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EX-10.16 - ISRAMCO INCex10-16.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 

 
FORM 10-K
 

 Mark one:
 
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009
   
r 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
COMMISSION FILE NUMBER: 0-12500

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

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

713-621-3882
(Registrant's Telephone Number, including Area Code)

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

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

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

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

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

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained in this Form, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.r

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

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

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

As of March 12, 2010, there were 2,717,691 shares of the Registrant's common stock par value $0.01 per share ("Common Stock") outstanding. The aggregate market value of the Common Stock held by non-affiliates of the Registrant at June 30, 2009, based on the last sale price of such equity reported on the Nasdaq market, was approximately $141 million.

DOCUMENTS INCORPORATED BY REFERENCE

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

ISRAMCO, INC.
2009 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

                  

 
Page
 PART I
 
     
ITEM 1.
 4
ITEM 1A.
  14
ITEM 1B.
  24
ITEM 2.
  24
ITEM 3.
  24
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
     
PART II
 
   
  25
ITEM 5.
  26
ITEM 6.
  26
ITEM 7.
  25
ITEM 8.
  37
ITEM 9.
  38
ITEM 9A.
38
ITEM 9B.
38
     
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
 
ITEM 15.
  40


 
 
Special note regarding forward-looking statements

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

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

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

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

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

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

·  
the ability to replace oil and natural gas reserves;

·  
environmental risks;

·  
drilling and operating risks;

·  
exploration and development risks;
 
·  
competition, including competition for acreage in oil and gas producing areas and for experienced personnel;

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

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

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

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

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

Overview

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

At December 31, 2009, our estimated total proved oil, natural gas reserves and natural gas liquids, as prepared by our independent reserve engineering firm, Cawley, Gillespie & Associates, Inc., were approximately 8,565 thousand barrels of oil equivalent (“MBOE”), consisting of 3,002 thousand barrels (Bbls) of oil, and 24,452 million cubic feet (Mcf) of natural gas and 1,488 thousand barrels (Bbls) natural gas liquids. Approximately 97.7% of our proved reserves were classified as proved developed. See Note 19 Supplemental Information to Consolidated Financial Statements to our consolidated financial statements.
 
Our business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs, acquiring strategic oil and gas properties and improving of existing oil and gas properties. Over the course of 2009, we have expanded our activities in the United States through continued development of existing proved properties. An additional important goal for implementing our business strategy is to maintain the lowest possible operating cost structure, among other things, by serving as operator of a substantial portion of our oil and natural gas properties.
 
Exploration, Development and Production

United States

We, through our wholly-owned subsidiaries, are involved in oil and gas exploration, developing, production and operation of wells in the United States. We own varying working interests in oil and gas wells in Louisiana, Texas, New Mexico, Oklahoma, Wyoming, Utah and Colorado and currently serve as operator of approximately 620 wells located mainly in Texas and New Mexico. The following is a summary of significant developments during 2008 through the present, including certain 2010 plans.

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

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

 
Israel

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

Matan and Michal Licenses.  In January 2009, Noble Energy, Inc. (“Noble”) completed the Tamar # 1 (“Tamar”) well at a depth of 16,076 feet and in approximately 5,500 feet of water.  This well is located offshore Israel and is operated by Noble.  After analysis of post drilling and production test data, Noble estimates the gross mean resources potential of Tamar to be 5 trillion cubic feet of natural gas.  Noble reports that performance modeling indicates that the well can ultimately be completed to achieve a production rate of over 150 million cubic feet per day (“Mmcf/d”).

Following the Tamar #1 well Noble and its other partners drilled two additional wells.  One was an exploration well, the Dalit # 1 well (on the Michal License) that was spudded on March 6, 2009. The second well was an appraisal well known as the Tamar #2 (on the Matan License) that was drilled to further define the resources available in the Tamar structure and to obtain information that will be important in the planning of the development for this field. 

On April 15, 2009, Noble announced flow test results from the Dalit natural gas discovery in the Michal license.  The tests, which yielded a flow rate of 33 Mmcf/d of natural gas, were limited by the testing equipment available on the drilling rig. Performance modeling indicates the well can be ultimately completed to achieve a production rate of approximately 200 Mmcf/d. Based on log and test results, Dalit is estimated to contain gross mean resources of approximately 500 billion cubic feet of natural gas.
 
On July 7, 2009, Noble announced the results from its Tamar #2 appraisal well. This well was, drilled to a total depth of 16,880 feet in 5,530 feet of water and is located approximately 3.5 miles northeast of the original discovery, Tamar #1. It was drilled on the flank of the structure with the intent of confirming reservoir quality and continuity, the appraisal well was also designed to confirm the projected gas/water contact.
 
The results of the Tamar #2 have considerably reduced the uncertainty in previous resource estimates for the structure. The gross mean resource estimate for Tamar has been raised to 6.3 trillion cubic feet, which represents a 26 percent increase over the estimate made following the Tamar #1 drilling.  In order to further confirm the Tamar drilling results, a reservoir consulting firm, Netherland, Sewell & Associates, Inc. (“NASI”), was retained to prepare an independent assessment of the discovered natural gas resources.
 
In August 2009 the partners in the Tamar gas field received a reserve report from NASI. According to the report the estimated 2P reserve (Proved + Probable Reserves) are 7.7 trillion cubic feet and the 1P reserve (Proved Reserves) are estimated to be 6 trillion cubic feet.
 
In December 2009, the Israeli Petroleum Commissioner granted the partners two leases that are expire on December 2038 covering Tamar and Dalit gas fields

We own an overriding royalty interest of 1.5375% in the Tamar and Dalit gas fields, which will increase to 2.7375% after payout.  

Med Yavne Lease.  Based on the gas finds known as "Or 1" and "Or South", a 30 year lease covering 53 square kilometers (approximately 13,100 acres) offshore Israel, was granted in June 2000 (the "Med Yavne Lease"). The original operator of the Med Yavne Lease was BG International Limited, a member of the British Gas Group ("BG").  BG resigned as the operator of the Lease and relinquished of its working interests in the Med Yavne Lease, and the partners appointed I.O.C Israel Oil Company as the successor operator.
 
According to the operator's estimates, which are based on the results of drilling the Or 1 and on a 3D seismic survey performed in the area of the Med Yavne lease, the recoverable gas reserves of Or 1 reserve are estimated at 35 billion cubic feet.  In January 2008 and in January 2009, I.O.C Israel Oil Company received an opinion from a consulting firm in the United States that performed a techno-economic examination of the development of the Or 1 reserve.  This opinion indicates that, under certain assumptions, development of the reserve by connection to a nearby platform (at a distance of seven miles) and from there via an existing transportation pipeline to the coast of Israel, may be economically feasible.  It is the intention of the partners in Med Yavne Lease to cooperate with independent third parties to jointly develop Or 1 reserve with their gas reserve.
 
 
Our participation interest of the Med Yavne Lease is 0.7052 %

Med Ashdod 2 and Hof Licenses.  In 2009 the Israel Petroleum Commission cancelled the Med Ashdod 2 and Hof licenses as a result of the failure of the operating interests to commence drilling operations as specified.  The Company had a 0.35% interest in the Med Ashdod 2 license and a 20% interest in the Hof license.

The table below sets forth the working interests of Isramco and all related and unrelated participants in the Med Yavne lease in Israel as of December 31, 2009 and the total acreage and the expiration date of the lease.
 
TABLE OF WORKING INTEREST
 (% Interest of 100%)

Name of Participant
 
Med Yavne Lease
 
Isramco (1)
    0.7052  
         
Related parties:
       
         
Isramco Negev 2, Limited
    49.863  
Partnership
       
         
I.O.C. Israel Oil Company
    14.7743  
         
I.N.O.C. Dead Sea
    --  
Limited Partnership
       
         
Naphtha Explorations
    3.5117  
Limited Partnership
       
         
J.O.E.L.  Jerusalem Oil Exploration, Ltd.
    4.4318  
         
Equital
    3.3291  
         
Unrelated parties
    23.3849  
         
Total
    100.00  
         
Area (acres)
    13,100  
         
Expiration Date (2)
 
6/10/2030
 

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

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

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

   
Before Payout
   
After Payout
 
Overriding Interest in the Med Yavne Lease (1)
   
0.1
%
   
1.3
%
Overriding Interest in the Michal & Matan Licenses
   
1.5375
%
   
2.7375
%
 
(1) A 30-year lease covering an area of approximately 53 square kilometers (including the area of the gas discovery) was granted in June 2000.
 
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 60 months. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivative contracts, which would potentially allow us to not record the change in fair value of our derivative contracts in the consolidated statements of operations. We carry our derivatives at fair value on our consolidated balance sheets, with the changes in the fair value included in our consolidated statements of operations in the period in which the change occurs. Our results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivative contracts.
 
As of December 31, 2009 we had swap contracts for a volume of 778,077 barrels of crude oil during 60 months, commencing January 2010, and swap contracts for a volume of 2,724,690 MMBTU of natural gas during 28 months commencing January 2010.
 
Hereunder are the open swap contracts positions as of December 31, 2009:
 
   
Swap Contracts
 
   
Natural Gas
   
Crude Oil
 
   
Volume
(MMBTU)
(*)
   
Weighted
Average
Price
($/MMBTU)
   
Volume
(Bbl)
   
Weighted
Average
Price
($/Bbl)
 
2010
   
1,785,648
     
7.88
     
254,868
     
79.59
 
2011
   
764,820
     
8.22
     
240,336
     
86.55
 
2012
   
174,222
     
8.65
     
127,473
     
82.37
 
2013
   
-
     
-
     
89,400
     
85.15
 
2014
   
-
     
-
     
66,000
     
86.95
 
 (*) Mcf = MMBTU
 
 
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, 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 8, “Long-term Debt”) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. We have elected to designate these positions for hedge accounting and therefore the unrealized gains and losses are recorded in ccumulated other comprehensive loss. The Company measures hedge effectiveness by assessing the changes in the fair value or expected future cash flows of the hedged item.
 
Our open interest rate positions, as described above, are as follows:

National amount (in thousands)
 
Start Date
 
Maturity Date
 
Weighted-Average
Interest Rate
 
  20,000  
April 2009
 
February 2011
    3.63 %
  6,000  
April 2009
 
February 2011
    2.90 %
 
Competitive Conditions in the Business

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring attractive producing oil and natural gas properties, obtaining purchasers and transporters of the oil and natural gas we produce and hiring and retaining key employees. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.
 
Markets and Major Customers
 
Through our wholly-owned subsidiary Jay Management Company, LLC ("Jay Management"), we operate a substantial portion of our oil and natural gas properties. As the operator of a property, the Company makes full payment of the costs associated with each property and seeks reimbursement from the other working interest owners in the property for their share of those costs. Isramco’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general were adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected.
 
The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. The Company has not experienced any significant losses from uncollectible accounts. The Company does not believe the loss of any one of its purchasers would materially affect the Company’s ability to sell the oil and natural gas it produces. The Company believes other purchasers are available in the Company’s areas of operations.
 
 
Seasonality of Business

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

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

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

Regulations

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

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.
 
Certain of our operations, or the operations of service companies engaged by us, may be subject to permits and restrictions under these statutes for emissions of air pollutants.  In this regard, the EPA proposed in a consent decree, which has not been approved by a federal court, that by January 31, 2011 it will issue a proposal to revise its national emissions standards for hazardous air pollution for crude oil and natural gas production, as well as gas transmission and storage as well as new source performance standards for oil and gas production.
 
Climate change legislation and greenhouse gas regulation
 
The issue of “global warming” has attracted significant attention and many believe that emissions of certain gases contribute to this problem. Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, and the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are considered “greenhouse gases” regulated by the Kyoto Protocol.  Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. Additionally, the United States Supreme Court has ruled, in Massachusetts, et al. v. EPA, that the EPA abused its discretion under the Clean Air Act by refusing to regulate carbon dioxide emissions from mobile sources. As a result of the Supreme Court decision and the change in presidential administrations, on December 7, 2009, the EPA issued a finding that many believe serves as the foundation under the Clean Air Act to issue other rules that could result in the promulgation of federal greenhouse gas regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, on September 22, 2009, the EPA also issued a greenhouse gasmonitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their greenhouse gas emissions, including methane and carbon dioxide, to the EPA. These emissions will be published on a register to be made available on the Internet. These regulations could apply to our operations. The EPA has proposed two other rules that would regulategreenhouse gas emissions, one of which would regulate greenhouse gases from stationary sources, and mightaffect sources in the oil and natural gas exploration and production industry and the pipeline industry. The EPA’s findings, the greenhouse gas reporting rule, and the proposed rules to regulate the emissions of greenhouse gases would result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry.
 
On June 26, 2009, the United States House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA.” On November 5, 2009 the Senate Committee on Environment and Public Works approved the “Clean Energy Jobs and American Power Act of 2009,” authored by John Kerry and Barbara Boxer, that is similar in many ways to ACESA. One of the purposes of these bills is to control and reduce emissions of greenhouse gases in the United States.  These bills would establish an economy-wide cap on emissions of greenhouse gases in the United States and would require an overall reduction in greenhouse gasemissions of 17% to 20% (from 2005 levels) by 2020, and by over 80% by 2050. Under these bills, most sources of greenhouse gas emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet the overall emission reduction goals of the bills. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of these bills would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. President Obama has indicated that he is in support of the adoption of legislation such as the two bills discussed above, and the White House is expending significant efforts to push for the legislation.
 
 
In two recent court decisions, one before the United States Second Circuit Court of Appeals and one before the United States Fifth Circuit Court of Appeals (The Fifth Circuit), the Court has allowed cases filed to require the imposition of greenhouse gas regulations to proceed. In the first case, Connecticut v. American Electric Power, the Second Circuit ruled that several states and other plaintiffs could continue their suit to impose greenhouse gas reductions on several utility defendants, concluding that a political question and standing objections of the defendants did not prohibit the suit from going forward. The Fifth Circuit, in Comer v. Murphy Oil, ruled that plaintiffs could similarly pursue a damage suit and the political question did not prohibit the suit. The Comer v. Murphy Oil   case involves claims by plaintiffs who suffered damages from Hurricane Katrina and are seeking to recover damages from certain greenhouse gas emitters, asserting their emissions contributed to their increased damages. In another case filed in the Texas District Court in Austin on October 6, 2009, a citizens group sued the Texas Commission on Environmental Quality (“TCEQ”) asserting that the agency was required to regulate carbon dioxide emissions from parties applying for permits under the Texas Clean Air Act. This lawsuit could result in  additional regulation of our operations, if the Texas courts require the TCEQ to regulate carbon dioxide and perhaps other greenhouse gases, such as methane,.
 
In summary, we may be subject to EPA greenhouse gasmonitoring and reporting rules, and potentially new EPA permitting rules if adopted, that would apply greenhouse gaspermitting 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.
 
Hazard communications and community right to know
 
We are subject to federal and state hazard communications and community right to know statutes, including, but not limited to, the federal Emergency Planning and Community Right-to- Know Act,  and regulations. These regulations govern record keeping and reporting of the use and release of hazardous substances.
 
 
Occupational Safety and Health Act
 
We are subject to the requirements of the federal Occupational Safety and Health Act, commonly referred to as OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public.
 
Employees

As of December 31, 2009, we had 29 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.
 
Available Information
 
We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Isramco, Inc., that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov.

ITEM 1A. RISK FACTORS

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

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

·  
worldwide and domestic supplies of crude oil and natural gas;
·  
actions taken by foreign oil and gas producing nations;
·  
the level of global crude oil and natural gas inventories;
·  
the 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;
·  
the price and level of foreign imports of oil, natural gas and NGLs;
 
 
·  
the effect of worldwide energy conservation efforts;
·  
the price and availability of alternative and competing fuels;
·  
the availability of pipeline capacity and infrastructure;
·  
the availability of crude oil transportation and refining capacity;
·  
weather conditions;

·  
electricity dispatch;
·  
domestic and foreign governmental regulations and taxes; and
·  
the overall economic environment.
 
The long-term effect of these and other factors on the prices of oil, natural gas and NGLs are uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:

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

·  
reducing the carrying value of our crude oil and natural gas properties;
·  
reducing the amounts of our estimated proved oil and natural-gas reserves;
·  
reducing the standardized measure of discounted future net cash flows relating to oil and natural-gas reserves; and
·  
limiting our access to sources of capital, such as equity and long-term debt.
 
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. Climate-change legislation establishing a “cap-and-trade” plan for green-house gases (GHGs) has been approved by the U.S. House of Representatives. It is not possible at this time to predict whether or when the U.S. Senate may act on climate-change legislation. The U.S. Environmental Protection Agency (EPA) has also taken recent action related to GHGs. Based on recent developments, the EPA now purports to have a basis to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act.
 
 
 ·  
Taxes. The U.S. President’s Fiscal Year 2011 Budget Proposal includes provisions that would, if enacted, make significant changes to United States 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. The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural-gas industry in the hydraulic-fracturing process. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. This legislation, if adopted, could establish an additional level of regulation and permitting at the federal level.
 
 ·   
Derivatives. The U.S. Congress is currently considering derivatives reform legislation focusing on expanding Federal regulation surrounding the use of financial derivative instruments, including credit default swaps, commodity derivatives and other over-the-counter derivatives. Among the recommendations included in the proposals are the requirements for centralized clearing or settling of such derivatives as well as the expansion of collateral margin requirements for certain derivative market participants.
 
Oil and gas drilling is a speculative activity and risky.

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

Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy.
These factors, combined with volatile oil, natural-gas and NGLs prices, declining business and consumer confidence, and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, or if an economic recovery is slow or prolonged, demand for petroleum products could continue to diminish or stagnate, which could impact the price at which we can sell our oil, natural gas and NGLs, affect our vendors’, suppliers’ and customers’ ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition.
 
Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or assumptions underlying our reserve estimates could cause the quantities and net present value of our reserves to be overstated or understated.
 
There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated. The reserve information included or incorporated by reference in this report represents estimates prepared by our internal engineers. The procedures and methods for estimating the reserves by our internal engineers were reviewed by an independent petroleum engineering firm. Estimation of reserves is not an exact science. In accordance with the SEC’s revisions to rules for oil and gas reserves reporting, which we adopted effective December 31, 2009, our reserves estimates are based on the 12-month unweighted average of the first of the month prices; therefore, reserves quantities will change when actual prices increase or decrease. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, any of which may cause these estimates to vary considerably from actual results, such as:

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

·  
assumed effects of regulation by governmental agencies;

·  
assumptions concerning future oil and natural gas prices, future operating costs and capital expenditures; and
 
·  
estimates of future severance and excise taxes, workover and remedial costs.
 
Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared 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 current market value of the estimated oil and natural-gas reserves attributable to our properties. In accordance with SEC requirements effective January 1, 2010, the estimated discounted future net cash flows from proved reserves are based upon average 12-month sales prices using the average beginning-of-month price, while actual future prices and costs may be materially higher or lower.
 
Unless we replace our reserves, our reserves and production will decline, which would adversely affect our financial condition, results of operations and cash flows.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration activities. Thus, our future oil and natural gas production and, therefore, our cash flow and income are highly dependent upon our level of success in finding or acquiring additional reserves. However, we cannot assure you that our future acquisition, development and exploration activities will result in any specific amount of additional proved reserves or that we will be able to drill productive wells at acceptable costs.
 
 
The successful acquisition of producing properties requires an assessment of a number of factors. These factors include recoverable reserves, future oil and natural gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. Such assessments are inexact and their accuracy is inherently uncertain. In connection with such assessments, we perform a review of the subject properties that we believe is thorough. However, there is no assurance that such a review will reveal all existing or potential problems or allow us to fully assess the deficiencies and capabilities of such properties. We cannot assure you that we will be able to acquire properties at acceptable prices because the competition for producing oil and natural gas properties is intense and many of our competitors have financial and other resources that are substantially greater than those available to us.
 
There is a possibility that we will lose the leases to our oil and gas properties.

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

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

Our business may be affected by oil and gas price volatility.
 
Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing oil and natural gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we will be able to borrow under our Senior Credit Agreements will be subject to periodic redetermination based in part on current oil and natural gas prices and on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our properties.
 
 
Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility are:
 
·  
the domestic and foreign supply of, and demand for oil and natural gas;
 
·  
the ability of members of the Organization of Petroleum Exporting Countries (OPEC) and other producing countries to agree upon and maintain oil prices and production levels;
 
·  
political instability, armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;
 
·  
the growth of consumer product demand in emerging markets, such as India and China;
 
·  
labor unrest in oil and natural gas producing regions;
 
·  
weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;
 
·  
the price and availability of alternative and competing fuels;
   
·  
the price and level of foreign imports of oil, natural gas and NGLs; and
   
·  
worldwide economic conditions.

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

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

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

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

·  
our actual production is less than hedged volumes;

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

·  
the counterparties to our hedging agreements fail to perform under the contracts.
 
 
The current economic crisis may have a negative impact on the liquidity of the counterparties to our hedging arrangements, which increases the risk of those counterparties failing to perform under those agreements. If those parties do fail to perform, we will be exposed to the price risks we had sought to mitigate and our operating results, financial position and cash flows may be materially and adversely affected. As of December 31, 2009 approximately 74%, 77%, 44%, 34% and 27% of our forecasted oil production and natural gas liquids hedged for 2010, 2011, 2012, 2013 and 2014 respectively and approximately 71%, 35% and 9% of our forecasted gas production hedged for 2010, 2011 and 2012.

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.

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

Governmental and environmental regulations could adversely affect our business.

Our business is subject to federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing of oil and natural gas and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste, unitization and pooling of properties and other matters. These laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and natural gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our revenues.
 
 
Our operations are also subject to complex environmental laws and regulations adopted by the various jurisdictions in which we have or expect to have oil and natural gas operations. We could incur liability to governments or third parties for any unlawful discharge of oil, natural gas or other pollutants into the air, soil or water, including responsibility for remedial costs. We could potentially discharge these materials into the environment in any of the following ways:

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

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

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

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

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

Our ability to sell our natural-gas and crude-oil production could be materially harmed if we fail to obtain adequate services such as transportation.
 
The marketability of our production depends in part upon the availability, proximity and capacity of pipeline facilities and tanker transportation. If any of the pipelines or tankers become unavailable, we would be required to find a suitable alternative to transport the gas and oil, which could increase our costs and/or reduce the revenues we might obtain from the sale of the gas and oil.

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

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

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

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

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

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

·  
other hazards arising out of Israeli governmental sovereignty over areas in which we own oil and gas interests.
 
Members of Isramco’s management team own a significant amount of common stock, giving them influence or control in corporate transactions and other matters, and the interests of these individuals could differ from those other shareholders.
 
Members of our management team beneficially own approximately 51.3% of our outstanding shares of common stock as of March 12, 2010. As a result, these shareholders are in a position to significantly influence or control the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of an amendment to our articles of incorporation or bylaws and the approval of mergers and other significant corporate transactions.
 
 
Our stock price is volatile and could continue to be volatile and has limited liquidity; Accordingly, investors may not be able to sell any significant number of shares of our stock at prevailing market prices.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable
 
ITEM 2. PROPERTIES
 
Oil and Gas Exploration and Production - Properties and Reserves
 
Reserve Information. For estimates of Isramco's net proved reserves of natural gas, crude oil and natural gas liquids, see Supplemental Information to Consolidated Financial Statements.
 
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas, crude oil and condensate and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. For related discussion, see ITEM 1A. Risk Factors.
 
ITEM 3. LEGAL PROCEEDINGS
 
We disclosed information in our quarterly report for the three months ended September 30, 2009 relating to two putative shareholder derivative actions that were filed by individual shareholders on June 1, 2009 and June 12, 2009, respectively, in the District Court of Harris County, Texas, naming certain of our officers and directors as defendants.  The complaints, which are similar, purport to assert derivative claims for the benefit of the Company to redress injuries allegedly suffered by the Company as a result of alleged breaches of fiduciary duties by the named defendants in connection with the Company’s entry into an Amended and Restated Agreement with Goodrich Global Ltd., a company owned and controlled by our Chairman and Chief Executive Officer, Haim Tsuff.  In particular, the plaintiffs objected to a provision in such agreement whereby Goodrich Global, Ltd. is allegedly entitled to receive an amount in cash equal to 5% of our pre-tax recorded profit.  The complaints sought unspecified money damages, disgorgement of any proceeds from the restated agreement, voiding of the agreement, other equitable relief, and costs and disbursements, including attorneys’ fees.
 
 
On July 10, 2009, Haim Tsuff and Goodrich removed both lawsuits from State to Federal court, with the consent of the Company and the other defendant directors.  Subsequently, the Company, Tsuff and Goodrich filed Motions to Dismiss, which are pending.  The plaintiffs requested that the cases be remanded back to State courts in which the cases were originally filed, and this request was granted.
 
Management believes that these cases have no merit and will vigorously defend the actions.

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. (Reserved)
 
 
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 10, 2010, there were approximately 294 holders of record of our common stock.

 
High
 
Low
 
2009
           
First Quarter
 
$
66.10
   
$
28.00
 
Second Quarter
   
124.86
     
32.00
 
Third Quarter
   
171.18
     
114.22
 
Fourth Quarter
   
132.42
     
67.05
 
         
2008
               
First Quarter
 
$
49.45
   
$
30.00
 
Second Quarter
   
50.00
     
31.06
 
Third Quarter
   
60.00
     
36.62
 
Fourth Quarter
   
46.47
     
19.20
 

We have never paid cash dividends on our common stock. We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future. Any future determination to pay dividends on common stock will be at the discretion of the board of directors and will be dependent upon then existing conditions, including other factors, as the board of directors deems relevant.
 
 
ITEM 6.   SELECTED FINANCIAL DATA

Not applicable

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

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

We are an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas properties located onshore in the United States. Our properties are primarily located in Texas, New Mexico and Oklahoma. We act as the operator of certain of these properties. Historically, we have grown through acquisitions, with a focus on properties within our core operating areas that we believe have significant development and exploration opportunities and where we can apply our technical experience and economies of scale to increase production and proved reserves while lowering lease operating costs.

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, 2009, our estimated total proved oil, natural gas reserves and natural gas liquids, as prepared by our independent reserve engineering firm, Cawley, Gillespie & Associates, Inc., were approximately 8,565 thousand barrels of oil equivalent (“MBOE”), consisting of 3,002 thousand barrels (Bbls) of oil, and 24,452 million cubic feet (Mcf) of natural gas and 1,488 thousand barrels (Bbls) natural gas liquids. Approximately 97.7% of our proved reserves were classified as proved developed.
 
 
Critical accounting policies

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

Oil and Natural Gas Activities

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

Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization and impairment expense. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir will also result in revisions to the amount of our estimated proved reserves.
 
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 60 months. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivative contracts, which would potentially allow us to not record the change in fair value of our derivative contracts in the consolidated statements of operations. We carry our derivatives at fair value on our consolidated balance sheets, with the changes in the fair value included in our consolidated statements of operations in the period in which the change occurs. Our results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivative contracts.
 
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 sources of cash during 2009 were cash flows from operating activities and loan from related party. The capital markets, as they relate to us, have been adversely impacted by the current financial crisis, concerns about the economic recession and its effect on commodity prices.  Continued volatility in the capital markets could adversely impact our ability to replace our reserves, and eventually, our production levels. 

Our future capital resources and liquidity may depend, in part, on our success in developing the leasehold interests that we 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 pricesand 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,
 
   
2009
   
2008
   
2007
 
   
(In thousands except percentage)
 
Revolving Credit Facility
 
$
32,950
   
$
43,200
   
$
24,000
 
Long – term debt – related party
   
79,354
     
80,354
     
36,581
 
Short – term debt – related party
   
-
     
-
     
-
 
Current maturities of long-term debt, short-term debt and bank overdraft
   
12,366
     
22,544
     
3,706
 
Total debt
   
124,670
     
146,098
     
64,287
 
                         
Stockholders’ equity
   
13,733
     
25,034
     
25,471
 
                         
Debt to capital ratio
   
90
%
   
85
%
   
72
%
 
At year-end 2009, our total debt was $124,670 thousand compared to total debt of $146,098 thousand at year-end 2008 and $64,287 thousand at year-end 2007. As of December 31, 2009, current debt included $12,000 thousand as current maturities of the Senior Credit Facility. However, the Company is not obligated to repay this facility prior to the due date, except for such payments as may be required under the Credit Agreement in the event of a redetermination and reduction of the borrowing base. As of December 31, 2009, the $12,000 included as current maturities thousand was due to the decision of management to continue reducing the our debt below the borrowing base.  As of December 31, 2008, current debt included $21,000 thousand as current maturities, which again was due to management’s decision to continue payments to reduce debt below the borrowing base.
 
 
Cash Flow

Our primary sources of cash in 2009, 2008 and 2007 were from operating and financing activities. Proceeds from loans obtained from related parties, proceeds from the Senior Credit Agreements and cash received from operations were offset by repayments of our Senior Credit Agreements, repayments of loans from related parties and cash used in investing activities to fund continued enhancement of operations acquisition activities. Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Working capital was substantially influenced by these variables. Fluctuation in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures or influence our ability to reduce our long-term loans. Prices for oil and natural gas have historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See “Results of Continuing Operations” below for a review of the impact of prices and volumes on sales.
 
 
Years Ended December 31,
 
2009
2008
2007
 
(In thousands)
Cash flows provided by (used in) operating activities
 
$
21,519
   
$
18,886
   
$
(662
)
Cash flows used in investing activities
   
(332
)
   
(97,753
)
   
(63,656
)
Cash flows provided by (used in) financing activities
   
(21,421
   
80,796
     
64,957
 
Net increase (decrease) in cash
 
$
(234
 
$
1,929
   
$
639
 

Operating Activities, Net cash flows provided by (used in) operating activities were $21,519 thousands, $18,886 thousands and ($662) thousands for the years ended December 31, 2009, 2008 and 2007, respectively. Key drivers of net operating cash flows are commodity prices, production volumes, heading activities and operating cost.

Net cash provided by operating activities increased in 2009 primarily due to a 8% increase in our average daily production volumes and gain from net cash received on settled derivative contracts which was partially offset by the 58%, 40% and 31% decrease in natural gas, oil and natural gas liquids prices, respectively. However, we are unable to predict future production levels or future commodity prices, and, therefore, we cannot predict future levels of net cash provided by operating activities.

Net cash provided by operating activities increased in 2008 compared to 2007 primarily due to the acquisition we made during 2008.

Investing Activities, The primary component of cash used in investing activities in 2009 and 2008 was capital spending for acquisitions and development. Cash used in investing activities was $332 thousand, $97,753 thousand and $63,656 thousand for the years ended December 31, 2009, 2008 and 2007, respectively.

In 2009, we spent an additional $645 thousand on capital expenditures and other property and equipment.
 
In 2008, we spent $98,673 thousand on acquisition of oil and gas properties and capital expenditures. We participated in the drilling of 3 gross wells in 2008. We spent an additional $369 thousand on other property and equipment during 2008.
 
In 2007, we spent $86,056 thousands on acquisition of oil and gas properties and capital expenditures. Our acquisitions were partially funded by the remaining restricted cash that we deposited in 2006. We participated in the drilling of 2 gross wells in 2007. We spent an additional $67 thousand on other property and equipment during 2007.
 

 
Financing Activities, The primary component of cash used in financing activities in 2009 was payment on long-term debt ($21,250). In 2008, the primary component of cash provided by financing activities was proceeds from long-term loans obtained from related parties ($43,773) and Senior Credit Agreements ($54,000), offset by repayments of long-term loans and repayments of Senior Credit Agreements ($16,800). Net cash flows provided by financing activities were $(21,421) thousands, $80,796 thousands and $64,957 thousands for the years ended December 31, 2009, 2008 and 2007, respectively.
 
Results of Continuing Operations

Selected Data
     
   
Years Ended December 31,
   
2009
   
2008
 
2007
   
(In thousands except per share and MBOE amounts)
Financial Results
                 
Oil and Gas sales
 
$
30,768
   
$
51,832
   
$
20,827
 
Equity in earnings of unconsolidated affiliates
   
-
     
-
     
1,201
 
Other
   
956
     
365
     
728
 
Total revenues and other
   
31,724
     
52,197
     
22,756
 
                         
Cost and expenses
   
42,024
     
63,619
     
21,183
 
Other expense (income)
   
13,369
     
(15,028
)
   
13,176
 
Income tax expense (benefit)
   
(10,090
   
377
     
(5,192
)
Net Income (loss)
   
(13,579
   
3,229
     
(6,411
)
Earnings per common share – basic and diluted
 
$
(5.00
 
$
1.19
   
$
(2.36
)
Weighted average number of shares outstanding-basic and diluted
   
2,717,691
     
2,717,691
     
2,717,691
 
Operating Results
                       
Adjusted EBITDAX (1)
 
$
26,796
   
$
22,548
   
$
16,874
 
Total proved reserves (MBOE)
   
8,565
     
8,213
     
8,329
 
Annual sales volumes (MBOE)
   
886
     
821
     
455.5
 
                         
Average cost per MBOE:
                       
Production (including transportation and taxes)
 
$
17.66
   
$
24.66
   
$
16.47
 
General and administrative
 
$
4.64
   
$
3.31
   
$
6.37
 
Depletion
 
$
17.34
   
$
21.59
   
$
13.48
 

(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 (loss) our net loss for 2009 totaled $(13,579) thousand, or $(5.00) per share, compared to net income for 2008 of $3,229 thousands, or $1.19 per share. This decrease was primarily due to sustained lower natural gas, oil and NGLs sales revenues due to lower prices and impact of derivatives, which were partially offset by increases in sales volumes of natural gas, oil and natural gas liquids (“NGL”), lower lease operating expenses, lower depreciation, depletion, amortization and impairment expenses and tax benefit. Our net income for 2008 totaled $3,229 thousand, or $1.19 per share, compared to net loss for 2007 of $(6,411) thousands, or $(2.36) per share. The increase in income for 2008 compared to 2007 was primarily due to the GFB acquisition which resulted in an increase of natural gas, oil and natural gas liquids sales, as well as higher commodity prices and gain on derivative contracts, which were partially offset by higher cost and expenses including impairment of oil and gas properties, higher interest expenses and income tax.
 
Revenues, Volumes and Average Prices
Sales Revenues
 
 
Years Ended December 31,
 
In thousands except percentages
2009
 
2008
   
D vs. 2009
 
2007
   
D vs. 2008
 
Gas sales
 
$
9,124
   
$
20,747
     
(56)
%
 
$
10,030
     
107
%
Oil sales
   
17,147
     
25,049
     
(32)
     
6,874
     
264
 
Natural gas liquid sales
   
4,497
     
6,036
     
(25)
     
3,923
     
54
 
Total
 
$
30,768
   
$
51,832
     
(41)
%
 
$
20,827
     
149
%
 
Our sales revenues for the year ended December 31, 2009 decreased by 41% when compared to same period of 2008, mainly due to lower natural gas, oil and condensate and NGLs commodity prices. Our sales revenues for 2008 increased by 149% when compared to 2007, due to the GFB acquisition which resulted in higher sales volumes of natural gas, oil and natural gas liquids and also due to higher oil, natural gas and natural gas liquids prices.
 
Volumes and Average Prices
 
   
Years Ended December 31,
 
   
2009
   
2008
   
D vs. 2009
   
2007
   
D vs. 2008
 
Natural Gas
                             
Sales volumes Mmcf
   
2,623
     
2,507
     
5
%
   
1,551
     
62
%
Price per Mcf
 
$
3.48
   
$
8.28
     
(58)
   
$
6.47
     
28
 
Total gas sales revenues (thousands)
 
$
9,124
   
$
20,747
     
(56)
%
 
$
10,030
     
107
%
                                         
Crude Oil
                                       
Sales volumes MBbl
   
293
     
258
     
14
%
   
96.7
     
167
%
Price per Bbl
 
$
58.52
   
$
97.1
     
(40)
   
$
71.1
     
37
 
Total oil sales revenues (thousands)
 
$
17,147
   
$
25,049
     
(32)
%
 
$
6,874
     
264
%
                                         
Natural gas liquids
                                       
Sales volumes MBbl
   
156
     
145
     
8
%
   
101
     
44
%
Price per Bbl
 
$
28.83
   
$
41.6
     
(31)
   
$
39
     
7
 
Total natural gas liquids sales revenues (thousands)
 
$
4,497
   
$
6,036
     
(25)
%
 
$
3,923
     
54
%
 
 
The company’s natural gas sales volumes increased by 5%, crude oil sales volumes by 14% and natural gas liquids sales volumes by 8% in 2009 compared to 2008, primarily due to fact that in 2008 we recorded 9 months of production associated with properties acquired in the GFB acquisition which in turn was partially offset by the natural decline in our production. The company’s natural gas sales volumes increased by 62%, crude oil sales volumes by 167% and natural gas liquids sales volumes by 44% in 2008 compared to 2007, primarily due to the GFB acquisition.

Our average natural gas price for 2009 decreased by 58%, or $4.80 per Mcf, when compared to 2008 and increased by 28%, or $1.81, when 2008 is compared to 2007. Our average crude oil price for 2009 decreased by 40%, or $38.58 per Bbl, when compared to 2008 and increased by 37%, or $26, when 2008 is compared to 2007. Our average natural gas liquids price for 2009 decreased by 31%, or $12.77 per Bbl, when compared to 2008 and increased by 7%, or $2.6 per Bbl, when 2008 is compared to 2007.
 
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, 2009 compared to 2008 and 2007.

In thousands
 
Natural Gas
   
Oil
   
Natural gas liquids
 
2007 sales revenues
 
$
10,030
   
$
6,874
   
$
3,923
 
Changes associated with sales volumes
   
6,184
     
11,467
     
1,737
 
Changes in prices
   
4,533
     
6,708
     
376
 
2008 sales revenues
   
20,747
     
25,049
     
6,036
 
Changes associated with sales volumes
   
960
     
3,398
     
458
 
Changes in prices
   
(12,583
   
(11,300
   
(1,997
2009 sales revenues
 
$
9,124
   
$
17,147
   
$
4,497
 
 
Adjusted EBITDAX.
 
To assess the operating results of Isramco, management analyzes income from operations before income taxes, interest expense, exploration expense, unrealized gain (loss) on derivative contracts and DD&A expense and impairments (“Adjusted EBITDAX”). Adjusted EBITDAX is not a GAAP measure. Isramco’s definition of Adjusted EBITDAX excludes exploration expense because exploration expense is not an indicator of operating efficiency for a given reporting period, but rather is monitored by management as a part of the costs incurred in exploration and development activities. Similarly, Isramco excludes DD&A expense and impairments from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Isramco’s financing methods or capital structure. Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make payments on its long term loans. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations.
 
 
However, Adjusted EBITDAX, as defined by Isramco, may not be comparable to similarly titled measures used by other companies. Therefore, Isramco’s consolidated Adjusted EBITDAX should be considered in conjunction with income (loss) from operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect income from continuing operations and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Isramco’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) from operations before income taxes.
 
  
 
Years Ended December 31,
In thousands except percentages
 
2009
   
2008
   
2007
 
Income from operations before income taxes
 
$
(23,669
)
 
$
3,606
   
$
(11,603
)
Depreciation, depletion, amortization and impairment expense
   
21,119
     
39,816
     
10,270
 
Interest expense
   
9,219
     
9,855
     
6,344
 
Unrealized gain on derivative contract
   
19,298
     
(32,657
)
   
11,352
 
Accretion Expenses
   
829
     
847
     
219
 
Exploration expense
   
-
     
-
     
292
 
Other nonrecurring items - amortization of Inventory
   
-
     
1,081
     
-
 
Consolidated Adjusted EBITDAX
 
$
26,796
   
$
22,548
   
$
16,874
 

Operating Expenses

   
Years Ended December 31,
 
In thousands except percentages
 
2009
   
2008
   
D vs. 2009
   
2007
   
D vs. 2008
 
Lease operating expense, transportation and taxes
 
$
15,651
   
$
20,242
     
(23
)%
 
$
7,500
     
170
%
Depreciation, depletion and amortization
   
15,368
     
17,723
     
(13
   
6,139
     
189
 
Impairments of oil and gas assets
   
5,751
     
22,093
     
(74
   
3,203
     
590
 
Impairments of other properties
   
-
     
-
     
-
     
928
     
-
 
Accretion expense
   
829
     
847
     
(2
   
219
     
287
 
Exploration costs
   
-
     
-
     
-
     
292
     
-
 
Loss from plug and abandonment
   
312
     
-
     
-
     
-
     
-
 
General and administrative
   
4,113
     
2,714
     
52
     
2,902
     
(6
)
   
$
42,024
   
$
63,619
     
(34)
%
 
$
21,183
     
200
%
 
 
During 2009, our operating expenses decreased by 34% when compared to 2008 due to the following factors:

·  
Lease operating expense, transportation and taxes decreased by 23%, or $4,591 thousand, in 2009 when compared to 2008 primarily as a result of cost savings programs initiated in response to the reduction in oil and gas prices experienced from 2008 into 2009. Cost savings were achieved through operating efficiencies, deferral of certain workovers and vendor negotiations. Additional reductions were due to lower commodity prices that affected the taxes paid during 2009. This decrease was partially offset by the fact that, in 2008, we recorded only 9 months of operating expense, transportation and taxes associated with the properties acquired in GFB acquisition, compared to 12 months during 2009. On a per unit basis, lease operating expenses (including transportation and taxes) decreased by $7.00 per MBOE to $17.66 per MBOE in 2009 from $24.66 per MBOE in 2008.

·  
Depreciation, Depletion &Amortization (DD&A) of the cost of proved oil and gas properties is calculated using the unit-of-production method. Our DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact our composite DD&A rate and expense, including but not limited to field production profiles, drilling or acquisition of new wells, disposition of existing wells, and reserve revisions (upward or downward) primarily related to well performance and commodity prices, and impairments. Changes to these factors may cause our composite DD&A rate and expense to fluctuate from period to period. DD&A decreased by 13%, or $2,355 thousand, in 2009 when compared to 2008 primarily due to higher prices (per MBOE) that impacted our estimated total reserves, which are the basis for the depletion calculation, and the impact of a 2008 impairment of $22,093 thousand on the depletable base used to calculate DD&A, which was partially offset by higher production. On a per unit basis, depletion expense decreased by $4.25 per MBOE to $17.34 per MBOE in 2009 from $21.59 per MBOE in 2008.

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

·  
General and administrative expenses increased by 52%, or $1,399 thousand, in 2009 when compared to 2008, primarily due to increases in compensation and benefit expenses associated with hiring additional employees required as a result of the GFB acquisition and assuming operation of approximately 350 additional wells in October 2008. The GFB acquisition also increased the volume of the activities and, as a result, the indirect expenses of the activities. In addition, the Company incurred increased legal expenses in 2009 due to a number of factors. The Company was required to pay an award of $288,000 in attorney’s fees as a result of an adverse court decision in a case filed by the Company in 2001. The Company was the subject of two derivative lawsuits filed in 2009. Also in 2009 the Company instituted lawsuits against several entities to recover damages relating to its investments in Barnett Shale operations and to the operation of the properties acquired in the Five States acquisition.
 
During 2008, our operating expenses increased by 200% when compared to 2007 due to the following factors:

·  
Lease operating expense, transportation and taxes increased by 170%, or $12,742 thousand, in 2008 when compared to 2007 due to approximately $10,800 thousand in additional operating expenses, transportation and taxes attributable to the properties acquired in the GFB acquisition. The remaining increase is attributable to higher commodity prices that affected the taxes paid during 2008 and to the fact that, in 2007, we recorded only 10 months of operating expense, transportation and taxes associated with the properties acquired in Five States acquisition, compared to 12 months during 2008.

·  
Depreciation, Depletion &Amortization (DD&A) of the cost of proved oil and gas properties is calculated using the unit-of-production method. Our DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact our composite DD&A rate and expense, including but not limited to field production profiles, drilling or acquisition of new wells, disposition of existing wells,  and reserve revisions (upward or downward) primarily related to well performance and commodity prices, and impairments. Changes to these factors may cause our composite DD&A rate and expense to fluctuate from year to year.  DD&A increased by 189%, or $11,584 thousand, in 2008 when compared to 2007 primarily due to approximately $8,520 thousand DD&A which was related to the oil and gas properties acquired in GFB acquisition. The remaining increase is attributed to lower commodity prices at year-end 2008 that impacted our estimated total reserves, which are the basis for the depletion calculation.
 
 
·  
Impairments of oil and gas assets of $22,093 thousand in 2008 were primarily a result of lower commodity prices in general and the low volume of oil and gas produced in a few of our North Texas fields and in the wells in which the Company participated in the Barnett Shale formation in Parker County, Texas, in particular.  

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

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

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

   
Years Ended December 31,
 
In thousands except percentages
 
2009
   
2008
   
D vs. 2009
   
2007
   
D vs. 2008
 
Interest expense net
 
$
9,219
   
$
9,855
     
(6
)%
 
$
6,344
     
55
%
Unrealized gain on marketable securities
   
-
     
-
     
-
     
(52
)
   
-
 
Realized gain on sale of investment and other
   
(250
)
   
(145
)
   
72
 
   
(1,754
)
   
(92
)
Net loss (gain) on derivative contracts
   
4,400
     
(24,738
)
   
(118
)
   
8,638
     
(386
)
Compensation for legal settlement
   
-
     
-
             
-
         
   
$
13,369
   
$
(15,028
)
   
(189
)%
 
$
13,176
     
(214
)%

Interest expense. Isramco’s interest expense decreased by 6%, or $636 thousand, for the year ended December 31, 2009 compared to the same period of 2008. This decrease is primarily due to the lower average outstanding balance of the loans which we obtained to fund the Five States acquisition in 2007 and the GFB acquisition in 2008, and to decreases in average LIBOR rates in 2009. The decrease was partially offset by the payments on interest rate swaps. Isramco’s interest expense for 2008 increased by 55%, or $3,511 thousand, compared to 2007.  This increase was primarily attributable to interest on loans we obtained from banks and related parties for funding the GFB acquisition.  The increase was partially offset by the lower average outstanding balance of the loans  we obtained to fund the Five States acquisition in 2007 and decreases in average LIBOR rates in 2008.   

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

Net loss (gain) on derivative contracts. We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with the prior year, we have elected not to designate any positions as cash flow hedges for accounting purposes. Accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statement of operations.
 
 
At December 31, 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 ($19.3 million unrealized loss partially offset by a $14.9 million gain from net cash received on settled contracts). This change is due to the changes in commodity prices and additional SWAP contracts we entered in 2009.
 
At December 31, 2008, we had a $23 million derivative asset, of which $12 million was classified as current. We recorded a net derivative gain of $24.7 million ($32.6 million unrealized gain partially offset by a $7.9 million loss from net cash payments on settled contracts) for the year ended December 31, 2008 compared to a net derivative loss of $8.6 million ($11.3 million unrealized loss and a $2.7 million net gain for cash received on settled contracts) for the year ended December 31, 2007. This increase in our net derivative gain was primarily attributable to the recent decrease in the forward strip pricing used to value our derivatives and additional SWAP contracts we entered in 2008.
 
Income Tax

Income tax benefit for the year ended December 31, 2009 increased by $10.5 million from the prior year. The increase in our income tax benefit from the prior year was primarily due to our pre-tax loss of $23.7 million for the year ended December 31, 2009 compared to our pre-tax income of $3.6 million in 2008. The effective tax rates for the years ended December 31, 2009 and 2008 were 42.6% and 10.5%, respectively. The change in the effective tax rate from the prior year is primarily due to the benefit generated by the changes in estimates of tax benefits associated with amended tax filings.

Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data–Note 1, “Summary of Significant Accounting Policies.”
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
The information called for by this Item 8 is included following the "Index to Financial Statements" contained in this Annual Report on Form 10-K.
 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES.
 
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2009, to ensure that information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.
The Company’s previously filed Form 10-Q for the period ended September 30, 2009 stated that the Company did not maintain effective controls over financial reporting, primarily due to the shortage of support and resources in our accounting department.  Specifically, the Company had not been successful in attracting and retaining experienced, skilled personnel, and these issues were further exacerbated by the acquisition of additional properties in March 2008 that resulted in inadequate documentation and communication of our accounting policies and procedures and deficiencies in our internal audit processes of our accounting policies and procedures.  Accordingly, for the purposes of the September 2009 10-Q, management determined and reported that these control deficiencies constituted a material weakness as of September 30, 2009.  Throughout 2009, Management took a series of actions designed to remedy these deficiencies.  As of the end of the period covered by this report, the Company’s Chief Executive Officer and its Chief Financial Officer have concluded that the Company’s ongoing remediation efforts (as described below) resulted in control enhancements which have operated for an adequate period of time to demonstrate operating effectiveness.

This section of Item 9A, “Evaluation of Disclosure Controls and Procedures,” should be read in conjunction with the Item 4T contained in the Company’s Form 10-Q for the period ended September 30, 2009.

Notwithstanding the foregoing, because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our Company have been detected.  These inherent limitations include the realities that judgments and decision-making can be faulty and that breakdowns can occur because of a simple error or mistake.  Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people or by management override of the control.  Moreover, the design of any system of controls is also based in part upon certain assumptions about the likelihood of future events.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING; CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING.
 
Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the times specified in the Securities and Exchange Commission’s rules and forms.  These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed under the Exchange Act is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.  Under the supervision and with the participation of our management, including our chief executive officer, chief financial officer, and chief accounting officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2009 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Our internal control over financial reporting includes policies and procedures that (1) pertain to maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (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 are being made only in accordance with authorizations of our management and board of directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.

Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable, not absolute, assurance with respect to financial statement preparation and presentation.  Projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate as a result of changes in conditions or deterioration in the degree of compliance.
Based on the assessment, our management has concluded that our internal control over financial reporting was effective as of December 31, 2009 and provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles.  The results of management’s assessment were reviewed with the Audit Committee of our Board of Directors.

Our internal control over financial reporting has been audited by Malone & Bailey, LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
 
As noted above, for purposes of the September 2009 10-Q, Management determined and reported that the Company did not maintain controls over financial reporting, primarily due to the shortage of support and resources in our accounting department.  Specifically, the Company had not been successful in attracting and retaining experienced, skilled personnel, and these issues were further exacerbated by the rapid growth of the company.  Management accordingly reported that these control deficiencies constituted a material weakness in the Company’s internal control over financial reporting as of September 30, 2009. 

Throughout 2009 Management took a number of actions to eliminate or reduce the control deficiencies identified.  These actions include, but are not limited to:
 
 
·  
hiring additional experienced and skilled personnel to further establish appropriate segregation of duties and appropriately distribute the allocation of work functions;
 
 
·  
retaining  qualified internal control consultants to  assist in our internal control compliance efforts, including establishing  new internal control procedures appropriate for a rapidly growing business and appropriate accounting policies and ensuring the proper and consistent application of those policies and procedures throughout the Company; and

·  
establishing entity-wide awareness, discipline and communication around internal controls, specifically surrounding compliance with internal controls over financial reporting.

Management has been involved in these activities and will continue to monitor progress on a consistent and ongoing basis at the Chief Executive Officer and Chief Financial Officer level, in conjunction with our Audit Committee. The Company believes that, as of December 31, 2009, it has effectively executed the remediation measures established to address the material weakness in its internal controls.  This process has and should continue to improve the review and oversight process relating to the Company’s internal controls.

The aforementioned changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2009 materially affected, or are reasonably likely to materially affect, our 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, 2009 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.
 
 
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Exhibits
 
3.1
 
Articles of Incorporation of Registrant with all amendments filed as an Exhibit to the S-l Registration Statement, File No. 2-83574.
     
3.2
 
Amendment to Certificate of Incorporation filed March 17, 1993, filed as an Exhibit with the S-l Registration Statement, File No. 33-57482.
     
3.3
 
By-laws of Registrant with all amendments, filed as an Exhibit to the S-l Registration Statement, File No. 2-83570.
     
4.1
 
First Amended and Restated Promissory Note dated as of February 27, 2007, issued to NAPHTHA ISRAEL PETROLEUM CORP., LTD. in the principal amount of $18,500,000 filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
     
4.2
 
First Amended and Restated Promissory Note dated as of February 27, 2007, issued to NAPHTHA ISRAEL PETROLEUM CORP., LTD. in the principal amount of $11,500,000 filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
     
4.3
 
First Amended and Restated Promissory Note dated as of February 27, 2007, issued to and I.O.C. ISRAEL OIL COMPANY, LTD. in the principal amount of $12,000,000 filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
     
4.4
 
Promissory Note dated as of February 27, 2007, issued to and J.O.E.L JERUSALEM OIL EXPLORATION, LTD. in the principal amount of $7,000,000, filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
4.5
 
Promissory Note dated as of May 25, 2008, issued to and J.O.E.L JERUSALEM OIL EXPLORATION, LTD. in the principal amount of $48,900,000 filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
     
10.1
 
Purchase and Sale Agreement, dated as of February 16, 2007, among Five States Energy Company, L.L.C. and each of the other parties listed as a party "Seller" on the signature pages thereof and ISRAMCO, Inc., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
10.2
 
LOAN AGREEMENT, dated as of February 27, 2007, between ISRAMCO, INC., and NAPHTHA ISRAEL PETROLEUM CORP., LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
10.3
 
LOAN AGREEMENT, dated as of February 27, 2007, between ISRAMCO, INC., and NAPHTHA ISRAEL PETROLEUM CORP., LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
10.4
 
LOAN AGREEMENT, dated as of February 27, 2007, Between ISRAMCO, INC., and I.O.C. ISRAEL OIL COMPANY, LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
10.5
 
LOAN AGREEMENT, dated as of February 26, 2007, between ISRAMCO, INC., and J.O.E.L JERUSALEM OIL EXPLORATION, LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
 
 
 
     
10.6
 
CREDIT AGREEMENT dated as of March 2, 2007 among ISRAMCO ENERGY, L.L.C., each of the lenders that is a signatory hereto or which becomes a signatory hereto; and WELLS FARGO BANK, N. A., a national banking association, as agent for the Lenders., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
     
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*
 
     
10.15*
 
     
10.16*
 
     
10.17*
 
     
14.1
 
Code of Ethics, filed as an Exhibit to Form 10-K for the year ended December 31, 2003.
     
31.1*
 
     
31.2*
 
     
32.1*
 
     
32.2*
 
__________________________
* 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 12, 2010
 
 
 
/S/ EDY FRANCIS                                                                                  
EDY FRANCIS,
CHIEF FINANCIAL OFFICER
(PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)
 
Date: March 12, 2010

 

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 12, 2010
Haim Tsuff
 
 Chief Executive Officer
   
         
/s/ Jackob Maimon                                   
 
President, Director
 
March 12, 2010
Jackob Maimon
       
         
/s/ Max Pridgeon                                     
 
Director
 
March 12, 2010
Max Pridgeon
       
         
/s/ Mark Kalton                                     
 
Director
 
March 12, 2010
Mark Kalton
       
         
/s/ Michelle R. Cinnamon Flores           
 
Director
 
March 12, 2010
Michelle R. Cinnamon Flores
       

 

INDEX TO FINANCIAL STATEMENTS





 
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, 2009.

Malone-Bailey, LLP, the Company’s independent registered public accounting firm, has issued an attestation report on the effectiveness on our internal control over financial reporting as of December 31, 2009.






/s/     Haim Tsuff                                                                                                               /s/     Edy Francis 
Haim Tsuff                                                                                                                       Edy Francis
Chief Executive Officer                                                                                                Chief Financial Officer
 
 
Houston, Texas
March 12, 2010


 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 

 
To the Board of Directors and Stockholders of
Isramco, Inc.
Houston, Texas
 

 
We have audited the accompanying consolidated balance sheets of Isramco, Inc. (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the three years ended December 31, 2009. We also have audited the Company’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Isramco, Inc as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years ended December 31, 2009, 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, 2009, 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 12, 2010

 
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
 
As of December 31
 
2009
   
2008
 
ASSETS
 
Current Assets:
           
Cash and cash equivalents
 
$
2,907
   
$
3,141
 
Accounts receivable, net
   
7,424
     
5,416
 
Restricted and designated cash
   
827
     
757
 
Deferred tax assets
   
3,644
     
-
 
Derivative asset
   
3,421
     
12,082
 
Prepaid expenses and other
   
656
     
592
 
Total Current Assets
   
18,879
     
21,988
 
                 
Property and Equipment, at cost – successful efforts method:
               
Oil and Gas properties
   
220,138
     
219,945
 
Other
   
672
     
450
 
Total Property and Equipment
   
220,810
     
220,395
 
Accumulated depreciation, depletion and amortization
   
(77,315
)
   
(56,196
)
Net Property and Equipment
   
143,495
     
164,199
 
                 
Marketable securities, at market
   
4,713
     
1,799
 
Debt cost
   
322
     
572
 
Derivative asset
   
2,158
     
10,942
 
Deferred tax assets and other
   
6,751
     
3,871
 
Total assets
 
$
176,318
   
$
203,371
 

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
Current liabilities:
           
Accounts payable and accrued expenses
 
$
9,798
   
$
7,712
 
Short term debt and bank overdraft
   
336
     
1,544
 
Current maturities of long-term debt
   
12,000
     
21,000
 
Derivative liability
   
693
     
943
 
Accrued interest and due to related party
   
4,677
     
5,606
 
Deferred tax liabilities
   
-
     
2,245
 
Total current liabilities
   
27,504
     
39,050
 
                 
Long-term debt
   
32,950
     
43,200
 
Accrued interest - related party
   
4,832
     
-
 
Long-term debt - related party
   
79,354
     
80,354
 
                 
Other Long-term Liabilities:
               
Asset retirement obligations
   
16,248
     
15,733
 
Derivative liability – non-current
   
1,697
     
-
 
Total other long-term liabilities
   
17,945
     
15,733
 
                 
Commitments and contingencies (Note 15)
               
                 
Shareholders’ equity:
               
Common stock $0.0l par value; authorized 7,500,000 shares;  issued 2,746,958 shares; outstanding 2,717,691 shares
   
27
     
27
 
Additional paid-in capital
   
23,194
     
23,194
 
Retained earnings (accumulated deficit)
   
(11,362
)
   
2,217
 
Accumulated other comprehensive income
   
2,038
     
(240
Treasury stock, 29,267 shares at cost
   
(164
)
   
(164
)
Total shareholders’ equity
   
13,733
     
25,034
 
Total liabilities and shareholders’ equity
 
$
176,318
   
$
203,371
 

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

Year Ended December 31
 
2009
   
2008
   
2007
 
                   
Revenues
                 
Oil and gas sales
 
$
30,768
   
$
51,832
   
$
20,827
 
Operator fees from related party
   
-
     
-
     
18
 
Office services to affiliate and other
                       
To related parties
   
-
     
-
     
480
 
To others
   
845
     
191
     
230
 
Other
   
111
     
174
     
-
 
Equity in earnings of unconsolidated affiliates
   
-
     
-
     
1,201
 
Total revenues
   
31,724
     
52,197
     
22,756
 
                         
Operating expenses
                       
Lease operating expense, transportation and taxes
   
15,651
     
20,242
     
7,500
 
Depreciation, depletion and amortization
   
15,368
     
17,723
     
6,139
 
Impairments of oil and gas assets
   
5,751
     
22,093
     
3,203
 
Impairments of other properties
   
-
     
-
     
928
 
Accretion expense
   
829
     
847
     
219
 
Exploration costs
   
-
     
-
     
292
 
Loss from plug and abandonment
   
312
     
-
     
-
 
General and administrative
                       
To related parties
   
-
     
-
     
226
 
To others
   
4,113
     
2,714
     
2,676
 
Total operating expenses
   
42,024
     
63,619
     
21,183
 
Operating income (loss)
   
(10,300
)
   
(11,422
)
   
1,573