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, 2011
   
r
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
COMMISSION FILE NUMBER: 0-12500

ISRAMCO, INC.
(Exact name of registrant as specified in its charter)
 
Delaware
13-3145265
 (State or Other Jurisdiction   of Incorporation)
   (IRS Employer Identification No.)

2425 West Loop South, Suite 810, Houston Texas 77027
(Address of Principal Executive Offices)

713-621-6785
(Registrant's Telephone Number, including Area Code)

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

Securities registered under Section 12(g) of the Exchange Act:
Common Stock, par value $0.01
(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  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.  Yes  x No  r
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  x No r
 
Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained in this Form, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. r

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer  r Accelerated filer  x    Non-accelerated filer  r     Smaller Reporting Company r
 
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 22, 2012, 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 March 23, 2012, based on the last sale price of such equity reported on the Nasdaq market, was approximately $227 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 2012 annual meeting of stockholders, which will be filed on or before April 30, 2012.

 
 
 
ISRAMCO, INC.
2011 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS
 
 
Page
  PART I
 
     
ITEM 1.
 4
ITEM 1A.
  12
ITEM 1B.
  21
ITEM 2.
  21
ITEM 3.
  21
ITEM 4.
 21
     
PART II
 
     
ITEM 5.
  22
ITEM 6.
  22
ITEM 7.
  22
ITEM 7A.
  32
ITEM 8.
  32
ITEM 9.
  33
ITEM 9A.
33
ITEM 9B.
33
     
PART III
 
     
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 
ITEM 11.
EXECUTIVE COMPENSATION
 
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENTAND RELATED STOCKHOLDER MATTERS
 
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
ITEM 14.
PRINCIPAL ACCOUNTING FEES & SERVICES
 
     
PART IV
   
     
ITEM 15.
  35

 
 
 
Special note regarding forward-looking statements

This report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number of anticipated wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. The actual results could differ materially from those anticipated in these forward-looking statements. One should consider carefully the statements under the “Risk Factors” section of this report and other sections of this report that describe factors that could cause our actual results to differ from those set forth in the forward-looking statements, including, but not limited to, the following factors:
 
•
the volatility in commodity prices for oil and natural gas, including continued declines in prices;
   
•
the possibility that the industry may be subject to future regulatory or legislative actions (including any additional taxes and changes in environmental regulation);
   
•
the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;
   
•
the possibility that production decline rates for some of our oil and gas producing properties are greater than we expect;
   
•
our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;
   
•
the ability to replace oil and natural gas reserves;
   
•
environmental risks;
   
•
drilling and operating risks;
   
•
exploration and development risks;
 
 
•
competition, including competition for acreage in oil and gas producing areas and for experienced personnel;
   
•
management’s ability to execute our plans to meet our goals;
   
•
our ability to retain key members of senior management and key technical employees;
   
•
our ability to repay our credit facility when due;
   
•
our ability to obtain goods and services, such as drilling rigs and tubulars, and access to adequate gathering systems and pipeline take-away capacity, to execute our drilling and development programs;
   
•
general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that the current economic recession in the United States will be severe and prolonged, which could adversely affect the demand for oil and natural gas and make it difficult, if not impossible, to access financial markets;
   
•
other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our business, operations or pricing.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in the section entitled “Risk Factors” included in this report. All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.
 
 
 
 
PART I
 
ITEM 1. BUSINESS

Overview

Isramco, Inc., a Delaware corporation incorporated in 1982 (hereinafter, “we”, the “Company” or “Isramco”), together with its subsidiaries is an independent oil and natural gas company engaged in the exploration, development and production of predominately oil and natural gas properties located onshore in the United States and off shore Israel and operate a well service company that provides well maintenance and workover services, well completion and recompletion services.

At December 31, 2011, our estimated total proved oil, natural gas reserves and natural gas liquids, as prepared by our independent reserve engineering firms, Netherland, Sewell & Associates, Inc and Cawley, Gillespie & Associates, Inc., were approximately 34,990 thousand barrels of oil equivalent (“MBOE”), consisting of 3,234 thousand barrels (MBbls) of oil, and 179,155 million cubic feet (MMcf) of natural gas and 1,896 thousand barrels (MBbls) of natural gas liquids. Approximately 27% of our proved reserves were classified as proved developed (See Note 16 Supplemental Oil and Gas Information to Consolidated Financial Statements to our consolidated financial statements). Full year 2011 production averaged 2.16 MBOE/d compared to 2.3 MBOE/d in 2010.
 
Our business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs, acquiring strategic oil and gas properties and improving of existing oil and gas properties. 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 and the operation of a well service company. We own varying working interests in oil and gas wells in Louisiana, Texas, New Mexico, Oklahoma, Wyoming, Utah and Colorado and currently serve as operator of approximately 589 wells located mainly in Texas and New Mexico.

In August, 2011 we created a new subsidiary and in October began operation of a well service company. We began the operations by acquiring five well services rigs and related equipment.
 
Israel
 
In 2007 we closed our branch in Israel in order to focus on our expanding presence in the United States Despite the closure of that branch we retained certain overriding royalties in three oil and gas licenses located offshore Israel, These licenses granted by the government of Israel known as the “Michal", "Matan" and "Shimson" Licenses.
 
In 2009, two natural gas discoveries, known as "Tamar" and "Dalit",  were made   within the area covered by Michal and Matan Licenses, respectively.  In December 2009, the Israeli Petroleum Commissioner granted Noble Energy, Inc. (“Noble”) and its partners, Isramco Negev 2-LP, Delek Drilling, Avner Oil & Gas, and Dor Gas (the “Tamar Consortium”), two leases (the “Tamar Lease” and the "Dalit Lease"). The Leases are scheduled to expire on December 2038 and cover the Tamar and Dalit gas fields (collectively the “Tamar Field”). The Tamar Field is approximately 95 kilometers of the coast of the Israel in the Israel exclusive economic zone of the Eastern Mediterranean with a water depth of approximately 1700 meters.
 
 
During January – March 2012, the Tamar Consortium has executed gas supply contracts for sales of natural gas to five separate industrial customers located in Israel and to the Israel Electricity Company.  It is anticipated that gas deliveries under such contracts would begin in mid 2013. The contracts are also subject to certain material conditions precedent.  Therefore there can be no assurances that there will be any actual gas deliveries under any of such supply contracts.
 
We own an overriding royalty interest of 1.5375% in the Tamar Field, which will increase to 2.7375% after payout (collectively the “Tamar Royalty”).  An overriding royalty interest is an ownership in a percentage of production or production revenues, free of cost of production or development from the underlying leases.  As with most overriding royalty interests, we have no control over the operations, drilling, expenses, or timing of production or sales or any other aspect of development or production of the underlying natural gas.
 
We have a third party reserve report from independent petroleum engineers, Netherland, Sewell & Associates dated March 21, 2012 and estimating reserves allocable to the Tamar Royalty as of December 31, 2011 (the “Tamar Reserve Report”). This reserve report estimates that by reason of its ownership of the Tamar Royalty, we have proven undeveloped reserves estimated at 154.1 billion cubic feet of natural gas.  The Tamar Reserve Report indicates that the undiscounted estimated future net revenue (after deduction of estimated production and ad valorem taxes but before estimated income tax) for such reserves (paid out over time) at $634,462,200.  The Tamar Reserve Report estimates the net present worth of such reserves, discounted at 10% annual discount rate factor, at $241,737,300 (See Note 16 Supplemental Oil and Gas Information to Consolidated Financial Statements to our consolidated financial statements).   The gas price used to value the reserves in the Tamar Reserve Report is the 12-month unweighted arithmetic average of the first-of-the-month Henry Hub spot price for each month in the period January through December 2011. That price of $4.118 per MMBTU is a hypothetical sales price held constant throughout the estimated life of the reserves allocable to the Tamar Royalty for purposes of the estimate and does not represent any actual sales price or contractual sales price for the gas.  The report indicates that there are no commercial oil deposits or condensate that is included as reserves.
 
The amount of proceeds, if any, we receive from the production of the natural gas will be determined not only by the timing of production and price received but, as our interest increases at payout, the expenses and costs incurred by the operations.  Payout is the point when all the cost of leasing, drilling, producing and operating the leases have been recovered from proceeds from production from the leases as defined in the royalty agreement.
 
As we do not control any of those factors affecting our payments (time of production, price received, costs incurred) for our interest and based on that and the other risk factors as set out herein it is difficult to determine the amounts or timing of any amounts  we receive with precision or when payout is likely to occur, if ever. Based on reserves and anticipated production and using the income from these interests may be very significant to the Company, if they can be commercially produced. 
 
Commercial production of such reserves is subject to numerous major risks.  These risks will include all of the typical risks associated with offshore oil and gas production. Commercial production of such reserves will also be subject to additional major risks that may be unique to the Tamar Field.  These include:
 
·  
There has not been any large scale production of natural gas offshore Israel.  Therefore there may be geological, geophysical or other unforeseen problems that may be unique to the offshore Israel site that could limit such production. In addition, even if commercial production of the reserves can be achieved, it is uncertain what the likely life of such commercial production is likely to be.
 
·  
Even if our reserves can be produced, there are no natural gas pipelines or other suitable transportation modalities that presently exist to transport the natural gas. Therefore, commercial exploitation of the reserves will require construction of pipelines or other transportation modalities to enable the natural gas to market.  The development plan presently contemplates transportation of gas production through a 152 kilometer pipeline through the Tamar Field to Ashdod.  There can be no assurance that the pipeline will be completed or completed on a timely basis.
 
·  
There has been significant political upheaval and unrest in the Mideast, particularly in Syria, Egypt and other countries near Israel. In addition, there is considerable hostility between Iran and Israel and other countries.  There is significant risk that war, acts of terrorism or other force majeure may delay, prevent or destroy commercial production of natural gas from the Tamar Field, thereby diminishing or preventing production of natural gas from the Tamar Field.
 
·  
The Tamar Consortium will be required to obtain significant financing to develop and produce the field and build transportation to market. There can be no assurances as to whether such financing will be procured, the timing of the financing or whether the financing will be procured on favorable terms and conditions.
 
·  
The market for natural gas in Israel exists but the financial ability of customers of the Tamar Consortium to take and pay for material amounts of such natural gas is unknown
 
The Company also has an interest in a separate area of the Eastern Mediterranean.  Based on a gas find, a 30 year lease covering 53 square kilometers (approximately 13,100 acres) offshore Israel was granted in June 2000 (the "Med Yavne Lease"). The original operator of the Med Yavne Lease was BG International Limited, a member of the British Gas Group ("BG").  BG resigned as the operator of the Lease and relinquished all of its working interests in the Med Yavne Lease.  The remaining participants in the lease appointed I.O.C - Israel Oil Company Ltd ("IOC") as the successor operator. 
 
Our participation interest of the Med Yavne Lease is 0.7052 %.  We also hold an overriding royalty interest in the Med Yavne Lease of 0.1% before payout and 1.3% after payout. We have no reserves attributed to this interest and this lease may not be capable of being economically produced
 
 
Derivative Instruments and Hedging Activities

We utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our anticipated future oil and natural gas production. We generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next 48 and 15 months, respectively. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivative contracts, which would potentially allow us to not record the change in fair value of our derivative contracts in the consolidated statements of operations. We carry our derivatives at fair value on our consolidated balance sheets, with the changes in the fair value included in our consolidated statements of operations in the period in which the change occurs. Our results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivative contracts.
 
As of December 31, 2011 we had swap contracts for a volume of 282,873 barrels of crude oil during 36 months, commencing January 2012, and swap contracts for a volume of 174,222 MMBTU of natural gas during 3 months commencing January 2012.
 
Hereunder are the open swap contracts positions as of December 31, 2011:
 
   
Swap Contracts
 
   
Natural Gas
   
Crude Oil
 
   
Volume
(MMBTU)
(*)
   
Weighted
Average
Price
($/MMBTU)
   
Volume
(Bbl)
   
Weighted
Average
Price
($/Bbl)
 
2012
   
174,222
     
8.65
     
127,473
     
99.67
 
2013
   
-
     
-
     
89,400
     
103.51
 
2014
   
-
     
-
     
66,000
     
103.51
 
(*) Mcf = MMBTU
 
During the second quarter of 2009, we made the decision to mitigate a portion of our interest rate risk with interest rate swaps. These swap instruments reduce our exposure to market rate fluctuations by converting variable interest rates to fixed interest rates.

Under these swaps, we make payments to, or receive payments from, the counterparties based upon the differential between a specified fixed price and a price related to the three-month LIBOR. These interest rate swaps convert a portion of our variable rate interest on our Scotia debt (as defined in Note 6, “Long-term Debt and Interest Expense”) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. We have elected to designate these positions for hedge accounting and therefore the unrealized gains and losses are recorded in accumulated other comprehensive loss. The Company measures hedge effectiveness by assessing the changes in the fair value or expected future cash flows of the hedged item.
 
As of December 31, 2011 we did not have open interest rate swap positions.
 
On March 9, 2010, pursuant to an agreement with Wells Fargo & Company, the derivative contracts between Isramco and Wells Fargo were terminated and the Company signed new swap contracts with Macquarie Bank, N.A. for an aggregate volume of 336,780 barrels of crude oil during the 46 month period commencing March 2011. 

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. There are also a great many well service companies that compete for the same customers as we compete. The primary areas in which we encounter substantial competition are in locating and acquiring attractive producing oil and natural gas properties, obtaining purchasers and transporters of the oil and natural gas we produce, attracting customers to a new well service business and hiring and retaining key employees during active times in the oil and gas industry. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States and in some instances individual states where we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. 
 
 
Markets and Major Customers
 
Through our wholly-owned subsidiary, we operate a substantial portion of our domestic oil and natural gas properties. As the operator of a property, the Company makes full payment of the costs associated with each property and seeks reimbursement from the other working interest owners in the property for their share of those costs. 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 as to its sales of oil and gas production. The Company does not believe the loss of any one of its purchasers would materially affect the Company’s ability to sell the oil and natural gas it produces. The Company believes other purchasers are available in the Company’s areas of operations.
 
Seasonality of Business

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

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

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

Regulations

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

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

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability.
 
Each state in which we operate also imposes some form of production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. We are liable for paying this tax on our production, and are also liable for various real and personal property taxes on our leases and facilities.
 
 
Environmental and Occupational Health and Safety Regulations
 
The oil and gas industry in the United States is subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment.  Many governmental agencies, such as the United States Environmental Protection Agency (the “EPA”) have issued lengthy and comprehensive regulations to implement and enforce these laws.  These laws and regulations often require difficult and costly compliance measures.  Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities.
 
In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of that person.  We endeavor to fully comply with these regulatory requirements; however, compliance increases our costs and consequently affects our profitability.
 
As a part of the overall environmental regulatory policy, the permitting, construction and operations of certain oil and gas facilities are regulated.  Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit.  Once operational, enforcement measures can include significant civil penalties for regulatory violations, regardless of intent.  Under appropriate circumstances, an administrative agency can issue a cease and desist order to require termination of operations.
 
Environmental regulation is becoming more comprehensive and additional programs, as well as increased obligations under existing programs, are anticipated.  In this regard, we expect additional regulation of naturally occurring radioactive materials, oil and natural gas exploration and production operations, waste management, and underground injection of water and waste material.  The adoption of additional regulations could have a material adverse effect on our financial condition and results of operations.  Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations.
 
Comprehensive Environmental Response, Compensation and Liability Act and Hazardous Substances
 
In 1980, the United States Congress enacted the federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or the Superfund law. This law, which has been amended since enactment, and comparable state laws impose strict liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of what are considered to be “hazardous substances” into the environment.  These persons include the current or former owners or operators of the sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances released at the site.  Under CERCLA, we may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment whether or not we are responsible for the release or even owned the site at the time of the release, as well as for damages to natural resources and for the costs of health studies. In addition, companies that incur liability frequently confront additional claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.
 
The Solid Waste Disposal Act and Waste Management
 
The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as RCRA, regulates the disposal of solid waste but generally excludes most wastes generated by the exploration and production of oil and natural gas, such as drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as hazardous wastes.  However, these wastes may be regulated by the EPA or state agencies as non-hazardous wastes as long as these wastes are not commingled with regulated hazardous wastes.  Moreover, in the ordinary course of our operations, other wastes generated in connection with our exploration and production activities may be regulated as hazardous waste under RCRA or hazardous substances under CERCLA.  From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA and analogous state laws.  Under these laws, we have been and may be required to remove or remediate these materials or wastes. At this time it is not possible to estimate the potential liabilities to which we may be subject from unknown, latent liability risks with respect to any properties where materials or wastes may have been released, but of which we have not been made aware.
 
 
The Clean Water Act, wastewater and storm water discharges
 
The oil and gas industry, and our operations, are also subject to the federal Clean Water Act and analogous state laws. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit.  Some of our properties may require permits for discharges of storm water runoff and, as part of our overall evaluation of our current operations, we may apply for storm water discharge permit coverage and updating storm water discharge management practices at some of our facilities. We believe that we will be able to obtain, or be included under, these permits, where necessary, and be required make only minor modifications to existing facilities and operations that would not have a material effect on us. The Clean Water Act and similar state acts regulate other discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages.
 
These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil.  More specifically, we are required to develop and maintain a plan applicable to each of our properties at which any significant volume of crude oil or other substance is stored and to ensure the site has sufficient protections (such as berms, etc.) to ensure that any spill will be contained and not reach navigable waters.
 
The Safe Drinking Water Act, groundwater protection, and the Underground Injection Control Program
 
The federal Safe Drinking Water Act (SWDA), the Underground Injection Control (UIC) program promulgated under the SWDA and state programs all regulate the drilling and operation of salt water disposal wells. EPA directly administers the UIC program in some states and in others the responsibility for the program has been delegated to the state.  This program requires that a permit be obtained before drilling salt water disposal well. Monitoring the integrity of well casing must also be conducted periodically to ensure the casing is not leaking saltwater to groundwater.  Violation of these regulations and/or contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SWDA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
 
We have not heretofore engaged in extensive hydraulic fracturing or other well stimulation services on the wells for which we are the operator and when we do we engage third parties to conduct these operations on our behalf.  

The Clean Air Act
 
The federal Clean Air Act, enacted in 1970, and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements.  The EPA has developed and continues to develop stringent regulations under the authority of the Clean Air Act governing emissions of toxic air pollutants from specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.
 
Some of our operations are located in areas designated as “non-attainment” areas, which are geographic areas that do not meet the federal air quality standards.  Air emission controls and requirements in non-attainment areas are generally more stringent that those imposed in other areas, and the construction of new, or expansion of existing, sources may be restricted.
 
 
Climate change legislation and greenhouse gas regulation
 
The issue of “global warming” has attracted significant attention and many believe that emissions of certain gases contribute to this problem. Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, and the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are considered “greenhouse gases” regulated by the Kyoto Protocol.  Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products.
 
In summary, we may be subject to EPA greenhouse gas monitoring and reporting rules, and potentially new EPA permitting rules if adopted, that would apply greenhouse gas permitting obligations and emissions limitations under the federal Clean Air Act. Whether or not any federal greenhouse gas regulations are enacted, more than one-third of the states have begun taking action on their own to control and/or reduce emissions of greenhouse gases. Several multi-state programs have been developed or are in the process of being developed, including the Regional Greenhouse Gas Initiative involving 10 Northeastern states, the Western Climate Initiative involving seven western states, and the Midwestern Greenhouse Gas Reduction Accord involving seven states. The latter two programs have several other states acting as observers and they may join one of the programs at a later date. Any of the climate change regulatory and legislative initiatives described above could have a material adverse effect on our business, financial condition, and results of operations.
 
The National Environmental Policy Act
 
Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are potentially subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.
 
Threatened and endangered species, migratory birds, and natural resources
 
Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties, may act to prevent oil and gas exploration activities or seek damages for harm to species, habitat, or natural resources resulting from drilling, construction or releases of oil, wastes, hazardous substances or other regulated materials, and may seek compensation for alleged natural resources damages and in some cases, criminal penalties.
 
Hazard communications and community right to know
 
We are subject to federal and state hazard communications and community right to know statutes, including, but not limited to, the federal Emergency Planning and Community Right-to- Know Act,  and regulations. These regulations govern record keeping and reporting of the use and release of hazardous substances.
 
 
Occupational Safety and Health Act
 
We are subject to the requirements of the federal Occupational Safety and Health Act, commonly referred to as OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public.

Hydraulic Fracturing

There have been several regulatory and governmental initiatives to restrict the hydraulic-fracturing process, which could have an adverse impact on our completion or production activities. The U.S. Environmental Protection Agency (EPA) has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic-fracturing practices notwithstanding the existence of current oil and gas regulations adopted at the state level. Moreover, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected to be available by 2014. The EPA has also announced plans to propose effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities by 2014. Certain other governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices, including evaluations by the U.S. Department of Energy and the DOI, and coordination of an administration-wide review of these practices by the White House Council on Environmental Quality. Congress is currently considering, and has from time to time in the past considered, bills that would regulate hydraulic fracturing and/or require public disclosure of chemicals used in the hydraulic-fracturing process. A number of states, including states in which we operate, have adopted or are considering legal requirements that could impose more stringent permitting, public disclosure, and well-construction requirements on hydraulic-fracturing activities.
 
These laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Compliance with these laws and regulations also, in most cases, requires new or amended permits that may contain new or more stringent technological standards or limits on emissions, discharges, disposals, or other releases in association with new or modified operations. Application for these permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with public notice and comment periods required prior to the issuance or amendment of a permit as well as the agency’s processing of an application. Many of the delays associated with the permitting process are beyond the control of the Company.
 
Many states where the Company operates also have, or are developing, similar environmental laws, regulations, or analogous controls governing many of these same types of activities. While the legal requirements may be similar in form, in some cases the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the development of a project or substantially increase the cost of doing business. 
 
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as new standards, such as air emission standards and water quality standards, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change and the threat of adverse impacts to groundwater arising from hydraulic-fracturing activities, are expected to continue to have an increasing impact on the Company’s operations.
 
Employees

As of December 31, 2011, we had 62 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.
 
Available Information
 
We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Isramco, Inc., that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov .
 

ITEM 1A. RISK FACTORS

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

Prices for oil, natural gas and NGLs ((Natural Gas Liquids) can fluctuate widely. Our revenues, operating results and future growth rates are highly dependent on the prices we receive for our oil, natural gas and NGLs. Historically, the markets for oil, natural gas and NGLs have been volatile and may continue to be volatile in the future. For example, in recent years market prices for natural gas in the United States have declined substantially from the highs achieved in 2008 and the rapid development of shale plays throughout North America has contributed significantly to this trend. Factors influencing the prices of oil, natural gas and NGLs are beyond our control. These factors include, among others:

·  
the worldwide military and political environment, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities or further acts of terrorism in the United States, or elsewhere, particularly Israel;
·  
worldwide and domestic supplies of crude oil, natural gas and NGLs;
·  
actions taken by foreign oil and gas producing nations;
·  
the level of global crude oil and natural gas inventories;
·  
the price and level of foreign imports of oil, natural gas and NGLs;
·  
the effect of worldwide energy conservation efforts;
·  
the price and availability of alternative and competing fuels;
·  
the cost of exploring for, developing, producing, transporting, and marketing oil, natural gas, and NGLs;
·  
the availability of pipeline capacity and infrastructure;
·  
the availability of crude oil transportation and refining capacity;
·  
consumer demand for oil, gas and NGLs;
·  
the growth of consumer product demand in emerging markets, such as India and China;
·  
labor unrest in oil and natural gas producing regions;
·  
regional pricing differentials;
·  
weather conditions;
·  
electricity dispatch;
·  
domestic and foreign governmental regulations and taxes; and
·  
the overall economic environment.
 
The long-term effect of these and other factors on the prices of oil, natural gas and NGLs are uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:

·  
adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;
·  
reducing the amount of oil, natural gas and NGLs that we can produce economically;
·  
causing us to delay or postpone some of our capital projects;
·  
reducing our revenues, operating income and cash flows;
·  
reducing the carrying value of our crude oil and natural gas properties;
·  
reducing the amounts of our estimated proved oil and natural-gas reserves;
·  
reducing the standardized measure of discounted future net cash flows relating to oil and natural-gas reserves; and
·  
limiting our access to sources of capital, such as equity and long-term debt.
 
 
Our domestic operations are subject to governmental risks that may impact our operations.
 
Our domestic operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, tribal, local and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies, price or gathering-rate controls, hydraulic fracturing and environmental protection regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including environmental and tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, currently proposed federal legislation, that, if adopted, could adversely affect our business, financial condition and results of operations, includes the following:
 
  ·  
 
 
Climate Change Congress has considered climate-change legislation that would seek to reduce emissions of green-house gases (GHGs) through establishment of a “cap-and-trade” plan. It is not possible at this time to predict whether or when Congress may re-introduce or act on climate-change legislation. The U.S. Environmental Protection Agency (EPA) has made findings that emissions of GHGs present a danger to public health and the environment and, based on these findings, has adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain sources, including, among others, onshore and offshore oil and natural-gas production facilities, which includes certain of our operations, on an annual basis. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.
 
  ·  
Taxes. The U.S. President’s Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural-gas exploration and development, and (iii) implementing certain international tax reforms.
 
  ·  
Hydraulic Fracturing is an essential and common practice used to stimulate production of natural gas and/or oil from dense subsurface rock formations such as shales that generally exist between 4,000 and 14,000 feet below ground. We apply hydraulic-fracturing techniques in some of our U.S. onshore oil and natural-gas drilling and completion programs. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The process is typically regulated by state oil and natural-gas commissions; however, the EPA, recently asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In February 2012, the DOI released draft regulations governing hydraulic fracturing on federal and Indian oil and gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing, and monitoring of well-stimulation operations. In addition, Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process are adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.
 
Certain states in which we operate, including, Louisiana, Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and additional well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and/or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, in the event state or local restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.
 
There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic-fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities and plans to propose these standards by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Also, the DOI is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. These ongoing or proposed studies, depending on any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.
 
  
The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.
 
The Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), signed into law in 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation required the Commodities Futures Trading Commission ("CFTC") and the Securities and Exchange Commission (SEC) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In July 2010, the CFTC granted temporary exemptive relief from certain swap regulation provisions of the legislation until December 21, 2011, or until the agency finalized the corresponding rules. In December 2011, the CFTC extended the potential latest expiration date of the exemptive relief to July 16, 2012. In its rulemaking under the new legislation, the CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions are exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize other regulations, including critical rulemaking on the definition of “swap”, “swap dealer” and “major swap participant.” Depending on the Company’s classification, the financial reform legislation may require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities. The financial reform legislation may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the legislation and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural-gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

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 future drilling. Drilling for oil and gas involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs or crews and the delivery of equipment. Although we believe that the use of 3-D seismic data and other advanced technology should increase the probability of success of our wells and should reduce average finding costs through elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic data and other traditional methods, drilling remains an inexact and speculative activity. In addition, the use of 3-D seismic data and such technologies requires greater pre-drilling expenditures than traditional drilling strategies and we could incur losses because of such expenditures. Our future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse effect on our future results of operations and financial condition. Although we may discuss drilling prospects that have been identified or budgeted for, we may ultimately not lease or drill these prospects within the expected time frame, or at all. We may identify prospects through a number of methods, some of which do not include interpretation of 3-D or other seismic data. The drilling and results for these prospects may be particularly uncertain. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including (i) the results of exploration efforts and the acquisition, review and analysis of the seismic data, (ii) the availability of sufficient capital resources and the other participants for the drilling of the prospects, (iii) the approval of the prospects by other participants after additional data has been compiled, (iv) economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews, (v) our financial resources and results (vi) the availability of leases and permits on reasonable terms for the prospects and (vii) the payment of royalties to lessors. There can be no assurance that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas. There are numerous uncertainties in estimating quantities of proved reserves, including many factors beyond our control.
 
 
 
Failure to fund continued capital expenditures could adversely affect our properties.
 
Our acquisition, exploration, and development activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations and loans from commercial banks and related parties. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of crude oil and natural gas, and our success in finding, developing and producing new reserves. If revenues were to decrease as a result of lower crude oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves, resulting in a decrease in production over time. If our cash flows from operations are not sufficient to meet our obligations and fund our capital budget, we may not be able to access debt, equity or other methods of financing on an economic basis to meet these requirements, particularly in the current economic environment. If we are not able to fund our capital expenditures, interests in some properties might be reduced or forfeited as a result.
 
Poor general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy.
 
These factors, combined with volatile oil, natural-gas and NGLs prices, declining business and consumer confidence, and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, or if an economic recovery is slow or prolonged, demand for petroleum products could continue to diminish or stagnate, which could impact the price at which we can sell our oil, natural gas and NGLs, affect our vendors’, suppliers’ and customers’ ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition.
 
Estimates of proved oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.
 
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 or understated. The reserve information included or incorporated by reference in this report represents estimates prepared by our independent reserve engineering firms; Netherland, Sewell & Associates and Cawley, Gillespie & Associates, Inc. Estimation of reserves is not an exact science. Estimates of economically recoverable oil and natural-gas reserves and of future net cash flows depend on a number of variable factors and assumptions, any of which may cause actual results to vary considerably from these estimates, such as:
 
 
•
 
historical production from an area compared with production from similar producing areas;
 
 
•
 
assumed effects of regulation by governmental agencies and court rulings;
 
 
•
 
assumptions concerning future oil and natural-gas prices, future operating costs and capital expenditures;
 
 
•
 
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 by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues, and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The discounted cash flows included in this report should not be construed as the fair value of the estimated oil, natural-gas, and NGLs reserves attributable to our properties. For the December 31, 2011, 2010, and 2009 reserves, in accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are based on average 12-month sales prices using the average beginning-of-month price, while reserves for all periods prior to December 31, 2009, are based on year-end sales prices. Actual future prices and costs may differ materially from the SEC regulation-compliant prices used for purposes of estimating future discounted net cash flows from proved reserves.
  
 
 
Discoveries or Acquisitions of reserves are needed to avoid a material decline in reserves and production.

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

Our oil and gas revenues are generated through oil and gas leases. These leases are conditioned on the performance of certain obligations, primarily the obligation to produce oil and/or gas or engage in operations designed to result in the production of oil and gas.  If production ceases and operations are not commenced within a specified time, the lease may be lost.  The loss of our leases may have a material impact on our revenues.
 
In the case of Israeli-based properties, we have interests in licenses that, subject to certain conditions, may result in leases being granted.  The leases are subject to certain obligations and are renewable at the discretion of various governmental authorities.  As such, if the parties responsible for operations are not able to fulfill their obligations under the leases, the leases may be modified, cancelled, not renewed, or renewed on terms different from the current leases.  The modification or cancellation of our leases could eliminate our interests and may have a material impact on our revenues.
 
Our business is highly competitive.

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

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

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

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

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

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

·  
our actual production is less than hedged volumes;

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

·  
the counterparties to our hedging agreements fail to perform under the contracts.
 
·  
a sudden unexpected event materially impacts oil and natural-gas prices.

The credit risk of financial institutions could adversely affect us.

We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, insurance companies and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions through our derivative transactions. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.

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

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

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

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

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

·  
human error, accidents, labor force and other factors beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;

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

·  
unavailability of materials and equipment;

·  
engineering and construction delays;
 
·  
unanticipated transportation costs and delays;

·  
unfavorable weather conditions;
 
·  
hazards resulting from unusual or unexpected geological or environmental conditions;
   
·  
environmental regulations and requirements;
 
·  
accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids, into the environment;

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

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

·  
the availability of alternative fuels and the price at which they become available.
 
 
We do not insure against all potential losses and could be materially and adversely affected by unexpected liabilities.

Our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development, production, processing and transportation of oil, natural gas and NGLs. Such risks include potential blowouts, cratering, fires, loss of well control, mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals. The occurrence of any of these risks could result in environmental pollution, damage to or destruction of our property, equipment and natural resources, injury to person or loss of life. Additionally, for our non-operated properties, we generally depend on the operator for operational safety and regulatory compliance.

To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well control, business interruption and pollution events that are considered sudden and accidental. We also maintain worker’s compensation and employer’s liability insurance. However, our insurance coverage does not provide 100% reimbursement of potential losses resulting from these operational hazards. Additionally, insurance coverage is generally not available to us for pollution events that are considered gradual, and we have limited or no insurance coverage for certain risks such as political risk, war and terrorism. Our insurance does not cover penalties or fines assessed by governmental authorities. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our profitability, financial condition and liquidity.

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

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

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

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

·  
other hazards arising out of Israeli governmental sovereignty over areas in which we own oil and gas interests.
 
 
Members of Isramco’s management team own a significant amount of common stock, giving them influence or control in corporate transactions and other matters, and the interests of these individuals could differ from those other shareholders.
 
Members of our management team beneficially own approximately 60.95% of our outstanding shares of common stock as of March 23, 2012. As a result, these shareholders are in a position to significantly influence or control the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of an amendment to our certificate of incorporation or bylaws and the approval of mergers and other significant corporate transactions.
 
Our stock price is volatile and could continue to be volatile and has limited liquidity; Accordingly, investors may not be able to sell any significant number of shares of our stock at prevailing market prices.

Investor interest in our common stock may not lead to the development of an active or liquid trading market. The market price of our common stock has fluctuated in the past and is likely to continue to be volatile and subject to wide fluctuations. In addition, the stock market has experienced extreme price and volume fluctuations. The stock prices and trading volumes for our stock has fluctuated widely  and the average daily trading volume of our stock continues to be limited and may continue  for reasons that may be unrelated to business or results of operations. General economic, market and political conditions could also materially and adversely affect the market price of our common stock and investors may be unable to resell their shares of common stock at or above their purchase price.  As a result of the limited trading in our stock, it may be difficult for investors to sell their shares in the public market at any given time at prevailing prices.
 
ITEM 1B. UNRESOLVED STAFF COMMENTS

None.
 
ITEM 2. PROPERTIES
 
Oil and Gas Exploration and Production - Properties and Reserves
 
Reserve Information. For estimates of Isramco's net proved reserves of natural gas, crude oil and natural gas liquids, see Note 16 to Consolidated Financial Statements, Supplemental Oil and Gas Information.
 
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Note 16 to Consolidated Financial Statements, Supplemental Oil and Gas Information, represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas, crude oil and condensate and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. For related discussion, see ITEM 1A. Risk Factors.
 
We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for us to conduct business in the future.
 
ITEM 3. LEGAL PROCEEDINGS
 
We previously disclosed information relating to two putative shareholder derivative petitions that were filed by individual shareholders of the Company in the District Court of Harris County, Texas.  These petitions each named certain of our officers and directors as defendants.  Each of these suits claims that the shareholders were damaged as a result of various breaches of fiduciary duty, self dealing and other wrongdoing in connection with the Restated Agreement between the Company and Goodrich Global, Ltd (“Goodrich”) and other matters, primarily on the part of the Company’s Chairman and Chief Executive Officer, Haim Tsuff, and Jackob Maimon. Jackob Maimon is a former President and a director who resigned from all positions held with us on June 29, 2011.

On or about April 6, 2011, a third complaint was filed in the 295th District Court of Harris County, Texas by Yuval Ran, who claimed to be a shareholder, against certain of our officers and directors and several corporate parties controlled by Haim Tsuff.  As with the prior suits, this complaint alleged various breaches of duty, self dealing and other wrongdoing in connection with the Restated Agreement between the Company and Goodrich, primarily on the part of the Company’s Chairman and Chief Executive Officer, Haim Tsuff, and Jackob Maimon  In addition, this suit alleged claims relating to other transactions between the Company and entities controlled by Haim Tsuff, including but not limited to the loan transactions between the Company and related parties, the lease and sale of a cruise ship, and the closure of the Company’s Israel branch office.  The third complaint was transferred to the 55th Judicial District Court of Harris County, Texas, by order signed April 20, 2011, and consolidated with the above-referenced first and second complaints by order signed May 21, 2011, into a single case, called “Lead Cause No. 2010-34535; In Re Isramco, Inc. Shareholder Derivative Litigation; In the 55th Judicial District Court of Harris County, Texas (the “Derivative Litigation”).
  
We also disclosed information in our quarterly report for the three months ended September 30, 2011 relating to an additional putative shareholder derivative complaint that was filed by an individual shareholder, Yuval Lapiner, on July 7, 2011 in the Delaware Chancery Court in Wilmington, Delaware, naming certain of our officers and directors as defendants. The claims asserted in this case are essentially the same damage claims as asserted in the lawsuit filed in April 2011 and described above. The Company filed motions in the Chancery Court to Dismiss or Stay the lawsuit and, by order dated October 20, 2011, the case was dismissed. The plaintiff did not appeal. Yuval Lapiner then filed a motion to intervene in the Derivative Litigation and that motion was denied Mr. Lapiner then filed a motion for attorney’s fees that was also denied.  On December 12, 2011 the court approved the terms of the mediated settlement and entered final order and judgment in the case.  The Company paid plaintiff attorney’s fees in the amount of $1,000,000 and replaced its bylaws, amended various committee charters and adopted other corporate governance changes as set out in the stipulation.  After the judgment was rendered Mr. Lapiner filed a motion for new trial and on February 12, 2012 filed a Notice of Appeal to the Fourteenth Court of Appeals in Houston, Texas. We do not believe the appeal will be successful nor do we believe there will be any change in the judgment.

On or about September 21, 2011, the Company’s former general counsel, Dennis Holifield resigned.  Mr. Holifield had been hired in March, 2011. On or about October 12, 2011, Mr. Holifield submitted a “Summary Report” to the SEC (the “Summary Report”), in which made numerous factual allegations regarding Haim Tsuff, the Company‘s Chief Executive Officer and Chairman; Edy Francis, the Company’s Chief Financial Officer; Amir Sanker, the Company’s Asset Manager; and other Company personnel.  In the Summary Report, Mr. Holifield characterized the alleged conduct as illegal or criminal.  On October 31, 2011 the Company received a written demand from, Mr. Holifield’s attorney on the Company for $900,000.

Messrs. Tsuff, Francis, and Sanker have reviewed all of Mr. Holifield’s allegations and have advised the Company that they have not engaged in any criminal conduct or other illegal activity. As of November 3, 2011, the Company’s Board of Directors has constituted a committee of independent directors consisting of Max Pridgeon and Asaf Yarkoni which has been directed to investigate all of the Holifield allegations and report back to the full board and make any recommendations, if any, for corrective action.

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.

Not applicable.  
 
 
PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
 
Our common stock is listed on the Nasdaq Capital Market under the symbol "ISRL". The following table sets forth for the periods indicated, the reported high and low closing prices for our common stock . As of March 22, 2012, there were approximately 268 holders of record of our common stock.

 
High
 
Low
 
2011
           
First Quarter
 
$
86.50
   
$
56.14
 
Second Quarter
   
68.66
     
58.99
 
Third Quarter
   
69.00
     
53.40
 
Fourth Quarter
   
93.40
     
55.05
 
         
2010
               
First Quarter
 
$
80.10
   
$
49.00
 
Second Quarter
   
70.50
     
45.05
 
Third Quarter
   
61.12
     
45.56
 
Fourth Quarter
   
90.36
     
55.96
 

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 and an owner of various royalty interests offshore Israel. Our properties are primarily located in Texas, New Mexico and Oklahoma and Israel. We act as the operator of most of our U.S. 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.  In 2011 we created a new subsidiary that provides well maintenance and workover services, well completion and recompletion services.
 
 
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, 2011, our estimated total proved oil, natural gas reserves and natural gas liquids, as prepared by our independent reserve engineering firms, Netherland, Sewell & Associates, Inc and Cawley, Gillespie & Associates, Inc., were approximately 34,990 thousand barrels of oil equivalent (“MBOE”), consisting of 3,234 thousand barrels (MBbls) of oil, and 179,155 million cubic feet (MMcf) of natural gas and 1,896 thousand barrels (MBbls) of natural gas liquids. Approximately 27% of our proved reserves were classified as proved developed (See Note 16 Supplemental Oil and Gas Information to Consolidated Financial Statements to our consolidated financial statements). Full year 2011 production averaged 2.16 MBOE/d compared to 2.3 MBOE/d in 2010.
 
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
 
Isramco estimates its proved oil and gas reserves as defined by the SEC and the FASB. This definition includes crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, government regulations, etc., i.e., at prices and costs as of the date the estimates are made. Prices include consideration of price changes provided only by contractual arrangements, and do not include adjustments based upon expected future conditions.
The Company’s estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually by our independent reserve engineering firm, Cawley, Gillespie & Associates, Inc and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions, and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A and could result in property impairments.

Depreciation, Depletion and Amortization

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

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

Asset Retirement Obligations

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

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 36 and 3 months, respectively. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivative contracts, which would potentially allow us to not record the change in fair value of our derivative contracts in the consolidated statements of operations. We carry our derivatives at fair value on our consolidated balance sheets, with the changes in the fair value included in our consolidated statements of operations in the period in which the change occurs. Our results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivative contracts.
 
Environmental Obligations and Other Contingencies
 
Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental remediation, litigation, and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability is incurred and reasonable estimates of the liability can be made. Estimates of environmental liabilities are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change the Company’s estimate of environmental-remediation costs, such as changes in laws and regulations, changes in the interpretation or administration of laws and regulations, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment, and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental or other contingent matters and actual costs may vary significantly from the Company’s estimates. The Company’s in-house legal counsel regularly assesses these contingent liabilities and, in certain circumstances, consults with third-party legal counsel or consultants to assist in forming the Company’s conclusion.
 
Income Taxes

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

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

Liquidity and Capital Resources
 
Our primary historical sources of capital and liquidity are internally generated cash flows from operations, availability under our senior credit agreement with our unrelated bank lenders with Bank of Nova Scotia (“Senior Credit Agreements”) and loans from various related party lenders (“Related Party Loans”) and asset dispositions. We continuously monitor our liquidity and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources and drilling success.
 
 
Note 6 to our Consolidated Financial Statements, Long-Term Debt and Interest Expense, describes the Senior Credit Agreements and Related Party Loans. Our Senior Credit Agreements originally provided a total $300 million in credit facilities. As of December 31, 2011, the total available borrowing base was zero.

On March 3, 2011 the Company terminated its relationship with Wells Fargo and repaid its outstanding balance.  

The borrowing base which relates to our oil and natural gas properties is redetermined on a semi-annual basis (with the Company and the lenders each having the right to one unscheduled redetermination per year) and adjusted based on our oil and natural gas properties, reserves, other indebtedness and other relevant factors. During the fourth quarter of 2011 the Lenders reduced the borrowing base to $0.  The Company is repaying the approximately $20,000,000 outstanding balance in six installments of $3,333,000 each with the first two payments already made for January and February 2012 and the remaining installments due each month thereafter through June 2012 when the entire balance will be repaid.  The Company is also in negotiations for similar credit facilities with several other commercial lenders, to obtain terms most favorable to the Company. While optimistic of a positive outcome of our consolidation efforts, the Company is uncertain as to whether it will be successful in obtaining new replacement financing or, if it is obtained, the timetable upon which such facility will be closed and other material terms and conditions. The Company believes that during the interim period that the terms of existing affiliate financing will remain flexible and additional funding will be made available if needed until a new credit facility can be entered. See Note 6 to Consolidated Financial Statements, Long-Term Debt and Interest Expense.
 
Our future capital resources and liquidity may depend, in part, on our success in developing the leasehold interests that we have acquired. Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success in finding and acquiring additional reserves. We expect to fund our future capital requirements through internally generated cash flows and borrowings under our Senior Credit Agreements. Long-term cash flows are subject to a number of variables, including the level of production and prices and our commodity price hedging activities as well as various economic conditions that have historically affected the oil and natural gas industry. 
 
Debt

   
As of December 31,
 
   
2011
   
2010
   
2009
 
   
(In thousands except percentage)
 
Senior Credit Facilities
 
$
-
   
$
22,725
   
$
32,950
 
Long – term debt – related party
   
60,211
     
76,354
     
79,354
 
Short – term debt – related party
   
6,456
     
-
     
-
 
Current maturities of long-term debt, short-term debt and bank overdraft
   
32,009
     
17,350
     
12,366
 
Total debt
   
98,676
     
116,429
     
124,670
 
                         
Stockholders’ equity
   
18,548
     
18,537
     
13,733
 
                         
Debt to capital ratio
   
84%
     
86
%
   
90
%
 
At year-end 2011, our total debt was $98,676,000, compared to total debt of $116,429,000 at year-end 2010 and $124,670,000 at year-end 2009. As of December 31, 2011, current debt included $20,000,000 as current maturities of the Senior Credit Facilities. During the fourth quarter of 2011 the Lenders reduced the borrowing base to $0.  The Company is repaying the approximately $20,000,000 outstanding balance in six installments of $3,333,000 each with the first two payments already made for January and February 2012 and the remaining installments due each month thereafter through June 2012 when the entire balance will be repaid.
 
On March 3, 2011, the Company entered into a Loan Agreement with I. O. C. - Israel Oil Company, LTD., an affiliate of the Company (“IOC”) pursuant to which it borrowed the sum of $11 million. The loan bears interest at a rate of 10% per annum and is payable in quarterly payments of interest only until March 3, 2012, when all accrued interest and principal is due and payable.  The loan may be prepaid at any time without penalty.  The loan is unsecured.  The purpose of the loan was to provide funds to Isramco for the payment of amounts due under the Wells Fargo Senior Credit Facility at maturity.  On March 3, 2011 Isramco paid the outstanding principal balance due under the Wells Fargo Senior Credit Agreement.  Subsequently, on March 9, 2011, pursuant to an agreement with Wells Fargo, the derivative contracts between Isramco and Wells Fargo were terminated at a cost to the Company of approximately $7,000,000.  Concurrently, the Company entered into new derivative contracts for 336,780 barrels of crude oil during the 46 month period commencing March 2011 with Macquarie Bank, N.A. During September 2011 Isramco paid $5,096,000 of principal and interest pursuant to Loan agreement with IOC. The Company is actively pursuing a consolidation of all outstanding debt with Macquarie Bank and other commercial lenders.
 
In October 2011 the agreement with IOC, pertaining to a loan in the outstanding principal amount of $6,456,000 was renegotiated. The payoff of principal amount was extended by 6 months to September 9, 2012. Interest accrued per annum was determined on LIBOR+5.5% from initial 10%.
 

Off-Balance Sheet Arrangements
 
At December 31, 2011, we did not have any off-balance sheet arrangements.
 
Cash Flow

Our primary source of cash in 2011 was cash flow from operating activities, loans from related party and proceeds from sale of investment in MediaMind Ltd shares. Our primary source of cash in 2010 and 2009 was our operating activities. In 2011 cash received from operations, from selling of investment in MediaMind Ltd shares and from related party was offset by repayments of borrowings under our Senior Credit Agreements, repayment of related party loans, purchase of equipment and payments made on settled derivatives contracts. In 2010 and 2009, cash received from operations was offset by repayments of borrowings under our Senior Credit Agreements and cash used in payments on addition to oil and gas properties, net of any divestiture activities.

Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Working capital was substantially influenced by these variables. Fluctuation in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal fluctuations characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See Results of Operations below for a review of the impact of prices and volumes on sales.
 
    Years Ended December 31,  
    2011     2010     2009  
    (In thousands)  
Cash flows provided by operating activities
 
$
6,946
   
$
12,063
   
$
21,519
 
Cash flows provided by (used in) investing activities
   
7,643
     
(1,437
)
   
(332
)
Cash flows used in financing activities
   
(18,124
)
   
(7,876
)
   
(21,421
) 
Net increase (decrease) in cash
 
$
(3,535
)
 
$
2,750
   
$
(234
) 

Operating Activities, Net cash flows prov i ded by operating activities were $6,946,000, $12,063,000 and $21,519,000 for the years ended December 31, 2011, 2010 and 2009, respectively. Key drivers of net operating cash flows are commodity prices, production volumes, hedging activities and operating cost.

During the year ended December 31, 2011, compared to the same period in 2010, net cash flow provided by operating activities decreased by $5,117,000 to $6,946,000. This decrease was primarily attributable to net cash paid on settled derivatives contracts of $7,007,000, less cash received on proceeds from settlements of derivative contracts, higher lease operating expenses all of which were partially offset by increased oil and natural gas liquids (“NGLs”) revenues.  The increase in revenues was primarily attributable to higher average oil and NGLs prices for the year ended December 31, 2011 of $94.12/bbl and $50.24/bbl respectively,  compared to $77.26/bbl and $36.97/bbl for the year ended December 31, 2010. However, we are unable to predict future production levels or future commodity prices, and, therefore, we cannot predict future levels of net cash provided by operating activities.

Net cash provided by operating activities decreased in 2010 compared to 2009 primarily due to a reduction in working capital of $4,549,000, higher lease operating expenses and expenses related to our well plugging and abandonment obligations. The reduction in net cash proceeds from our commodity price hedging activities of $8,308,000 was offset by increased oil and natural gas revenues of $8,561,000. The increase in revenues was primarily attributable to higher average oil, gas and NGLs prices for the year ended December 31, 2010 of $77.26/bbl, $4.71/mcf and $36.97/bbl, compared to $58.52/bbl, $3.48/mcf and $28.83/bbl for the year ended December 31, 2009.

Investing Activities, The primary driver of cash provided by investing activities in 2011 was proceeds from sale of marketable securities which was offset by purchase of other property and equipment of approximately $6,500,000 and an additional $2,549,000 spent on capital expenditures. Net cash   flows provided (used in) in investing activities for the years ended December 31, 2011 and 2010 were $7,643,000 and $(1,437,000) respectively.
 
In 2010, we spent an additional $3,454,000 on capital expenditures and an additional $157,000 on other property and equipment. We participated in the drilling of 3 gross wells in 2010. In December, 2010, we completed the sale of our interests in certain properties in Wise and Parker Counties, Texas, for approximately $2.2 million.
 
In 2009, we spent an additional $645,000 on capital expenditures and other property and equipment.
 
 
Financing Activities, Net cash flows used in financing activities were $18,124,000 and $7,876,000 for the years ended December 31, 2011 and 2010, respectively. Excess cash flow from proceeds of sale of marketable securities, operations and a loan from related party were primarily used to repay borrowings under our Senior Credit Agreements to the extent available. During the year ended in 2011, we repaid borrowings of $29,612,000. During the year ended in 2010, we repaid borrowings of $7,876,000.
 
Results of Continuing Operations

Selected Data
     
   
Years Ended December 31,
   
2011
   
2010
 
2009
   
(In thousands except per share and MBOE amounts)
Financial Results
                 
Oil and Gas sales
 
$
44,228
   
$
39,329
   
$
30,768
 
Other
   
1,420
     
2,871
     
956
 
Total revenues and other
   
45,648
     
42,200
     
31,724
 
                         
Cost and expenses
   
41,278
     
41,059
     
42,024
 
Other expense (income)
   
(6,991
)
   
5,784
     
13,369
 
Income tax expense (benefit)
   
3,975
     
(1,856
)
   
(10,090
)
Net income (loss) attributable to common shareholders
   
7,386
     
(2,787
)
   
(13,579
)
Net income attributable to noncontrolling interests
   
5
     
-
     
-
 
Net income (loss) attributable to Isramco
   
7,381
     
(2,787
)
   
(13,579
)
Earnings (loss) per common share – basic
 
$
2.72
   
$
(1.03
)
 
$
(5.00
)
Earnings (loss) per common share –diluted
 
$
2.72
   
$
(1.03
)
 
$
(5.00
)
                         
Weighted average number of shares outstanding-basic
   
2,717,691
     
2,717,691
     
2,717,691
 
Weighted average number of shares outstanding- diluted
   
2,717,691
     
2,717,691
     
2,717,691
 
                         
Operating Results
                       
Adjusted EBITDAX ( 1 )
 
$
30,606
   
$
22,472
   
$
26,796
 
Total proved reserves (MBOE)
   
34,990
     
9,031
     
8,565
 
Annual sales volumes (MBOE)
   
789
     
841
     
886
 
                         
Average cost per MBOE:
                       
Production (excluding transportation and taxes)
 
$
20.55
   
$
18.32
   
$
12.99
 
General and administrative
 
$
5.63
   
$
6.09
   
$
4.64
 
Depletion
 
$
12.66
   
$
14.44
   
$
17.34
 

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

Financial Results
 
Net Income, our net income was $7,381,000, or $2.72 per share for the year ended December 31, 2011. This compares to net loss of ($2,787,000), or ($1.03) per share, for the year ended December 31, 2010.
 
The increase in net income was primarily due to the impact of sale of marketable securities, derivatives, higher oil and NGLs sales revenues due to higher prices and lower depreciation, depletion and amortization expenses. This was partially offset by a decrease in sales volumes of natural gas, oil and natural gas liquids (“NGLs”) caused by natural decline in production, higher taxes paid due to increase in revenues, higher impairments of oil and gas assets and higher lease operating expenses.

Our net loss for 2010 totaled ($2,787,000), or ($1.03) per share, compared to a net loss for 2009 of ($13,579,000), or ($5.00) per share. The decrease in net loss was primarily due to higher natural gas, oil and NGLs sales revenues due to higher prices, the impact of derivatives, lower depreciation, depletion and amortization expenses and lower interest expense. This was partially offset by a decrease in sales volumes of natural gas, oil and NGLs caused by adverse weather conditions in Texas that restricted our ability to access, repair and maintain our wells in the first quarter of 2010, along with the natural decline in production, and higher lease operating expenses.
 
Revenues, Volumes and Average Prices
Sales Revenues
 
 
Years Ended December 31,
 
In thousands except percentages
2011
 
2010
   
D vs. 2011
 
2009
   
D vs. 2010
 
Gas sales
 
$
11,135
   
$
11,157
     
NM
%
 
$
9,124
     
22
%
Oil sales
   
26,260
     
22,405
     
17
     
17,147
     
31
 
Natural gas liquid sales
   
6,833
     
5,767
     
18
     
4,497
     
28
 
Total
 
$
44,228
   
$
39,329
     
12
%
 
$
30,768
     
28
%
 
NM—not meaningful

Our sales revenues for the year ended December 31, 2011 increased by 12% when compared to the same period of 2010, mainly due to higher oil and NGLs commodity prices. Our sales revenues for the year ended December 31, 2010 increased by 28% when compared to the same period of 2009, mainly due to higher natural gas, oil and condensate and NGLs commodity prices.
 
Volumes and Average Prices
 
   
Years Ended December 31,
 
   
2011
   
2010
   
D vs. 2011
   
2009
   
D vs. 2010
 
Natural Gas
                             
Sales volumes Mmcf (2)
   
2,241
     
2,368
     
(5)
%
   
2,623
     
(10)
%
Price per Mcf (1)
 
$
4.97
   
$
4.71
     
6
   
$
3.48
     
35
 
Total gas sales revenues (thousands)
 
$
11,135
   
$
11,157
     
NM
 
 
$
9,124
     
22
%
                                         
Crude Oil
                                       
Sales volumes MBbl
   
279
     
290
     
(4)
%
   
293
     
(1)
%
Price per Bbl (1)
 
$
94.12
   
$
77.26
     
22
   
$
58.52
     
32
 
Total oil sales revenues (thousands)
 
$
26,260
   
$
22,405
     
17
%
 
$
17,147
     
31
%
                                         
Natural gas liquids
                                       
Sales volumes MBbl (2)
   
136
     
156
     
(13)
%
   
156
     
NM
%
Price per Bbl (1)
 
$
50.24
   
$
36.97
     
36
   
$
28.83
     
28
 
Total natural gas liquids sales revenues (thousands)
 
$
6,833
   
$
5,767
     
18
%
 
$
4,497
     
28
%
 
(1)    
Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.
 
(2)    
At the end of 2010, the company sold interests in several oil and gas properties which resulted in lower natural gas, oil and natural gas liquids ("NGLs") volumes in 2011.
 
 
The company’s natural gas sales volumes decreased by 5%, crude oil sales volumes by 4% and natural gas liquids sales volumes by 13% for the year ended December 31, 2011 compared to the same period of 2010.  This decrease was primarily caused by natural decline in production.

Our average natural gas price for the year ended December 31, 2011 increased by 6%, or $0.26 per Mcf, when compared to the same period of 2010. Our average crude oil price for the year ended December 31, 2011 increased by 22%, or $16.86 per Bbl, when compared to the same period of 2010. Our average natural gas liquids price for the ended December 31, 2011 increased by 36%, or $13.27 per Bbl, when compared to the same period of 2010.

In 2010 the Company’s natural gas sale volumes decreased by 10%, crude oil sale volumes by 1% and natural gas liquid sale volumes by 0% compared to 2009. This decrease was primarily caused by adverse weather conditions in Texas that restricted our ability to access, repair and maintain our wells in the first quarter of 2010, along with the natural decline in production.
 
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, 2011 compared to 2010 and 2009.

In thousands
 
Natural Gas
   
Oil
   
Natural gas liquids
 
2009 sales revenues
 
$
9,124
   
$
17,147
   
$
4,497
 
Changes associated with sales volumes
   
(887
)
   
(176
)
   
-
 
Changes in prices
   
2,920
     
5,434
     
1,270
 
2010 sales revenues
   
11,157
     
22,405
     
5,767
 
Changes associated with sales volumes
   
(598
)
   
(850
)
   
(739
)
Changes in prices
   
576
     
4,705
     
1,805
 
2011 sales revenues
 
$
11,135
   
$
26,260
   
$
6,833
 
 
Adjusted EBITDAX.
 
To assess the operating results of Isramco, management analyzes income from operations before income taxes, interest expense, exploration expense, unrealized gain (loss) on derivative contracts and DD&A expense and impairments (“Adjusted EBITDAX”). Adjusted EBITDAX is not a GAAP measure. Isramco’s definition of Adjusted EBITDAX excludes exploration expense because exploration expense is not an indicator of operating efficiency for a given reporting period, but rather is monitored by management as a part of the costs incurred in exploration and development activities. Similarly, Isramco excludes DD&A expense and impairments from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Isramco’s financing methods or capital structure. Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make payments on its long term loans. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations.
 
However, Adjusted EBITDAX, as defined by Isramco, may not be comparable to similarly titled measures used by other companies. Therefore, Isramco’s consolidated Adjusted EBITDAX should be considered in conjunction with income (loss) from operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect income from continuing operations and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Isramco’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) from operations before income taxes.
 
  
 
Years Ended December 31,
In thousands
 
2011
   
2010
   
2009
 
Income from operations before income taxes
 
$
11,361
   
$
(4,643
)
 
$
(23,669
)
Depreciation, depletion, amortization and impairment expense
   
14,016
     
13,893
     
21,119
 
Interest expense
   
7,760
     
7,646
     
9,219
 
Unrealized gain on derivative contract
   
(3,384
)
   
4,727
     
19,298
 
Accretion Expenses
   
853
     
849
     
829
 
Consolidated Adjusted EBITDAX
 
$
30,606
   
$
22,472
   
$
26,796
 
 
 
Operating Expenses

   
Years Ended December 31,
 
In thousands except percentages
 
2011
   
2010
   
D vs. 2011
   
2009
   
D vs. 2010
 
Lease operating expense, transportation and taxes
 
$
20,981
   
$
19,894
     
5
%
 
$
15,651
     
27
%
Depreciation, depletion and amortization
   
9,982
     
12,142
     
(18
)
   
15,368
     
(21
)
Impairments of oil and gas assets
   
4,034
     
1,751
     
130
     
5,751
     
(70
)
Accretion expense
   
853
     
849
     
NM
     
829
     
2
 
Production Services
   
675
     
-
             
-
         
Loss from plug and abandonment
   
315
     
1,300
     
(76
)
   
312
     
317
 
General and administrative
   
4,438
     
5,123
     
(13
)
   
4,113
     
25
 
   
$
41,278
   
$
41,059
     
1
%
 
$
42,024
     
(2
)%
 
During 2011, our operating expenses increased by 1% when compared to 2010 due to the following factors:

·  
Lease operating expense, transportation cost and taxes increased by 5%, or $1,087,000 in 2011 when compared to 2010.  This increase was the result of the costs associated with a plan we initiated last year to workover a number of our wells, along with the incremental costs involved in operating older, more mature fields that require additional repair and maintenance. In addition due to changes in regulatory requirements in Texas we incurred additional expenses regarding previously inactive wells in order to renew production in the future. Finally, the higher oil and NGL sales increased the taxes paid during 2011.  On a per unit basis, lease operating expenses (excluding transportation and taxes) increased by $2.23 per MBOE to $20.55 per MBOE in 2011 from $18.32 per MBOE in 2010.

·  
Depreciation, Depletion &Amortization (DD&A) of the cost of proved oil and gas properties is calculated using the unit-of-production method. Our DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact our composite DD&A rate and expense, including but not limited to field production profiles, drilling or acquisition of new wells, disposition of existing wells,  and reserve revisions (upward or downward) primarily related to well performance and commodity prices, and impairments. Changes in these factors may cause our composite DD&A rate and expense to fluctuate from period to period.  DD&A decreased by 18%, or $2,160,000, in 2011 when compared to 2010, primarily due to higher prices (per MBOE) that impacted our estimated total reserves, which are the basis for the depletion calculation, lower oil and gas production. On a per unit basis, depletion expense decreased by $1.78 per MBOE to $12.66 per MBOE in 2011 from $14.44 per MBOE in 2010.

·  
Impairments of oil and gas assets of $4,034,000 in 2011 were primarily a result of lower natural gas prices in general and the low volume of gas produced in a few of our fields.
 
·  
The expenses for production services pertain to our well service activities performed by our new subsidiary.

·  
General and administrative expenses decreased by 13%, or $685,000 in 2011 when compared to 2010, primarily due to attorney’s fees and expenses related to certain derivative litigation pending in Harris County, Texas incurred in 2010 which was finalized in 2011. The decrease was partially offset by legal expenses associated with legal claim submitted by former employee.
 
During 2010, our operating expenses decreased by 2% when compared to 2009 due to the following factors:

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

·  
Depreciation, Depletion &Amortization (DD&A) of the cost of proved oil and gas properties is calculated using the unit-of-production method. Our DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact our composite DD&A rate and expense, including but not limited to field production profiles, drilling or acquisition of new wells, disposition of existing wells, and reserve revisions (upward or downward) primarily related to well performance and commodity prices, and impairments. Changes to these factors may cause our composite DD&A rate and expense to fluctuate from period to period. Our DD&A decreased by 21%, or $3,226,000, in 2010 when compared to 2009 primarily due to higher prices (per MBOE) that impacted our estimated total reserves, which are the basis for the depletion calculation and the impact of a 2009 impairment of $5,751,000 on the depletable base used to calculate DD&A. On a per unit basis, depletion expense decreased by $2.90 per MBOE to $14.44 per MBOE in 2010 from $17.34 per MBOE in 2009.

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

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

Other expenses (income)

   
Years Ended December 31,
 
In thousands except percentages
 
2011
   
2010
   
D vs. 2011
   
2009
   
D vs. 2010
 
Interest expense net
 
$
7,760
   
$
7,646
     
1
%  
$
9,219
     
(17
)%
Realized gain on sale of investment and other
   
(15,910
)
   
-
             
(250
)
   
(100
) 
Net loss (gain) on derivative contracts
   
922
     
(1,862
)
   
(150
)
   
4,400
     
(142
)
Currency exchange rate differences
   
237
     
-
     
-
     
-
     
-
 
   
$
(6,991
)
 
$
5,784
     
(221
) %
 
$
13,369
     
(57
)%

Interest expense . Isramco’s interest expense increased by 1%, or $114 thousand, for the year ended December 31, 2011 compared to the same period of 2010.  This increase is primarily due to a new loan obtained by the company that was used, along with other proceeds and capital, to make required payments on debt to Macquarie Bank, N.A in connection with assignment and transfer of Wells Fargo Senior Credit Facility which were partially offset by the lower average outstanding balance of the loans.  
In 2010 Isramco’s interest expense decreased by 17%, or $1,573,000, for the year ended December 31, 2010 compared to the same period of 2009. This decrease is primarily due to the lower average outstanding balance of the loans which we obtained to fund the Five States acquisition in 2007 and the GFB acquisition in 2008, and to decreases in average LIBOR rates during 2010. The decrease was partially offset by the payments on interest rate swaps.

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, 2011, the Company had a $2.4 million derivative asset, of which $1 million was classified as current. For the year ended December 31, 2011, the Company recorded a net derivative loss of $0.9 million (a $3.4 million unrealized gain offset by a $4.3 million loss from net cash paid on settled contracts).

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

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

Income tax expense for the year ended December 31, 2011 was primarily driven by sale of investment in MediaMind shares. The net income resulted in $15.91 million.
 
Income tax benefit for the year ended December 31, 2010 decreased by $8.2 million from the prior year. The decrease in our income tax benefit from the prior year was primarily due to our pre-tax loss of $4.6 million for the year ended December 31, 2010 compared to our pre-tax loss of $23.7 million in 2009. The effective tax rates for the years ended December 31, 2011, 2010 and 2009 were 35%, 40% and 42.6%, respectively.
 
 
Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data–Note 1, “Summary of Significant Accounting Policies.”
 
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Derivative Instruments and Hedging Activity
 
We are exposed to various risks, including energy commodity price risk. If oil and natural gas prices decline significantly our ability to finance our capital budget and operations could be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have adopted a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The type of derivative instrument that we typically utilize is swaps. The total volumes which we hedge through the use of our derivative instruments vary from period to period.
 
We are exposed to market risk on our open derivative contracts of non-performance by our counterparties. However, we do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings. Each of the counterparties to our derivative contracts is a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement. Please refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Derivatives and Hedging Activities" for additional information.
 
We are also exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Periodically, we look to utilize interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. As of December 31, 2011 we did not have open interest rate swap positions. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.
 
We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Derivatives and Hedging Activities" for more details.
 
Fair Market Value of Financial Instruments
 
The estimated fair values for financial instruments under ASC 825, Financial Instruments , (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 7, "Fair Value of Financial Instruments" for additional information.
 
Interest Sensitivity
 
We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk results primarily from fluctuations in short-term rates, which are LIBOR based, that may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our obligations.

At December 31, 2011, total debt was $98,876,000.This debt bears interest at floating or market interest rates. The interest rate applicable to approximately 99% of this debt is based upon LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate.
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
The information called for by this Item 8 is included following the "Index to Financial Statements" contained in this Annual Report on Form 10-K.
 
 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES.
 
We have established disclosure controls and procedures to ensure that material information relating to Isramco, including its consolidated subsidiaries, is made known to the officers who certify Isramco’s financial reports and to other members of senior management and the Board of Directors.
 
Based on their evaluation, Isramco’s principal executive and principal financial officers have concluded that Isramco’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 2011 to ensure that the information required to be disclosed by Isramco in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
   
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Isramco’s management is responsible for establishing and maintaining adequate internal control over financial reporting for Isramco, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Isramco’s management, including our principal executive and principal financial officers, Isramco conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework, which was completed on March 12, 2012, management concluded that its internal control over financial reporting was effective as of December 31, 2011.

The effectiveness of Isramco’s internal control over financial reporting as of December 31, 2011 has been audited by MaloneBailey, LLP, an independent registered public accounting firm who audited Isramco’s consolidated financial statements as of and for the year ended December 31, 2011, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data” in this report.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
 
There was no change in Isramco’s internal control over financial reporting during the fourth quarter of 2011 that has materially affected, or is reasonably likely to materially affect, Isramco’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.
 
 
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, 2011 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.
 
 
PART IV
 
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Exhibits
 
3.1
 
Certificate of Incorporation of Registrant with all amendments filed as an Exhibit to the S-l Registration Statement, File No. 2-83574.
     
3.2
 
Amendment to Certificate of Incorporation filed March 17, 1993, filed as an Exhibit with the S-l Registration Statement, File No. 33-57482.
     
3.3
 
By-laws of Registrant filed as Exhibit 3(ii) to the 8-k filed January 18, 2012 and incorporated herein by reference.
     
4.1
 
First Amended and Restated Promissory Note dated as of February 27, 2007, issued to NAPHTHA ISRAEL PETROLEUM CORP., LTD. in the principal amount of $18,500,000 filed as an Exhibit to the 10-K for the year ended December 31, 2010 and incorporated herein by reference.
     
4.2
 
First Amended and Restated Promissory Note dated as of February 27, 2007, issued to NAPHTHA ISRAEL PETROLEUM CORP., LTD. in the principal amount of $11,500,000 filed as an Exhibit to the 10-K for the year ended December 31, 2010 and incorporated herein by reference.
     
4.3
 
First Amended and Restated Promissory Note dated as of February 27, 2007, issued to and I.O.C. ISRAEL OIL COMPANY, LTD. in the principal amount of $12,000,000 filed as an Exhibit to the 10-K for the year ended December 31, 2010 and incorporated herein by reference.
     
4.4
 
Promissory Note dated as of February 27, 2007, issued to and J.O.E.L JERUSALEM OIL EXPLORATION, LTD. in the principal amount of $7,000,000, filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
4.5
 
Promissory Note dated as of May 25, 2009, issued to and J.O.E.L JERUSALEM OIL EXPLORATION, LTD. in the principal amount of $48,900,000 filed as an Exhibit to the 10-K for the year ended December 31, 2010 and incorporated herein by reference.
     
10.1
 
Purchase and Sale Agreement, dated as of February 16, 2007, among Five States Energy Company, L.L.C. and each of the other parties listed as a party "Seller" on the signature pages thereof and ISRAMCO, Inc., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
10.2
 
LOAN AGREEMENT, dated as of February 27, 2007, between ISRAMCO, INC., and NAPHTHA ISRAEL PETROLEUM CORP., LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
10.3
 
LOAN AGREEMENT, dated as of February 27, 2007, between ISRAMCO, INC., and NAPHTHA ISRAEL PETROLEUM CORP., LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
10.4
 
LOAN AGREEMENT, dated as of February 27, 2007, Between ISRAMCO, INC., and I.O.C. ISRAEL OIL COMPANY, LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
10.5
 
LOAN AGREEMENT, dated as of February 26, 2007, between ISRAMCO, INC., and J.O.E.L JERUSALEM OIL EXPLORATION, LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
10.6
 
CREDIT AGREEMENT dated as of March 2, 2007 among ISRAMCO ENERGY, L.L.C., each of the lenders that is a signatory hereto or which becomes a signatory hereto; and WELLS FARGO BANK, N. A., a national banking association, as agent for the Lenders., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
 
10.7
 
GUARANTY AGREEMENT, dated as of March 2, 2007 by ISRAMCO, Inc. in favor of Wells Fargo Bank, N.A., as administrative agent (the "ADMINISTRATIVE AGENT") for the lenders that are or become parties to the Credit Agreement referred to in Item 10.6., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
10.8
 
PLEDGE AGREEMENT, dated as of March 2, 2007 by Isramco, Inc. in favor of Wells Fargo Bank, N.A., as administrative agent for itself and the lenders (the "LENDERS") which are parties to the Credit Agreement referred to in Item 10.6, filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
 
 
10.9
 
Employment Agreement dated as of September 1, 2007 between Isramco Inc. and Edy Francis, filed as an Exhibit to the 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference.+
     
10.10
 
Agreement dated as of December 31, 2007 between Isramco Inc. and I.O.C. Israel Oil Company Ltd and addendum dated January 1, 2008, filed as an Exhibit to the 10-Q for the quarter ended March 31, 2008 and incorporated herein by reference.
     
10.11
 
Amended and restated credit agreement dated on April 28, 2008 between Isramco Resources, LLC and The Bank of Nova Scotia and Capital One, N.A., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2008 and incorporated herein by reference.
     
10.12
 
Amended and Restated Loan Agreement dated as of May 25, 2008 between Isramco Inc. and J.O.E.L. Jerusalem Oil Explorations Ltd. filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
     
10.13
 
Amended and Restated Agreement dated as of November 17, 2008 between Isramco Inc. and Goodrich Global Ltd. filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
     
10.14
 
First Amendment to Loan Agreement dated as of February 1, 2009, between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd.($18.5 million) filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
     
10.15
 
First Amendment to Loan Agreement dated as of February 1, 2009, between Isramco, Inc, and Naphtha Israel Petroleum Corp., Ltd.($11.5 million) filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
     
10.16
 
Loan Agreement dated as of July 14, 2009 between Isramco, Inc. and I.O.C. – Israel Oil Company, Ltd.($6.0 million) filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
     
10.17
 
First Amendment to Loan Agreement dated as of February 1, 2009 between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd.($12.0 million) filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
     
10.18
 
Loan Agreement dated as of March 3, 2011 between Isramco, Inc. and I.O.C. – Israel Oil Company, Ltd.($11.0 million) filed as an Exhibit to the 10-K for the year ended December 31, 2010 and incorporated herein by reference.
     
 10.19*    First Amendment to Loan Agreement dated as of October 1, 2011 between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd. ($11.0 million)
     
 10.20*    2011 Stock Incentive Plan
     
14.1
 
Code of Ethics, filed as an Exhibit to Form 10-K for the year ended December 31, 2003.
     
23.1*
 
     
23.2*
 
     
31.1*
 
     
31.2*
 
     
32.1*
 
     
32.2*
 
     
99.1*
 
     
99.2*
 
     
101.INS
 
XBRL Instance Document
     
 101.SCH  
XBRL Taxonomy Extension Schema
     
 101.CAL  
XBRL Taxonomy Extension Calculation Linkbase
     
 101.DEF  
XBRL Taxonomy Extension Definition Linkbase
     
 101.LAB  
XBRL Taxonomy Extension Label Linkbase
     
 101.PRE  
XBRL Taxonomy Extension Presentation Linkbase
__________________________
* Filed Herewith.
+ Management Agreement
 
 
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 23, 2012
 
 
/S/ EDY FRANCIS                                                                                  
EDY FRANCIS,
CHIEF FINANCIAL OFFICER
(PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)
 
Date: March 23, 2012

 
Pursuant to the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the capacities and on the dates indicated.
 
Signature
 
Title
 
Date
         
/s/ Haim Tsuff                      
 
Chairman of the Board &
 
March 23, 2012
Haim Tsuff
 
 Chief Executive Officer
   
         
/s/ Josef From
 
Director
 
March 23, 2012
Josef From
       
         
/s/ Max Pridgeon
 
Director
 
March 23, 2012
Max Pridgeon
       
         
/s/ Frans Sluiter
 
Director
 
March 23, 2012
Frans Sluiter
       
         
/s/ Itai Ram
 
Director
 
March 23, 2012
Itai Ram
       
         
/s/ Asaf Yarkoni
 
Director
 
March 23, 2012
Asaf Yarkoni
       


INDEX TO FINANCIAL STATEMENTS

 
Page
F-1
F-2
F-3
F-4
F-5
F-6
F-7



 
 
 
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
 

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

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2011.

MaloneBailey, LLP, the Company’s independent registered public accounting firm, has issued an attestation report on the effectiveness on our internal control over financial reporting as of December 31, 2011.
 
 
/s/     Haim Tsuff                                                                                                                /s/     Edy Francis                  
Haim Tsuff                                                                                                                       Edy Francis
Chief Executive Officer                                                                                                Chief Financial Officer
 
 
Houston, Texas
March 23, 2012

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 

 
To the Board of Directors and Stockholders of
Isramco, Inc.
Houston, Texas
 
 
We have audited the accompanying consolidated balance sheets of Isramco, Inc. and its subsidiaries (collectively the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the three years ended December 31, 2011. We also have audited the Company’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Isramco, Inc and its subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ MALONE BAILEY, LLP               
www.malone-bailey.com
Houston, Texas

March 23, 2012
 
 
ISRAMCO INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
 
As of December 31
 
2011
   
2010
 
ASSETS
 
Current Assets:
           
Cash and cash equivalents
  $ 2,122     $ 5,657  
Accounts receivable, net
    6,459       6,110  
Restricted and designated cash
    290       889  
Inventories
    86       -  
Deferred tax assets
    2,539       3,368  
Derivative asset
    961       2,156  
Prepaid expenses and other
    620       715  
Total Current Assets
    13,077       18,895  
                 
Property and Equipment, at cost – successful efforts method:
               
Oil and Gas properties
    225,108       222,122  
Advanced payment for equipment
    650       -  
Other
    6,860       922  
Total Property and Equipment
    232,618       223,044  
Accumulated depreciation, depletion, amortization and impairment
    (105,224 )     (91,208 )
Net Property and Equipment
    127,394       131,836  
                 
Marketable securities, at market
    4,554       16,099  
Debt cost
    -       70  
Derivative asset
    1,421       343  
Deferred tax assets and other
    5,461       4,635  
Total assets
  $ 151,907     $ 171,878  
                 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
Current liabilities:
               
Accounts payable and accrued expenses
  $ 9,360     $ 9,316  
Bank overdraft
    823       335  
Current maturities of long term debt
    20,000       14,350  
Derivative liability
    -       1,133  
Due to related party and accrued interest
    25,518       9,371  
Total current liabilities
    55,701       34,505  
                 
Long-term debt
    -       22,725  
                 
Due to related party and accrued interest
    60,408       77,132  
                 
Other Long-term Liabilities:
               
Asset retirement obligations
    17,250       16,577  
Derivative liability – non-current
    -       2,402  
Total other long-term liabilities
    17,250       18,979  
                 
Commitments and contingencies (Note 13)
               
                 
Shareholders’ equity:
               
Common stock $0.0l par value; authorized 7,500,000 shares; issued 2,746,958 shares; outstanding 2,717,691 shares
    27       27  
Additional paid-in capital
    23,194       23,194  
Accumulated deficit
    (6,768 )     (14,149 )
Accumulated other comprehensive income
    2,254       9,629  
Treasury stock, 29,267 shares at cost
    (164 )     (164 )
Total  Isramco, Inc. shareholders’ equity
    18,543       18,537  
Non controlling interest
    5       -  
Total equity
    18,548       18,537  
Total liabilities and shareholders’ equity
  $ 151,907     $ 171,878  

See notes to the consolidated financial statements.
 
 
F-3
 
ISRAMCO INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share amounts)

Year Ended December 31
 
2011
   
2010
   
2009
 
                   
Revenues
                 
Oil and gas sales
 
$
44,228
   
$
39,329
   
$
30,768
 
Production services
   
896
     
-
     
-
 
Office services
   
437
     
655
     
845
 
Other
   
87
     
2,216
     
111
 
Total revenues
   
45,648
     
42,200
     
31,724
 
                         
Operating expenses
                       
Lease operating expense, transportation and taxes
   
20,981
     
19,894
     
15,651
 
Depreciation, depletion and amortization
   
9,982
     
12,142
     
15,368
 
Impairments of oil and gas assets
   
4,034
     
1,751
     
5,751
 
Accretion expense
   
853
     
849
     
829
 
Production services
   
675
     
-
     
-
 
Loss from plug and abandonment
   
315
     
1,300
     
312
 
General and administrative
   
4,438
     
5,123
     
4,113
 
Total operating expenses
   
41,278
     
41,059
     
42,024
 
Operating income (loss)
   
4,370
     
1,141
     
(10,300
)
                         
Other expenses (income)
                       
Interest expense, net
   
7,760
     
7,646
     
9,219
 
Realized gain on marketable securities
   
(15,910
)
   
-
     
(250
)
Net loss (gain) on derivative contracts
   
922
     
(1,862)
     
4,400
 
Currency exchange rate differences
   
237
     
-
     
-
 
Total other expenses (income)
   
(6,991
)
   
5,784
     
13,369
 
                         
Income (loss) before income taxes
   
11,361
     
(4,643
)
   
(23,669
 )
Income tax benefit (expense)
   
(3,975
)
   
1,856
     
10,090
 
                         
Net income (loss)
 
$
7,386
   
$
(2,787
)
 
$
(13,579
)
Net income attributable to non-controlling interests
   
5
     
-
     
-
 
Net income (loss) attributable to Isramco
 
$
7,381
   
$
(2,787
)
 
$
(13,579
)
                         
Earnings (loss) per share – basic:
 
$
2.72
   
$
(1.03
)
 
$
(5.00
)
                         
Earnings (loss) per share – diluted:
 
$
2.72
   
$
(1.03
)
 
$
(5.00
)
                         
Weighted average number of shares outstanding-basic:
   
2,717,691
     
2,717,691
     
2,717,691
 
Weighted average number of shares outstanding-diluted:
   
2,717,691
     
2,717,691
     
2,717,691
 
 
See notes to the consolidated financial statements.

 
F-4
 
ISRAMCO INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 and 2009

 
    Common stock        
    Number of shares     Amount     Additional Paid-In
Capital
    Accumulated other comprehensive income (loss)     Retained Earnings
(Accumulated Deficit)
    Treasury stock     Non-controlling interests     Total Shareholders’Equity  
    $ in thousands, except share amounts  
                                                 
Balances at January 1, 2009
    2,717,691     $ 27     $ 23,194     $ (240 )   $ 2,217     $ (164 )     -     $ 25,034  
                                                                 
Net loss
                                    (13,579 )                     (13,579 )
Net unrealized gain on available for sale marketable  securities, net of taxes of $1,035
                            2,011                               2,011  
Net gain on derivative contracts, net of taxes $138
                            267                               267  
Total comprehensive loss
                                                            2,278  
                                                                 
Balance of December 31, 2009
    2,717,691     $ 27     $ 23,194     $ 2,038     $ (11,362 )   $ (164 )   $ -     $ 13,733  
                                                                 
Net loss
                                    (2,787 )                     (2,787 )
Net unrealized gain on available for sale marketable  securities, net of taxes of $3,965
                            7,258                               7,258  
Net gain (loss) on derivative contracts, net of taxes $171
                            333                               333  
Total comprehensive loss
                                                            7,591  
                                                                 
Balance of December 31, 2010
    2,717,691     $ 27     $ 23,194     $ 9,629     $ (14,149 )   $ (164 )   $ -     $ 18,537  
                                                                 
Net income
                                    7,381               5       7,386  
Net unrealized loss on available for sale marketable  securities, net of taxes of $3,983
                            (7,397 )                             (7,397 )
Net gain (loss) on derivative contracts, net of taxes $12
                            22                               22  
Total comprehensive gain
                                                            (7,375 )
                                                                 
Balance of December 31, 2011
    2,717,691     $ 27     $ 23,194     $ 2,254     $ (6,768 )   $ (164 )   $ 5     $ 18,548  

See notes to consolidated financial statements.
 
 
F-5
 
ISRAMCO INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

Year Ended December 31
 
2011
   
2010
   
2009
 
                   
Cash Flows From Operating Activities:
                 
Net income (loss)
 
$
7,386
   
$
(2,787
)
 
$
(13,579
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                       
                         
Depreciation, depletion, amortization and impairment
   
14,016
     
13,893
     
21,119
 
Accretion expense
   
853
     
849
     
829
 
Realized gain on marketable securities
   
(15,910
)
   
  -
     
(250
)
Changes in deferred taxes
   
3,975
     
(1,856
)
   
(9,841
)
Net unrealized loss (gain) on derivative contracts
   
(3,384
)
   
4,727
     
19,298
 
Amortization of debt cost
   
252
     
252
     
252
 
Realized gain on sale of investment and capital gain
   
-
     
(2,160
)
   
(3
)
Changes in components of working capital and other assets and liabilities
                       
Accounts receivable
   
(349
) 
   
1,314
     
(2,008
)
Prepaid expenses and other current assets
   
(86
)
   
(59
)
   
(167
) 
Due to related party
   
959
     
(2,360
)
   
3,866
 
Inventories
   
(86
)
   
-
     
-
 
Accounts payable and accrued expenses
   
(680
)
   
250
     
2,003
 
Net cash provided by operating activities
   
6,946
     
12,063
     
21,519
 
                         
Cash flows from investing activities:
                       
Addition to property and equipment, net
   
(9,060
)
   
(3,611
)
   
(645
)
Proceeds from sale of gas properties and equipment
   
32
     
2,236
     
1
 
Restricted cash and deposit, net
   
598
     
(62
)
   
(70
) 
Purchase of marketable securities
   
-
     
-
     
(370
)
Proceeds from sale of marketable securities
   
16,073
     
-
     
752
 
Net cash provided by (used in) investing activities
   
7,643
     
(1,437
)
   
(332
)
                         
Cash flows from financing activities:
                       
Repayments on  loans – related parties, net
   
(12,537
)
   
-
     
(963
) 
Proceeds on loans-related parties , net
   
11,000
     
-
     
2,000
 
Repayment of long-term debt
   
(17,075
)
   
(7,875
)
   
(21,250
)
Borrowings (repayments) of bank overdraft, net
   
488
     
(1
)
   
(1,208
) 
Net cash used in financing activities
   
(18,124
)
   
(7,876
)
   
(21,421
) 
                         
Net increase (decrease) in cash and cash equivalents
   
(3,535
)
   
2,750
     
(234
) 
Cash and cash equivalents at beginning of year
   
5,657
     
2,907
     
3,141
 
Cash and cash equivalents at end of year
 
$
2,122
   
$
5,657
   
$
2,907
 
 
See notes to the consolidated financial statements.
 
 
F-6
 
ISRAMCO INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Fair Value Measurements
 
Certain of Isramco’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:
 
 
•
 
Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Isramco measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
 
 
•
 
Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.
 
 
•
 
Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

Cash and Cash Equivalents.
 
Isramco records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.
 
Allowance for Doubtful Accounts
 
The Company establishes provisions for losses on accounts receivable if it determines that it will not collect all or part of the outstanding balance. The Company regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method.
 
Oil and Gas Operations.

The Company applies the successful efforts method of accounting for oil and gas properties. Under the successful efforts method, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Acquisition costs and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated.
 
 
Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
 
Amortization rates are updated to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.
 
The Company reviews its property and equipment in accordance with Accounting Standard Codification (ASC) 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate property and equipment as an event occurs or circumstances change that would more likely than not reduce the fair value of the property and equipment below the carrying amount. If the carrying amount of property and equipment is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the discounted cash flow.
 
In 2011, 2010 and 2009, we reported an impairment charge of $4,034,000, $1,751,000 and $5,751,000, respectively, relating to our oil and gas properties.
 
Property, Plant and Equipment Other than Oil and Natural Gas Properties
 
Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated depreciable lives of the assets using the straight-line method. Depreciation expense for the years ended December 31, 2011, 2010 and 2009 was $246,000, $165,000 and $111,000 respectively. We depreciate our operational assets over their depreciable lives to their salvage value, which is a fair value higher than the assets’ value as scrap. Salvage value approximates 15% of an operational asset’s acquisition cost. When an operational asset is stacked or taken out of service, we review its physical condition, depreciable life and ultimate salvage value to determine if the asset is no longer operable and whether the remaining depreciable life and salvage value should be adjusted. When we scrap an asset, we accelerate the depreciation of the asset down to its salvage value. When we dispose of an asset, a gain or loss is recognized. We did not identify any triggering events or record any asset impairments during 2011, 2010 and 2009.
 
As of December 31, 2011, the estimated useful lives of our asset classes are as follows:
 
Description
  
Years
 
Well service rigs and components
  
 
15
  
Oilfield trucks, vehicles and related equipment
  
 
7-10
  
Well service auxiliary equipment
  
 
7-15
  
Furniture and equipment
  
 
3-7
  

A long-lived asset or asset group should be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. For purposes of testing for impairment, we group our long-lived assets along our lines of business based on the services provided, which is the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. We would record an impairment charge, reducing the net carrying value to an estimated fair value, if the asset group’s estimated future cash flows were less than its net carrying value. Events or changes in circumstance that cause us to evaluate our fixed assets for recoverability and possible impairment may include changes in market conditions, such as adverse movements in the prices of oil and natural gas, or changes of an asset group, such as its expected future life, intended use or physical condition, which could reduce the fair value of certain of our property and equipment. The development of future cash flows and the determination of fair value for an asset group involves significant judgment and estimates.

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

Trading and available-for-sale securities are recorded at fair market value. Isramco holds no held-to-maturity securities. Unrealized holding gains and losses on trading securities are included in earnings. Unrealized holding gains or losses, net of the related tax effects, on available-for-sale securities are excluded from earnings and are reported net of applicable taxes as accumulated other comprehensive income, a separate component of shareholders' equity, until realized.
 
 
  Asset Retirement Obligation
 
ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records asset retirement obligations to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells and gas gathering systems. The Company estimates the expected cash flow associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells as these obligations are incurred. See “Note 14. Asset Retirement Obligations.”

Concentrations of Credit Risk
 
The Company through its wholly-owned subsidiary Jay Management Company, LLC ("Jay Management") operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general were adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could also be adversely affected.
 
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.

In 2011, one individual purchaser of the Company's production accounted for 30% of the Company’s total sales and an additional three individual purchasers of the Company's production accounted for approximately 26% of its total sales (two purchasers approximately 9% each and another approximately 8%), collectively representing 56% of the Company's total sales. In 2010, one individual purchaser of the Company's production accounted for 23% of the Company’s total sales and an additional three individual purchasers of the Company's production accounted for approximately 27% of its total sales (approximately 9% each), collectively representing 50% of the Company's total sales. In 2009, two individual purchasers of the Company's production each accounted for in excess of 10% of the Company’s total sales and an additional three individual purchasers of the Company's production accounted for approximately 25.5% of its total sales (approximately 8.5% each), collectively representing 50% of the Company's total sales.

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 collectability of the revenue is reasonably assured. The Company follows the entitlement method of accounting for recording oil and gas revenues. Under this method, any revenues received in excess of the Company’s interest in production are treated as a liability. If revenues received are less than Company's interest in production, the deficiency is recorded as an asset. The Company's imbalance position was not significant in terms of volumes or values at December 31, 2011 and 2010.
 
Revenues from our well service activities are recognized when all of the following criteria have been met: (i) evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price to the customer is fixed and determinable and (iv) collectability is reasonably assured.
 
 
•
 
Evidence of an arrangement exists when a final understanding between us and our customer has occurred, and can be evidenced by a completed customer purchase order, field ticket, supplier contract, or master service agreement.
 
 
•
 
Delivery has occurred or services have been rendered when we have completed requirements pursuant to the terms of the arrangement as evidenced by a field ticket.
 
 
•
 
The price to the customer is fixed and determinable when the amount that is required to be paid is agreed upon. Evidence of the price being fixed and determinable is evidenced by contractual terms, our price book, a completed customer purchase order, or a field ticket.
 
 
•
 
Collectability is reasonably assured when we screen our customers and provide goods and services to customers according to determined credit terms that have been granted based on credit evaluation and assessment.
 
We present our revenues net of any sales taxes collected by us from our customers that are required to be remitted to local or state governmental taxing authorities.
 

Price Risk Management Activities
 
The Company follows ASC 815, Derivatives and Hedging . From time to time, the Company may hedge a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the Company’s consolidated statements of operations.

In 2011, 2010 and 2009, we recorded gain (loss) of ($0.9) million, $1.9 million and ($4.4) million, respectively, related to our derivative instruments. Fair values are derived principally from market quoted and other independent third-party quotes.

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

As of the date of this report there are no open interest rate swap positions.

Income Taxes

We account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, but which are deferred until future periods. Current taxes payable represent our liability related to our income tax returns for the current year, while net deferred tax expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Management estimates the changes in both deferred tax assets and liabilities using the basis of assets and liabilities for financial reporting purposes and for enacted rates that management estimates will be in effect when the differences reverse. Further, management makes certain assumptions about the timing of temporary tax differences for the differing treatments of certain items for tax and accounting purposes or whether such differences are permanent. The final determination of our tax liability involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction as well as the significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and nature of income earned and expenditures incurred.
 
We establish valuation allowances to reduce deferred tax assets if we determine that it is more likely than not (e.g., a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Additionally, we record uncertain tax positions at their net recognizable amount, based on the amount that management deems is more likely than not to be sustained upon ultimate settlement with the tax authorities in the domestic and international tax jurisdictions in which we operate.
 
See “Note 8. Income Taxes” for further discussion of accounting for income taxes, changes in our valuation allowance, components of our tax rate reconciliation and realization of loss carryforwards.
 
Legal Contingencies    
 
When estimating our liabilities related to litigation, we take into account all available facts and circumstances in order to determine whether a loss is probable and reasonably estimable.
 
Various suits and claims arising in the ordinary course of business are pending against us. We conduct business throughout the continental United States and may be subject to jury verdicts or arbitrations that result in outcomes in favor of the plaintiffs. We continually assess our contingent liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and our need for the disclosure of these items. We establish a provision for a contingent liability when it is probable that a liability has been incurred and the amount is reasonably estimable.
 
Earnings per Share
 
The Company’s basic earnings per share (EPS) amounts have been computed based on the average number of shares of common stock outstanding for the period and include the effect of any participating securities as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units and performance-based stock awards if the inclusion of these items is dilutive.
 
For the year ended December 31, 2011, Isramco's stock options were anti-dilutive.
 
 
Noncontrolling Interests  

Noncontrolling interests represent third-party ownership in the net assets of the Company’s consolidated subsidiary and are presented as a component of equity .

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

Recently Issued Accounting Pronouncements
 
ASU 2010-13.    In April 2010, the FASB issued ASU No. 2010-13, Compensation — Stock Compensation (Topic 718): Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. This ASU codifies the consensus reached in EITF Issue No. 09-J, “Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades.” The amendments to the Codification clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity shares trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. ASU 2010-13 is effective for fiscal years beginning on or after December 15, 2010. The amendments in this update should be applied by recording a cumulative-effect adjustment to the opening balance of retained earnings. The cumulative-effect adjustment should be calculated for all awards outstanding as of the beginning of the fiscal year in which the amendments are initially applied, as if the amendments had been applied consistently since the inception of the award. The cumulative-effect adjustment should be presented separately. We adopted the provisions of ASU 2010-13 on January 1, 2011, and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

ASU 2011-05.    In June 2011, the FASB issued ASU 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. The amendments in this ASU allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. ASU 2011-05 should be applied retrospectively for interim and annual reporting periods beginning after December 15, 2011 with early adoption permitted. Adoption of this ASU will have no impact on the Company’s consolidated financial statements.

ASU 2011-12.    In December 2011, the FASB issued ASU 2011-12, Deferral of the Effective Date for Amendment to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This ASU defers the guidance on whether to require entities to present reclassification adjustments out of accumulated other comprehensive income by component in both the statement where net income is presented and the statement where other comprehensive income is presented for both interim and annual financial statements. ASU 2011-12 reinstated the requirements for the presentation of reclassifications that were in place prior to the issuance of ASU 2011-05 and did not change the effective date of ASU 2011-05. ASU 2011-12 should be applied consistently with ASU 2011-05; accordingly, this ASU is to be applied retrospectively for interim and annual reporting periods beginning after December 15, 2011, with early adoption permitted. Adoption of this ASU will have no impact on the Company’s consolidated financial statements.

ASU 2011-04.    In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This ASU represents the converged guidance of the FASB and the IASB on measuring fair value and for disclosing information about fair value measurements. The amendments in this ASU clarify the Board’s intent about the application of existing fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value and for disclosing information about fair value measurements. ASU 2011-04 is effective prospectively for interim and annual reporting periods beginning after December 15, 2011. Adoption of this ASU will have no impact on the Company’s consolidated financial statements.
 
 
2.  New Subsidiaries
 
In August 2011 the Company created three new subsidiaries. Only one of them has started activity and has acquired equipment and been providing a full range of well services to major oil companies and independent oil and natural gas production companies. The services include rig-based and workover services, well completion and recompletion services, plugging and abandonment of wells at the end of their useful lives and other ancillary oilfield services. The Company operates in major oil and natural gas producing regions in Texas and New Mexico.
 
3.  Transactions with Affiliates and Related Parties

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

In August 2011 the Company sold all of its investment in a company called MediaMind Ltd. The realized gain from this transaction amounted to $15,910,000.
 
Sales of marketable securities resulted in realized gains of $15,910,000, $0 and $250,000 for the years ended December 31, 2011, 2010 and 2009, respectively.

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

As of December 31
 
2011
   
2010
 
   
Cost
   
Market Value
   
Cost
   
Market Value
 
   
$
1,087
   
$
4,554
   
$
1,200
   
$
16,099
 
 
In January and February 2012, the Company sold its investment of 278,408 shares of stock in an affiliated company Jerusalem Oil Exploration Ltd.  The total consideration received from the sale was approximately $4,833,000.
 
 
5.  Derivative and Hedging Activities
 
The Company enters into derivative commodity contracts to economically hedge its exposure to price fluctuations on a portion of its anticipated oil and natural gas production. It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to the Company’s derivative contracts is a lender in the Company’s Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement.

As of December 31, 2011, the Company has 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.
 
As of December 31, 2011 we had swap contracts for volume of 48,567 barrels of crude oil during 36 months, commencing January 2012, and swap contracts for volume of 270,613 MMBTU of natural gas during 3 months commencing January 2012. 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 2011, 2010 and 2009 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, 2011, the Company had a $2.4 million derivative asset, of which $1 million was classified as current. For the year ended December 31, 2011, the Company recorded a net derivative loss of $0.9 million (a $3.4 million unrealized gain offset by a $4.3 million loss from net cash paid on settled contracts).

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

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

Natural Gas
 
At December 31, 2011, the Company had the following natural gas swap positions:
 
Period
 
Swaps
 
   
Volume in
MMbtu’s
   
Price /
Price Range
   
Weighted
Average Price
 
January 2012 – March 2012
   
174,222
     
8.65
     
8.65
 
 
Crude Oil
 
At December 31, 2011, the Company had the following crude oil swap positions:
 
Period
 
Swaps
 
   
Volume in
Bbls
   
Price /
Price Range
   
Weighted
Average Price
 
January 2012 – December 2012
   
127,473
     
88.20-103.51
     
99.67
 
January 2013 – December 2013
   
89,400
     
103.51
     
103.51
 
January 2014 – December 2014
   
66,000
     
103.51
     
103.51
 
 
 
On March 9, 2011, pursuant to an agreement with Wells Fargo, the derivative contracts between Isramco and Wells Fargo were terminated and the Company signed new swap contracts with Macquarie Bank, N.A. for an aggregate volume of 336,780 barrels of crude oil during the 46 month period commencing March 2011. The payment required for the termination of these contracts was approximately $7 million.

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.

Under these swaps, the Company makes payments to, or receives payments from, the counterparties based upon the differential between a specified fixed price and a price related to the one-month London Interbank Offered Rate (“LIBOR”). These interest rate swaps convert a portion of the variable rate interest of our Scotia Senior Credit Facility (as defined in Note 6, “Long-term Debt and Interest Expenses”) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. We have elected to designate these positions for hedge accounting and therefore the unrealized gains and losses are recorded in accumulated other comprehensive loss. The Company measures hedge effectiveness by assessing the changes in the fair value or expected future cash flows of the hedged item.
 
As of December 31, 2011 the Company did not have open interest rate swap positions.
 
6.  Long-Term Debt and Interest Expense
 
Long-Term Debt as December 31 consisted of the following (in thousands):
 
     
2011
     
2010
 
Libor + 2% Bank Revolving Credit Facility due 2011
   
-
     
9,450
 
Libor + 2% Bank Revolving Credit Facility due 2012
   
20,000
     
27,625
 
Libor + 6% Related party Debt
   
12,000
     
12,000
 
Libor + 5.5% Related party Debt
   
-
     
954
 
Libor + 6% Related party Debt
   
11,500
     
11,500
 
Libor + 6% Related party Debt
   
6,000
     
6,000
 
Libor + 6% Related party Debt
   
41,861
     
48,900
 
Libor + 5.5% Related party Debt
   
6,456
     
-
 
     
97,817
     
116,429
 
Less: Current Portion of Long-Term Debt
   
(37,642
)
   
(17,350
)
Total
   
60,175
     
99,079
 
 
Senior Revolving Credit Facilities

The Company entered into a Senior Secured Revolving Credit Agreement, dated as of March 27, 2008 and Amended and Restated as of December 19, 2008 (the “Scotia Senior Credit Agreement”), with each of the lenders from time to time party thereto (the “Lenders”).  The Bank of Nova Scotia is the administrative agent for the Lenders and Capital One, N.A. is the syndication agent for the Lenders. The Scotia Senior Credit Agreement originally provided for a $150 million facility due in 2012 with a borrowing base of $54 million that is redetermined from time to time and adjusted based on the Company’s oil and gas properties, reserves, other indebtedness and other relevant factors. During the first quarter of 2011, the Lenders reduced the borrowing base to $28 million. On July 28, 2011 the borrowing base available under the other credit facility with the Bank of Nova Scotia (“Scotia”) was redetermined to $20,000,000.

During the fourth quarter of 2011 the Lenders reduced the borrowing base to $0.  The Company is repaying the approximately $20,000,000 outstanding balance in six installments of $3,333,000 each with the first two payments already made for January and February 2012 and the remaining installments due each month thereafter through June 2012 when the entire balance will be repaid.
 

The Company is also in negotiations for similar credit facilities with several other commercial lenders, to obtain terms most favorable to the Company.  While optimistic of a positive outcome of our consolidation efforts, the Company is uncertain as to whether it will be successful in obtaining new replacement financing or, if is obtained, the timetable upon which such facility will be closed and other material terms and conditions.

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

The Scotia Senior Credit Agreement contains customary financial and other covenants, including minimum working capital levels of not less than 1.0 to 1.0, leverage ratio of not greater than 3.5 to 1.0 and minimum coverage of interest of not less than 2.5 to 1.0. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, changes of control, asset sales, and liens on properties.
 
The Company entered into a Senior Secured Revolving Credit Agreement, dated as of March 2, 2007 as Amended and Restated as of June 15, 2007 (the “Wells Fargo Senior Credit Agreement”), with the lenders from time to time party thereto (the “Lenders”) and Wells Fargo Bank, N.A, as administrative agent for the Lenders. The Wells Fargo Senior Credit Agreement originally provided for a $150 million facility due in March, 2011 with a borrowing base of $35.3 million that is redetermined from time to time and adjusted based on the Company’s oil and gas properties, reserves, other indebtedness and other relevant factors.

On or about March 3, 2011, the Corporation paid the outstanding principal balance of the Wells Fargo Senior Credit Facility.  By agreement of the parties, the derivative contracts remained in place until March 9, 2011, when these contracts were novated and replaced by new derivative contracts, for the same volumes but at current market prices, with Macquarie Bank, N.A.  In connection with this transaction, the Wells Fargo Senior Credit Facility was transferred to and assumed by Macquarie Bank, N.A.  This facility currently has no outstanding principal or current availability. The credit facility was assigned and transferred to Macquarie Bank, N.A. in anticipation of the finalization of a successor credit facility pursuant to which all of the Corporation’s debt (including its related party debt) will be consolidated into a single facility at Macquarie Bank, N.A., or some other commercial lender. As of the date of this report the credit facility is about to be terminated and all collateral related thereto will be released.  The Company is also in negotiations for similar credit facilities with several other commercial lenders, to obtain terms most favorable to the Company.  While optimistic of a positive outcome of our consolidation efforts, the Company is uncertain as to whether it will be successful in obtaining new replacement financing or, if is obtained, the timetable upon which such facility will be closed and other material terms and conditions.

Related Party Debt

In July 2009 the Company entered into a loan transaction with I.O.C. Israel Oil Company, Ltd. (“IOC”), related party, pursuant to which the Company borrowed $6 million (the “IOC Loan”).  The purpose of the IOC Loan was to provide funds to Isramco Resources, LLC, which in turn paid this amount to Bank of Nova Scotia, as administrative agent, and Capital One, N.A., as a syndication agent, under the Scotia Senior Credit Agreement. This payment reduced the outstanding balance below the borrowing base and avoided the imposition of additional interest under the Scotia Senior Credit Agreement.
 
Amounts outstanding under the IOC Loan bear interest at LIBOR plus 6.0%. The IOC Loan matures in five years, with accrued interest payable annually on each anniversary date of the loan.  The IOC Loan may be prepaid at any time without penalty.

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

Pursuant to a Loan Agreement dated as of February 26, 2007 Isramco obtained a loan from JOEL Jerusalem Oil Exploration Ltd, a related party ("JOEL"), a related party, in the principal amount of $7 million, repayable at the end of 3 months (that was extended until July 11, 2007). Interest accrues at a per annum rate of 5.36%.
 
On July 2007, the Company and JOEL reached an agreement to revise the period of the Loan to seven years and the interest rate to LIBOR plus 6%.

In February and March, 2008 we obtained loans from JOEL in the aggregate principal amount of $48.9 million, repayable at the end of 4 months at an interest rate of LIBOR plus 1.25% per annum. Pursuant to a loan agreement signed in June 2009, the maturity date of this loan was extended for an additional period of seven years. Interest accrues at a per annum rate of LIBOR plus 6%. Principal and interest are due and payable in four equal annual installments, commencing on June 30, 2012. At any time we can make prepayments without premium or penalty.
 
Mr. Jackob Maimon, Isramco's president at the time and a former director of the Company is a director of JOEL. Mr. Haim Tsuff, Isramco's Chief Executive Officer and Chairman, is a controlling shareholder of JOEL.
 
 
In connection with the Company’s purchase of certain oil and gas interests mainly in New Mexico and Texas in February 2007 (See Note 2), the Company obtained loans in the total principal amount of $42 million from Naphtha Israel Petroleum Corp. Ltd., (“Naphtha”) with terms and conditions as below:

Pursuant to a Loan Agreement dated as of February 27, 2007 (the "First Loan Agreement"); Isramco obtained an $18.5 million loan from Naphtha. The outstanding principal amount of the loan accrues interest at per annum rate equal to the London Inter-bank Offered Rate (LIBOR) plus 5.5%, not to exceed 11% per annum. Interest is payable at the end of each loan year. Principal plus any accrued and unpaid interest are due and payable on February 26, 2014. Interest after the maturity date accrues at the per annum rate of LIBOR plus 12% until paid in full. At any time, Isramco is entitled to prepay the outstanding amount of the loan without penalty or prepayment. To secure its obligations that may be incurred under the Loan Agreement, Jay Petroleum, LLC, a wholly – owned subsidiary of Isramco, agreed to guarantee the indebtedness. Naphtha can accelerate the loan and exercise its rights under the collateral upon the occurrence any one or more of the following events of default: (i) Isramco's failure to pay any amount that may become due in connection with the loan within five (5) days of the due date (whether by extension, renewal, acceleration, maturity or otherwise) or fail to make any payment due under any hedge agreement entered into in connection with the transaction, (ii) Isramco's material breach of any of the representations or warranties made in the loan agreement or security instruments or any writing furnished pursuant thereto, (iii) Isramco's failure to observe any undertaking contained in transaction documents if such failure continues for 30 calendar days after notice, (iv) Isramco's insolvency or liquidation or a bankruptcy event or (v) Isramco's criminal indictment or conviction under any law pursuant to which such indictment or conviction can lead to a forfeiture by Isramco of any of the properties securing the loan.
 
Pursuant to a Loan Agreement dated as of February 27, 2007 (the "Second Loan Agreement") Isramco obtained a loan (the “Second Loan” , in the principal amount of $11.5 million from Naphtha, repayable at the end of seven years. Interest accrues at a per annum rate of LIBOR plus 6%. Principal is due and payable in four equal installments, commencing on the fourth anniversary of the date of the loan. Interest is payable annually upon each anniversary date of this loan. At any time Isramco can make prepayments without premium or penalty. The Second Loan is not secured. The other terms of the Second Loan Agreement are identical to the terms of the First Loan Agreement.

Pursuant to a Loan Agreement dated as of February 27, 2007 (the "Third Loan Agreement ") Isramco obtained a loan in the principal amount of $12 million (the “Third Loan”) from Naphtha, repayable at the end of five years. Interest accrues at a per annum rate of LIBOR plus 6%. Principal is due and payable in four equal annual installments, commencing on the second anniversary of the loan. Accrued interest is payable in equal annual installments. At any time Isramco can make prepayments without premium or penalty. The Third Loan is not secured. The other terms of the Third Loan Agreement are identical to the terms of the Loan Agreement.

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

On March 3, 2011, the Company entered into a Loan Agreement with IOC pursuant to which it borrowed the sum of $11 million.  The loan bears interest at a rate of 10% per annum and is payable in quarterly payments of interest only until March 3, 2012, when all accrued interest and principal is due and payable.  The loan may be prepaid at any time without penalty.  The loan is unsecured.  The purpose of the loan was to provide funds to Isramco for the payment of amounts due under the Wells Fargo Senior Credit Facility at maturity.  On March 3, 2011 Isramco paid the outstanding principal balance due under the Wells Fargo Senior Credit Agreement.  Subsequently, on March 9, 2011, pursuant to an agreement with Wells Fargo, the derivative contracts between Isramco and Wells Fargo were terminated at a cost to the Company of approximately $7,000,000.  Concurrently, the Company entered into new derivative contracts for 336,780 barrels of crude oil during the 46 month period commencing March 2011 with Macquarie Bank, N.A. During September 2011 Isramco paid $5,096,000 of principal and interest pursuant to Loan agreement with IOC. The Company is actively pursuing a consolidation of all outstanding debt with Macquarie Bank and other commercial lenders.
 
In October 2011 the agreement with IOC, pertaining to a loan in the outstanding principal amount of $6,456,000 was renegotiated. The payoff of principal amount was extended by 6 month to September 9, 2012. Interest accrued per annum was determined on LIBOR+5.5% from initial 10%.
 
Mr. Haim Tsuff, Isramco's Chief Executive Officer and Chairman, is a controlling shareholder of Naphtha and IOC.
 
Debt Maturities

Aggregate maturities of long-term debt at December 31, 2011 are due in future years as follows (in thousands):

2012
   
37,642
 
2013
   
18,100
 
2014
   
24,100
 
2015
   
15,100
 
2016
   
2,875
 
Total
 
$
97,817
 
 

Interest Expense

The following table summarizes the amounts included in interest expense for the years ended December 31, 2011, 2010 and 2009:

 
  
Years Ended December 31,
 
 
  
2011
   
2010
   
2009
 
 
  
(In thousands)
 
Current debt, long-term debt and other - banks
  
$
1,323
   
$
1,719
   
$
2,658
 
Long-term debt – related parties
   
6,437
     
5,927
     
6,561
 
 
  
                     
 
  
$
7,760
   
$
7,646
   
$
9,219
 

7. Fair Value of Financial Instruments

Pursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820) the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.
 
 
The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of December 31, 2011 and 2010. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for the years ended December 31, 2011 and 2010.
 
  
December 31, 2011
 
 
Level 1
 
Level 2
   
Level 3
   
Total
 
Assets
                   
Marketable securities
  $ 4,554     $ —     $ —     $ 4,554  
Commodity derivatives
    —       2,382       —       2,382  
                                 
    Total
  $ 4,554     $ 2,382     $ —     $ 6,936  
 
 
 
  
 
December 31, 2010
 
   
Level 1
   
Level 2
   
Level 3
   
Total
 
Assets
                       
Marketable securities
 
$
16,099
   
$
—
   
$
—
   
$
16,099
 
Commodity derivatives
   
—
     
2,499
     
—
     
2,499
 
                                 
    Total
 
$
16,099
   
$
2,499
   
$
—
   
$
18,598
 
                                 
Liabilities
                               
Commodity derivatives
 
$
—
   
$
3,501
   
$
—
   
$
3,501
 
Interest rate derivatives
   
—
     
34
     
—
     
34
 
                                 
    Total
 
$
—
   
$
3,535
   
$
—
   
$
3,535
 
 
Marketable securities listed above are carried at fair value. The Company is able to value its marketable securities based on quoted fair values for identical instruments, which resulted in the Company reporting its marketable securities as Level 1.
 
Derivatives listed above include swaps that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s consolidated statements of operations, in case of commodity derivatives, and in “Other comprehensive income”, in case of  interest rate derivatives. The Company is able to value these assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves.
 
As of December 31, 2011 and 2010, the Company’s derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, while no assurance to this effect can be provided, the Company does not anticipate such nonperformance. Each of the counterparties to the Company’s derivative contracts is a lender in the Company’s Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreements.
 
8.  Income Taxes
 
Isramco operates through its various subsidiaries in the United States (“U.S.”); accordingly, income taxes have been provided based upon the tax laws and federal and state income tax rates in the U.S. as they apply to Isramco’s current ownership structure.
 
Isramco accounts for income taxes pursuant to Accounting Standards Codification (ASC) 740, Accounting for Income Taxes, which requires recognition of deferred income tax liabilities and assets for the expected future tax consequences of events that have been recognized in Isramco’s financial statements or tax returns. Isramco provides for deferred taxes on temporary differences between the financial statements and tax bases of its assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse.
 
Isramco adopted Accounting Standards Codification (ASC) 740-10, effective January 1, 2007.  Isramco recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations. There were no unrecognized tax benefits that if recognized would affect the tax rate. There were no interest or penalties recognized as of the date of adoption or for the twelve months ended December 31, 2011.  The Company's tax years subsequent to 2006 are either currently under audit or remain open and subject to examination by federal tax authorities and the tax authorities in Louisiana, New Mexico, Oklahoma and Texas, which are the jurisdictions in which the Company has had its principal operations. In certain of these jurisdictions, the Company operates through more than one legal entity, each of which may have different open years subject to examination. It is important to note that years are technically open for examination until the statute of limitations in each respective jurisdiction expires.
 
 
The income tax provision differs from the amount of income tax determined by applying the Federal Income Tax Rate to pre-tax income from continuing operations due to the following items:
 
 
  
Years Ended December 31,
 
 
  
2011
   
2010
   
2009
 
 
  
(In thousands)
 
Expected tax (benefit) expense
  
$
3,975
   
$
(1,632
)
 
$
(8,285)
 
State income taxes, net
  
 
-
     
18
     
4
 
Foreign income taxes
  
 
-
     
-
     
-
 
Change in estimate of income tax basis (1)
  
 
-
     
-
     
(1,637
)
Other
   
-
     
(242
)
   
(172
)
Total tax expense (benefit)
  
$
3,975
   
$
(1,856
)
 
$
(10,090
) 

(1)
Changes in estimated income tax basis in connection with the preparation of 2006 and 2008 amended federal income tax returns.
 
Deferred tax assets at December 31, 2011 and 2010 are comprised primarily of net operating loss carry forwards and book impairment from write downs of assets. Deferred tax liabilities consist primarily of the difference between book and tax basis depreciation, depletion and amortization (DD&A) and impairment. Book basis in excess of tax basis for oil and gas properties and equipment primarily results from differing methodologies for recording property costs and depreciation, depletion and amortization under accounting principles generally accepted in the United States and the applicable income tax statutes and regulations in the jurisdictions in which the Company operates. There is a net deferred tax asset and it is management’s opinion that a valuation allowance is not needed, as it is more likely than not based on objective evidence that realization of the deferred tax assets is reasonably assured.
 
The principal components of Isramco’s deferred tax assets and liabilities as of December 31 were as follows (in thousands):
 
   
2011
   
2010
 
Deferred current tax assets:
           
Unrealized hedging transactions
 
$
-
   
$
385
 
Accrued interest
   
2,875
     
3,738
 
Deferred current tax assets
 
$
2,875
   
$
4,123
 
                 
Deferred current tax liabilities:
               
Unrealized hedging transactions
 
$
(336
)
 
$
(755
)
   
$
(336
)
 
$
(755
)
                 
Net current deferred tax assets
 
$
2,539
   
$
3,368
 
                 
Deferred noncurrent tax assets:
               
Unrealized hedging transactions
 
$
-
   
$
841
 
Book-tax differences in property basis
               
Net operating loss carry-forwards
   
12,020
     
12,154
 
Other
           
33
 
Deferred noncurrent tax assets
 
$
12,020
   
$
13,028
 
                 
                 
Deferred noncurrent tax liabilities:
               
Unrealized hedging transactions
 
$
(497
)
 
$
(120
)
Book-tax differences in property basis
   
(4,538
)
   
(1,344
)
Book-tax differences in marketable securities
   
(1,214
)
   
(5,265
)
Other
   
(310
)
   
(1,664
)
Deferred noncurrent tax liabilities
 
$
(6,559
)
 
$
(8,393
)
                 
Net noncurrent deferred tax assets
 
$
5,461
   
$
4,635
 
 
 
The principal components of Isramco's Income Tax Provision for the years indicated below were as follows (in thousands):
 
   
2011
   
2010
   
2009
 
Current income tax:
                 
Federal
 
$
  -    
$
  -    
$
-
 
Foreign
      -         -      
-
 
State
      -         -      
-
 
Total current income tax
 
$
  -    
$
  -    
$
-
 
                         
Deferred income tax
                       
Federal
 
$
3,975
   
$
(1,874
)
 
$
(10,094
) 
Foreign
      -         -      
-
 
State
   
-
     
18
     
4
 
Total deferred income tax
 
$
3,975
   
$
(1,856
)
 
$
(10,090
) 
Provision for income tax
 
$
3,975
   
$
(1,856
)
 
$
(10,090
) 

At December 31, 2011 the Company has U.S. tax loss carry forwards of approximately $34,343,000 which will expire in various amounts beginning in 2023 and ending in 2030.  Utilization of such loss carry forwards could be limited to the extent Isramco has an ownership change that triggers the limitation under Section 382 of Internal Revenue Code of 1986, as amended.  
 
9.  Earnings Per Share
 
The following table sets forth the computation of Net Income (Loss) Per Share Available to Common Stockholders for the years ended December 31 (in thousands, except per share data):
 
   
2011
   
2010
   
2009
 
Numerator for Basic and Diluted Earnings per Share -
                 
Net Income (loss)
 
$
7,381
   
$
(2,787
)
 
$
(13,579
)
                         
                         
Denominator for Basic Earnings per Share -
                       
Weighted Average Shares
   
2,717,691
     
2,717,691
     
2,717,691
 
Potential Dilutive Common Shares -
   
-
     
-
     
-
 
Adjusted Weighted Average Shares
   
2,717,691
     
2,717,691
     
2,717,691
 
                         
Net Income (Loss) Per Share Available to Common Stockholders – Basic
 
$
2.72
   
$
(1.03
)
 
$
(5.00
)
Net Income (Loss) Per Share Available to Common Stockholders – Diluted
 
$
2.72
   
$
(1.03
)
 
$
(5.00
)
                         
 
 
10.  Stock Options

The 1993 Stock Option Plan (the 1993 Plan) was approved at the annual meeting of shareholders held in August 1993. As of December 31, 2009, 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 2011, 2010 and 2009. 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.
 
At the Annual Shareholders Meeting in 2011, the shareholders adopted the 2011 Stock Incentive Plan.  That plan will be administered by the Compensation Committee of the Board of Directors and there are 200,000 shares under that plan that may be awarded.  Independent members of the board of directors as well as employee of and consultants to the Company are eligible to receive awards.  The awards can be in the form of stock options, restricted stock or other stock–based awards. The awards are intended to qualify as performance-based compensation for purposes of Section 162(m) of the Internal Revenue Code. There are no granted awards outstanding under the 2011 Stock Incentive Plan.
 
11.  Supplemental Cash Flow Information
 
Cash paid for interest and income taxes was as follows for the years ended December 31 (in thousands):
 
   
2011
   
2010
   
2009
 
Interest
 
$
6,723
   
$
9,160
   
$
6,263
 
                         
Income taxes
 
$
-
   
$
-
   
$
-
 
 
The consolidated statements of cash flows for the year ended December 31, 2011 exclude the following non-cash transactions:
 
·  
Property and equipment of $484,000 included in accounts payable
 
12.   Concentrations of Credit Risk

Financial instruments, which potentially expose Isramco to concentrations of credit risk, consist primarily of trade accounts receivable and oil and gas derivative assets. Isramco's customer base includes several of the major United States oil and gas operating and production companies. Although Isramco is directly affected by the well-being of the oil and gas production industry, management does not believe a significant credit risk existed as of December 31, 2011. 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.
 
 
13.  Commitments and Contingencies

Commitments

Isramco has a few immaterial lease agreements.

Contingencies

From time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. All known liabilities are accrued based on the Company’s best estimate of the potential loss. In the opinion of management, Isramco's ultimate liability, if any, in these pending actions would not have a material adverse effect on the financial position, operating results or liquidity of Isramco.
 
14.  Asset Retirement Obligation
 
If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, the Company records a liability (an asset retirement obligation or ARO) on the consolidated balance sheet and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.
 
The following table presents the reconciliation of the beginning and ending aggregate carrying amount legal obligations associated with the retirement of oil and gas properties at December 31 (in thousands):
 
   
2011
   
2010
   
2009
 
Liability for asset retirement obligation at  the beginning of the year
 
$
16,577
   
$
16,248
   
$
15,733
 
Liabilities Incurred
   
62
     
4
     
-
 
Liabilities settled and divested
   
(242
)
   
(524
)
   
(314
)
Accretion expense
   
853
     
849
     
829
 
Liability for asset retirement obligation at  the end of the year
 
$
17,250
   
$
16,577
   
$
16,248
 
 
15.  Subsequent Events

The Company has evaluated subsequent events through March 23, 2012 which is the date the consolidated financial statements were issued.
 
 
16.  Supplementary Oil and Gas Information (Unaudited)

The following supplemental information regarding the oil and gas activities of Isramco for 2011, 2010 and 2009 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
 
2011
   
2010
 
   
United States
   
United States
 
Unproved properties not being amortized
 
$
-
   
$
-
 
Proved property being amortized
   
225,108
     
222,122
 
Accumulated depreciation, depletion amortization and impairment
   
(104,522
)
   
(90,752
)
Net capitalized costs
   
120,586
     
131,370
 

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

As of December 31
 
2011
   
2010
   
2009
 
   
United States
 
Property acquisition costs—proved and unproved properties
 
$
151
   
$
-
   
$
-
 
Exploration costs
 
$
-
   
$
-
   
$
-
 
Development costs
 
$
2,398
   
$
3,454
   
$
423
 

OIL AND GAS RESERVES

Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
 
Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.
 
 
The following table illustrates the Company's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by our independent reserve engineering firms, Netherland, Sewell & Associates, Inc  and Cawley, Gillespie & Associates, Inc.
 
In December 2009, Isramco adopted revised oil and gas reserve estimation and disclosure requirements that conformed the definition of proved reserves to the Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting rules, issued by the SEC in 2008. An accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economic to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technologies to estimate proved oil, natural-gas, and natural-gas liquids (NGLs) reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes.
 
The unaudited supplemental information on oil and gas exploration and production activities for 2011, 2010, and 2009 has been presented in accordance with the revised reserve estimation and disclosure rules, which were not applied retrospectively. The December 31, 2008 data is presented in accordance with Financial Accounting Standards Board (FASB) oil and gas disclosure requirements effective at that time.
 
   
Oil Bbls
   
Gas Mcf
 
                                     
   
United States
   
Israel
   
Total
   
United States
   
Israel
   
Total
 
December 31, 2008
   
2,678,994
     
- 
     
2,678,994
     
25,696,175
     
- 
     
25,696,175
 
                                                 
Revisions of previous estimates
   
616,674
     
- 
     
616,674
     
1,378,468
     
- 
     
1,378,468
 
Acquisition of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Sales of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Production
   
(293,601
)
   
- 
     
(293,601
)
   
(2,622,389
)
   
- 
     
(2,622,389
)
December 31, 2009
   
3,002,067
     
- 
     
3,002,067
     
24,452,254
     
- 
     
24,452,254
 
                                                 
Revisions of previous estimates
   
606,445
     
- 
     
606,445
     
1,616,809
     
- 
     
1,616,809
 
Acquisition of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Sales of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Production
   
(290,589
)
           
(290,589
)
   
(2,368,158
)
   
- 
     
(2,368,158
)
December 31, 2010
   
3,317,923
     
- 
     
3,317,923
     
23,700,905
     
- 
     
23,700,905
 
                                                 
Revisions of previous estimates
   
180,104
     
- 
     
180,104
     
3,573,698
     
- 
     
3,573,698
 
Extensions, discoveries, and other additions
   
15,033
     
- 
     
15,033
     
21,847
     
154,100,000 
     
154,121,847
 
Acquisition of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Sales of minerals in place
   
-
             
-
     
-
             
-
 
Production
   
(278,601
)
   
- 
     
(278,601
)
   
(2,241,384
)
   
- 
     
(2,241,384
)
December 31, 2011
   
3,234,459
     
- 
     
3,234,459
     
25,055,066
     
154,100,000 
     
179,155,066 
 
                                                 
Proved Developed Reserves
                                               
                                                 
December 31, 2011
   
3,234,459
     
- 
     
3,234,459
     
25,055,066
     
- 
     
25,055,066
 
December 31, 2010
   
3,317,923
     
- 
     
3,317,923
     
23,700,905
     
- 
     
23,700,905
 
December 31, 2009
   
3,002,067
     
- 
     
3,002,067
     
24,452,254
     
- 
     
24,452,254
 
December 31, 2008
   
2,678,994
     
- 
     
2,678,994
     
25,696,175
     
- 
     
25,696,175
 
                                                 
Proved Undeveloped  Reserves
                                               
                                                 
December 31, 2011
   
-
     
-
     
-
     
-
     
154,100,000 
     
154,100,000 
 
December 31, 2010
   
-
     
-
     
-
     
-
     
-
     
-
 
December 31, 2009
   
-
     
-
     
-
     
-
     
-
     
-
 
December 31, 2008
   
-
     
-
     
-
     
-
     
-
     
-
 
                                             
-
 
 
 
   
NGL Bbls
   
Total MBOE
 
                                     
   
United States
   
Israel
   
Total
   
United States
   
Israel
   
Total
 
December 31, 2008
   
1,252,003
     
- 
     
1,252,003
     
8,213,693
     
- 
     
8,213,693
 
                                                 
Revisions of previous estimates
   
391,115
     
- 
     
391,115
     
 
1,237,534
     
- 
     
 
1,237,534
 
Acquisition of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Sales of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Production
   
(155,793
)
   
- 
     
(155,793
)
   
(886,459
)
   
- 
     
(886,459
)
December 31, 2009
   
1,487,325
     
- 
     
1,487,325
     
8,564,768
     
- 
     
8,564,768
 
                                                 
Revisions of previous estimates
   
431,465
     
- 
     
431,465
     
1,307,378
     
- 
     
1,307,378
 
Acquisition of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Sales of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Production
   
(155,640
)
   
- 
     
(155,640
)
   
(840,922
)
   
- 
     
(840,922
)
December 31, 2010
   
1,763,150
     
- 
     
1,763,150
     
9,031,224
     
- 
     
9,031,224
 
                                                 
Revisions of previous estimates
   
265,863
     
- 
     
265,863
     
1,041,583
     
- 
     
1,041,583
 
Extensions, discoveries, and other additions
   
3,897
     
- 
     
3,897
     
22,571
     
25,683,333 
     
25,705,904
 
Acquisition of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Sales of minerals in place
   
-
     
- 
     
-
     
-
     
- 
     
-
 
Production
   
(136,446
)
   
- 
     
(136,446
)
   
(788,611
)
   
- 
     
(788,611
)
December 31, 2011
   
1,896,464
     
- 
     
1,896,464
     
9,306,767
     
25,683,333  
     
34,990,100
 
                                                 
Proved Developed Reserves
                                               
                                                 
December 31, 2011
   
1,896,464
     
- 
     
1,896,464
     
9,306,767
     
- 
     
9,306,767
 
December 31, 2010
   
1,763,150
     
- 
     
1,763,150
     
9,031,224
     
- 
     
9,031,224
 
December 31, 2009
   
1,487,325
     
- 
     
1,487,325
     
8,564,768
     
- 
     
8,564,768
 
December 31, 2008
   
1,252,003
     
- 
     
1,252,003
     
8,213,693
     
- 
     
8,213,693
 
                                                 
Proved Undeveloped  Reserves
                                               
                                                 
December 31, 2011
   
-
     
-
     
-
     
-
     
25,683,333  
     
25,683,333  
 
December 31, 2010
   
-
     
-
     
-
     
-
     
-
     
-
 
December 31, 2009
   
-
     
-
     
-
     
-
     
-
     
-
 
December 31, 2008
   
-
     
-
     
-
     
-
     
-
     
-
 
 
(1)
Gas reserves are converted to BOE at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to BOE on a one-to-one basis with oil.
 
 
Extensions, discoveries, and other additions —

2011 — the increase in Israel is due to the recording of reserves at the Tamar development offshore Israel.
 
Revisions of Previous Estimates —
 
2011 — Proved reserves must be estimated using the assumption that prices and costs remain constant for the duration of the reservoir life. The upward Revisions of Previous Estimates was due to significantly higher average first-day of the month oil gas and NGLs prices calculated for the 12 months ended December 31, 2011 compared to prices as of December 31, 2010.
 
2010 — Proved reserves must be estimated using the assumption that prices and costs remain constant for the duration of the reservoir life. The upward Revisions of Previous Estimates was due to significantly higher average first-day of the month oil, gas and NGLs prices calculated for the 12 months ended December 31, 2011 compared to prices as of December 31, 2009.
 
The SEC amended its definitions of oil and natural gas reserves effective December 31, 2009. Previous periods were not restated for the new rules. Key revisions include a change in pricing used to prepare reserve estimates to a 12-month unweighted average of the first-day-of-the-month prices, the inclusion of non-traditional resources in reserves, definitional changes, allowing the application of reliable technologies in determining proved reserves, and other new disclosures (Revised SEC rules). 

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOW

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

The Company believes that the following factors should be taken into account when reviewing the following information:
 
 
•
future costs and selling prices will probably differ from those required to be used in these calculations;
     
 
•
due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;
     
 
•
a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and
     
 
•
future net revenues may be subject to different rates of income taxation.
 

Under the Standardized Measure for the year ended December 31, 2009, the future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year-end prices were required. At December 31, 2011 and 2010, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts.
 
millions
 
United States
   
Israel
   
 
Total
 
December 31, 2011
                 
Future cash inflows (1)
 
$
506,668,204
   
$
634,462,200 
   
$
1,141,130,404 
 
Future development costs
   
(875,854
)
   
- 
     
(875,854
)
Future production costs
   
(240,176,108
)
   
- 
     
(240,176,108
)
Future income tax expenses (2)
   
(45,477,986
)
   
(341,573,223 
)
   
(387,051,209
)
                         
Future net cash flows
   
220,138,256
     
292,888,977 
     
513,027,233 
 
10% annual discount for estimated timing of cash flows
   
(107,734,348
)
   
(168,565,572 
)
   
(276,299,920
)
                         
Standardized measure of discounted future net cash flows
 
$
112,403,908 
   
$
124,323,405 
   
$
236,727,313 
 
                         
December 31, 2010
                       
Future cash inflows
 
$
429,260,906
   
$
- 
   
$
429,260,906
 
Future development costs
   
(740,588
)
   
- 
     
(740,588
)
Future production costs
   
(208,228,155
)
   
- 
     
(208,228,155
)
Future income tax expenses
   
(33,475,234
)
   
- 
     
(33,475,234
)
                         
Future net cash flows
   
186,816,929
     
- 
     
186,816,929
 
10% annual discount for estimated timing of cash flows
   
(89,183,575
)
   
- 
     
(89,183,575
)
                         
Standardized measure of discounted future net cash flows
 
$
97,633,354 
   
$
- 
   
$
97,633,354 
 
                         
December 31, 2009
                       
Future cash inflows
 
$
294,721,432
   
$
- 
   
$
294,721,432
 
Future development costs
   
(556,810
)
   
- 
     
(556,810
)
Future production costs
   
(147,470,220
)
   
- 
     
(147,470,220
)
Future income tax expenses
   
-
     
- 
     
-
 
                         
Future net cash flows
   
146,694,402
     
- 
     
146,694,402
 
10% annual discount for estimated timing of cash flows
   
(68,284,971
)
   
- 
     
(68,284,971
)
                         
Standardized measure of discounted future net cash flows
 
$
78,409,431
   
$
- 
   
$
78,409,431
 
 
(1)
The increase in Israel is due to the recording of reserves at the Tamar development offshore Israel.
(2)
The government of Israel imposes a tax or charge upon oil and gas revenues, including revenues from oil and gas produced from the Tamar well. Currently, such oil and gas revenues would be subject to a sliding scale of taxation, beginning with the imposition of a 20% charge on oil and gas revenues at such time as total revenues received equal 1.5 times the costs expended and increasing in steps to a 50% charge imposed at such time as revenues received equal 1.5 times the costs expended.  The current tax law provides some relief for oil and gas revenues received from reservoirs developed before January 2014 by delaying the imposition of the charges; i.e. the 20% charge would become effective at such time as total revenues received equal 2 times the costs expended and the maximum 50% charge would not become effective until revenues received equaled 2.8 times costs expended. Isramco’s overriding royalty would be subject to the above taxation at such time, and at the same rates, as the revenues attributable to the operating interest. The income tax expenses include the taxation and income tax.
 
 
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Company’s proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2011

Changes in Standardized Measure of Discounted Future Net Cash Flows
 
Relating to Proved Oil and Gas Reserves
                 
                   
millions
 
 
United States
   
 
International
   
 
Total
 
2011
                 
Balance at January 1
  $ 97,633,354     $ -     $ 97,633,354  
        Sales and transfers of oil and gas produced, net of production costs 
    (23,247,735 )      -       (23,247,735 )
Net changes in prices and production costs
    18,142,794       -       18,142,794  
Changes in estimated future development costs, net of current development costs
    (1,213,256 )     -       (1,213,256 )
        Extensions, discoveries, additions, and improved recovery, less related costs 
    -       124,323,405       124,323,405  
Development costs incurred during the period
            -          
Revisions of previous quantity estimates
    14,623,353       -       14,623,353  
Purchases of minerals in place
    -       -       -  
Sales of minerals in place
    -       -       -  
Accretion of discount
    10,476,340       -       10,476,340  
Net change in income taxes
    (5,726,668 )     -       (5,726,668 )
Change in production rates and other
    1,599,863       -       1,599,863  
                         
Balance at December 31
  $ 112,288,045     $ 124,323,405     $ 236,611,450  
                         
2010
                       
Balance at January 1
  $ 78,409,431     $ -     $ 78,409,431  
        Sales and transfers of oil and gas produced, net of production costs 
    (19,435,256 )      -       (19,435,256 ) 
Net changes in prices and production costs
    28,652,935       -       28,652,935  
Changes in estimated future development costs, net of current development costs
    (2,930,885 )     -       (2,930,885 )
        Extensions, discoveries, additions, and improved recovery, less related costs 
    -       -       -  
Development costs incurred during the period
    -       -       -  
Revisions of previous quantity estimates
    17,549,795       -       17,549,795  
Purchases of minerals in place
    -       -          
Sales of minerals in place
    -       -          
Accretion of discount
    7,092,982       -       7,092,982  
Net change in income taxes
    (17,494,664 )      -       (17,494,664 ) 
Change in production rates and other
    5,789,016       -       5,789,016  
                         
Balance at December 31
  $ 97,633,354     $ -     $ 97,633,354  
                         
                         
2009
  $       $       $    
Balance at January 1
    73,377,612       -       73,377,612  
Sales and transfers of oil and gas produced, net of production costs 
    (15,116,990 )     -       (15,116,990 )
Net changes in prices and production costs
    4,638,711       -       4,638,711  
Changes in estimated future development costs, net of current development costs
    211,024       -       211,024  
        Extensions, discoveries, additions, and improved recovery, less related costs 
    -       -       -  
Development costs incurred during the period
    -       -       -  
Revisions of previous quantity estimates
    11,948,600       -       11,948,600  
Purchases of minerals in place
    -       -       -  
Sales of minerals in place
    -       -       -  
Accretion of discount
    6,626,173       -       6,626,173  
Net change in income taxes
    -       -       -  
Change in production rates and other
    (3,275,699 )     -       (3,275,699 )
                         
Balance at December 31
  $ 78,409,431     $ -     $ 78,409,431  

 
Unaudited Quarterly Financial Information
  (In Thousands, Except Per Share Data)

Quarter Ended
 
March 31
   
June 30
   
September 30
   
December 31
 
2011
                       
Total Revenues
 
$
11,150
     
11,747
     
11,177
     
11,574
 
Net Income (loss) before taxes
   
(6,623
)
   
2,001
     
22,607
     
(6,624
)
Net Income (loss) attributable to common shareholders
   
(4,306
)
   
1,301
     
14,694
     
(4,303
)
Net income attributable to noncontrolling interests 
   
-
     
-
     
-
     
5
 
Net income (loss) attributable to Isramco
   
(4,306
)
   
1,301
     
14,694
     
(4,308
)
Earnings (loss) per share:
                               
Net income (loss) attributable to common stockholders - basic
 
$
(1.58
)
   
0.48
     
5.41
     
(1.59
)
Net income (loss) attributable to common stockholders - diluted 
 
$
(1.58
)
   
0.48
     
5.41
     
(1.59
)
Average number common shares outstanding - basic
   
2,717,691
     
2,717,691
     
2,717,691
     
2,717,691
 
Average number common shares outstanding - diluted
   
2,717,691
     
2,717,691
     
2,717,691
     
2,717,691
 
                                 
2010
                               
Total Revenues
 
$
10,165
     
9,527
     
9,928
     
12,580
 
Net Income (loss) before taxes
 
$
2,057
     
1,464
     
(3,802
)
   
(4,362
)
Net Income (loss)
 
$
1,357
     
966
     
(2,510
)
   
(2,600
)
                                 
Earnings (loss) per share:
                               
Net income (loss) attributable to common stockholders - basic
 
$
0.50
   
$
0.36
   
$
(0.92
) 
 
$
(0.96
) 
Net income (loss) attributable to common stockholders - diluted 
 
$
0.50
   
$
0.36
   
$
(0.92
) 
 
$
(0.96
) 
Average number common shares outstanding - basic
   
2,717,691
     
2,717,691
     
2,717,691
     
2,717,691
 
Average number common shares outstanding - diluted
   
2,717,691
     
2,717,691
     
2,717,691
     
2,717,691
 
                                 
2009
                               
Total Revenues
 
$
7,007
   
$
7,399
   
$
7,810
   
$
9,508
 
Net Income (loss) before taxes
 
$
2,713
   
$
(12,223
)
 
$
(3,236
) 
 
$
(10,923
) 
Net Income (loss)
 
$
1,790
   
$
(8,014
)
 
$
(2,018
) 
 
$
(5,337
) 
                                 
Earnings (loss) per share:
                               
Net income (loss) attributable to common stockholders - basic
 
$
0.66
   
$
(2.95
)
 
$
(0.74
) 
 
$
(1.96
) 
Net income (loss) attributable to common stockholders - diluted 
 
$
0.66
   
$
(2.95
)
 
$
(0.74
)
 
$
(1.96
)
Average number common shares outstanding - basic
   
2,717,691
     
2,717,691
     
2,717,691
     
2,717,691
 
Average number common shares outstanding - diluted
   
2,717,691
     
2,717,691
     
2,717,691
     
2,717,691
 
 
EXHIBIT 10.19
 

 
FIRST AMENDMENT TO LOAN AGREEMENT
 
BY AND BETWEEN
 
ISRAMCO, INC.
as Borrower,
 
and
 
I.O.C. – ISRAEL OIL COMPANY, LTD.
 
Effective as of October 1, 2011
 
 
 
 
 
 
 
 
 
 
TABLE OF CONTENTS
 
    Page
Article I DEFINITIONS
1
Section 1.1
Terms Defined Above
1
Section 1.2
Terms Defined in Loan Agreement
1
Section 1.3
Other Definitional Provisions
1
     
Article II AMENDMENTS TO LOAN AGREEMENT
1
Section 2.1
Amendments and Supplements to Definitions
1
Section 2.2
Amendment to Section 8.1 of the Loan Agreement. Section 8.1 of the Loan Agreement is amended by replacing the address of Borrower with the following:
2
     
Article III CONDITIONS
2
Section 3.1
Loan Documents
3
Section 3.2
Representations and Warranties
3
Section 3.3
No Default
3
Section 3.4
No Change
3
Section 3.5
Security Instruments
3
Section 3.6
Other Instruments or Documents
3
     
Article IV MISCELLANEOUS
3
Section 4.1
Adoption, Ratification and Confirmation of Loan Agreement
3
Section 4.2
Successors and Assigns
3
Section 4.3
Counterparts; Electronic Delivery of Signature Pages
3
Section 4.4
Number and Gender
3
Section 4.5
Entire Agreement
4
Section 4.6
Invalidity
4
Section 4.7
Titles of Articles, Sections and Subsections
4
Section 4.8
Governing Law
4

 
 
 
 
FIRST AMENDMENT TO LOAN AGREEMENT
 
This FIRST AMENDMENT TO LOAN AGREEMENT (this “ First Amendment ”) executed effective as of October 1, 2011 (the “ Effective Date ”), is between ISRAMCO, INC. , a corporation formed under the laws of the State of Delaware, and I.O.C. – ISRAEL OIL COMPANY, LTD. , an Israeli limited company (together with its successors and assigns “ Lender ”).
 
R E C I T A L S:
 
A.           Borrower and Lender are parties to that certain Loan Agreement dated as of March 1, 2011, as amended (the “Loan Agreement”), pursuant to which Lender agreed to make loans to and extensions of credit on behalf of Borrower; and
 
B.           Borrower and Lender desire to amend the Loan Agreement in the particulars hereinafter provided.
 
NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, the parties hereto agree as follows:
 
ARTICLE I
DEFINITIONS
 
Section 1.1   Terms Defined Above .  As used in this First Amendment, each of the terms defined in the opening paragraph and the Recitals above shall have the meaning assigned to such terms therein.
 
Section 1.2   Terms Defined in Loan Agreement .  Each term defined in the Loan Agreement and used herein without definition shall have the meaning assigned to such term in the Loan Agreement, unless expressly provided to the contrary.
 
Section 1.3   Other Definitional Provisions
 
(a)   The words “hereby”, “herein”, “hereinafter”, “hereof”, “hereto” and “hereunder” when used in this First Amendment shall refer to this First Amendment as a whole and not to any particular Article, Section, subsection or provision of this First Amendment.
 
(b)   Section, subsection and Exhibit references herein are to such Sections, subsections and Exhibits to this First Amendment unless otherwise specified.
 
ARTICLE II
AMENDMENTS TO LOAN AGREEMENT
 
Borrower and Lender agree that the Loan Agreement is hereby amended, effective as of the Effective Date, in the following particulars.
 
Section 2.1   Amendments and Supplements to Definitions .
 
(a)   The following term, which is defined in Section 1.12 of the Loan Agreement, is hereby amended in its entirety to read as follows:
 
Maturity Date shall mean, unless the Note is sooner accelerated pursuant to this Agreement, September 1, 2012.
 
 
Page - 1
First Amendment to Loan Agreement
 
 
(b)   The following term, which is defined in Section 1.18 of the Loan Agreement, is hereby amended in its entirety to read as follows:
 
Stated Rate .shall mean a rate per annum equal to LIBOR + 5.5%; provided, however, that if the Stated Rate ever exceeds the Maximum Rate then and from time to time thereafter be fixed at a rate per annum equal to the Maximum Rate then and from time to time thereafter in effect until the total amount of interest accrued at the Stated Rate on the unpaid balance of this Note equals the total amount of interest which would have accrued at the Maximum Rate from time to time in effect.
 
(c)   Article 1 of the Loan Agreement is hereby further amended and supplemented by adding the following new definition where alphabetically appropriate, which reads in its entirety as follows:
 
“ First Amendment ” shall mean that certain First Amendment to Loan Agreement dated as of November 10, 2011 and effective as of October 1, 2011 between Borrower and Lender.
 
Section 2.2   Amendment to Section 8.1 of the Loan Agreement.   Section 8.1 of the Loan Agreement is amended by replacing the address of Borrower with the following:
 
If to the Borrower, to:

Mr. Edy Francis, CFO
Isramco, Inc.
2425 West Loop South, Suite 810
Houston, TX 77027
Telephone No.:  (713) 621 -6785
Facsimile No.:  (713) 621 – 3988
e – mail edyf@isramco-jay.com

With a copy to:

Isramco, Inc.
General Counsel
2425 West Loop South, Suite 810
Houston, TX 77027
Telephone No.:  (713) 621 -6785
e – mail:   cwarnock@isramco-jay.com
 
 
Page - 2
First Amendment to Loan Agreement
 

ARTICLE III
CONDITIONS
 
The enforceability of this First Amendment against Lender is subject to the satisfaction of the following conditions precedent:
 
Section 3.1   Loan Documents .  Lender shall have received multiple original counterparts, as requested by Lender, of this First Amendment executed and delivered by a duly authorized officer of Borrower and Lender.
 
Section 3.2   Representations and Warranties .  Except as affected by the transactions contemplated in the Loan Agreement and this First Amendment, each of the representations and warranties made by Borrower in or pursuant to the Loan Documents shall be true and correct in all material respects as of the Effective Date, as if made on and as of such date.
 
Section 3.3   No Default .  No Default or Event of Default shall have occurred and be continuing as of the Effective Date.
 
Section 3.4   No Change .  No event shall have occurred since the Closing Date, which, in the reasonable opinion of Lender, could have a Material Adverse Effect.
 
Section 3.5   Security Instruments .  All of the Security Instruments shall be in full force and effect and provide to Lender the security intended thereby to secure the Indebtedness, as amended and supplemented hereby.
 
Section 3.6   Other Instruments or Documents .  Lender or counsel to Lender shall receive such other instruments or documents as they may reasonably request.
 
ARTICLE IV
MISCELLANEOUS
 
Section 4.1   Adoption, Ratification and Confirmation of Loan Agreement .  Each of Borrower and Lender does hereby adopt, ratify and confirm the Loan Agreement, as amended hereby, and acknowledges and agrees that the Loan Agreement, as amended hereby, is and remains in full force and effect.
 
Section 4.2   Successors and Assigns .  This First Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Loan Agreement.
 
Section 4.3   Counterparts; Electronic Delivery of Signature Pages .  This First Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument and shall be enforceable as of the Effective Date upon the execution of one or more counterparts hereof by Borrower, and Lender.  In this regard, each of the parties hereto acknowledges that a counterpart of this First Amendment containing a set of counterpart executed signature pages reflecting the execution of each party hereto shall be sufficient to reflect the execution of this First Amendment by each necessary party hereto and shall constitute one instrument.  Delivery of an executed signature page of this First Amendment by facsimile or e-mail shall be effective as delivery of an original executed signature page of this First Amendment.
 
Section 4.4   Number and Gender .  Whenever the context requires, reference herein made to the single number shall be understood to include the plural; and likewise, the plural shall be understood to include the singular.  Words denoting sex shall be construed to include the masculine, feminine and neuter, when such construction is appropriate; and specific enumeration shall not exclude the general but shall be construed as cumulative.  Definitions of terms defined in the singular or plural shall be equally applicable to the plural or singular, as the case may be, unless otherwise indicated.
 
 
Page - 3
First Amendment to Loan Agreement
 
 
Section 4.5   Entire Agreement .  This First Amendment constitutes the entire agreement among the parties hereto with respect to the subject hereof.  All prior understandings, statements and agreements, whether written or oral, relating to the subject hereof are superseded by this First Amendment.
 
Section 4.6   Invalidity .  In the event that any one or more of the provisions contained in this First Amendment shall for any reason be held invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this First Amendment.
 
Section 4.7   Titles of Articles, Sections and Subsections .  All titles or headings to Articles, Sections, subsections or other divisions of this First Amendment or the exhibits hereto, if any, are only for the convenience of the parties and shall not be construed to have any effect or meaning with respect to the other content of such Articles, Sections, subsections, other divisions or exhibits, such other content being controlling as the agreement among the parties hereto.
 
Section 4.8   Governing Law .  This First Amendment shall be deemed to be a contract made under and shall be governed by and construed in accordance with the internal laws of the State of Texas.
 
This First Amendment, the Loan Agreement, as amended hereby, the Note, and the other Loan Documents represent the final agreement between the parties and may not be contradicted by evidence of prior, contemporaneous, or subsequent oral agreements of the parties.
 
There are no unwritten oral agreements between the parties.
 
IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed and delivered by their proper and duly authorized officers as of the Effective Date.
 

BORROWER:
 
 
 
ISRAMCO, INC.
   
By:                                                                                          
Haim Tsuff, Chief Executive Officer
     

LENDER:
 
 
 
I.O.C. - ISRAEL OIL COMPANY, LTD.
 
By:                                                                                           
 
 
By:  ______________________________________
 

 
Page - 4
First Amendment to Loan Agreement
 
EXHIBIT 10.20
 
 
ISRAMCO, INC.
2011 STOCK INCENTIVE PLAN


1.   Purpose .  The purpose of this Plan is to provide incentive to key Employees and members of the Board of Directors of, and consultants and advisors to, the Company, any Parent Corporation, or any Subsidiary, to encourage proprietary interest in the Company, to encourage such key Employees, members of the Board of Directors, consultants and advisors to remain in the employ and/or service of the Company and its Parent Corporation and Subsidiaries, and to attract new Employees, members of the Board of Directors, consultants and advisors with outstanding qualifications.
 
2.   Definitions .  Unless otherwise defined herein or the context otherwise requires, the capitalized terms used herein shall have the following meanings:
 
(a)   “ Award ” shall mean an award of Non-statutory Stock Options, Incentive Stock Options, or the award or sale of Restricted Shares.
 
(b)   “ Award Agreement ” shall mean a written agreement in such form as may from time to time be approved by the Board, setting forth the terms and conditions of an Award.
 
(c)   “ Board ” shall mean the Board of Directors of the Company.
 
(d)   “ Change of Control Transaction ” shall mean (i) the acquisition, directly or indirectly, by any person, entity or group (within the meaning of Section 13(d)(3) of the Exchange Act) of the beneficial ownership of securities holding more than fifty percent (50%) of the total combined voting power of all outstanding securities of the Company, other than any Person that is a Parent Corporation as of the date of approval of this Plan by the Board; (ii) a merger or consolidation in which the Company is not the surviving entity, except for a transaction in which the stockholders of the Company immediately prior to such merger or consolidation hold, in the aggregate, securities possessing more than fifty percent (50%) of the total combined voting power of all outstanding voting securities of the surviving entity immediately after such merger or consolidation; (iii) a reverse merger in which the Company is the surviving entity but in which securities possessing more than fifty percent (50%) of the total combined voting power of all outstanding voting securities of the Company are transferred to or acquired by a person or entity different from the persons or entities holding those securities immediately prior to such merger; or (iv) the sale, transfer or other disposition (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company.
 
2011 Stock Incentive Plan
 
 
 
(e)   “ Code ” shall mean the Internal Revenue Code of 1986, as amended.
 
(f)   “ Common Stock ” shall mean the Company’s common stock, par value $0.01 per share.
 
(g)   “ Company ” shall mean Isramco, Inc., a Delaware corporation.
 
(h)   “ Employee ” shall mean any individual who is employed by the Company, a Subsidiary or Parent Corporation, as determined by the Board.
 
(i)   “ Exchange Act ” shall mean the Securities Exchange Act of 1934, as amended and in effect from time to time, or any successor statute.
 
(j)   “ Exercise Price ” shall mean the purchase price per share deliverable upon the exercise of an Option.
 
(k)   “ Fair Market Value ” shall mean the value of one (1) share of Common Stock, determined as follows:
 
(i)   If the shares of Common Stock are (A) listed on an exchange, the closing price as reported for composite transactions on the business day immediately prior to the date of valuation or, if no sale occurred on that date, then the mean between the closing bid and asked prices on such exchange on such date, and (B) if listed on The Nasdaq Capital Market System of the National Association of Securities Dealers, Inc. Automated Quotation System (“ Nasdaq ”), or any successor, the last sale price on the business day immediately prior to the date of valuation or, if no sale occurred on such date, then the mean between the highest bid and lowest asked prices as of the close of business on the business day immediately prior to the date of valuation, as reported in Nasdaq;
 
(ii)   If the shares of Common Stock are not listed on an exchange or on The Nasdaq Capital Market, or any successor, System or Nasdaq SmallCap but are otherwise traded over-the-counter, the mean between the highest bid and lowest asked prices quoted in the Nasdaq system as of the close of business on the business day immediately prior to the date of valuation or, if on such date such security is not quoted in the Nasdaq system, the mean between the representative bid and asked prices on such date in the domestic over-the-counter market as reported by the National Quotation Bureau, Inc., or any similar successor organization; and
 
2011 Stock Incentive Plan
2
 
 
(iii)   If neither clause (i) nor (ii) above applies, the fair market value as reasonably determined by the Board using reasonable valuation principles reasonably applied in good faith and in accordance with the regulations under Section 409A of the Code.  Such determination shall be conclusive and binding on all persons.
 
(l)   “ Incentive Stock Option ” shall mean an Option granted to an Employee that meets the requirements of Section 422 of the Code.
 
(m)   “ Non-statutory Stock Option ” shall mean an Option that does not meet the requirements of Section 422 of the Code.
 
(n)   “ Option ” shall mean a Non-statutory Stock Option or an Incentive Stock Option.
 
(o)   “ Parent Corporation ” shall mean any corporation or other entity (other than the Company) in an unbroken chain of corporations or other entities ending with the Company if each of the corporations or other entities other than the Company owns stock or other equity securities possessing 50% or more of the combined voting power of all classes of stock or other equity securities in one of the other corporations or other entities in such chain.
 
(p)   “ Participant ” shall have the meaning ascribed to it in Section 6 hereof.
 
(q)   “ Person ” shall have the meaning ascribed to it in Section 3(a) (9) of the Exchange Act, and shall include a “group,” as defined in Rule 13d-5 promulgated thereunder.
 
(r)   “ Plan ” shall mean this Isramco, Inc. 2011 Stock Incentive Plan.
 
(s)   “ Restricted Shares ” shall mean shares of Common Stock granted or sold pursuant to this Plan, subject to the other terms and conditions contained herein or in the applicable Award Agreement.
 
2011 Stock Incentive Plan
3
 
 
(t)    “ Subsidiary ” shall mean, as to any person, (i) any corporation more than 50% of whose stock of any class or classes having by the terms thereof ordinary voting power to elect a majority of the directors of such corporation (irrespective of whether or not at the time stock of any class or classes of such corporation shall have or might have voting power by reason of the happening of any contingency) is at the time owned by such person and/or one or more Subsidiaries of such person, (ii) any limited liability company more than 50% of whose equity interests having by the terms thereof ordinary voting power to manage the operations of such limited liability company (irrespective of whether or not at the time interests of any class or classes of such limited liability company shall have or might have voting power by reason of the happening of any contingency) is at the time owned by such person and/or one or more Subsidiaries of such person, and (iii) any partnership, association, joint venture or other entity in which such person and/or one or more Subsidiaries of such person have more than a 50% equity interest therein.
 
3.   Effective Date and Duration of Plan .  This Plan shall become effective upon its approval by the Board subject to its subsequent approval by the stockholders of the Company.  This Plan shall terminate ten years from the date this Plan becomes effective, and no Award may be granted under this Plan thereafter, but such termination shall not affect any Award theretofore granted.
 
4.   Types of Awards .  Awards pursuant to this Plan may be (i) Incentive Stock Options, (ii) Non-statutory Stock Options, or (iii) Restricted Shares.
 
5.   Administration .
 
(a)   This Plan will be administered by the Board, whose construction and interpretation of the terms and provisions hereof shall be final and conclusive.  The Board may in its sole discretion make Awards and authorize the Company to issue shares of Common Stock pursuant to such Awards, as provided in, and subject to the terms and conditions of, this Plan.  The Board shall have authority, subject to the express provisions of this Plan, to construe this Plan and the respective Award Agreements, to prescribe, amend and rescind rules and regulations relating to this Plan, to determine the terms and provisions of Award Agreements, which need not be identical, to advance the lapse of any waiting, forfeiture or installment periods and exercise dates, and to make all other determinations in the judgment of the Board necessary or desirable for the administration of this Plan.  The Board may correct any defect or supply any omission or reconcile any inconsistency in this Plan or in any Award Agreement in the manner and to the extent it shall deem expedient to carry this Plan into effect and it shall be the sole and final judge of such expediency.  No director shall be liable for any action or determination taken or made in good faith under or with respect to this Plan or any Award.
 
2011 Stock Incentive Plan
4
 
 
(b)   Delegation of Authority .  The Board may, to the full extent permitted by law, delegate any or all of its powers under this Plan to the Compensation Committee of the Board, as such Committee may be constituted from time to time, or such other Committee of the Board as the Board may determined from time to time (the “ Committee ”) of two or more directors, and if the Committee is so appointed all references to the Board in this Plan shall mean and relate to such Committee to the extent of the powers so delegated.  The Board may, from time to time, delegate to the Company’s Chief Executive Officer authority under this Plan to grant Awards to Participants.
 
6.   Eligibility .  Awards shall be made only to persons who are, at the time of grant, officers, employees, members of the Board of Directors, consultants or advisors to the Company or any Parent Corporation or Subsidiary (collectively, “ Participants ”; individually, a “ Participant ”), but only Employees may be granted Incentive Stock Options.  A Participant who has been granted an Award may, if such person is otherwise eligible and if otherwise in accordance with the terms of this Plan, be granted an additional Award or Awards if the Board shall so determine.
 
7.   Stock Subject to Plan .  Subject to adjustment as provided in Section 13 hereof, the maximum number of shares of Common Stock of the Company which may be issued and sold pursuant to Awards made under this Plan is 200,000 shares.  Such shares may be authorized and unissued shares or may be shares issued and thereafter acquired by the Company.  If either (i) Restricted Shares are forfeited or repurchased by the Company following their award under this Plan, or (ii) Options granted under this Plan are canceled, repurchased or expire or terminate for any reason without having been exercised in full, the forfeited or repurchased Restricted Shares, or the unpurchased shares of Common Stock subject to any such Option, as the case may be, shall again be available for subsequent Awards under this Plan.  Restricted Shares, Options and shares of Common Stock issuable upon exercise of Options granted under this Plan may be subject to transfer restrictions, repurchase rights or other restrictions as shall be determined by the Board.
 
8.   Award Agreements .  As a condition to the grant of an Award under this Plan, each Participant shall sign an Award Agreement in such form, and providing for such terms and conditions, as the Board shall determine at the time such Award is authorized to be granted.  Such Award Agreements need not be identical but shall comply with, and be subject to, the terms and conditions set forth herein.
 
9.   Options Generally .
 
(a)   Purchase Price .  The Exercise Price of an Option shall be determined by the Board on the date of grant and set forth in the Award Agreement. The Exercise Price shall not be less than the Fair Market Value of the Common Stock as of the date of grant.
 
2011 Stock Incentive Plan
5
 
 
(b)   Payment of Exercise Price .  Payment of the Exercise Price of an Option shall be made in such manner as provided in the Award Agreement, which may include (i) cash, (ii) delivery of shares of Common Stock owned by the holder of the Option for longer than six months, (iii) a cashless exercise effected in accordance with rules adopted by the Board, upon approval by the Board, (iv) any other manner permitted by law and allowed by the Board in its sole discretion, or (v) any combination of the foregoing.
 
(c)   Option Term .  Each Option and all rights thereunder shall expire on such date as the Board shall determine on the date the Option is authorized to be granted, and such Option shall be subject to earlier termination as may be provided in this Plan and in the applicable Award Agreement.  The Board shall have authority to extend the term of a Non-statutory Stock Option at any time.  In no event may any Option remain in effect after the expiration of ten years from the date on which such Option is granted (or five years in the case of Options described in Section 10(b)) .
 
(d)   Exercise of Options .  Each Option shall be exercisable either in full or in installments at such time or times and during such period as shall be set forth in the Award Agreement evidencing such Option; provided , however , that (i) no Option shall have a term in excess of ten years from the date of grant (or five years in the case of Options described in Section 10(b) ), and (ii) the periods of time following an Option holder’s cessation of employment with the Company, any Parent Corporation or Subsidiary, or service as a member of the Board or consultant or advisor to the Company, any Parent Corporation or Subsidiary, or following an Option holder’s death or disability, during which an Option may be exercised, as provided in paragraph (f) below, shall not be included for purposes of determining the number of shares of Common Stock with respect to which such Option may be exercised.
 
(e)   Rights as a Stockholder .  A Participant shall have no rights as a stockholder with respect to any shares covered by an Option until the date of issue of a stock certificate to such person for such shares.  Except as otherwise expressly provided in this Plan, no adjustment shall be made for dividends or other rights for which the record date is prior to the date such stock certificate is issued.
 
(f)   Effect of Cessation of Service .  Notwithstanding anything contained in this Plan to the contrary, no Option may be exercised unless, at the time of such exercise, the Participant is, and has been continuously since the date of grant of such person’s Option, an Employee, a member of the Board of Directors, or serving as a consultant or advisor to one or more of the Company, a Parent Corporation or a Subsidiary, except if and to the extent the applicable Award Agreement provides otherwise (other than with respect to an Incentive Stock Option for which Section 10 hereof shall apply); provided , however , that in no event may any Option be exercised after the expiration date of the Option.
 
2011 Stock Incentive Plan
6
 
 
(g)   Transfer Restrictions .  Except as otherwise approved by the Board, during the life of the Participant an Option shall be exercisable only by or on behalf of such person and no Option granted under the Plan shall be assignable or transferable by the person to whom it is granted, either voluntarily or by operation of law (including a domestic relations order), except by will or the laws of descent and distribution.
 
(h)   Restrictions .  The Company may condition the grant or exercise of any Option upon the grantee’s execution of an agreement that restricts or limits the rights of the grantee to sell or transfer the Common Stock issued thereunder.
 
10.   Incentive Stock Options .
 
Options granted under this Plan that are intended to be Incentive Stock Options shall be specifically designated as Incentive Stock Options and shall be subject to the following additional terms and conditions:

(a)   Dollar Limitation .  The aggregate Fair Market Value (determined as of the respective date or dates of the grant) of the Common Stock with respect to which Incentive Stock Options granted to any Employee under this Plan (and under any other plans of the Company or any Parent Corporation or Subsidiary) are exercisable for the first time shall not exceed $100,000 in any calendar year.  In the event that Section 422 of the Code is amended to alter the limitation set forth therein, the limitation of this paragraph (a) shall be automatically adjusted accordingly.
 
(b)   10% Shareholder .  If any Employee to whom an Incentive Stock Option is to be granted under this Plan is at the time of the grant of such Option the owner of stock possessing more than 10% of the total combined voting power of all classes of stock of the Company or of any Parent Corporation or any Subsidiary, then the following special provisions shall be applicable to the Incentive Stock Option granted to such individual:
 
(i)   the Exercise Price per share of Common Stock subject to such Incentive Stock Option shall not be less than 110% of the Fair Market Value thereof at the time of grant; and
 
(ii)   the exercise period of such Incentive Stock Option shall not exceed five years from the date of grant.
 
(c)   Exercise Price .  Except as may be provided in Section 10(b) , the Exercise Price per share of Common Stock subject to such Incentive Stock Option shall not be less than the Fair Market Value at the time of grant.
 
2011 Stock Incentive Plan
7
 
 
(d)   Effect of Cessation of Service .  No Incentive Stock Option may be exercised unless, at the time of such exercise, the Participant is, and has been continuously since the date of grant of such Option, an Employee, except that if and to the extent the applicable Award Agreement so provides:
 
(i)   the Option may be exercised within a period not to exceed three months after the date the holder thereof ceases to be an Employee for any reason other than death or disability;
 
(ii)   if the Participant dies while in the employ of the Company, a Parent Corporation or a Subsidiary or within three months after such Participant ceases to be such an Employee, the Option may be exercised by the person to whom it is transferred by will or the laws of descent and distribution within a period not to exceed one year after the date of death; and
 
(iii)             if the Participant becomes disabled (within the meaning of Section 22(e)(3) of the Code) while the Participant is an Employee, the Option may be exercised within a period not to exceed one year after the date such holder ceases to be an Employee because of such disability.
 
Except as modified by the preceding provisions of this Section 10 , all the provisions of this Plan applicable to Options generally shall be applicable to Incentive Stock Options granted hereunder.

11.   Restricted Shares.
 
(a)   Awards of Shares .  Awards of Restricted Shares may be made under this Plan on such terms and conditions as the Board may from time to time approve, including the price, if any, to be paid by the recipient of the Restricted Shares.  Awards of Restricted Shares may be made alone, in addition to or in tandem with other Awards under this Plan Subject to the terms of this Plan, the Board shall determine the number of Restricted Shares to be awarded to each recipient and the Board may impose different terms and conditions on a Restricted Share Award than on any other Award made to the same recipient or other Award recipients.  Each recipient of Restricted Shares shall, except in the circumstances described in paragraph (b) below, be issued one or more stock certificates evidencing such Restricted Shares.  Each such certificate shall be registered in the name of such recipient, and shall bear an appropriate legend referring to the terms and conditions applicable to the Restricted Shares evidenced thereby.
 
2011 Stock Incentive Plan
8
 
 
(b)   Forfeiture of Restricted Shares .  In making an Award of Restricted Shares, the Board may impose a requirement that the recipient must remain in the employment or service (including service as an advisor or consultant) of the Company or any Parent Corporation or Subsidiary for a specified minimum period of time, or else forfeit all or a portion of such Restricted Shares. In such case, the certificate(s) evidencing the Restricted Shares shall be held in custody by the Company until such Shares are no longer subject to forfeiture.  The Board shall have authority to determine whether to accelerate the termination of any forfeiture provisions contained in any applicable Award Agreement.
 
(c)   Rights as a Stockholder; Stock Dividends .  Subject to any restrictions set forth in the applicable Award Agreement, a recipient of Restricted Shares shall have voting, dividend and all other rights of a stockholder of the Company as of the date such Shares are issued and registered in such recipient’s name (whether or not certificates evidencing such Shares are delivered to such recipient).  Except as may otherwise be set forth in the applicable Award Agreement, stock dividends issued with respect to Restricted Shares shall be treated as additional Restricted Shares under the applicable Award Agreement and shall be subject to the same terms and conditions that apply to the Restricted Shares with respect to which such dividends are issued.
 
12.   General Award Restrictions .
 
(a)   Investment Representations .  The Company may require any person to whom an Award is made, as a condition of such Award, to give written assurances in substance and form satisfactory to the Company to the effect that such person is acquiring the Common Stock subject to the Award for such person’s own account for investment and not with any present intention of selling or otherwise distributing the same, and to such other effects as the Company deems necessary or appropriate in order to comply with applicable federal and state securities laws.
 
(b)   Legends .  All certificates representing shares issued upon exercise of an Option or Restricted Shares shall have endorsed thereon the following legend:
 
THESE SECURITIES HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”), OR THE SECURITIES LAWS OF ANY STATE AND MAY NOT BE TRANSFERRED WITHOUT REGISTRATION UNDER THE SECURITIES ACT AND ANY APPLICABLE STATE SECURITIES LAWS OR AN OPINION OF COUNSEL, SATISFACTORY TO THE COMPANY, THAT SUCH REGISTRATION IS NOT REQUIRED.
 
2011 Stock Incentive Plan
9
 
 
(c)   Special Conditions to Issuance of Shares .  Each Award shall be subject to the requirement that, if at any time counsel to the Company shall determine that the listing, registration or qualification of the shares of Common Stock subject to such Award upon any securities exchange or under any state or federal law, or the consent or approval of any governmental or regulatory body, is necessary as a condition of, or in connection with, the issuance or purchase of such shares thereunder, such shares may not be issued unless such listing, registration, qualification, consent or approval shall have been effected or obtained on conditions acceptable to the Board.  Nothing herein shall be deemed to require the Company to apply for or to obtain such listing, registration or qualification.
 
13.   Recapitalization .  In the event that the number of outstanding shares of Common Stock of the Company changes or the Common Stock is exchanged for a different kind of shares or other securities of the Company, in either case by reason of any recapitalization, reclassification, stock split, stock dividend, combination or subdivision, appropriate adjustment shall be made in the number and kind of shares available under this Plan and under any Options granted under this Plan as determined by the Board.  Such adjustment to outstanding Options shall be made without change in the total exercise price applicable to the unexercised portion of such Options, but a corresponding adjustment in the applicable Exercise Price shall be made.  No adjustment shall be made pursuant to this Section 13 that would, within the meaning of any applicable provisions of the Code: (i) constitute a modification, extension or renewal of any Incentive Stock Option or a grant of additional benefits to the holder of an Incentive Stock Option; or (ii) cause an Option to become subject to Section 409A of the Code.
 
14.   Change of Control Transaction .
 
(a)   Unless otherwise provided in an Award Agreement, if a Change of Control Transaction occurs, outstanding Options shall be subject to the agreement implementing such transaction.  Such agreement, without the Participant’s consent, may provide for terms and conditions as determined by the Board (or any officer of the Company authorized by the Board), including, without limitation, the following:
 
(i)   the continuation of such outstanding Options by the Company (if the Company is the surviving entity);
 
(ii)   the assumption of the Plan and such outstanding Options by the surviving entity or its parent;
 
(iii)   subject to Section 13, the substitution by the surviving entity or its parent of options with substantially the same terms for such outstanding Options; or
 
2011 Stock Incentive Plan
10
 
 
(iv)   the acceleration of all unexercised outstanding Options that would become exercisable during at least the 12-month period after the closing date of the Change of Control Transaction to a date prior to such closing date, and the termination of Options to the extent not exercised prior to such closing date.  To the extent that such Options are exercised in accordance with this subsection (iv), the Board, in its sole discretion, may elect to pay to a Participant an amount of cash, per share, equal to the Fair Market Value of the share of Common Stock (as such Fair Market Value is determined by the Board) issued as a result of the exercise of such Option minus the Exercise Price in exchange for the surrender of such share of Common Stock.  Acceleration of a greater number of outstanding Options may be provided in the sole discretion of the Board.
 
(b)   If a Change of Control Transaction occurs, the Board, in its sole discretion, may accelerate the termination of some or all forfeiture provisions contained in any applicable Award Agreement.
 
15.   No Special Employment Rights .  Nothing contained in this Plan or in any Award Agreement shall confer upon any Award recipient any right with respect to the continuation of such person’s employment by the Company (or any Parent Corporation or Subsidiary) or interfere in any way with the right of the Company (or any Parent Corporation or Subsidiary) at any time to terminate such employment or to increase or decrease the compensation of the Award recipient from the rate in existence at the time of the Award.  Whether an authorized leave of absence, or absence in military or government service, shall constitute termination or cessation of employment for purposes of this Plan or any Award shall be determined by the Board.
 
16.   Other Employee Benefits .  The amount of any compensation deemed to be received by an Employee as a result of any Award (including the exercise of an Option, or the sale of shares of Common Stock received upon such exercise or of Restricted Shares) will not constitute “earnings” with respect to which any other employee benefits of such employee are determined, including, without limitation, benefits under any pension, profit sharing, life insurance or salary continuation plan.
 
17.   Amendment of this Plan .  The Board may at any time and from time to time modify, amend or terminate this Plan in any respect, except to the extent stockholder approval is required by law.  The termination or any modification or amendment of this Plan shall not, without the consent of an Award recipient, affect such Award recipient’s rights under any Award Agreement unless such Award Agreement so specifies.  With the consent of the affected Award recipient, the Board may amend outstanding Award Agreements in a manner not inconsistent with this Plan.  The Board shall have the right to amend or modify the terms and provisions of this Plan and of any outstanding Incentive Stock Options granted under this Plan to the extent necessary to qualify any or all such Options for such favorable federal income tax treatment (including deferral of taxation upon exercise) as may be afforded incentive stock options under Section 422 of the Code.
 
2011 Stock Incentive Plan
11
 
 
18.   Withholding .
 
(a)   Each Participant shall, no later than the date as of which the value of an Award first becomes includible in such person’s gross income for applicable tax purposes, pay to the Company, or make arrangements satisfactory to the Board regarding payment of, federal, state, local or other taxes of any kind required by law to be withheld with respect to such Award.  The obligations of the Company under this Plan shall be conditional on such payment or arrangements, and the Company (and where applicable, a Subsidiary or Parent Corporation) shall, to the extent permitted by law, have the right to deduct any such taxes from any payment otherwise due to the Participant.
 
(b)   To the extent permitted by the Board, and subject to the terms and conditions as the Board may provide, a Participant may elect to have the withholding tax obligation, or any additional tax obligation with respect to any Awards hereunder, satisfied by (i) having the Company withhold shares of Common Stock otherwise deliverable to such person with respect to the Award or (ii) delivering to the Company shares of unrestricted Common Stock previously owned by the person, provided, that the Participant may elect to withhold only the minimum statutory taxes.
 
19.   Compliance with Code Section 409A .
 
The Plan is intended to be exempt from the requirements of Code Section 409A and any regulations or guidance that may be adopted thereunder from time to time and shall be interpreted and administered consistent with that intent.  No Non-statutory Stock Option may be granted if such Option contains a term or condition that would provide for the deferral of income recognition beyond the date the Option is exercised. The Plan may be amended or interpreted by the Board as it determines necessary or appropriate in accordance with Code Section 409A and to avoid a plan failure under Code Section 409A(a)(1).  Notwithstanding the foregoing, if any Award is subject to and not exempt from, Code Section 409A, and if amounts under the Award are payable upon a Participant’s “separation from service” (as defined in Code Section 409A) when the Participant is a “specified employee” (as defined in Code Section 409A), the payment shall be delayed until the first business day that is at least six months after the Participant’s “separation from service.”
 
2011 Stock Incentive Plan
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EXHIBIT 23.1
 
CONSENT OF CAWLEY, GILLESPIE & ASSOCIATES, INC.
 
 
 
The undersigned hereby consents to the inclusion of the information included in this Annual Report on Form 10-K with respect to the oil and gas reserves of Isramco, Inc as of the year ended December 31, 2011. We hereby further consent to all references to our firm included in this Annual Report on Form 10-K.
 
 
 

 
 CAWLEY, GILLESPIE & ASSOCIATES, INC.
 
 
 
Fort Worth, Texas
 
March 6, 2012
 
 
 
EXHIBIT 23.2
 
 
 
 
 

 
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion of our reserves report which sets forth our estimates of proved undeveloped, probable, and possible gas reserves and future revenue, as of December 31, 2011, to the Isramco, Inc. overriding royalty interest in Tamar Field, located in the Tamar Lease I/12, offshore Israel, appearing in this Isramco, Inc. Annual Report on Form 10-K.


NETHERLAND, SEWELL & ASSOCIATES, INC.

/s/ Danny D. Simmons
By:                                                                   
Danny D. Simmons, P.E.
President and Chief Operating Officer


Houston, Texas
March 23, 2012
 

 
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients.  The digital document is intended to be substantively the same as the original signed document maintained by NSAI.  The digital document is subject to the parameters, limitations, and conditions stated in the original document.  In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

 
EXHIBIT 31.1
 
RULE 13A-14(A) / 15D-14(A) CERTIFICATIONS

I, Haim Tsuff, certify that:

1. I have reviewed this annual report on Form 10-K of Isramco, Inc. for the year ended December 31, 2011;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in the in the Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting  to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of the internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons fulfilling the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 23, 2012       
 
 /s/ HAIM TSUFF                                       
HAIM TSUFF
CHIEF EXECUTIVE OFFICER
(PRINCIPAL EXECUTIVE OFFICER)

 

 
 
EXHIBIT 31.2
 
RULE 13A-14(A) / 15D-14(A) CERTIFICATIONS

I, Edy Francis, certify that:

1. I have reviewed this annual report on Form 10-K of Isramco, Inc. for the year ended December 31, 2011;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in the in the Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting  to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of the internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons fulfilling the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 23, 2012         
 
/s/ EDY FRANCIS                                                                             
EDY FRANCIS
CHIEF FINANCIAL OFFICER
(PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)
 
 
 
 
EXHIBIT 32.1
CERTIFICATION BY CHIEF EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Isramco, Inc. (the "Company") on Form 10-K for the year ended December 31, 2011 (the "Report") filed with the Securities and Exchange Commission, I, Haim Tsuff, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Company's Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

MARCH 23, 2012           
 
/s/ HAIM TSUFF                                        
HAIM TSUFF
CHIEF EXECUTIVE OFFICER
(PRINCIPAL EXECUTIVE OFFICER)


A SIGNED ORIGINAL OF THIS STATEMENT REQUIRED BY SECTION 906 HAS BEEN PROVIDED TO ISRAMCO, INC. AND WILL BE RETAINED BY ISRAMCO, INC. AND FURNISHED TO THE SECURITIES AND EXCHANGE COMMISSION OR ITS STAFF UPON REQUEST.
 
 
 
 
EXHIBIT 32.2

CERTIFICATION BY CHIEF EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Isramco, Inc. (the "Company") on Form 10-K for the year ended December 31, 2011 (the "Report") filed with the Securities and Exchange Commission, I, Edy Francis, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Company's Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

MARCH 23, 2012           
 
/s/ EDY FRANCIS                                                                         
EDY FRANCIS
CHIEF FINANCIAL OFFICER
(PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)


A SIGNED ORIGINAL OF THIS STATEMENT REQUIRED BY SECTION 906 HAS BEEN PROVIDED TO ISRAMCO, INC. AND WILL BE RETAINED BY ISRAMCO, INC. AND FURNISHED TO THE SECURITIES AND EXCHANGE COMMISSION OR ITS STAFF UPON REQUEST.
EXHIBIT 99.1
 
March 6, 2012
 

 
Mr. Haim Tsuff -   CEO
Isramco, Inc
2425 West Loop South, Suite 810
Houston, Texas 77027
 

 
Re:    Evaluation Summary - SEC Price
  Isramco, Inc Interests
Total Proved Reserves
As of December 31, 2011                                                     
 
 
Pursuant to the Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue
 

Dear Mr. Tsuff:

As requested, this report was prepared on March 6, 2012 for Isramco, Inc for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to the subject interests in certain properties in various states. This evaluation utilized an effective date of December 31, 2011, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (“SEC").   The results of this evaluation are presented in the accompanying tabulations, with a composite summary of the values presented below:
 
 
       
Proved Developed Producing
   
Proved Developed Non-Producing
   
Total Proved
 
Net Reserves
                       
   Oil
 
- Mbbl
      3,011.3       223.2       3,234.5  
   Gas
 
- MMcf
      24,380.9       674.2       25,055.1  
   NGL
 
- Mbbl
      1,882.8       13.6       1,896.5  
Revenue
                             
   Oil
  - M$       280,359.7       20,739.4       301,099.0  
   Gas
  - M$       117,313.1       2,476.9       119,790.0  
   NGL
  - M$       85,122.8       656.4       85,779.1  
   Other
  - M$       0.0       0.0       0.0  
Severance Taxes
  - M$       29,122.9       1,418.2       30,541.1  
Ad Valorem Taxes
  - M$       16,004.3       733.3       16,737.6  
Operating Expenses
  - M$       190,048.5       2,848.9       192,897.4  
Other Deductions
  - M$       0.0       0.0       0.0  
Investments
  - M$       0.0       875.9       875.9  
Net Cash Flows
  - M$       247,619.8       17,996.4       265,616.3  
Discounted @ 10%   (Present Worth)
  - M$       127,588.4       7,930.5       135,518.9  
 
 
 
 
 
Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes.  In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”.  The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.   The oil reserves include oil and condensate.  Oil and natural gas liquid (NGL) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base. Our estimates are for proved developed reserves only and do not include any probable or possible reserves.
 
Presentation
This report is divided into three reserve category sections: Total Proved (“TP”), Proved Developed Producing (“PDP”) and Proved Developed Non-Producing (“PDNP”).  Within the PDP and PDNP category sections there are grand total Table I and Table II “oneline” summaries.  The Table I presents composite reserve estimates and economic forecasts for the particular reserve category.  The Table II “oneline” summary presents estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flow for the individual properties that make up the corresponding Table I.  The data presented in each Table I is explained in page 1 of the Appendix.  The methods employed in estimating reserves are described in page 2 of the Appendix.  For a more detailed explanation of the report layout, please refer to the Table of Contents following this letter.

Hydrocarbon Pricing
 The base SEC oil and gas prices calculated for December 30, 2011 were $96.19/bbl and $4.113/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2011 and the base gas price is based upon Henry Hub spot prices (EIA) during 2011. Adjustments to oil and gas prices were forecast based upon 2010-2011 historical data and were applied by property. Adjustments may include treating costs, transportation charges and/or crude quality and gravity corrections.  All economic factors were held constant in accordance with SEC guidelines.
 
Economic Parameters
Shrinkage factors were applied to each property against net gas volumes. Ownership was accepted as furnished and has not been independently confirmed. Direct lease operating expenses were forecast based upon 2010-2011 historical expenses.  Investments were applied going forward as provided by your office. Severance tax values were determined by applying normal state severance tax rates. Ad valorem tax rates were forecast as provided by your office. All economic parameters, including lease operating expenses and investments, were held constant (not escalated) throughout the life of these properties.

SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix.  The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein.  The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered.  However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
 
 
 
 

Reserve Estimation Methods
The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
 
Non-producing reserve estimates, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
 
General Discussion
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included except as noted above.
 
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. We do not own an interest in the properties or Isramco, Inc and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.
 


Yours very truly,
 

 
CAWLEY, GILLESPIE & ASSOCIATES, INC.
 
Texas Registered Engineering Firm F-693
 

EXHIBIT 99.2
 
 
 
 
 
 
 
 
 
March 21, 2012




Isramco, Inc.
2425 West Loop South, Suite 810
Houston, Texas 77027

Ladies and Gentlemen:

In accordance with your request, we have estimated the proved undeveloped, probable, and possible gas reserves and future revenue, as of December 31, 2011, to the Isramco, Inc. overriding royalty interest in Tamar Field, located in the Tamar Lease I/12, offshore Israel.  We completed our evaluation on or about the date of this letter.  It is our understanding that the proved reserves estimated in this report constitute approximately 73 percent of all proved reserves owned by Isramco, Inc.  The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas.  Definitions are presented immediately following this letter.  This report has been prepared for Isramco, Inc.'s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the gas reserves and future net revenue to the Isramco, Inc. overriding royalty interest in these properties, as of December 31, 2011, to be:

   
Gas Reserves
   
Future Net Revenue (M$)
 
   
Gross
   
Net
         
Present Worth
 
Category
 
(BCF)
   
(BCF)
   
Total
   
at 10%
 
                         
Proved Undeveloped
    6,892.6       154.1       634,462.2       241,737.3  
                                 
Probable Undeveloped
    2,817.9       70.9       292,131.8       36,795.9  
                                 
Possible Undeveloped
    1,562.4       39.3       161,974.1       12,279.1  

Gas volumes are expressed in billions of cubic feet (BCF) at standard temperature and pressure bases.  These properties are not expected to produce commercial volumes of condensate.  Monetary values shown in this report are expressed in United States dollars ($) or thousands of United States dollars (M$).

The estimates shown in this report are for proved undeveloped, probable, and possible reserves.  This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.  Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status.  The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Isramco, Inc.'s share of the gross (100 percent) revenue from the properties prior to any deductions.  Future net revenue is after deductions for Isramco, Inc.'s share of production taxes and ad valorem taxes but before consideration of any income taxes.  The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money.  Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
 
 
 
 
 
 
 
 
 
The gas price used in this report is the 12-month unweighted arithmetic average of the first-day-of-the-month Henry Hub spot price for each month in the period January through December 2011.  The average price of $4.118 per MMBTU is held constant throughout the lives of the properties.

Because Isramco, Inc. owns no working interest in these properties, no operating costs or capital costs would be incurred.  However, estimated operating costs and capital costs have been used to confirm economic producibility and determine economic limits for the properties.  These cost estimates are based on our knowledge of similar operations.  Operating costs are held constant throughout the lives of the properties, and capital costs are held constant to the date of expenditure.  Isramco, Inc. would not incur any costs due to abandonment, nor would it realize any salvage value for the lease and well equipment.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities.  Since Isramco, Inc. owns an overriding royalty interest rather than a working interest in these properties, it would not incur any costs due to possible environmental liability.

The reserves shown in this report are estimates only and should not be construed as exact quantities.  Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves.  Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.  In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance.  If the reserves are recovered, the revenues therefrom could be more or less than the estimated amounts.  Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred by the working interest owners in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, and property ownership interests.  The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards).  We used standard engineering and geoscience methods, or a combination of methods, including volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations.  The reserves shown in this report are for undeveloped locations; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
 
 
 
 
 
 
 
The data used in our estimates were obtained from Isramco, Inc.; public data sources; and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate.  Supporting geoscience, performance, and work data are on file in our office.  The contractual rights to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed.  The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.  We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699


/s/ C.H. (Scott) Rees III
By:
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer




/s/ Richard B. Talley, Jr.                                                                           /s/ David E. Nice
By:                                                                                By:
Richard B. Talley, Jr., P.E. 102425                                                                           David E. Nice, P.G. 346
Vice President                                                                           Vice President


Date Signed:  March 21, 2012                                                                           Date Signed:  March 21, 2012


RBT:DEG
 
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients.  The digital document is intended to be substantively the same as the original signed document maintained by NSAI.  The digital document is subject to the parameters, limitations, and conditions stated in the original document.  In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
 
 
 
 
 
 
 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a).  Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties.   Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir .  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery.  When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

 
(i)
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
 
(ii)
Same environment of deposition;
 
(iii)(iv)
Similar geological structure; and
Same drive mechanism.
 
Instruction to paragraph (a)(2) : Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen .  Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.  In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate .  Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate .  The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves .  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
(ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Supplemental definitions from the 2007 Petroleum Resources Management System:
 
Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.  Improved recovery reserves are considered producing only after the improved recovery project is in operation.
 
Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.  Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons.  Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production.  In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
 
 
Definitions - Page 1 of 7
 
 
 
 
 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(7) Development costs.   Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.  More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 
(i)
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
 
(ii)
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
 
(iii)
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
 
(iv)
Provide improved recovery systems.
       
(8) Development project .  A development project is the means by which petroleum resources are brought to the status of economically producible.  As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well .  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible .  The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.  The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR) .  Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs .  Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.  Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property.  Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

 
(i)
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies.  Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
 
(ii)
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
 
(iii)
Dry hole contributions and bottom hole contributions.
 
(iv)
Costs of drilling and equipping exploratory wells.
 
(v)
Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well .  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well .  An extension well is a well drilled to extend the limits of a known reservoir.
 
 
Definitions - Page 2 of 7
 
 
 
 
 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(15) Field .  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.  There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.  Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field.  The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

 
(i)
Oil and gas producing activities include:

 
(A)
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
 
(B)
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
 
(C)
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
 
(1)
Lifting the oil and gas to the surface; and
 
(2)
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
 
(D)
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
 
Instruction 1 to paragraph (a)(16)(i) : The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank.  If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

 
a.
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
 
b.
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

 
(ii)
Oil and gas producing activities do not include:

 
(A)
Transporting, refining, or marketing oil and gas;
 
(B)
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
 
(C)
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
 
(D)
Production of geothermal steam.
 
(17) Possible reserves.   Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 
(i)
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.  When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
 
 
Definitions - Page 3 of 7
 
 
 
 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
 
(ii)
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain.  Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
 
(iii)
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
 
(iv)
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
 
(v)
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir.  Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
 
(vi)
 Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology.  Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
 
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 
(i)
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves.  When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
 
(ii)
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.  Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
 
(iii)
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
 
(iv)
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
 
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

 
(i)
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.  They become part of the cost of oil and gas produced.  Examples of production costs (sometimes called lifting costs) are:

 
(A)
Costs of labor to operate the wells and related equipment and facilities.
 
(B)
Repairs and maintenance.
 
(C)
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
 
 
Definitions - Page 4 of 7
 
 
 
 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
 
 
(D)
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
 
(E)
Severance taxes.
 
 
(ii)
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities.  To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate.  Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 
(i)
The area of the reservoir considered as proved includes:

 
(A)
The area identified by drilling and limited by fluid contacts, if any, and
 
(B)
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
(iii)
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
(iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
 
 
(A)
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
 
(B)
The project has been approved for development by all necessary parties and entities, including governmental entities.

 
(v)
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.  The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties.   Properties with proved reserves.

(24) Reasonable certainty.   If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
 
 
Definitions - Page 5 of 7
 
 
 
 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves.   Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26) : Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).


 
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
 
932-235-50-30  A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

 
a.
Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
 
b.
Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

 
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
 
932-235-50-31  All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

 
a.
Future cash inflows.  These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves.  Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
 
b.
Future development and production costs.  These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.  If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
 
c.
Future income tax expenses.  These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved.  The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
 
d.
Future net cash flows.  These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
 
e.
Discount.  This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
 
f.
Standardized measure of discounted future net cash flows.  This amount is the future net cash flows less the computed discount.

(27) Reservoir.   A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
 
 
Definitions - Page 6 of 7
 
 
 
 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(28) Resources.   Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations.  A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable.  Resources include both discovered and undiscovered accumulations.

(29) Service well.   A well drilled or completed for the purpose of supporting production in an existing field.  Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well.   A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition.  Such wells customarily are drilled without the intent of being completed for hydrocarbon production.  The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration.  Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves.   Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 
(i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
(ii)
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
 
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
 
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

 
Ÿ
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
 
Ÿ
The company's historical record at completing development of comparable long-term projects;
 
Ÿ
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
 
Ÿ
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
 
Ÿ
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

 
(iii)
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties.   Properties with no proved reserves.
 
 
 
Definitions - Page 7 of 7