expenses increased by 44%, or $893 thousand, in 2007 when compared to 2006 primarily due to increases in compensation and benefit expenses associated with additional employees required in connection with the Five States acquisition. This acquisition also increased the volume of the activities and, as a result, the indirect expenses of those activities.

Other expenses (income)

	Years Ended December 31,
In thousands except percentages	2008			2007			D vs. 2008			2006			D vs. 2007
Interest expense (income), net	$	9,855		$	6,344			55	%	$	(154	)		(4,219	)%
Unrealized loss (gain) on marketable securities		-			(52	)		-			(1,177	)		(96	)
Realized gain on sale of investment and other		(145	)		(1,754	)		(92	)		(39	)		4,397
Net loss (gain) on derivative contracts		(24,738	)		8,638			(386	)		(2,604	)		(432	)
Compensation for legal settlement		-			-						(2,536	)		-
	$	(15,028	)	$	13,176			(214	)	$	(6,510	)		(302	)

Interest expense. Isramco’s interest expense for 2008 increased by 55%, or $3,511 thousand, compared to 2007. This increase is primarily attributable to interest on loans we obtained from banks and related parties for funding the GFB acquisition. The increase was partially offset by the lower average outstanding balance of loans which we obtained to fund the Five States acquisition in 2007 and decreases in average LIBOR rates in 2008. Isramco’s interest expense for 2007 increased by $6,498 thousand compared to 2006. This increase was primarily due to the loans we obtained from banks and related parties for funding the Five States acquisition. For additional information, see Debt above.

Realized gain on sale of investment and other. In April 2007, IsramTech, a wholly owned subsidiary of the Company, sold part of its equity interests in High –Tech Company for aggregate consideration of $1,700 thousand (net of commission). As a result of this transaction, the Company recorded a one-time non-recurring net gain of $1,621 thousand.

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, 2008, we had a $23 million derivative asset, of which $12 million was classified as current. We recorded a net derivative gain of $24.7 million ($32.6 million unrealized gain partially offset by a $7.9 million loss from net cash payments on settled contracts) for the year ended December 31, 2008 compared to a net derivative loss of $8.6 million ($11.3 million unrealized loss and a $2.7 million net gain for cash received on settled contracts) for the year ended December 31, 2007. This increase in our net derivative gain is primarily attributable to the recent decrease in the forward strip pricing used to value our derivatives and additional SWAP contracts we entered in 2008.

At December 31, 2007, we had a $9.4 million derivative liability, of which $3.1 million was classified as current. We recorded a net derivative loss of $8.6 million ($11.3 million unrealized loss and a $2.7 million net gain for cash received on settled contracts) for the year ended December 31, 2007 compared to a derivative gain of $2.6 for the year ended December 31, 2006. This decrease is due to the increase in commodity prices and additional SWAP contracts we entered in 2007.

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Income Tax

The Company’s tax expense changed from a benefit of $5,192 thousand in 2007 to an expense of $377 thousand in 2008. The overall increase is the result of increased profitability from continuing operations due to the Company’s acquisition of oil and gas properties in 2007 and 2008. The variance in the tax rate from the statutory 34%, used in the US, is due mainly to the refund of 2007 taxes paid by the US branch in Israel, deferred state tax items (net of federal benefit) and other return to accrual items on the US consolidated income tax return.

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 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 (T). CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES.

Disclosure controls and procedures are controls and other procedures of a registrant designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Exchange Act is properly recorded, processed, summarized, and reported, within the time periods specified in the Securities and Exchange Commission's ("SEC") rules and forms. Disclosure controls and procedures include processes to accumulate and evaluate relevant information and communicate such information to a registrant's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosures.

We evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2007, as required by Rule 13a-15 of the Exchange Act. As described below, under "Management's Report on Internal Control Over Financial Reporting," material weaknesses were identified in our internal control over financial reporting as of December 31, 2007. The material weaknesses identified in the annual report on Form 10-K for the year ended December 31, 2007 began with the acquisition of the Five States properties in March 2007, and related primarily to the shortage of support and resources in our accounting department. Based on the evaluation described above, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2007, our disclosure controls and procedures were not effective to ensure (i) that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the SEC's rules and forms, and (ii) information required to be disclosed by us in our reports that we file or submit 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.

We again evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2008, as required by Rule 13a-15 of the Exchange Act. As described below, under "Management's Report on Internal Control Over Financial Reporting," continuing material weaknesses were identified in our internal control over financial reporting as of December 31, 2008. As noted above, the material weaknesses identified in this reporting began with the acquisition of the Five States properties in March 2007. These weaknesses have not been fully addressed, largely due to the inability of the Company to attract and retain experienced, skilled personnel, and were exacerbated by the acquisition of additional properties from GFB and TransRepublic in March 2008. As in 2007, the material weakness primarily related to the shortage of support and resources in our accounting department. Based on the evaluation described above, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2008, our disclosure controls and procedures were still not effective to ensure (i) that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the SEC's rules and forms, and (ii) information required to be disclosed by us in our reports that we file or submit 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.

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING; CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with generally accepted accounting principles.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

A “material weakness” in internal control over financial reporting (as defined in Auditing Standard No. 2 of the Public Company Accounting Oversight Board) is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. A “significant deficiency” is a control deficiency, or combination of control deficiencies, that adversely affects a company's ability to initiate, authorize, record, process, or report external financial data reliably in accordance with generally accepted accounting principles, such that there is more than a remote likelihood that a misstatement of the company's annual or interim financial statements that is more than inconsequential will not be prevented or detected.

Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2008, the end of the fiscal period covered by this report and determined that the internal controls in place as of the assessment were not sufficient. Specifically, management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in Internal Control--Integrated Framework. In assessing the effectiveness of our internal control over financial reporting, management identified the following material weaknesses in internal control over financial reporting as of December 31, 2008:

Material weaknesses in the Company's Control Environment. Our control environment did not sufficiently promote effective internal control over financial reporting throughout the organization. Specifically, we had a shortage of support and resources in our accounting department, which resulted in inadequate: (i) documentation and communication of our accounting policies and procedures; and (ii) internal audit processes of our accounting policies and procedures.

As a result of the material weaknesses described above, our management concluded that we did not maintain effective internal control over financial reporting as of December 31, 2008, based on the criteria established by COSO.

Management believes that our rapid growth since the acquisition in March 2007 of approximately 650 producing oil and gas wells is primarily responsible for the circumstances in which the material weaknesses described above resulted. The March 2007 transaction, whereby our activities and revenues grew by a factor of almost 1,000%, required that we fundamentally re-organize the Company and its operations. In addition, in February 2008, we concluded the GFB Acquisition, which added approximately 590 producing properties to our company. In March 2008 and October 2008, we took over operations on a substantial number of these properties. In this connection, while we sold our Israeli based businesses to concentrate exclusively on our oil and gas exploration activities in the United States and to focus our resources on overseeing our expansion, the need for competent and experienced accounting personnel was both greater than we anticipated and much more difficult to satisfy than we expected. Adding to our difficulty was the “boom” in the oil and gas industry that began in roughly late 2007 and concluded in the fall of 2008. This “boom” created an extremely competitive market for experienced oil and gas personnel, which made the location and employment of competent individuals very expensive, time consuming and difficult. This market remains tight, and very competitive.

In this regard, the accounting system utilized by Five States, the seller of the properties we acquired in March, 2007, differed from the system used by GFB and TransRepublic, the sellers of the properties we acquired in February, 2008, and both systems differed from the system we utilized prior to these acquisitions. Despite the expenditure of significant time and expense, integration of the three accounting systems has been more difficult, and time consuming, than anticipated.

Our efforts in this regard have been further complicated by the difficulty in integrating three different operational systems into one. Each of the sellers had its own method of operating which encompassed issues such as payroll, field operations, and even the identification of the wells. It has been more difficult than we anticipated to reconcile these differences.

Finally, the efforts and resources that we invested in completing the above-described transactions themselves adversely affected the time and other resources that we were able in investing in our internal control compliance efforts.

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Remediation Initiatives

We have retained Deloitte & Touche, a registered accounting firm, to assist in our internal control compliance efforts, including establishing new internal audit procedures appropriate for a rapidly growing business and selection of appropriate accounting controls software. During 2009, we plan to implement a number of remediation measures to address the material weaknesses described above. Our remediation plans include:

1. We plan to hire additional personnel to assist us with documenting and communicating our accounting policies and procedures to ensure the proper and consistent application of those policies and procedures throughout the Company. In 2008, in recognition of the weaknesses identified in the 2007 financial statements, we hired a controller and two accountants. We are planning to hire more accountants and other professional staff. The selection process for a replacement has begun and is expected to be completed during the second or third quarter of 2009.

2. We plan to implement formal processes requiring periodic self-assessments, independent tests, and reporting of our personnel's adherence to our accounting policies and procedures.

3. We plan to (i) continue to require additional training for our current accounting personnel; (ii) to hire additional accounting personnel to enable the allocation of job functions among a larger group of accounting staff; and (iii) to consider restructuring our accounting department, each to increase the likelihood that our accounting personnel will have the resources, experience, skills, and knowledge necessary to effectively perform the accounting system functions assigned to them.

4. We plan to implement a new accounting system with automatic control checkpoints for day-to-day business processes. In this regard, we have acquired the new accounting software and have begun the process of transferring data from our existing system to the new system. We have also had key members of our staff trained in the new system. We anticipate that the data transfer will be completed by June 30, 2009. At this point, we plan to run our existing and new systems concurrently to ensure that the new system performs satisfactorily. We plan to be utilizing the new system by September 30, 2009.

To date we have spent in excess of $150 thousand in our efforts to create a fully integrated accounting and compliance system, and we anticipate that an expenditure of approximately $150 thousand will be required in 2009 to complete this task. In this regard, management recognizes that many of these enhancements require continual monitoring and evaluation for effectiveness. The development of these actions is an iterative process and will evolve as the Company continues to evaluate and improve our internal controls over financial reporting.

Management has been involved in these activities and will continue to review progress on these activities on a consistent and ongoing basis at the Chief Executive Officer and Chief Financial Officer level, in conjunction with our Audit Committee. We also plan to take additional steps to elevate Company awareness about and communication of these important issues through formal channels such as Company meetings, departmental meetings, and training.

Changes in Internal Controls Over Financial Reporting

As described above, there have been material changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. The Management and the Audit Committee of the Company's Board of Directors have developed the remedial measures to address the internal control deficiencies identified above and will continue to take action as required to remedy these deficiencies. The Company will monitor the effectiveness of planned actions and will make any other changes and take such other actions as management or the Audit Committee determines to be appropriate.

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the SEC that permit the company to provide only management’ report in this annual report.

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, 2008 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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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Exhibits

3.1 Articles 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.

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.

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.

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.

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., 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., 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.

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.

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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.

10.13* Amended and Restated Agreement dated as of November 17, 2008 between Isramco Inc. and Goodrich Global Ltd. +

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

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

___________________________

* 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 20, 2009

/S/ EDY FRANCIS

EDY FRANCIS,

CHIEF FINANCIAL OFFICER

(PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)

Date: March 20, 2009

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/ Jackob Maimon	President, Director	March 20, 2009
Jackob Maimon

/s/ Max Pridgeon	Director	March 20, 2009
Max Pridgeon

/s/ Michelle R. Cinnamon Flores	Director	March 20, 2009
Michelle R. Cinnamon Flores

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INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets at December 31, 2008 and 2007	F-2
Consolidated Statements of Operations for the years ended December 31,2008, 2007 and 2006	F-3
Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 2008, 2007 and 2006	F-4
Consolidated Statements of Cash Flows for the years ended December 31,2008, 2007 and 2006	F-5
Notes to Consolidated Financial Statements

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Isramco, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Isramco, Inc. (“Isramco”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, changes in shareholders' equity, and cash flows for each of the three years ended December 31, 2008. These consolidated financial statements are the responsibility of Isramco's management. Our responsibility is to express an opinion on these consolidated financial statements 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 consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Isramco, Inc., as of December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

/s/ MALONE & BAILEY, PC

www.malone-bailey.com

Houston, Texas

March 20, 2009

F-1

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ISRAMCO INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

As of December 31	2008			2007
ASSETS
Current Assets:
Cash and cash equivalents	$	3,141		$	1,212
Accounts receivable, net		5,416			6,595
Restricted and designated cash		757			1,501
Deferred tax assets		-			1,047
Derivative asset		12,082			-
Prepaid expenses and other		592			748
Total Current Assets		21,988			11,103

Property and Equipment, at cost – successful efforts method:
Oil and Gas properties		219,945			108,940
Other		450			81
Total Property and Equipment		220,395			109,021
Accumulated depreciation, depletion and amortization		(56,196	)		(16,338	)
Net Property and Equipment		164,199			92,683

Marketable securities, at market		1,799			6,809
Debt cost		572			-
Derivative asset		10,942			-
Deferred tax assets and other		3,871			113
Total assets	$	203,371		$	110,708

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	7,712		$	4,259
Short term debt and bank overdraft		1,544			706
Current maturities of long-term debt		21,000			3,000
Derivative liability		943			3,081
Accrued interest and due to related party		5,606			3,433
Deferred tax liabilities		2,245			-
Current income taxes and other		-			227
Total current liabilities		39,050			14,706

Long-term debt		43,200			24,000
Long-term debt - related party		80,354			36,581

Other Long-term Liabilities:
Asset retirement obligations		15,733			2,670
Derivative liability – non-current		-			6,325
Deferred tax liabilities		-			955
Total other long-term liabilities		15,733			9,950

Commitments and contingencies (Note 14)

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)		2,217			(1,012	)
Accumulated other comprehensive income		(240	)		3,426
Treasury stock, 29,267 shares at cost		(164	)		(164	)
Total shareholders’ equity		25,034			25,471

Total liabilities and shareholders’ equity

203,371

110,708

See notes to the consolidated financial statements.

F-2

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ISRAMCO INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share amounts)

Year Ended December 31	2008			2007			2006

Revenues
Oil and gas sales	$	51,832		$	20,827		$	2,167
Operator fees from related party		-			18			69
Office services to affiliate and other
To related parties		-			480			480
To others		191			230			276
Other		174			-			-
Equity in earnings of unconsolidated affiliates		-			1,201			2,570
Total revenues		52,197			22,756			5,562

Operating expenses
Lease operating expense, transportation and taxes		20,242			7,500			1,119
Depreciation, depletion and amortization		17,723			6,139			455
Impairments of oil and gas assets		22,093			3,203			668
Impairments of other properties		-			928			-
Accretion expense		847			219			71
Exploration costs		-			292			125
Operator expense		-			-			330
General and administrative
To related parties		-			226			227
To others		2,714			2,676			1,782
Total operating expenses		63,619			21,183			4,777
Operating income (loss)		(11,422	)		1,573			785

Other expenses (income)
Interest expense (income), net		9,855			6,344			(154	)
Unrealized loss (gain) on marketable securities		-			(52	)		(1,177	)
Realized gain on sale of investment and other		(145	)		(1,754	)		(39	)
Net loss (gain) on derivative contracts		(24,738	)		8,638			(2,604	)
Compensation for legal settlement		-			-			(2,536	)
Total other expenses (income)		(15,028	)		13,176			(6,510	)

Income (loss) from continuing operations before income taxes		3,606			(11,603	)		7,295
Income tax benefit (expense)		(377	)		5,192			(726	)

Income (loss) from continuing operations		3,229			(6,411	)		6,569
Loss from discontinued operation		-			-			(3,111	)
Gain from disposal of discontinued operation		-			-			384
Net income (loss)	$	3,229		$	(6,411	)	$	3,842

Earnings (loss) per share – basic and diluted:
Continuing operations	$	1.19		$	(2.36	)	$	2.42
Discontinued operations		-			-			(1.01	)
Total	$	1.19		$	(2.36	)	$	1.41

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-3

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ISRAMCO INC.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

	Common stock
	Number of shares	Amount		Additional Paid-In Capital			Accumulated other comprehensive income (loss)			Retained Earnings			Treasury stock			Total Shareholders’Equity
				$ in thousands, except share amounts
Balances at January 1, 2006	2,717,691	$	27	$	26,240		$	833		$	1,557		$	(164	)	$	28,493

Net income											3,842						3,842

Net unrealized gain on available for sale marketable securities, net of taxes of $417	-		-		-			810			-			-			810
Net gain (loss) on foreign exchange rate, net of taxes of $824								1,599									1,599
Total comprehensive income																	6,251

Balances at December 31, 2006	2,717,691		27		26,240			3,242			5,399			(164	)		34,744

Net loss											(6,411	)					(6,411	)
Other equity adjustments					(3,046	)											(3,046	)
Net unrealized gain on available for sale marketable securities, net of taxes of $450								874									874
Net gain (loss) on foreign exchange rate, net of taxes $355								(690	)								(690	)
Total comprehensive loss																	(6,227	)

Balance of December 31, 2007	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

See notes to consolidated financial statements.

F-4

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ISRAMCO INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

Year Ended December 31	2008			2007			2006

Cash Flows From Operating Activities:
Net income (loss)	$	3,229		$	(6,411	)	$	3,842
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations		-			-			2,727
Income (loss) from continuing operations		3,229			(6,411	)		6,569

Depreciation, depletion, amortization and impairment		39,816			10,270			1,123
Accretion expense		847			219			71
Unrealized and realized gain on marketable securities		(76	)		(344	)		(1,177	)
Equity in earnings of unconsolidated affiliates		-			(741	)		(1,316	)
Changes in deferred taxes		468			(5,488	)		271
Net unrealized loss (gain) on derivative contracts		(32,657	)		11,352			(1,718	)
Amortization of debt cost		189			-			-
Realized gain on sale of investment and capital gain		(68	)		(1,664	)		-
Changes in components of working capital and other assets and liabilities
Accounts receivable		1,179			(6,192	)		202
Prepaid expenses and other current assets		408			92			(1,103	)
Related party		288			-			-
Accounts payable and accrued liabilities		3,378			(1,755	)		3,271
Net cash provided by (used in) operating activities
Continuing operating		17,001			(662	)		6,193
Discontinuing operating		-			-			1,040
Net cash provided by (used in) operating activities		17,001			(662	)		7,233

Cash flows from investing activities:
Investment in affiliate		-			-			(1,197	)
Addition to property and equipment, net		(99,042	)		(86,123	)		(9,737	)
Proceeds from sale of gas properties and equipment		68			36			-
Proceeds from restricted deposit, net		745			15,498			(17,000	)
Proceeds from sale of subsidiary - Magic		-			2,150			-
Proceeds from sale of other investment		-			2,270			-
Purchase of marketable securities		-			(740	)		(2,056	)
Proceeds from sale of marketable securities		476			3,253			5,957
Continuing operating		(97,753	)		(63,656	)		(24,033	)
Discontinuing operating		-			-			(8	)
Net cash used in investing activities		(97,753	)		(63,656	)		(24,041	)

Cash flows from financing activities:
Proceeds from loans – related parties, net		45,658			36,716			17,164
Proceeds from long-term debt		54,000			35,300			-
Repayment of long-term debt		(16,800	)		(8,300	)		-
Payments for financing cost		(1,015	)		-			-
Borrowings (repayments) of short - term debt, net		838			1,241			(22	)
Continuing operating		82,681			64,957			17,142
Discontinuing operating		-			-			(961	)
Net cash provided by financing activities		82,681			64,957			16,181

Net increase (decrease) in cash and cash equivalents		1,929			639			(627	)
Cash and cash equivalents at beginning of year		1,212			573			1,200
Cash and cash equivalents at end of year	$	3,141		$	1,212		$	573

See notes to the consolidated financial statements.

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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 subsidiaries (“Isramco” or the “Company”) are primarily engaged in the acquisition, development, production and exploration of oil and natural gas properties located, mainly in onshore United States of America (“United States”). The Company operates in one segment, oil and natural gas exploration and exploitation. The consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. Investments in unconsolidated affiliates, in which Isramco is able to exercise significant influence, are accounted for using the equity method. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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. These estimates include oil and natural gas reserve quantities that form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. 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 collectibility 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, 2008 or 2007.

Oil and Gas Operations.

Isramco accounts for its natural gas and crude oil exploration and production activities under the successful efforts method of accounting.

Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed on a lease-by-lease basis, and any impairment in value is recognized. Lease rentals are expensed as incurred.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is complete if it is determined that there is economic producibility supported by either actual production, a conclusive formation test. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. A significant portion of the property costs reflected in the accompanying consolidated balance sheets are from acquisitions of proved properties from other oil and gas company (see Note 2). Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and crude oil, are capitalized.

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.

Assets are grouped in accordance with paragraph 30 of Statement of Financial Accounting Standards (SFAS) No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

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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.

Isramco accounts for impairments under the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." When circumstances indicate that an asset may be impaired, Isramco compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on Company and third party 's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

In 2008, 2007 and 2006, we reported impairment charge of $22,093 thousand, $3,203 thousand and $668 thousand, 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. On December 31, 2007, we sold undeveloped real estate located in Israel to related party (for further information see Note 5 “closure of the Israeli branch office”).

In 2007, we reported an impairment charge of $928 thousand to undeveloped real estate located in Israel.

In 2006, we reported an impairment charge of $2,200 thousand to the vessel included in discontinued operation.

Marketable Securities

Statement of Financial Accounting Standard No. 115 (SFAS No. 115),”Accounting for Certain Investments in Debt and Equity Securities”, requires Isramco to classify its debt and equity securities in one of three categories: trading, available-for-sale and held-to-maturity. Trading securities are bought and held principally for the purposes of selling them in the near term. Held-to-maturity securities are those securities in which Isramco has both the ability and intent to hold the security until maturity. All other securities not included in trading or held-to-maturity are classified as available-for-sale.

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

In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS 143). SFAS 143 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. Upon adoption, the Company recorded an asset retirement obligation to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells. The Company estimated the expected cash flow associated with the obligation and discounted the amount 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 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.

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 be adversely affected.

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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 that method, any revenues received in excess of the Company's share is treated as a liability. If revenues received are less than Company's share, the deficiency is recorded as an asset. The Company's imbalance position was not significant in terms of volumes or values at December 31, 2008 and 2007.

Price Risk Management Activities

The Company follows SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), as amended. 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 consolidated statements of operations.

In 2008, 2007 and 2006, we recorded gain (loss) of $24.7 million, $(8.6) million and $2.6 million, respectively, related to our derivative instruments. Fair values are derided 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 8, “Long-term Debt”) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. We have elected to designate thesepositions 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.

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.

In July 2006, the Financial Accounting Standards Board (FASB) issued Financial Interpretation (FIN) 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB 109 (FIN 48). FIN 48 created 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 Company adopted the provisions of FIN 48 effective January 1, 2007 which did not have a material impact on the Company’s operating results, financial position or cash flows. The Company did not record a cumulative effect adjustment related to the adoption of FIN 48.

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 SFAS No. 52, 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 stockholders’ equity. Foreign currency transaction gains and losses are included in current income. The functional currency of our Israeli subsidiaries is the New Israeli Shekel.

Earnings per Share

Isramco follows SFAS No. 128, Earnings per Share, for computing and presenting earnings per share, which requires, among other things, dual presentation of basic and diluted loss per share on the face of the consolidated statement of operations. Basic EPS is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted into common shares or resulted in the issuance of common shares that then shared in the earnings of the entity. For the year ended December 31, 2008, Isramco's stock options were anti-dilutive.

Environmental

Isramco is subject to extensive federal, state, local and foreign environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require Isramco to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Liabilities for expenditures of no capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. No significant amounts for environmental liabilities were recorded at December 31, 2008 and 2007.

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Stock-Based Compensation

In January 2006, the Company adopted SFAS No. 123(R), Share-Based Payment (SFAS 123(R)). SFAS 123(R) revises SFAS No. 123, Accounting for Stock-Based Compensation (SFAS 123), and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. The Company used the modified prospective application method as detailed in SFAS 123(R).

Prior to adopting SFAS 123(R), the Company adopted SFAS No. 123, Accounting for Stock-Based Compensation (SFAS 123) prospectively, using the fair value recognition method to all employee and director awards granted, modified or settled after January 1, 2003. Prior to the adoption, the Company elected to follow Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and related interpretations in accounting for its employee stock options. There

Recently Issued Accounting Standards and Developments

On December 31, 2008, the Securities and Exchange Commission (SEC) issued the final rule, “Modernization of Oil and Gas Reporting” (“Final Rule”). The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and technological advances. Revised requirements in the Final Rule include, but are not limited to:

·	Oil and gas reserves must be reported using a 12-month average of the closing prices on the first day of each of such months, rather than a single day year-end price:

·	Companies will be allowed to report, on a voluntary basis, probable and possible reserves, previously prohibited by SEC rules; and

·	Easing the standard for the inclusion of proved undeveloped reserves (PUDs) and requiring disclosure of information indicating any progress toward the development of PUDs.

We are currently evaluating the potential impact of adopting the Final Rule. The SEC is discussing the Final Rule with the FASB and IASB staffs to align accounting standards with the Final Rule. These discussions may delay the required compliance date. Absent any change in such date, we will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009. Voluntary early compliance is not permitted.

In March 2008, the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging Activities. SFAS 161 is effective beginning January 1, 2009 and required entities to provide expanded disclosures about derivative instruments and hedging activities including (1) the ways in which an entity uses derivatives, (2) the accounting for derivatives and hedging activities, and (3) the impact that derivatives have (or could have) on an entity’s financial position, financial performance, and cash flows. SFAS 161 requires expanded disclosures and does not change the accounting for derivatives. Isramco is currently evaluating the impact of SFAS 161, but we do not expect the adoption of this standard to have a material impact on our financial results.

In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115 (SFAS 159), which permits entities to choose to measure many financial instruments and certain other items at fair value (Fair Value Option). Election of the Fair Value Option is made on an instrument-by-instrument basis and is irrevocable. At the adoption date, unrealized gains and losses on financial assets and liabilities for which the Fair Value Option has been elected would be reported as a cumulative adjustment to beginning retained earnings. Following the election of the Fair Value Option for certain financial assets and liabilities, the Company would report unrealized gains and losses due to changes in fair value in earnings at each subsequent reporting date. The Company adopted SFAS 159 effective January 1, 2008 which did not have a material impact on the Company’s operating results, financial position or cash flows as the Company did not elect the Fair Value Option for any of its financial assets or liabilities.

In September 2006, the FASB issued SFAS 157, Fair Value Measurements (SFAS 157), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This pronouncement applies to other standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurements. The Company adopted the provisions of SFAS 157 on January 1, 2008. See “Fair Value Measurements” below for more details.

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Fair Value Measurements

In September 2006, the FASB issued SFAS 157 which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The provisions of SFAS 157 are effective January 1, 2008. The FASB has also issued Staff Position (FSP) SFAS 157-2 (FSP No. 157-2), which delays the effective date of SFAS 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. Effective January 1, 2008, the Company adopted SFAS 157 as discussed above and has elected to defer the application thereof to nonfinancial assets and liabilities in accordance with FSP No. 157-2. Non-recurring nonfinancial assets and nonfinancial liabilities for which the Company has not applied the provisions of SFAS 157 include those measured at fair value in goodwill impairment testing, asset retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination.

In October 2008, the FASB issued FSP SFAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active (FSP No. 157-3), which clarifies the application of SFAS No. 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active. The guidance provided by FSP No. 157-3 did not have a material impact on the Company’s consolidated operating results, financial position or cash flows.

The Company utilizes derivative contracts to economically hedge against the variability in cash flows associated with the forecasted sale of its anticipated future oil and natural gas production. The Company generally economically hedges a substantial, but varying, portion of anticipated oil and natural gas production for the next 24-39 months. Derivatives are carried at fair value on the consolidated balance sheets, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs.

Periodically, the Company utilizes marketable securities to invest a portion of its cash on hand. These securities are carried at fair value on the consolidated balance sheets; with the changes in the fair value net of tax included in the accumulated other comprehensive income for the period in which the change occurs.

As defined in SFAS 157, fair value is 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. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category generally include non-exchange-traded derivatives such as commodity swaps, interest rate swaps, options and collars.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table sets 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, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety 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.

	December 31, 2008
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Marketable securities	$	1,799	$	—	$	—	$	1,799
Commodity derivatives		—		23,024		—		23,024

	$	1,799	$	23,024	$	—	$	24,823

Liabilities
Interest rate derivatives	$	—	$	943	$	—	$	943

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Derivatives listed above include swaps that are carried at fair value. The fair value amounts in current period earnings associated with the Company’s derivatives resulted from Level 2 fair value methodologies; that is, the Company is able to value the assets and liabilities based on observable market data for similar instruments. 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, 2008, the Company’s derivative contracts were placed at 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, the Company does not anticipate such nonperformance.

Marketable securities listed above are carried at fair value. The fair value amounts on the Company’s balances associated with the Company’s marketable securities resulted from Level 1 fair value methodologies; that is, the Company is able to value the assets based on quoted fair values for identical instruments.

2. Acquisitions

GFB Acquisition

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

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 agreement). Although the acquisition was closed on March 2, 2007, the effective dated of the purchase was determined to be 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 will result 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 are 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. Additionally, pursuant to an agreement between Sigma Energy Corporation ("Sigma"), an unrelated party that originated the transaction with Five States, Isramco and Isramco Energy, Isramco Energy paid to Sigma on March 2, 2007, the amount of $300 thousand and after Payout (as defined in the Agreement with Sigma), IEN undertook to assign to Sigma a direct ownership interests equal to 3.75% of the interests acquired by Isramco Energy under the Purchase Agreement

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	2007
	(In thousands)
Oil and gas properties (after adjustments)	$	88,304
Asset retirement obligation		(2,020	)

Net asset acquired	$	86,284

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The following unaudited pro forma information assumes that GFB and Trans Republic acquisition and the Five States acquisition occurred as of January 1, 2007.

The pro forma results are not necessarily indicative of what actually would have occurred had the acquisition been in effect for the period presented.

Year Ended December 31, 2008	As Reported		Pro Forma
Revenues	$	52,197	$	59,682

Net income	$	3,229	$	4,419

Income (loss) per share - basic and diluted
Total	$	1.19	$	1.63

Year Ended December 31, 2007	As Reported			Pro Forma
Revenues	$	22,756		$	38,918

Net loss	$	(6,411	)	$	(1,822	)

Income (loss) per share - basic and diluted
Total	$	(2.36	)	$	(0.67	)

3. Transactions with Affiliates and Related Parties

There is no operation in Israel in 2008.

Until December 31, 2007, we acted as operator for joint venture with related parties in Israel engaged in the exploration of oil and gas for which it receives operating fees equal to the greater of 6% of the actual direct costs or minimum monthly fees of $6,000.

Operator fees earned and related operator expenses are as follows (in thousands):

Year ended December 31	2007		2006
Operator fees:
Gad 1	$	-	$	-
Med Ashdod Lease		18		69

Operator income	$	18	$	69

Operator expenses	$	-	$	330

In December 2003, we entered into a consulting agreement with Doron Avraham, at that time the Vice President of the Isramco. Pursuant to this agreement, we agreed to pay the consultant the sum of $15 thousand per month plus expenses in consideration for the services that he provides to Isramco. The consulting agreement expired in November 2007.

We paid I.O.C. - Israel Oil Company, Ltd. (“I.O.C”) $226 thousand and $235 thousand for the years ended December 31, 2007 and 2006, respectively, for rent and office, secretarial and computer services. I.O.C is fully owned by Naphtha Israel Petroleum Corp. Naphtha is the sole shareholder of Naphtha Holdings, Ltd., which is the record holder of 48.4% of our outstanding common stock and which may be deemed to be controlled by Haim Tsuff, the Chairman of the Board of Directors and Chief Executive Officer of Isramco.

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Isramco Oil and Gas Ltd. (“IOG”), a wholly-owned subsidiary of Isramco (on December 31, 2007 we sold IOG to related party, for further information see Note 5 “closure of the Israeli branch office”) was the general partner of Isramco-Negev 2 Limited Partnership, from which we received management fees and expense reimbursements of approximately $480 thousand for each of the years ended December 31, 2007 and 2006.

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 $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 scheduled to end on December 31, 2008, an amount in cash equal to five percent (5%) of the Company’s pre-tax recorded profit (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 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 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. In the year ended December 31, 2008 we paid Goodrich the total amount of $310 thousand.

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 director of Isramco. Pursuant to this consulting agreement, we pay the consultant $240 thousand per annum in installments of $20 thousand per month plus expenses in consideration of the services that he provides to the Company. The agreement expired in May 2008.

4. Investments in Affiliate

Isramco Oil and Gas Ltd. (“IOG”), a wholly-owned subsidiary of Isramco, was the general partner of the Isramco Negev 2 Limited Partnership (the “Limited Partnership”). The daily management of the Limited Partnership is under the control of the general partner; however, matters involving the rights of the Limited Partnership unit holders are subject to supervision of a supervisor, appointed to supervise the Limited Partnership activities, and in some instances the approval of the Limited Partnership unit holders. Through IOG, we own a 0.05% interest in the Limited Partnership, which is accounted for by the equity method of accounting.

On December 31, 2007, Isramco sold IOG, including the participation unit in Isramco Negev 2 LP, to related party (for further information see Note 5 “closure of the Israeli branch office”). As of December 31, 2006, Isramco owned 345,309,522 units or 8.17% of the issued Limited Partnership units of the Limited Partnership, Isramco Negev 2. Summarized financial information of Isramco Negev 2 Limited Partnership is as follows (amounts in thousands):

Statement of Operations

Year Ended December 31,	2007		2006
Income	$	3778	$	14,819
Expenses		1,094		1,001

Net income	$	2684	$	13,818

On December 31, 2007, Isramco sold the participation unit in IOC Dead Sea 2 LP to related party (for further information see Note 5 “closure of the Israeli branch office”). As of December 31, 2006, Isramco owned 7,877,248 of units (24.97%% of the issued Partnership units) of the I.N.O.C Dead Sea Limited Partnership. Summarized financial information of I.N.O.C. Dead Sea Limited Partnership is as follows (amounts in thousands):

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Statement of Operations

Year Ended December 31,	2007		2006
Income	$	4,222	$	3,091
Expenses	$	293		(280	)

Net income	$	3,929	$	2,811

5. Closure of the Israeli Branch Office

On December 31, 2007, Isramco and I.O.C- Israel Oil Company Ltd, an Israeli company and related party ("IOC"), entered into an agreement pursuant to which the Company sold and transferred to IOC its Israeli based activities and assets currently conducted and managed by the Company's Israel branch office (the "Branch Office") and its own shares in Isramco Oil & Gas (the general partner of Negev 2 LP), for aggregate consideration of approximately $13.6 million. Following the sale of these assets, the Company no longer conducts operations in Israel though it will continue to hold interests in certain oil and gas assets offshore Israel. The decision was taken in light of the Company's expanding oil and gas operations in the United States and management's decision that it is in the Company's best interests to focus on the oil and gas operations in the United States and terminate activities in Israel which, prior to the sale transaction reported hereunder, comprised a relatively insignificant component of the Company's overall operations.

The principal assets transferred to IOC include participation units in the Israeli oil and gas limited partnerships Isramco Negev 2 ("Negev") and INOC Dead Sea ("Dead Sea"), both of which were held by the Branch Office. The participation units of both Negev and Dead Sea trade on the Tel Aviv Stock Exchange. The sale of the units was completed through a private non-market transaction with IOC where the sale price of the Negev and Dead Sea units was established at, respectively, a 7% and 10% discount to the closing sale price of these units on the Tel Aviv Stock Exchange on December 30, 2007. The discounts were established by an independent appraiser. The Branch Office also transferred to IOC all operating activities at the Branch Office, including employees, fixed assets, marketable securities and certain rights and liabilities, as well as the Company's holdings of Isramco Oil and Gas Ltd. and title to undeveloped real estate located in Israel.

IOC is a wholly-owned subsidiary of Naphtha Israel Petroleum Corp, Ltd. ("Naphtha"). Naphtha holds 100% of Naphtha Holdings Ltd., which holds approximately 48% of the Company's issued and outstanding stock.

Since this is a transaction between entities under common control, the Company recorded the loss of approximately $3,046 million from the transaction, as a reduction of shareholders’ equity (additional paid in capital).

The proceeds of the sale were used by the Company to repay a loan that Naphtha advanced to the Company in March 2007 for purposes of enabling the Company to complete the acquisition from Five States of certain oil and gas properties in the United States.

6. Marketable Securities

For the year ended December 31, 2008, 2007 and 2006, we had net unrealized gains on marketable securities of $0, $0 and $1,054 thousand, respectively. Sales of marketable securities resulted in realized gains of $0, $52 thousand and $1,177 thousand for the years ended December 31, 2008, 2007 and 2006, respectively.

Available-for-sale securities, which are primarily traded on the Tel-Aviv Stock Exchange and on the OTC Bulletin Board, consist of the following (in thousands):

As of December 31	2008				2007
	Cost		Market Value		Cost		Market Value
	$	1,219	$	1,799	$	1,619	$	6,809

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7. 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, 2008, 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.

At December 31, 2008, the Company had 18 open positions summarized in the tables below: 7 natural gas swap arrangements and 11 crude oil swap arrangements. 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 2008, 2007 and 2006 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, 2008, the Company had a $23 million derivative asset, 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 ($32.6 million unrealized gain partially offset by a $7.9 million loss from net cash payments on settled contracts).

As of December 31, 2007, the Company had a $9.4 million derivative liability, which $3.1 million was classified as current. For the year ended December 31, 2007 the Company recorded a net derivative loss of $8.6 million ($11.3 million unrealized loss and a $2.7 million net gain for cash received on settled contracts).

As of December 31, 2006, the Company had a $1.7 million derivative asset, all of which was classified as current. The Company recorded a net derivative gain of $2.6 for the year ended December 31, 2006.

Natural Gas

At December 31, 2008, the Company had the following natural gas swap positions:

Period	Swaps
	Volume in MMbtu’s		Price / Price Range		Weighted Average Price
January 2009 – December 2009		2,054,928	$	7.77-9.60	$	8.25
January 2010 – December 2010		1,785,648		7.49-8.32		7.88
January 2011 – December 2011		764,820		8.22		8.22
January 2012 – March 2012		174,222		8.65		8.65

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Crude Oil

At December 31, 2008, the Company had the following crude oil swap positions:

Period	Swaps
	Volume in Bbls		Price / Price Range		Weighted Average Price
January 2009 – December 2009		274,596	$	63.90-104.25	$	81.00
January 2010 – December 2010		254,868		63.30-101.70		79.59
January 2011 – December 2011		210,307		82.10-91.05		87.53
January 2012 – March 2012		31,953		88.20		88.20

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 our variable rate interest of our Scotia debt (as defined in Note 8, “Long-term Debt”) 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:

National amount (in thousands):	Start Date	Maturity Date	Weighted-Average Interest Rate
32,000	April 2009	February 2011	3.63%
6,000	April 2009	February 2011	2.90%

8. Long-Term Debt and Interest Expense

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

	2008		2007
Libor + 2% Bank Revolving Credit Facility due 2011	17,950		27,000
Libor + 2% Bank Revolving Credit Facility due 2012	46,250		-
Libor + 6% Related party Debt	12,000		12,000
Libor + 5.5% Related party Debt	954		6,081
Libor + 6% Related party Debt	18,500		18,500
Libor + 6% Related party Debt	48,900		-
	144,554		63,581
Less: Current Portion of Long-Term Debt	(21,000	)	(3,000	)
Total	123,554		60,581

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Senior Revolving Credit Facility

The Company entered into the Senior Secured Revolving Credit Agreement, dated as of March 27, 2008 and Amended and Restated as of December 19, 2008 (the “Senior Credit Agreement”), between the Company, each of the lenders from time to time party thereto (the “Lenders”), Bank of Nova Scotia, as administrative agent for the Lenders and Capital One, N.A as a syndication agent for the Lenders. The Senior Credit Agreement provides for a $150 million facility due in 2012 with an increased borrowing base of $54 million that will be 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 fourth quarter of 2008, the lenders reduced the borrowing base to $45 million.

Amounts outstanding under the Senior Credit Agreement will 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 will fluctuate based on the utilization of the borrowing base. Borrowings under the Senior Credit Agreement are secured by first lien and security interest on the real and personal property of Isramco Resources.

The Company entered into the Senior Secured Revolving Credit Agreement, dated as of March 2, 2007 as Amended and Restated as of June 15, 2007 (the “Senior Credit Agreement”), between the Company, each of the lenders from time to time party thereto (the “Lenders”), Wells Fargo Bank, N.A, as administrative agent for the Lenders and. The Senior Credit Agreement provides for a $150 million facility due in 2011with an increased borrowing base of $35.3 million that will be 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 second quarter of 2007, the Lenders reduced the borrowing base to $27 million.

Amounts outstanding under the Senior Credit Agreement will 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 will fluctuate based on the utilization of the borrowing base. Borrowings under the Senior Credit Agreement will be secured by a guarantee from Isramco and a pledge by Isramco of the shares of Isramco Energy.

Related party Debt

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

In February and March, 2008 we obtained loans from JOEL, a related party, 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 and director is a director of JOEL and Mr. Haim Tsuff, Isramco’s Chief Executive Officer and Chairman, is a controlling shareholder of JOEL.

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

Pursuant to a Loan Agreement dated as of February 27, 2007 (the "Loan Agreement"), Isramco obtained $18.5 million. 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.

Mr. Jackob Maimon, Isramco's President at the time and a director is a director of Naphtha Petroleum and Mr. Haim Tsuff, Isramco's Chief Executive Officer and Chairman is a controlling shareholder of Naphtha Petroleum.

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Pursuant to a Loan Agreement dated as of February 27, 2007 (the "Second Loan Agreement") Isramco obtained a loan from Naphtha Petroleum, in the principal amount of $11.5 million, 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 Loan Agreement.

Pursuant to a Loan Agreement dated as of February 27, 2007 (the "Third Loan Agreement ") Isramco obtained a loan from Naphtha Petroleum, in the principal amount of $12 million, 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. 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"), 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%. Mr. Jackob Maimon, Isramco's president at the time and a current director is a director of JOEL and Mr. Haim Tsuff, Isramco's Chief Executive Officer and Chairman is a controlling shareholder of JOEL.

Effective February 1, 2009, each of the loans from I.O.C. – Israel Oil Company, Inc. and Naphtha Israel Petroleum Corp., Ltd., to the Corporation was amended and restated to extend the payment deadlines arising and after February, 2009, by two years.

Aggregate maturities required on long-term debt at February 1, 2009 are due in future years as follows (in thousands):

2009	$	21,000
2010		1,400
2011		19,350
2012		44,875
2013		19,500
Thereafter		38,429
Total	$	144,554

Interest expense (income)

The following table summarizes the amounts included in interest expense for the years ended December 31, 2008, 2007 and 2006:

	Years Ended December 31,
	2008			2007		2006
	(In thousands)
Current debt, long-term debt and other - banks corporation	$	3,369	$	1,624	$	(318)
Long-term debt – related parties		6,486		4,720		164

	$	9,855	$	6,344	$	(154	)

9. 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 rates of the U.S. as they apply to Isramco’s current ownership structure.

Isramco accounts for income taxes pursuant to SFAS No. 109, 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 basis of assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse.

Isramco adopted FIN 48, effective January 1, 2007. Isramco recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing tax benefits. There are no unrecognized tax benefits that if recognized would affect the tax rate. There was no interest or penalties recognized as of the date of adoption or for the twelve months ended December 31, 2008. The Company files tax returns in the U.S. and states in which it has operations and is subject to taxation. Tax years subsequent to 2005 remain open to examination by taxing authorities.

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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 for the years ended December 31, 2008, 2007 and 2006 due to the following:

	Years Ended December 31,
	2008				2007			2006
	(In thousands)
Expected tax benefit (expense)	$	1,262		$	(4,061	)	$	2,553
State taxes, net		(164	)		244			153
Foreign income taxes		(659)			(1,160	)		700
Accretion and other		(62	)		(215	)		(2,680	)

Total tax expense (benefit)	$	377		$	(5,192	)	$	726

Deferred tax assets at December 31, 2008 and 2007 are comprised primarily of net operating loss carryforwards 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). 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 United States generally accepted accounting principles and income tax reporting. There is a net deferred tax asset and it is management’s opinion that a valuation allowance is not needed.

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

	2008			2007
Deferred current tax assets:
Unrealized hedging transactions	$	-		$	1,047
Other		1,542
Deferred current tax assets	$	1,542		$	1,047

Deferred current tax liabilities:
Unrealized hedging transactions	$	(3,787	)	$	-
	$	(3,787	)	$	-

Net current deferred tax assets (liabilities)	$	(2,245	)	$	1,047

Deferred noncurrent tax assets:
Unrealized hedging transactions	$	-		$	2,151
Book-tax differences in property basis		1,905			-
Losses carry-forward		5,639			-
Other		131			-
Deferred noncurrent tax assets	$	7,675		$	2,151


Deferred noncurrent tax liabilities:
Unrealized hedging transactions	$	(3,720	)	$	-
Book-tax differences in property basis		-			(786	)
Book-tax differences in marketable securities		(197	)		(1,764	)
Other		-			(556	)
Deferred noncurrent tax liabilities	$	(3,917	)	$	(3,106	)

Net noncurrent deferred tax assets (liabilities)	$	3,758		$	(955	)

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

	2008			2007			2006
Current income tax:
Federal	$	276		$	1,427		$	(167	)
Foreign		(659	)		741			400
State		114			-			150
Total current income tax	$	(269	)	$	2,168		$	383

Deferred income tax
Federal	$	884		$	7,360		$	343
Foreign		-			-			-
State		(238	)		-			-
Total deferred income tax	$	646		$	7,360		$	343
Provision for income tax	$	377		$	(5,192	)	$	726

At December 31, 2008, the Company has U.S. tax loss carry forwards of approximately $16,586 thousand, which will expire in various amounts beginning in 2029 and ending in 2030.

10. Earnings Per Share

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

	2008		2007			2006
Numerator for Basic and Diluted Earnings per Share -
Net Income (loss) from continuing operations	$	3,229	$	(6,411	)	$	6,569
Net Income (loss)		-		-		$	3,842

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 Per Share Available to Common Stockholders – Basic and Diluted

Continuing operations	$	1.19	$	(2.36	)	$	2.42

Total	$	1.19	$	(2.36	)	$	1.41

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11. 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, 2007, 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 2008, 2007 and 2006. 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.

12. Supplemental Cash Flow Information

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

	2008		2007		2006
Interest	$	7,014	$	3,284	$	217

Income taxes	$	80	$	174	$	76

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

The consolidated statements of cash flows for the year ended December 31, 2007 exclude the following non-cash transactions:

·	Property and equipment of $700 thousand included in accounts payable
·	Sale of assets, liabilities and rights in total amount of $13.6 million against loan from related party

·	Asset retirement obligation from acquired properties of $2.1 million included in the oil and gas properties

13. 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, 2008. 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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14. 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.

15. 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):

	2008			2007
Liability for asset retirement obligation at the beginning of the year	$	2,670		$	356
Liabilities Incurred		8,480			2,050
Liabilities Settled		(17	)		-
Accretion		847			219
Revisions (*)		3,753			45
Liability for asset retirement obligation at the end of the year	$	15,733		$	2,670

(*) 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.

16. Geographical Segment Information

In 2008, all activities are within the United States.

Isramco's operations for 2007 involve one industry segment - the exploration, development, and production of oil and natural gas. Prior to 2007, Isramco operated in two industry segments - oil and gas activities and leasing its cruise line vessel. Its current oil and gas activities are concentrated in the United States and Israel (on December 31, 2007 the Company sold the majority of the Company’s Israeli based activities and assets, for further information see Note 5 “closure of the Israeli branch”) . Operating outside the United States subjects Isramco to inherent risks such as a loss of revenues, property and equipment from such hazards as exploration, nationalization, war, terrorism and other political risks, risks of increased taxes and governmental royalties, renegotiation of contracts with government entities and change in laws and policies governing operations of foreign-based companies.

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Isramco's oil and gas business is subject to operating risks associated with the exploration, and production of oil and gas, including blowouts, pollution and acts of nature that could result in damage to oil and gas wells, production facilities of formations. In additions, oil and gas prices have fluctuated substantially in recent years as a result of events, which were outside of Isramco's control.

Geographic segments (in thousands)	United States			Israel		Total Oil and gas

2007
Sales and other operating revenues	$	20,916		$	1,840	$	22,756
Costs and operating expenses		19,796			1,387		21,183
Operating profit (loss)	$	1,120		$	453	$	1,573

Interest income							( 434	)
Interest expense							6,778
Gain on marketable securities and net gain in investee							( 52	)
Realized gain on sale of investment and capital gain							(1,754	)
Loss from swap transaction							8,638
Income taxes (benefit)							(5,192	)
Net loss before discontinued operation							(6,411	)
Loss on discontinued operation							-
Net loss							(6,411	)

Identifiable assets at December 31, 2007	$	99,955		$	-	$	99,955
Cash and corporate assets							10,753
Total assets at December 31, 2007						$	110,708


2006
Sales and other operating revenues	$	2,167		$	825	$	2,992
Costs and operating expenses		2,290			251		2,541
Operating profit (loss)		(123	)		574		451

Interest income and other							448
Net gain in investee and gain on marketable							3,747
Securities
General corporate expenses							(2,236	)
Internet expense							(294	)
Compensation for legal settlement							2,536
Gain from swap transaction							2,604
Other income							39
Income taxes							(726	)
Net income before discontinued operation							6,569
Loss on discontinued operation							(2,727	)
Net income						$	3,842

Identifiable assets at December 31, 2006	$	10,560		$	66	$	10,626
Cash and corporate assets							51,447
Total assets at December 31, 2006						$	62,073

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17. Discontinued operation

In March 2004, Isramco purchased a luxury cruise liner for aggregate consideration of $8.05 million. Isramco, through its wholly owned subsidiary, Magic 1 Cruise Line Corp., a British Virgin Island corporation (“Magic I Corp.”), leased the vessel to European based tour operator from April 2005 through October 2005 and from April 6, 2006 through November 5, 2006. In December 2006, Isramco sold all of the outstanding share capital of Magic 1 Corp. to an unrelated third party for total consideration of approximately $2.15 million The sale included the assumption by the purchaser of a loan in the principal amount of $3.3 million. Following the sale, Isramco is no longer engaged in the cruising business.

Results of operation from discontinued operation for the year ended December 31,

(in thousands except for share information)

	2006
Revenues	$	1,712
Expenses:
Interest expense		622
Cost of revenue from vessel		1,418
Depreciation		945
General and administrative		7
Impairment of vessel		2,200

Total expenses		5,192


Loss before income taxes		3,480
Income taxes		-

Net loss from vessel activity		3,480

Interest expenses to parent company		369
Capital gain from sale of activity		384

Net loss from discontinued operation	$	2,727

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18. Supplementary Oil and Gas Information (Unaudited)

The following supplemental information regarding the oil and gas activities of Isramco for 2008, 2007 and 2006 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	2008			2007
	United States			United States
Unproved properties not being amortized	$	-		$	3,603
Proved property being amortized		219,945			105,337
Accumulated depreciation, depletion amortization and impairment		(56,109	)		(16,291	)
Net capitalized costs		163,833			93,649

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

As of December 31	2008		2007		2006
	United States
Property acquisition costs—proved and unproved properties	$	97,502	$	86,284	$	1,609
Exploration costs	$	-	$	269	$	125
Development costs	$	1,167	$	2,691	$	4,652

OIL AND GAS RESERVES

Oil and gas proved reserves cannot be measured exactly. The engineers interpreting the available data, as well as price and other economic factors, base reserve estimates on many variables related to reservoir performance, which require evaluation. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data, the production performance of the reservoirs as well as extensive engineering judgment. Consequently, reserve estimates are subject to revision, as additional data become available during the producing life of a reservoir. When a commercial reservoir is discovered, proven reserves are initially determined based on limited data from the first well or wells. Subsequent data may better define the extent of the reservoir and additional production performance, well tests and engineering studies will likely improve the reliability of the reserve estimate. The evolution of technology may also result in the application of improved recovery techniques such as supplemental or enhanced recovery projects, or both, which have the potential to increase reserves beyond those envisioned during the early years of a reservoir's producing life.

The following table represents Isramco's net interest in estimated quantities of proved developed and undeveloped reserves of crude oil, condensate, natural gas liquids and natural gas and changes in such quantities at December 31, 2008, 2007 and 2006, and for the years then ended. Net proved reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserve volumes that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserve volumes that are expected to be recovered from new wells on undrilled acreage or from existing wells where a significant expenditure is required for recompilation. All of Isramco's proved reserves are in the United States. Isramco's oil and gas reserves are priced at $5.62 and $44.60 per barrel per Mcf, respectively, at December 31, 2008.

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	Oil BBls			Gas Mcf			NGL BBls
December 31, 2005		105,368			1,644,700			-
								-
Revisions of previous estimates		24,071			(59,066	)		-
Acquisition of minerals in place		-			-			-
Sales of minerals in place		---			-			-
Production		(13,464	)		(213,634	)		-
December 31, 2006		115,975			1,372,000			-

Revisions of previous estimates		358,044			1,455,617			838,595
Acquisition of minerals in place		1,625,855			24,075,738			1,425,600
Sales of minerals in place		-			-			-
Production		(96,793	)		(15,507,89	)		(100,534	)
December 31, 2007		2,003,081			25,352,566			2,163,661

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

Isramco's proved developed reserves are as follows:

	Developed						Undeveloped
	Oil BBls		Gas Mcf		NGL BBls		Oil BBls		Gas Mcf		NGL BBls
December 31, 2008		2,678,994		25,696,175		1,252,003		-		-		-
December 31, 2007		1,808,317		23,338,079		1,873,949		194,764		2,014,487		289,711
December 31, 2006		115,975		1,372,000		-		5,876		618,700		-
December 31, 2005		105,368		1,644,700		-		20,652		484,101		-

Interest in proved reserves of unconsolidated affiliates

	Oil BBls		Gas Mcf
December 31, 2006		--		1,979,000
December 31, 2005		--		1,979,000

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STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOW

The standardized measure of discounted future net cash flows relating to Isramco's proved oil and gas reserves is calculated and presented in accordance with Statement of Financial Accounting Standards No. 69. Accordingly, future cash inflows were determined by applying year-end oil and gas prices to Isramco's estimated share of the future production from proved oil and gas reserves.

Future production and development costs were computed by applying year-end costs to future years. Applying year-end statutory tax rates to the estimated net future cash flows derived future income taxes. A prescribed 10% discount factor was applied to the future net cash flows.

In Isramco's opinion, this standardized measure is not a representative measure of fair market value. The standardized measure is intended only to assist financial statement users in making comparisons among companies.

	2008			2007			2006
Future cash inflows	$	277,008,941		$	450,981,415		$	18,208,000
Future development costs		(511,810	)		(3,502,500	)		(866,000	)
Future production costs		(146,421,245	)		(178,384,211	)		(7,170,000	)
Future income tax expenses		-			(63,983,746	)		(2,976,000	)
Future net cash flows before 10% discount		130,075,886			205,110,958			7,196,000
10%Annual discount for estimated timing of cash flows		(56,698,274	)		(108,345,218	)		(2,875,000	)

Standardized measure discounted future net cash flows	$	73,377,612		$	96,765,740		$	4,321,000

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2008, 2007 and 2006 were as follows:

	2008			2007			2006
Beginning of the year	$	96,765,740		$	4,321,000		$	10,695,000
Sales and transfers of oil and gas produced, net of production costs		(31,469,183	)		(13,267,315	)		(1,048,000	)
Net changes in prices and production costs		(144,454,304	)		6,084,956			(5,629,000	)
Net changes in income taxes		28,376,801			(8,075,637	)		4,961,000
Changes in estimated future development costs, net of current development costs		(3,546,457	)		(3,395,813	)		--
Acquisition of minerals in place		124,894,615			95,870,804			992,000
Revision of previous estimates		(45,059,969	)		23,413,049			(1,716,000	)
Change of discount		23,513,947			794,008			1,396,000
Change in production rate and other		24,356,422			(8,979,313	)		(2,123,000	)

End of year	$	73,377,612		$	96,765,740		$	4,321,000

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Unaudited Quarterly Financial Information

(In Thousands, Except Per Share Data)

Quarter Ended	March 31			June 30			September 30			December 31
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) from discontinued operation		-			-			-			-
Net Income	$	(7,646	)	$	(32,186	)	$	34,488		$	8,573

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

2007
Total Revenues	$	3,122		$	7,215		$	5,355		$	7,064
Net Income (loss) before taxes	$	(2,807	)	$	1,936		$	(970	)	$	(9,761	)
Net income (loss) from discontinued operation		-			-			-			-
Net Income	$	(1,766	)	$	1,198		$	(647	)	$	(5,196	)

Earnings (loss) per Common Share
-Basic and Diluted	$	(0.65	)	$	0.44		$	(0.24	)	$	(1.91	)

2006
Total Revenues	$	1,576		$	1,708		$	1,081		$	1,197
Net Income (loss) before taxes	$	2,650		$	1,337		$	225		$	3,083
Net income (loss) from discontinued operation	$	(2,500	)	$	231		$	458		$	(916	)
Net Income	$	394		$	1,066		$	582		$	1,800

Earnings (loss) per Common Share
-Basic and Diluted	$	0.14		$	0.39		$	0.21		$	0.67

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