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, 2009r
            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.


Table of Contents










ISRAMCO,
INC.


2009
FORM 10-K ANNUAL REPORT





TABLEOF CONTENTS











PagePART IITEM
      1.
            BUSINESS
            4ITEM
      1A.
            RISK
      FACTORS
            14ITEM
      1B.
            UNRESOLVED
      STAFF COMMENTS
            24ITEM
      2.
            PROPERTIES
            24ITEM
      3.
            LEGAL
      PROCEEDINGS
            24ITEM
      4.
            SUBMISSION OF MATTERS TO A VOTE
      OF SECURITY HOLDERSPART
      II25ITEM
      5.
            MARKET FOR
      REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
      PURCHASES OF EQUITY SECURITIES
            26ITEM
      6.
            SELECTED
      FINANCIAL DATA
            26ITEM
      7.
            MANAGEMENT'S
      DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
      OPERATIONS
            25ITEM
      8.
            CONSOLIDATED
      FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
            37ITEM
      9.
            CHANGES IN AND
      DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
      DISCLOSURE
            38ITEM
      9A.
            CONTROLS AND
      PROCEDURES
            38ITEM
      9B.
            OTHER
      INFORMATION
            38PART
      IIIITEM
      10.
            DIRECTORS,
      EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEITEM
      11.
            EXECUTIVE
      COMPENSATIONITEM
      12.
            SECURITY
      OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENTAND RELATED
      STOCKHOLDER MATTERSITEM
      13.
            CERTAIN
      RELATIONSHIPS AND RELATED TRANSACTIONS, AND
      DIRECTOR INDEPENDENCEITEM
      14.
            PRINCIPAL
      ACCOUNTING FEES & SERVICESITEM
      15.
            EXHIBITS,
      FINANCIAL STATEMENT SCHEDULES
            40











Table of Contents







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.





3
 Table of Contents





PART
I





ITEM1. 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.




4
 Table of Contents





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.




5
 Table of Contents




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 LeaseIsramco
      (1)
            
            
            0.7052Related
      parties:Isramco
      Negev 2, Limited
            
            
            49.863PartnershipI.O.C.
      Israel Oil Company
            
            
            14.7743I.N.O.C.
      Dead Sea
            
            
            --Limited
      PartnershipNaphtha
      Explorations
            
            
            3.5117Limited
      PartnershipJ.O.E.L.  Jerusalem
      Oil Exploration, Ltd.
            
            
            4.4318Equital
            
            
            3.3291Unrelated
      parties
            
            
            23.3849Total
            
            
            100.00Area
      (acres)
            
            
            13,100Expiration
      Date (2)
            
            6/10/2030








6
 Table of Contents




(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
      PayoutOverriding
      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
      ContractsNatural
      Gas
            
            
            Crude
      OilVolume
              (MMBTU)
              (*)
            
            
            Weighted
              Average
              Price
              ($/MMBTU)
            
            
            Volume
              (Bbl)
            
            
            Weighted
              Average
              Price
              ($/Bbl)2010
            
            
            1,785,648
            
            
            
            7.88
            
            
            
            254,868
            
            
            
            79.592011
            
            
            764,820
            
            
            
            8.22
            
            
            
            240,336
            
            
            
            86.552012
            
            
            174,222
            
            
            
            8.65
            
            
            
            127,473
            
            
            
            82.372013
            
            
            -
            
            
            
            -
            
            
            
            89,400
            
            
            
            85.152014
            
            
            -
            
            
            
            -
            
            
            
            66,000
            
            
            
            86.95


(*) Mcf = MMBTU





7
 Table of Contents





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
      Rate20,000
            
            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.




8
 Table of Contents




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.




9
 Table of Contents




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.




10
 Table of Contents




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.




11
 Table of Contents




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.




12
 Table of Contents




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.




13
 Table of Contents




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 atwww.sec.gov.





ITEM1A. 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;




14
 Table of Contents




·
            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.





15
 Table of Contents




·
            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.





16
 Table of Contents




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.




17
 Table of Contents




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.





18
 Table of Contents




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.





19
 Table of Contents





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;




20
 Table of Contents




·
            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.




21
 Table of Contents




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.





22
 Table of Contents




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.





23
 Table of Contents




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.





ITEM1B. UNRESOLVED STAFF
COMMENTS





Not
applicable




ITEM2. 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.





ITEM3. 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.




24
 Table of Contents




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.





ITEM4. (Reserved)







PART
II





ITEM5. 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
            
            Low2009First
      Quarter
            
            $
            66.10
            
            
            $
            28.00Second
      Quarter
            
            
            124.86
            
            
            
            32.00Third
      Quarter
            
            
            171.18
            
            
            
            114.22Fourth
      Quarter
            
            
            132.42
            
            
            
            67.052008First
      Quarter
            
            $
            49.45
            
            
            $
            30.00Second
      Quarter
            
            
            50.00
            
            
            
            31.06Third
      Quarter
            
            
            60.00
            
            
            
            36.62Fourth
      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.




25
 Table of Contents




ITEM6.   SELECTED FINANCIAL DATA





Not
applicable





ITEM7. 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.





26
 Table of Contents




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.




27
 Table of Contents




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.




28
 Table of Contents




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
            
            
            $
            24,000Long
      – term debt – related party
            
            
            79,354
            
            
            
            80,354
            
            
            
            36,581Short
      – term debt – related party
            
            
            -
            
            
            
            -
            
            
            
            -Current
      maturities of long-term debt, short-term debt and bank
      overdraft
            
            
            12,366
            
            
            
            22,544
            
            
            
            3,706Total
      debt
            
            
            124,670
            
            
            
            146,098
            
            
            
            64,287Stockholders’
      equity
            
            
            13,733
            
            
            
            25,034
            
            
            
            25,471Debt
      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.




29
 Table of Contents




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
            
            
            
            64,957Net
      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.




30
 Table of Contents





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
      DataYears
      Ended December 31,2009
            
            
            2008
            
            2007(In
      thousands except per share and MBOE amounts)Financial
      ResultsOil
      and Gas sales
            
            $
            30,768
            
            
            $
            51,832
            
            
            $
            20,827Equity
      in earnings of unconsolidated affiliates
            
            
            -
            
            
            
            -
            
            
            
            1,201Other
            
            
            956
            
            
            
            365
            
            
            
            728Total
      revenues and other
            
            
            31,724
            
            
            
            52,197
            
            
            
            22,756Cost
      and expenses
            
            
            42,024
            
            
            
            63,619
            
            
            
            21,183Other
      expense (income)
            
            
            13,369
            
            
            
            (15,028
            )
            
            
            13,176Income
      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
            
            
            
            2,717,691Operating
      ResultsAdjusted
      EBITDAX (1)
            
            $
            26,796
            
            
            $
            22,548
            
            
            $
            16,874Total
      proved reserves (MBOE)
            
            
            8,565
            
            
            
            8,213
            
            
            
            8,329Annual
      sales volumes (MBOE)
            
            
            886
            
            
            
            821
            
            
            
            455.5Average
      cost per MBOE:Production
      (including transportation and taxes)
            
            $
            17.66
            
            
            $
            24.66
            
            
            $
            16.47General
      and administrative
            
            $
            4.64
            
            
            $
            3.31
            
            
            $
            6.37Depletion
            
            $
            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.




31
 Table of Contents




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.
      2008Gas
      sales
            
            $
            9,124
            
            
            $
            20,747
            
            
            
            (56)
            %
            
            $
            10,030
            
            
            
            107
            %Oil
      sales
            
            
            17,147
            
            
            
            25,049
            
            
            
            (32)
            
            
            
            6,874
            
            
            
            264Natural
      gas liquid sales
            
            
            4,497
            
            
            
            6,036
            
            
            
            (25)
            
            
            
            3,923
            
            
            
            54Total
            
            $
            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.
      2008Natural
      GasSales
      volumes Mmcf
            
            
            2,623
            
            
            
            2,507
            
            
            
            5
            %
            
            
            1,551
            
            
            
            62
            %Price
      per Mcf
            
            $
            3.48
            
            
            $
            8.28
            
            
            
            (58)
            
            
            $
            6.47
            
            
            
            28Total
      gas sales revenues (thousands)
            
            $
            9,124
            
            
            $
            20,747
            
            
            
            (56)
            %
            
            $
            10,030
            
            
            
            107
            %Crude
      OilSales
      volumes MBbl
            
            
            293
            
            
            
            258
            
            
            
            14
            %
            
            
            96.7
            
            
            
            167
            %Price
      per Bbl
            
            $
            58.52
            
            
            $
            97.1
            
            
            
            (40)
            
            
            $
            71.1
            
            
            
            37Total
      oil sales revenues (thousands)
            
            $
            17,147
            
            
            $
            25,049
            
            
            
            (32)
            %
            
            $
            6,874
            
            
            
            264
            %Natural
      gas liquidsSales
      volumes MBbl
            
            
            156
            
            
            
            145
            
            
            
            8
            %
            
            
            101
            
            
            
            44
            %Price
      per Bbl
            
            $
            28.83
            
            
            $
            41.6
            
            
            
            (31)
            
            
            $
            39
            
            
            
            7Total
      natural gas liquids sales revenues (thousands)
            
            $
            4,497
            
            
            $
            6,036
            
            
            
            (25)
            %
            
            $
            3,923
            
            
            
            54
            %




32
 Table of Contents




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 liquids2007
      sales revenues
            
            $
            10,030
            
            
            $
            6,874
            
            
            $
            3,923Changes
      associated with sales volumes
            
            
            6,184
            
            
            
            11,467
            
            
            
            1,737Changes
      in prices
            
            
            4,533
            
            
            
            6,708
            
            
            
            3762008
      sales revenues
            
            
            20,747
            
            
            
            25,049
            
            
            
            6,036Changes
      associated with sales volumes
            
            
            960
            
            
            
            3,398
            
            
            
            458Changes
      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.




33
 Table of Contents




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
            
            
            2007Income
      from operations before income taxes
            
            $
            (23,669
            )
            
            $
            3,606
            
            
            $
            (11,603
            )Depreciation,
      depletion, amortization and impairment expense
            
            
            21,119
            
            
            
            39,816
            
            
            
            10,270Interest
      expense
            
            
            9,219
            
            
            
            9,855
            
            
            
            6,344Unrealized
      gain on derivative contract
            
            
            19,298
            
            
            
            (32,657
            )
            
            
            11,352Accretion
      Expenses
            
            
            829
            
            
            
            847
            
            
            
            219Exploration
      expense
            
            
            -
            
            
            
            -
            
            
            
            292Other
      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.
      2008Lease
      operating expense, transportation and taxes
            
            $
            15,651
            
            
            $
            20,242
            
            
            
            (23
            )%
            
            $
            7,500
            
            
            
            170
            %Depreciation,
      depletion and amortization
            
            
            15,368
            
            
            
            17,723
            
            
            
            (13
            )
            
            
            6,139
            
            
            
            189Impairments
      of oil and gas assets
            
            
            5,751
            
            
            
            22,093
            
            
            
            (74
            )
            
            
            3,203
            
            
            
            590Impairments
      of other properties
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            928
            
            
            
            -Accretion
      expense
            
            
            829
            
            
            
            847
            
            
            
            (2
            )
            
            
            219
            
            
            
            287Exploration
      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
            %




34
 Table of Contents




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.




35
 Table of Contents




·
            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.
      2008Interest
      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.




36
 Table of Contents




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.”





ITEM8. 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.








ITEM9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE





None





ITEM9A. 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.
 37
 Table of Contents
 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.
 38
 Table of Contents
 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.


ITEM9B. OTHER INFORMATION





None





39
 Table of Contents




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.





40
 Table of Contents





ITEM15. 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
      $12,000,000filed
      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.   41
 Table of Contents
  10.6
              
              CREDIT
      AGREEMENT dated as of March 2, 2007 among ISRAMCO ENERGY, L.L.C., each of
      the lenders that is a signatory hereto or which becomes a signatory
      hereto; and WELLS FARGO BANK, N. A., a national banking association, as
      agent for the Lenders., filed as an Exhibit to the 10-Q for the quarter
      ended March 31, 2007 and incorporated herein by
  reference.10.7
              
              GUARANTY
      AGREEMENT, dated as of March 2, 2007 by ISRAMCO, Inc. in favor of Wells
      Fargo Bank, N.A., as administrative agent (the "ADMINISTRATIVE AGENT") for
      the lenders that are or become parties to the Credit Agreement referred to
      in Item 10.6., filed as an Exhibit to the 10-Q for the quarter ended March
      31, 2007 and incorporated herein by reference.10.8
              
              PLEDGE
      AGREEMENT, dated as of March 2, 2007 by Isramco, Inc. in favor of Wells
      Fargo Bank, N.A., as administrative agent for itself and the lenders (the
      "LENDERS") which are parties to the Credit Agreement referred to in Item
      10.6, filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007
      and incorporated herein by reference.10.9
              
              Employment
      Agreement dated as of September 1, 2007 between Isramco Inc. and Edy
      Francis, filed as an Exhibit to the 10-Q for the quarter ended September
      30, 2007 and incorporated herein by reference.+10.10
              
              Agreement
      dated as of December 31, 2007 between Isramco Inc. and I.O.C. Israel Oil
      Company Ltd and addendum dated January 1, 2008, filed as an Exhibit to the
      10-Q for the quarter ended March 31, 2008 and incorporated herein by
      reference.10.11
              
              Amended
      and restated credit agreement dated on April 28, 2008 between Isramco
      Resources, LLC and The Bank of Nova Scotia and Capital One, N.A., filed as
      an Exhibit to the 10-Q for the quarter ended March 31, 2008 and
      incorporated herein by reference.10.12
              
              Amended
      and Restated Loan Agreement dated as of May 25, 2008 between Isramco Inc.
      and J.O.E.L. Jerusalem Oil Explorations Ltd. filed
      as an Exhibit to the 10-K for the year ended December 31, 2009 and
      incorporated herein by reference.10.13
              
              Amended
      and Restated Agreement dated as of November 17, 2008 between Isramco Inc.
      and Goodrich Global Ltd. filed
      as an Exhibit to the 10-K for the year ended December 31, 2009 and
      incorporated herein by reference.10.14*
              
              First Amendment to Loan Agreement dated as of February
      1, 2009, between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd.($18.5
      million)10.15*
              
              First Amendment to Loan Agreement dated as of February
      1, 2009, between Isramco, Inc, and Naphtha Israel Petroleum Corp.,
      Ltd.($11.5 million)10.16*
              
              Loan Agreement dated as of July 14, 2009 between
      Isramco, Inc. and I.O.C. – Israel Oil Company, Ltd.($6.0
      million)10.17*
              
              First Amendment to Loan Agreement dated as of February
      1, 2009 between Isramco, Inc. and I.O.C. Israel Oil Company, Ltd.($12.0
      million)14.1
              
              Code
      of Ethics, filed as an Exhibit to Form 10-K for the year ended December
      31, 2003.31.1*
              
              Certification of Chief Executive Officer pursuant to
      Section 302 of Sarbanes-Oxley Act.31.2*
              
              Certification of Chief Financial Officer pursuant to
      Section 302 of Sarbanes-Oxley Act32.1*
              
              Certification of Chief Executive and Principal Financial
      Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
      906 Of the Sarbanes-Oxley act of 200232.2*
              
              Certification of Chief Financial Officer pursuant to 18
      U.S.C. Section 1350, as adopted pursuant to Section 906 Of the
      Sarbanes-Oxley act of 2002
 __________________________


* Filed
Herewith.


+
Management Agreement





42
 Table of Contents








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








43
 Table of Contents





INDEX
TO FINANCIAL STATEMENTS





PageManagement’s Report on Internal Control Over Financial
      Reporting
            F-1Report of
      Independent Registered Public Accounting Firm
            F-2Consolidated
      Balance Sheets at December 31, 2009 and 2008
            F-3Consolidated
      Statements of Operations for the years ended December 31,2009, 2008 and
      2007
            F-4Consolidated
      Statements of Changes in Shareholders' Equity for the years ended December
      31, 2009, 2008 and 2007
            F-5Consolidated
      Statements of Cash Flows for the years ended December 31,2009, 2008 and
      2007
            F-6Notes to
      Consolidated Financial Statements
            F-7











44
 Table of Contents





MANAGEMENT’SREPORT 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





F-1
 Table of Contents





REPORTOF 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





F-2
 Table of Contents






ISRAMCOINC.


CONSOLIDATED
BALANCE SHEETS


(In
thousands, except share and per share amounts)





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





LIABILITIES
      AND SHAREHOLDERS’ EQUITYCurrent
      liabilities:Accounts
      payable and accrued expenses
            
            $
            9,798
            
            
            $
            7,712Short
      term debt and bank overdraft
            
            
            336
            
            
            
            1,544Current
      maturities of long-term debt
            
            
            12,000
            
            
            
            21,000Derivative
      liability
            
            
            693
            
            
            
            943Accrued
      interest and due to related party
            
            
            4,677
            
            
            
            5,606Deferred
      tax liabilities
            
            
            -
            
            
            
            2,245Total
      current liabilities
            
            
            27,504
            
            
            
            39,050Long-term
      debt
            
            
            32,950
            
            
            
            43,200Accrued
      interest - related party
            
            
            4,832
            
            
            
            -Long-term
      debt - related party
            
            
            79,354
            
            
            
            80,354Other
      Long-term Liabilities:Asset
      retirement obligations
            
            
            16,248
            
            
            
            15,733Derivative
      liability – non-current
            
            
            1,697
            
            
            
            -Total
      other long-term liabilities
            
            
            17,945
            
            
            
            15,733Commitments
      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
            
            
            
            27Additional
      paid-in capital
            
            
            23,194
            
            
            
            23,194Retained
      earnings (accumulated deficit)
            
            
            (11,362
            )
            
            
            2,217Accumulated
      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.





F-3
 Table of Contents





ISRAMCOINC.


CONSOLIDATED
STATEMENTS OF OPERATIONS


(in
thousands, except share and per share amounts)


Year
      Ended December 31
              
              2009
              
              
              2008
              
              
              2007RevenuesOil
      and gas sales
              
              $
              30,768
              
              
              $
              51,832
              
              
              $
              20,827Operator
      fees from related party
              
              
              -
              
              
              
              -
              
              
              
              18Office
      services to affiliate and otherTo
      related parties
              
              
              -
              
              
              
              -
              
              
              
              480To
      others
              
              
              845
              
              
              
              191
              
              
              
              230Other
              
              
              111
              
              
              
              174
              
              
              
              -Equity
      in earnings of unconsolidated affiliates
              
              
              -
              
              
              
              -
              
              
              
              1,201Total
      revenues
              
              
              31,724
              
              
              
              52,197
              
              
              
              22,756Operating
      expensesLease
      operating expense, transportation and taxes
              
              
              15,651
              
              
              
              20,242
              
              
              
              7,500Depreciation,
      depletion and amortization
              
              
              15,368
              
              
              
              17,723
              
              
              
              6,139Impairments
      of oil and gas assets
              
              
              5,751
              
              
              
              22,093
              
              
              
              3,203Impairments
      of other properties
              
              
              -
              
              
              
              -
              
              
              
              928Accretion
      expense
              
              
              829
              
              
              
              847
              
              
              
              219Exploration
      costs
              
              
              -
              
              
              
              -
              
              
              
              292Loss
      from plug and abandonment
              
              
              312
              
              
              
              -
              
              
              
              -General
      and administrativeTo
      related parties
              
              
              -
              
              
              
              -
              
              
              
              226To
      others
              
              
              4,113
              
              
              
              2,714
              
              
              
              2,676Total
      operating expenses
              
              
              42,024
              
              
              
              63,619
              
              
              
              21,183Operating
      income (loss)
              
              
              (10,300
              )
              
              
              (11,422
              )
              
              
              1,573Other
      expenses (income)Interest
      expense (income), net
              
              
              9,219
              
              
              
              9,855
              
              
              
              6,344Unrealized
      loss (gain) on marketable securities
              
              
              -
              
              
              
              -
              
              
              
              (52
              )Realized
      gain on sale of investment and other
              
              
              (250
              )
              
              
              (145
              )
              
              
              (1,754
              )Net
      loss (gain) on derivative contracts
              
              
              4,400
              
              
              
              (24,738
              )
              
              
              8,638Total
      other expenses (income)
              
              
              13,369
              
              
              
              (15,028
              )
              
              
              13,176Income
      (loss) from continuing operations before income taxes
              
              
              (23,669
              )
              
              
              3,606
              
              
              
              (11,603
              )Income
      tax benefit (expense)
              
              
              10,090
              
              
              
              (377
              )
              
              
              5,192Net
      income (loss)
              
              $
              (13,579
              )
              
              $
              3,229
              
              
              $
              (6,411
              )Earnings
      (loss) per 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


See notes
to the consolidated financial statements.





F-4
 Table of Contents




ISRAMCOINC.


CONSOLIDATED
STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY


FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 and 2007





Common
      stockNumber
      of shares
            
            Amount
            
            
            Additional
      Paid-In
              Capital
            
            
            Accumulated
      other comprehensive income (loss)
            
            
            Retained
      Earnings
              (Accumulated
      Deficit)
            
            
            Treasury
      stock
            
            
            Total
      Shareholders’Equity$
      in thousands, except share amountsBalances
      at January 1, 2007
            
            2,717,691
            
            
            27
            
            
            
            26,240
            
            
            
            3,242
            
            
            
            5,399
            
            
            
            (164
            )
            
            
            34,744Net
      loss
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (6,411
            )
            
            
            
            
            
            
            (6,411
            )Other
      equity adjustments
            
            
            
            
            
            
            
            
            (3,046
            )
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (3,046
            )Net
      unrealized gain on available for sale marketable securities, net of taxes
      of $450
            
            
            
            
            
            
            
            
            
            
            
            
            874
            
            
            
            
            
            
            
            
            
            
            
            874Net
      gain (loss) on foreign exchange rate, net of taxes $355
            
            
            
            
            
            
            
            
            
            
            
            
            (690
            )
            
            
            
            
            
            
            
            
            
            
            (690
            )Total
      comprehensive loss
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (6,227
            )Balance
      of December 31, 2007
            
            2,717,691
            
            
            27
            
            
            
            23,194
            
            
            
            3,426
            
            
            $
            (1,012
            )
            
            
            (164
            )
            
            
            25,471Net
      income
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            3,229
            
            
            
            
            
            
            
            3,229Net
      unrealized loss on available for sale marketable  securities, net of
      taxes of $1,568
            
            
            
            
            
            
            
            
            
            
            
            
            (3,044
            )
            
            
            
            
            
            
            
            
            
            
            (3,044
            )Net
      gain (loss) on derivative contracts, net of taxes $321
            
            
            
            
            
            
            
            
            
            
            
            
            (622
            )
            
            
            
            
            
            
            
            
            
            
            (622
            )Total
      comprehensive loss
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (437
            )Balance
      of December 31, 2008
            
            2,717,691
            
            $
            27
            
            
            $
            23,194
            
            
            $
            (240
            )
            
            $
            2,217
            
            
            $
            (164
            )
            
            $
            25,034Net
      loss
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (13,579
            )
            
            
            
            
            
            
            (13,579
            )Net
      unrealized gain on available for sale marketable  securities, net of
      taxes of $1,035
            
            
            
            
            
            
            
            
            
            
            
            
            2,011
            
            
            
            
            
            
            
            
            
            
            
            2,011Net
      gain (loss) on derivative contracts, net of taxes $138
            
            
            
            
            
            
            
            
            
            
            
            
            267
            
            
            
            
            
            
            
            
            
            
            
            267Total
      comprehensive loss
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            2,278Balance
      of December 31, 2009
            
            2,717,691
            
            $
            27
            
            
            $
            23,194
            
            
            $
            2,038
            
            
            $
            (11,362
            )
            
            
            (164
            )
            
            
            13,733





See notes
to consolidated financial statements.




F-5
 Table of Contents





ISRAMCOINC.


CONSOLIDATED
STATEMENTS OF CASH FLOWS


(In
thousands)





Year
      Ended December 31
            
            2009
            
            
            2008
            
            
            2007Cash
      Flows From Operating Activities:Net
      income (loss)
            
            $
            (13,579
            )
            
            $
            3,229
            
            
            $
            (6,411
            )Adjustments
      to reconcile net income (loss) to net cash provided by operating
      activities:Depreciation,
      depletion, amortization and impairment
            
            
            21,119
            
            
            
            39,816
            
            
            
            10,270Accretion
      expense
            
            
            829
            
            
            
            847
            
            
            
            219Unrealized
      and realized gain on marketable securities
            
            
            (250
            )
            
            
            (76
            )
            
            
            (344
            )Equity
      in earnings of unconsolidated affiliates
            
            
            -
            
            
            
            -
            
            
            
            (741
            )Changes
      in deferred taxes
            
            
            (9,841
            )
            
            
            468
            
            
            
            (5,488
            )Net
      unrealized loss (gain) on derivative contracts
            
            
            19,298
            
            
            
            (32,657
            )
            
            
            11,352Amortization
      of debt cost
            
            
            252
            
            
            
            189
            
            
            
            -Realized
      gain on sale of investment and capital gain
            
            
            (3
            )
            
            
            (68
            )
            
            
            (1,664
            )Changes
      in components of working capital and other assets and
      liabilitiesAccounts
      receivable
            
            
            (2,008
            )
            
            
            1,179
            
            
            
            (6,192
            )Prepaid
      expenses and other current assets
            
            
            (167
            )
            
            
            408
            
            
            
            92Due
      to related party
            
            
            305
            
            
            
            288
            
            
            
            -Increase
      (decrease) in accrued interest - related party
            
            
            3,561
            
            
            
            1,885
            
            
            
            -Accounts
      payable and accrued liabilities
            
            
            2,003
            
            
            
            3,378
            
            
            
            (1,755
            )Net
      cash provided by (used in) operating activities
            
            
            21,519
            
            
            
            18,886
            
            
            
            (662
            )Cash
      flows from investing activities:Addition
      to property and equipment, net
            
            
            (645
            )
            
            
            (99,042
            )
            
            
            (86,123
            )Proceeds
      from sale of gas properties and equipment
            
            
            1
            
            
            
            68
            
            
            
            36Proceeds
      from restricted deposit, net
            
            
            (70
            )
            
            
            745
            
            
            
            15,498Proceeds
      from sale of subsidiary - Magic
            
            
            -
            
            
            
            -
            
            
            
            2,150Proceeds
      from sale of other investment
            
            
            -
            
            
            
            -
            
            
            
            2,270Purchase
      of marketable securities
            
            
            (370
            )
            
            
            -
            
            
            
            (740
            )Proceeds
      from sale of marketable securities
            
            
            752
            
            
            
            476
            
            
            
            3,253Net
      cash used in investing activities
            
            
            (332
            )
            
            
            (97,753
            )
            
            
            (63,656
            )Cash
      flows from financing activities:Proceeds
      (payments) from loans – related parties, net
            
            
            (963
            )
            
            
            43,773
            
            
            
            36,716Proceeds
      from long-term debt
            
            
            2,000
            
            
            
            54,000
            
            
            
            35,300Repayment
      of long-term debt
            
            
            (21,250
            )
            
            
            (16,800
            )
            
            
            (8,300
            )Payments
      for financing cost
            
            
            -
            
            
            
            (1,015
            )
            
            
            -Borrowings
      (repayments) of short - term debt, net
            
            
            (1,208
            )
            
            
            838
            
            
            
            1,241Net
      cash provided by financing activities
            
            
            (21,421
            )
            
            
            80,796
            
            
            
            64,957Net
      increase (decrease) in cash and cash equivalents
            
            
            (234)
            
            
            
            1,929
            
            
            
            639Cash
      and cash equivalents at beginning of year
            
            
            3,141
            
            
            
            1,212
            
            
            
            573Cash
      and cash equivalents at end of year
            
            $
            2,907
            
            
            $
            3,141
            
            
            $
            1,212





See notes
to the consolidated financial statements.





F-6
 Table of Contents




ISRAMCOINC.


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS





1.  Summary
of Significant Accounting Policies





Basis
of Presentation and Principles of Consolidation





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





Use
of Estimates





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





Cash
and Cash Equivalents.





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





Allowance
for Doubtful Accounts





The
Company establishes provisions for losses on accounts receivable if it
determines that it will not collect all or part of the outstanding balance. The
Company regularly reviews collectibility and establishes or adjusts the
allowance as necessary using the specific identification method. There is no
significant allowance for doubtful accounts as of December 31, 2009 or
2008.





Oil
and Gas Operations.





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





F-7
 Table of Contents




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





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





The
Company reviews its property and equipment in accordance with Accounting
Standard Codification (ASC) 360, Property, Plant, and
Equipment (ASC 360). ASC 360 requires the Company to evaluate property
and equipment as an event occurs or circumstances change that would more likely
than not reduce the fair value of the property and equipment below the carrying
amount. If the carrying amount of property and equipment is not recoverable from
its undiscounted cash flows, then the Company would recognize an impairment loss
for the difference between the carrying amount and the discounted cash
flow.





In 2009,
2008 and 2007, we reported impairment charge of $5,751 thousand, $22,093
thousand and $3,203 thousand, respectively, relating to our oil and gas
properties.





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





Other
operating property and equipment are stated at the lower of cost or fair market
value. Provision for depreciation and amortization is calculated using the
straight-line method over the estimated useful lives of the respective
assets. The cost of normal maintenance and repairs is charged to operating
expense as incurred. Material expenditures, which increase the life of an asset,
are capitalized and depreciated over the estimated remaining useful life of the
asset. The cost of properties sold, or otherwise disposed of, and the
related accumulated depreciation or amortization are removed from the accounts
and any gains or losses are reflected in current operations. On December 31,
2007, we sold undeveloped real estate located in Israel to related party (for
further information see Note 5 “closure of the Israeli branch
office”).





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





Marketable
Securities





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





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





Asset
Retirement Obligation





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




F-8
 Table of Contents




Concentrations
of Credit Risk





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





The
purchasers of the Company’s oil and natural gas production consist primarily of
independent marketers, major oil and natural gas companies and gas pipeline
companies. The Company has not experienced any significant losses from
uncollectible accounts. The Company does not believe the loss of any one of its
purchasers would materially affect the Company’s ability to sell the oil and
natural gas it produces. The Company believes other purchasers are
available in the Company’s areas of operations.




Revenue
Recognition





Revenues
from the sale of oil and natural gas are recognized when the products are sold
to a purchaser at a fixed or determinable price, delivery has occurred and title
has transferred, and collectibility of the revenue is reasonably assured. The
Company follows the entitlement method of accounting for recording oil and gas
revenues under that method, any revenues received in excess of the Company's
share is treated as a liability. If revenues received are less than Company's
share, the deficiency is recorded as an asset. The Company's imbalance position
was not significant in terms of volumes or values at December 31, 2009 and
2008.





Price
Risk Management Activities




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





In 2009,
2008 and 2007, we recorded gain (loss) of $(4.4) million, $24.7 million and
$(8.6) million, respectively, related to our derivative instruments. Fair values
are derived principally from market quoted and other independent third-party
quotes.





During
the second quarter of 2008, we made the decision to mitigate a portion of our
interest rate risk with interest rate swaps. These swap instruments reduce our
exposure to market rate fluctuations by converting variable interest rates to
fixed interest rates. These interest rate swaps convert a portion of our
variable rate interest of our Scotia debt (as defined in Note 8, “Long-term
Debt”) to a fixed rate obligation, thereby reducing the exposure to market rate
fluctuations. We have elected to designate these positions for hedge accounting
and therefore the unrealized gains and losses are recorded in accumulated other
comprehensive loss. The Company measures hedge effectiveness by assessing the
changes in the fair value or expected future cash flows of the hedged
item.





F-9
 Table of Contents




Income
Taxes




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




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




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





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





Translation
of Foreign Currencies





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





Legal
Contingencies




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





Earnings
per Share





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


For the
year ended December 31, 2009, Isramco's stock options were
anti-dilutive.





F-10
 Table of Contents




Environmental





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




Recently
Issued Accounting Pronouncements




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




In August
2009, the FASB issued Accounting Standards Update (ASU) No. 2009-05, Fair
Value Measurements and Disclosures (ASU 2009-05). ASU 2009-05 amends
Subtopic 820-10, Fair ValueMeasurements and Disclosures, to provide guidance on the fair value
measurement of liabilities. ASU 2009-05 provides clarification for circumstances
in which a quoted price in an active market for the identical liability is not
available. ASU 2009-05 is effective for interim and annual periods beginning
after August 26, 2009. The Company adopted the provisions of ASU
2009-05 for the period ended December 31, 2009. There was no impact on the
Company’s operating results, financial position or cash flows.




In June
2009, the FASB issued ASU No. 2009-01, Generally Accepted Accounting
Principles(ASU 2009-01). ASU 2009-01 establishes “The FASB
Accounting Standards Codification,” or Codification, which became the source of
authoritative GAAP recognized by the FASB to be applied by nongovernmental
entities. On the effective date, the Codification superseded all
then-existing non-SEC accounting and reporting standards. All other
nongrandfathered non-SEC accounting literature not included in the Codification
will become nonauthoritative. ASU 2009-01 is effective for interim and annual
periods ending after September 15, 2009. The Company adopted the
provisions of ASU 2009-01 for the period ended September 30, 2009. There
was no impact on the Company’s operating results, financial position or cash
flows.




In May
2009, the FASB issued SFAS No. 165, Subsequent Events (ASC 855)
to establish general standards of accounting for and disclosure of events that
occur after the balance sheet date but before financial statements are issued or
are available to be issued. ASC 855 is effective for interim and annual
reporting periods ending after June 15, 2009. The Company adopted the
provisions of ASC 855 for the period ended June 30, 2009. There was no
impact on the Company’s operating results, financial position or cash
flows.




In April
2009, the FASB issued FASB Staff Position (FSP) No. FAS 107-1 and Accounting
Principles Board (APB) 28-1, Interim Disclosures about Fair Value
of Financial Instruments (ASC 825-10-65) to change the reporting
requirements on certain fair value disclosures of financial instruments to
include interim reporting periods. The Company adopted ASC 825-10-65 in the
second quarter of 2009. There was no impact on the Company’s operating results,
financial position or cash flows; however additional disclosures were added to
the accompanying notes to the consolidated financial statements for the
Company’s fair value of financial instruments. See Note 9 “Fair Value Measurements” for
more details.




F-11
 Table of Contents




In April
2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, Recognition and Presentation of
Other-Than-Temporary Impairments,(ASC 320-10-65), to expand
other-than-temporary impairment guidance for debt securities to enhance the
application of the guidance and improve the presentation and disclosure of
other-than temporary impairments on debt and equity securities within the
financial statements. The adoption of ASC 320-10-65 in the second quarter of
2009 did not have a significant impact on the Company’s operating results,
financial position or cash flows.




In April
2009, the FASB issued FSP No. FAS 157-4, Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly,(ASC
820-10-65) to provide additional guidance for estimating fair value when the
volume and level of activity for an asset or liability has significantly
decreased. In addition, ASC 820-10-65 includes guidance on identifying
circumstances that indicate a transaction is not orderly. The adoption of ASC
820-10-65 in the second quarter of 2009 did not have a significant impact on the
Company’s operating results, financial position or cash flows.





Effective
January 1, 2009, the Company adopted FSP No. FAS 157-2, Effective Date of FASB Statement
No. 157 (ASC 820-10-55). ASC 820-10-55 delayed the effective date of
ASC 820 for all non-financial assets and non-financial liabilities, except for
items that are recognized or disclosed at fair value in the financial statements
on a recurring basis (at least annually), until the beginning of the first
quarter of fiscal 2009. These include goodwill and other non-amortizable
intangible assets. The adoption of ASC 820-10-55 did not have a significant
impact on the Company’s operating results, financial position or cash flows. See
Note 6 “Asset Retirement
Obligations” for more details.




In
December 2008, the SEC issued Release No. 33-8995,Modernization of Oil and Gas
Reporting (ASC 2010-3), which amends the oil and gas disclosures for oil
and gas producers contained in Regulations S-K and S-X, as well as adding a
section to Regulation S-K (Subpart 1200) to codify the revised disclosure
requirements in Securities Act Industry Guide 2, which is being eliminated. The
goal of Release No. 33-8995 is to provide investors with a more meaningful
and comprehensive understanding of oil and gas reserves. Energy companies
affected by Release No. 33-8995 are now required to price proved oil and
gas reserves using the unweighted arithmetic average of the price on the first
day of each month within the 12-month period prior to the end of the reporting
period, unless prices are defined by contractual arrangements, excluding
escalations based on future conditions. SEC Release No. 33-8995 is
effective beginning for financial statements for fiscal years ending on or after
December 31, 2009. The impact on the Company’s operating results, financial
position and cash flows has been recorded in the financial statements;
additional disclosures were added to the accompanying notes to the consolidated
financial statements for the Company’s supplemental oil and gas disclosure. See
Note 19, Supplemental Oil and
Gas Informationfor more details.





In March
2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities—an amendment of FASB Statement
No. 133 (ASC 815-10-65). ASC 815-10-65 requires entities that
utilize derivative contracts to provide qualitative disclosures about their
objectives and strategies for using such instruments, as well as any details of
credit-risk-related contingent features contained within derivatives. ASC
815-10-65 also requires entities to disclose additional information about the
amounts and location of derivatives located within the financial statements, how
the provisions of ASC 815 have been applied, and the impact that hedges have on
an entity’s operating results, financial position or cash flows. The Company
adopted ASC 815-10-65 on January 1, 2009. There was no impact on the
Company’s operating results, financial position or cash flows; however
additional disclosures were added to the accompanying notes to the consolidated
financial statements for the Company’s derivative contracts. See Note 8 “Derivatives and Hedging
Activities” for more details.




2.  Acquisitions





GFB
Acquisition





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





F-12
 Table of Contents




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





As
      of December 31
            
            2008(In
      thousands)Oil
      and gas properties (after adjustments)
            
            $
            105,982Asset
      retirement obligation
            
            
            (8,480
            )Net
      asset acquired
            
            $
            97,502





Five
States Acquisition





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





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





As
      of December 31
            
            2007(In
      thousands)Oil
      and gas properties (after adjustments)
            
            $
            88,304Asset
      retirement obligation
            
            
            (2,020
            )Net
      asset acquired
            
            $
            86,284





F-13
 Table of Contents





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





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





Year
      Ended December 31,  2008
            
            As
      Reported
            
            
            Pro
      FormaRevenues
            
            $
            52,197
            
            
            $
            59,682Net
      income
            
            $
            3,229
            
            
            $
            4,419Income
      (loss) per share - basic and dilutedTotal
            
            $
            1.19
            
            
            $
            1.63








Year
      Ended December 31,  2007
            
            As
      Reported
            
            
            Pro
      FormaRevenues
            
            $
            22,756
            
            
            $
            38,918Net
      loss
            
            $
            (6,411
            )
            
            $
            (1,822
            )Income
      (loss) per share - basic and dilutedTotal
            
            $
            (2.36
            )
            
            $
            (0.67
            )





3.  Transactions
with Affiliates and Related Parties





There
were no active operations conducted by the Company in Israel in 2008 or
2009.





Until
December 31, 2007, we acted as operator for a joint venture with related parties
in Israel that engaged in the exploration of oil and gas. In this capacity we
received operating fees equal to the greater of 6% of the actual direct costs or
monthly fees of $6,000.




F-14
 Table of Contents





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





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





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





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




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





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




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




F-15
 Table of Contents




4.  Investments
in Affiliate





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





On
December 31, 2007, Isramco sold IOG, including the participation unit in Isramco
Negev 2 Limited Partnership, to a related party (for further information see
Note 5 “closure of the Israeli branch office”).  Summarized financial
information of Isramco Negev 2 Limited Partnership is as follows (amounts in
thousands):





Statement
of Operations





Year
      Ended December 31,
            
            2007Income
            
            $
            3778Expenses
            
            
            1,094Net
      income
            
            $
            2684





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





Statement
of Operations





Year
      Ended December 31,
            
            2007Income
            
            $
            4,222Expenses
            
            $
            293Net
      income
            
            $
            3,929





5.  Closure
of the Israeli Branch Office





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





F-16
 Table of Contents




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





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





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





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





6.   Marketable
Securities





For the
year ended December 31, 2009, 2008 and 2007, we had net unrealized gains on
marketable securities of $0 thousand. Sales of marketable securities resulted in
realized gains of $250, $0 thousand and $52 thousand for the years ended
December 31, 2009, 2008 and 2007, respectively.





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





As
      of December 31
            
            2009
            
            
            2008Cost
            
            
            Market
      Value
            
            
            Cost
            
            
            Market
      Value$
            1,087
            
            
            $
            4,713
            
            
            $
            1,219
            
            
            $
            1,799





7.  Derivative
and Hedging Activities





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





At
December 31, 2009, the Company has entered into swaps agreements. A swap
requires the Company to make a payment to, or receive receipts from, the
counterparty based upon the differential between a specified fixed price and a
price related to those quoted on the New York Mercantile Exchange (NYMEX) for
each respective period.




F-17
 Table of Contents




As of
December 31, 2009 we had swap contracts for volume of 778,077 barrels of
crude oil during 60 months, commencing January 2010, and swap contracts for
volume of 2,724,690 MMBTU of natural gas during 28 months commencing January
2010. Derivative commodity contracts settle based on NYMEX West Texas
Intermediate and Henry Hub prices, which may differ from the actual price
received by the Company. During 2009, 2008 and 2007 the Company did not elect to
designate any positions as cash flow hedges for accounting purposes, and
accordingly, recorded the net change in the mark-to-market valuation of these
contracts, as well as all payments and receipts on settled contracts, in current
earnings as a component of other income and expenses on the consolidated
statements of operations.





At
December 31, 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).





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





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





Natural
Gas





At
December 31, 2009, the Company had the following natural gas swap
positions:





Period
            
            SwapsVolume
      in
              MMbtu’s
            
            
            Price
      /
              Price Range
            
            
            Weighted
              Average PriceJanuary
      2010 – December 2010
            
            
            1,785,648
            
            
            $
            7.49-8.32
            
            
            $
            7.88January
      2011 – December 2011
            
            
            764,820
            
            
            
            8.22
            
            
            
            8.22January
      2012 – March 2012
            
            
            174,222
            
            
            
            8.65
            
            
            
            8.65





Crude
Oil





At
December 31, 2009, the Company had the following crude oil swap
positions:





Period
            
            SwapsVolume
      in
              Bbls
            
            
            Price
      /
              Price Range
            
            
            Weighted
              Average PriceJanuary
      2010 – December 2010
            
            
            254,868
            
            
            
            63.30-101.70
            
            
            
            79.59January
      2011 – December 2011
            
            
            240,336
            
            
            
            79.50-91.05
            
            
            
            86.55January
      2012 – December 2012
            
            
            127,473
            
            
            
            80.20-88.20
            
            
            
            82.37January
      2013 – December 2013
            
            
            89,400
            
            
            
            85.15
            
            
            
            85.15January
      2014 – December 2014
            
            
            66,000
            
            
            
            86.95
            
            
            
            86.95





F-18
 Table of Contents




During
the second quarter of 2008, we made the decision to mitigate a portion of our
interest rate risk with interest rate swaps. These swap instruments reduce our
exposure to market rate fluctuations by converting variable interest rates to
fixed interest rates.





Under
these swaps, the Company makes payments to, or receives payments from, the
counterparties based upon the differential between a specified fixed price and a
price related to the one-month London Interbank Offered Rate (“LIBOR”). These
interest rate swaps convert a portion of our variable rate interest of our
Scotia debt (as defined in Note 8, “Long-term Debt”) to a fixed rate obligation,
thereby reducing the exposure to market rate fluctuations. We have elected to
designate these positions for hedge accounting and therefore the unrealized
gains and losses are recorded in accumulated other comprehensive loss. The
Company measures hedge effectiveness by assessing the changes in the fair value
or expected future cash flows of the hedged item.





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





National
      amount (in thousands):
            
            Start
      Date
            
            Maturity
      Date
            
            Weighted-Average
              Interest
      Rate20,000
            
            April
      2009
            
            February
      2011
            
            
            3.63
            %6,000
            
            April
      2009
            
            February
      2011
            
            
            2.90
            %





8.  Long-Term
Debt and Interest Expense





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





2009
            
            
            
            2008Libor
      + 2% Bank Revolving Credit Facility due 2011
            
            
            14,950
            
            
            
            17,950Libor
      + 2% Bank Revolving Credit Facility due 2012
            
            
            30,000
            
            
            
            46,250Libor
      + 6% Related party Debt
            
            
            12,000
            
            
            
            12,000Libor
      + 5.5% Related party Debt
            
            
            954
            
            
            
            954Libor
      + 6% Related party Debt
            
            
            11,500
            
            
            
            18,500Libor
      + 6% Related party Debt
            
            
            6,000
            
            
            
            -Libor
      + 6% Related party Debt
            
            
            48,900
            
            
            
            48,900124,304
            
            
            
            144,554Less:
      Current Portion of Long-Term Debt
            
            
            (12,000
            )
            
            
            (21,000
            )Total
            
            
            112,304
            
            
            
            123,554





F-19
 Table of Contents




Senior
Revolving Credit Facility





The
Company entered into a Senior Secured Revolving Credit Agreement, dated as of
March 27, 2008 and Amended and Restated as of December 19, 2008 (the
“Senior Credit Agreement”), with each of the lenders from time to time party
thereto (the “Lenders”), Bank of Nova Scotia, as administrative agent for the
Lenders and Capital One, N.A, as a syndication agent for the Lenders. The Senior
Credit Agreement provides for a $150 million facility due in 2012 with a
borrowing base of $54 million that will be redetermined from time to time and
adjusted based on the Company’s oil and gas properties, reserves, other
indebtedness and other relevant factors. During the fourth quarter of 2009, the
lenders reduced the borrowing base to $32 million.





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





The
Senior Credit Agreement contains customary financial and other covenants,
including minimum working capital levels of not less than 1.0 to 1.0, leverage
ratio of not greater than 3.5 to 1.0 and minimum coverage of interest of not
less than 2.5 to 1.0. In addition, the Company is subject to covenants limiting
dividends and other restricted payments, transactions with affiliates, changes
of control, asset sales, and liens on properties. At December 31, 2009, the
Company was in compliance with all of its debt covenants under the Senior Credit
Agreement.





The
Company entered into a Senior Secured Revolving Credit Agreement, dated as of
March 2, 2007 as Amended and Restated as of June 15, 2007 (the “Senior
Credit Agreement”), with the lenders from time to time party thereto (the
“Lenders”) and Wells Fargo Bank, N.A, as administrative agent for the Lenders.
This Senior Credit Agreement provides for a $150 million facility due in 2011
with a borrowing base of $35.3 million that will be redetermined from time to
time and adjusted based on the Company’s oil and gas properties, reserves, other
indebtedness and other relevant factors. During the second quarter of 2009, the
Lenders reduced the borrowing base to $20.4 million.





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





The
Senior Credit Agreement contains customary financial and other covenants,
including minimum working capital levels of not less than 1.0 to 1.0, leverage
ratio of not greater than 3.5 to 1.0 and minimum coverage of interest of not
less than 2.5 to 1.0. In addition, the Company is subject to covenants limiting
dividends and other restricted payments, transactions with affiliates, changes
of control, asset sales, and liens on properties. At December 31, 2009, the
Company was in compliance with all of its debt covenants under this Senior
Credit Agreement.





Related
party Debt





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





F-20
 Table of Contents




Amounts
outstanding under the Loan with IOC bear interest at LIBOR plus 6.0%. The IOC
loan matures in five years, with accrued interest payable annually on each
anniversary date of the loan.  The IOC loan may be prepaid at any time
without penalty.





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





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




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





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





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




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





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





Pursuant
to a Loan Agreement dated as of February 27, 2007 (the "Second Loan Agreement")
Isramco obtained a loan , in the principal amount of $11.5 million from Naphtha,
repayable at the end of seven years. Interest accrues at a per annum rate of
LIBOR plus 6%. Principal is due and payable in four equal installments,
commencing on the fourth anniversary of the date of the loan. Interest is
payable annually upon each anniversary date of this Loan. At any time Isramco
can make prepayments without premium or penalty. The Second Loan is not secured.
The other terms of the Second Loan Agreement are identical to the terms of the
Loan Agreement.





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





F-21
 Table of Contents





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





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





Debt
Maturities





Aggregate
maturities required on long-term debt at December 31, 2009 are due in
future years as follows (in thousands):





2010
            
            
            12,0002011
            
            
            21,0002012
            
            
            30,1752013
            
            
            18,1002014
            
            
            24,100Thereafter
            
            
            18,829Total
            
            $
            124,304





Interest
expense (income)





The
following table summarizes the amounts included in interest expense for the
years ended December 31, 2009, 2008 and 2007:





Years
      Ended December 31,2009
            
            
            2008
            
            
            2007(In
      thousands)Current
      debt, long-term debt and other - banks corporation
            
            $
            2,658
            
            
            $
            3,369
            
            
            $
            1,624Long-term
      debt – related parties
            
            
            6,561
            
            
            
            6,486
            
            
            
            4,720$
            9,219
            
            
            $
            9,855
            
            
            $
            6,344





9.
Fair Value of Financial Instruments




Effective
January 1, 2008, the Company adopted ASC 820. ASC 820 defines fair value,
establishes a framework for measuring fair value and expands the related
disclosure requirements. Pursuant to ASC 820, the Company’s determination of
fair value incorporates not only the credit standing of the counterparties
involved in transactions with the Company resulting in receivables on the
Company’s consolidated balance sheets, but also the impact of the Company’s
nonperformance risk on its liabilities.




F-22
 Table of Contents




ASC 820
defines fair value as the price that would be received to sell an asset or paid
to transfer a liability in an orderly transaction between market participants at
the measurement date (exit price). The Company utilizes market data or
assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique. These inputs can be readily observable, market
corroborated, or generally unobservable. The Company classifies fair value
balances based on the observability of those inputs. ASC 820 establishes a fair
value hierarchy that prioritizes the inputs used to measure fair value. The
hierarchy gives the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (level 1 measurement) and the lowest
priority to unobservable inputs (level 3 measurement).




The three
levels of the fair value hierarchy defined by ASC 820 are as
follows:




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




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




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




The
following tables set forth by level within the fair value hierarchy the
Company’s financial assets and liabilities that were accounted for at fair value
as of December 31, 2009 and December 31, 2008. As required by ASC 820,
a financial instrument’s level within the fair value hierarchy is based on the
lowest level of input that is significant to the fair value measurement. The
Company’s assessment of the significance of a particular input to the fair value
measurement requires judgment, and may affect the valuation of fair value assets
and liabilities and their placement within the fair value hierarchy
levels.




December
      31, 2009Level
      1
            
            
            Level
      2
            
            
            Level 3
            
            
            TotalAssetsMarketable
      securities
            
            $
            4,713
            
            
            $
            —
            
            
            $
            —
            
            
            $
            4,713Commodity
      derivatives
            
            
            —
            
            
            
            5,579
            
            
            
            —
            
            
            
            5,579Total
            
            $
            4,713
            
            
            $
            5,579
            
            
            $
            —
            
            
            $
            10,292LiabilitiesCommodity
      derivatives
            
            $
            —
            
            
            
            1,852
            
            
            $
            —
            
            
            $
            1,852Interest
      rate derivatives
            
            
            —
            
            
            
            538
            
            
            
            —
            
            
            
            538Total
            
            $
            —
            
            
            $
            2,390
            
            
            $
            —
            
            
            $
            2,390




F-23
 Table of Contents







December
      31, 2008Level
      1
            
            
            Level
      2
            
            
            Level 3
            
            
            TotalAssetsMarketable
      securities
            
            $
            1,799
            
            
            $
            —
            
            
            $
            —
            
            
            $
            1,799Commodity
      derivatives
            
            
            —
            
            
            
            23,024
            
            
            
            —
            
            
            
            23,024Total
            
            $
            1,799
            
            
            $
            23,024
            
            
            $
            —
            
            
            $
            24,823LiabilitiesInterest
      rate derivatives
            
            $
            —
            
            
            $
            943
            
            
            $
            —
            
            
            $
            943




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




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




As of
December 31, 2009 and December 31, 2008, the Company’s derivative
contracts were with major financial institutions with investment grade credit
ratings which are believed to have a minimal credit risk. As such, the Company
is exposed to credit risk to the extent of nonperformance by the counterparties
in the derivative contracts discussed above; however, the Company does not
anticipate such nonperformance. Each of the counterparties to the Company’s
derivative contracts is a lender in the Company’s Senior Credit Agreement. The
Company did not post collateral under any of these contracts as they are secured
under the Senior Credit Agreements.




10.  Income
Taxes




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




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




F-24
 Table of Contents




Isramco
adopted Accounting Standards Codification (ASC) 740-10, effective January 1,
2007.  Isramco recognizes interest and penalties related to
unrecognized tax benefits within the provision for income taxes on continuing
operations. There were no unrecognized tax benefits that if recognized would
affect the tax rate. There were no interest or penalties recognized as of the
date of adoption or for the twelve months ended December 31,
2009.  The Company files federal and state tax returns in
jurisdictions in which it has operations and is subject to taxation. Tax years
subsequent to 2005 remain open to examination by taxing authorities in
accordance with the normal statute of limitations in the jurisdictions in which
the Company files.





The
income tax provision differs from the amount of income tax determined by
applying the Federal Income Tax Rate to pre-tax income from continuing
operations for the years ended December 31, 2009, 2008 and 2007, respectively,
due to the following items:




Years
      Ended December 31,2008
            
            
            2007
            
            
            2006(In
      thousands)Expected
      tax benefit (expense)
            
            $
            (8,285)
            
            
            $
            1,262
            
            
            $
            (4,061
            )State
      income taxes, net
            
            
            4
            
            
            
            (164
            )
            
            
            244Foreign
      income taxes
            
            
            -
            
            
            
            (659)
            
            
            
            (1,160
            )Change
      in estimate of income tax basis (1)
            
            
            (1,637
            )
            
            
            -
            
            
            
            -Other
            
            
            (172
            )
            
            
            (62
            )
            
            
            (215
            )Total
      tax expense (benefit)
            
            $
            (10,090
            )
            
            $
            377
            
            
            $
            (5,192
            )





(1)
            Changes
      in estimated income tax basis in connection with the preparation of 2006
      and 2007 amended federal income tax
returns.




Deferred
tax assets at December 31, 2009 and 2008 are comprised primarily of net
operating loss carry forwards and book impairment from write downs of assets.
Deferred tax liabilities consist primarily of the difference between book and
tax basis depreciation, depletion and amortization (DD&A) and impairment.
Book basis in excess of tax basis for oil and gas properties and equipment
primarily results from differing methodologies for recording property costs and
depreciation, depletion and amortization under United States generally accepted
accounting principles and the applicable income tax statutes and regulations in
the jurisdictions in which the Company operates. There is a net deferred tax
asset and it is management’s opinion that a valuation allowance is needed, as it
is not more likely than not based on objective evidence that realization of the
deferred tax assets is reasonably assured.




F-25
 Table of Contents




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




2009
            
            
            2008Deferred
      current tax assets:Unrealized
      hedging transactions
            
            $
            242
            
            
            $
            -Accrued
      interest
            
            
            4,357
            
            
            
            1,542Deferred
      current tax assets
            
            $
            4,599
            
            
            $
            1,542Deferred
      current tax liabilities:Unrealized
      hedging transactions
            
            $
            (955
            )
            
            $
            (3,787
            )$
            (955
            )
            
            $
            (3,787
            )Net
      current deferred tax assets (liabilities)
            
            $
            3,644
            
            
            $
            (2,245
            )Deferred
      noncurrent tax assets:Unrealized
      hedging transactions
            
            $
            595
            
            
            $
            -Book-tax
      differences in property basis
            
            
            -
            
            
            
            1,905Net
      operating loss carry-forwards
            
            
            10,324
            
            
            
            5,639Other
            
            
            565
            
            
            
            131Deferred
      noncurrent tax assets
            
            $
            11,484
            
            
            $
            7,675Deferred
      noncurrent tax liabilities:Unrealized
      hedging transactions
            
            $
            (754
            )
            
            $
            (3,720
            )Book-tax
      differences in property basis
            
            
            (1,196
            )
            
            
            -Book-tax
      differences in marketable securities
            
            
            (1,232
            )
            
            
            (197
            )Other
            
            
            (1,664
            )
            
            
            -Deferred
      noncurrent tax liabilities
            
            $
            (4,846
            )
            
            $
            (3,917
            )Net
      noncurrent deferred tax assets (liabilities)
            
            $
            6,638
            
            
            $
            3,758








F-26
 Table of Contents




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





2009
            
            
            2008
            
            
            2007Current
      income tax:Federal
            
            $
            -
            
            
            $
            276
            
            
            $
            -Foreign
            
            
            -
            
            
            
            (659
            )
            
            
            741State
            
            
            -
            
            
            
            114
            
            
            
            -Total
      current income tax
            
            $
            -
            
            
            $
            (269
            )
            
            $
            741Deferred
      income taxFederal
            
            $
            (10,094
            )
            
            $
            884
            
            
            $
            (5,933
            )Foreign
            
            
            -
            
            
            
            -
            
            
            
            -State
            
            
            4
            
            
            
            (238
            )
            
            
            -Total
      deferred income tax
            
            $
            (10,090
            )
            
            $
            646
            
            
            $
            (5,933
            )Provision
      for income tax
            
            $
            (10,090
            )
            
            $
            377
            
            
            $
            (5,192
            )





At
December 31, 2009 the Company has U.S. tax loss carry forwards of approximately
$28,829 thousand which will expire in various amounts beginning in 2023 and
ending in 2029.  Utilization of such loss carry forwards could be
limited to the extent Isramco has an ownership change that triggers the
limitation under Section 382 of Internal Revenue Code of 1986, as
amended.  The
Company is in the process to file Amended Federal Income Tax Returns for 2007
and 2008.





11.  Earnings
Per Share





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





2009
            
            
            2008
            
            
            2007Numerator
      for Basic and Diluted Earnings per Share -Net
      Income (loss)
            
            $
            (13,579
            )
            
            $
            3,229
            
            
            $
            (6,411
            )Denominator
      for Basic Earnings per Share -Weighted
      Average Shares
            
            
            2,717,691
            
            
            
            2,717,691
            
            
            
            2,717,691Potential
      Dilutive Common Shares -
            
            
            -
            
            
            
            -
            
            
            
            -Adjusted
      Weighted Average Shares
            
            
            2,717,691
            
            
            
            2,717,691
            
            
            
            2,717,691Net
      Income (Loss) Per Share Available to Common Stockholders – Basic and
      Diluted
            
            $
            (5.00
            )
            
            $
            1.19
            
            
            $
            (2.36
            )





F-27
 Table of Contents




12.  Stock
Options





The 1993
stock option plan (the 1993 Plan) was approved at the annual meeting of
shareholders held in August 1993. As of December 31, 2007, 20,050 shares of
common stock were reserved for issuance under the 1993 Plan. Options granted
under the 1993 Plan may be either incentive stock options under the Internal
Revenue Code or options that do not qualify as incentive stock options. Options
granted under the 1993 Plan may be exercised for a period of up to ten years
from the grant date. The exercise price for an incentive stock option may not be
less than 100% of the fair market value of Isramco's common stock on the date of
grant. All the options granted under the 1993 Plan to date were fully vested on
the date of grant. The administrator of the 1993 Plan may set the exercise price
for a nonqualified stock option at less than 100% of the fair market value of
Isramco's common stock on the date of grant.





No stock
options were granted during 2009, 2008 and 2007. Shares of common stock reserved
for future issuance under the 1993 plan are 20,050 shares. There are no granted
stock options outstanding under the 1993 Plan as of balance sheet
date.





13.  Supplemental
Cash Flow Information





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





2009
            
            
            2008
            
            
            2007Interest
            
            $
            6,263
            
            
            $
            7,014
            
            
            $
            3,284Income
      taxes
            
            $
            -
            
            
            $
            80
            
            
            $
            174





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





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





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





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





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





14.   Concentrations
of Credit Risk





Financial
instruments, which potentially expose Isramco to concentrations of credit risk,
consist primarily of trade accounts receivable and oil and gas derivative
assets. Isramco's customer base includes several of the major United States oil
and gas operating and production companies. Although Isramco is directly
affected by the well-being of the oil and gas production industry, management
does not believe a significant credit risk existed as of December 31, 2009. The
fair value of oil and gas derivatives contracts will be significantly impacted
by the change in oil and gas future prices. Isramco continues to monitor and
review credit exposure of its marketing counter-parties.




F-28
 Table of Contents


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





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





15.  Commitments
and Contingencies





Commitments





Isramco
has a few immaterial lease agreements.





Contingencies





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





16.  Asset
retirement obligation





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





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





2009
            
            
            2008
            
            
            2007Liability
      for asset retirement obligation at  the beginning of the
      year
            
            $
            15,733
            
            
            $
            2,670
            
            
            $
            356Liabilities
      Incurred
            
            
            -
            
            
            
            8,480
            
            
            
            2,050Liabilities
      settled and divested
            
            
            (314
            )
            
            
            (17
            )
            
            
            -Accretion
            
            
            829
            
            
            
            847
            
            
            
            219Revisions
      (*)
            
            
            -
            
            
            
            3,753
            
            
            
            45Liability
      for asset retirement obligation at  the end of the
      year
            
            $
            16,248
            
            
            $
            15,733
            
            
            $
            2,670





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




F-29
 Table of Contents




17.  Geographical
Segment Information





In 2009
and 2008 all activities of the Company were within the United
States.





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





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





Geographic
      segments (in thousands)
            
            United
      States
            
            
            Israel
            
            
            Total
      Oil and gas2007Sales
      and other operating revenues
            
            $
            20,916
            
            
            $
            1,840
            
            
            $
            22,756Costs
      and operating expenses
            
            
            19,796
            
            
            
            1,387
            
            
            
            21,183Operating
      profit (loss)
            
            $
            1,120
            
            
            $
            453
            
            
            $
            1,573Interest
      income
            
            
            
            
            
            
            
            
            
            
            (
      434
            )Interest
      expense
            
            
            
            
            
            
            
            
            
            
            6,778Gain
      on marketable securities and net gain in investee
            
            
            
            
            
            
            
            
            
            
            (
      52
            )Realized
      gain on sale of investment and capital gain
            
            
            
            
            
            
            
            
            
            
            (1,754
            )Loss
      from swap transaction
            
            
            
            
            
            
            
            
            
            
            8,638Income
      taxes (benefit)
            
            
            
            
            
            
            
            
            
            
            (5,192
            )Net
      loss before discontinued operation
            
            
            
            
            
            
            
            
            
            
            (6,411
            )Loss
      on discontinued operation
            
            
            
            
            
            
            
            
            
            
            -Net
      loss
            
            
            
            
            
            
            
            
            
            
            (6,411
            )Identifiable
      assets at December 31, 2007
            
            $
            99,955
            
            
            $
            -
            
            
            $
            99,955Cash
      and corporate assets
            
            
            
            
            
            
            
            
            
            
            10,753Total
      assets at December 31, 2007
            
            
            
            
            
            
            
            
            
            $
            110,708





F-30
 Table of Contents







18.  Subsequent
Events





The
Company has evaluated subsequent events through March 12, 2010 which is the date
the consolidated financial statements were issued.





19.  Supplementary
Oil and Gas Information (Unaudited)





The
following supplemental information regarding the oil and gas activities of
Isramco for 2009, 2008 and 2007 is presented pursuant to the disclosure
requirements promulgated by the Securities and Exchange Commission and SFAS No.
69, "Disclosures About Oil and Gas Producing Activities." Capitalized costs
relating to oil and gas activities and costs incurred in oil and gas property
acquisition, exploration and development activities for each year are shown
below.





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





As
      of December 31
            
            2009
            
            
            2008United
      States
            
            
            United
      StatesUnproved
      properties not being amortized
            
            $
            -
            
            
            $
            -Proved
      property being amortized
            
            
            220,139
            
            
            
            219,945Accumulated
      depreciation, depletion amortization and impairment
            
            
            (77,117
            )
            
            
            (56,109
            )Net
      capitalized costs
            
            
            143,022
            
            
            
            163,836





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





As
      of December 31
            
            2009
            
            
            2008
            
            
            2007United
      StatesProperty
      acquisition costs—proved and unproved properties
            
            $
            -
            
            
            $
            97,502
            
            
            $
            86,284Exploration
      costs
            
            $
            -
            
            
            $
            -
            
            
            $
            269Development
      costs
            
            $
            423
            
            
            $
            1,167
            
            
            $
            2,691





OIL
AND GAS RESERVES





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




F-31
 Table of Contents





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




The
following table illustrates the Company’s estimated net proved reserves,
including changes, and proved developed reserves for the periods indicated, as
estimated by Cawley, Gillespie & Associates,
Inc.    Natural gas liquids are included in natural gas
reserves. The oil and natural gas liquids price as of December 31, 2009 is
based on the 12-month unweighted average of the first of the month prices of the
West Texas Intermediate posted price. Oil and natural gas liquids prices as of
December 31, 2008 and 2007 are based on the respective year-end West Texas
Intermediate posted price. The oil and natural gas liquids prices were adjusted
by lease for quality, transportation fees, and regional price differentials. The
gas price as of December 31, 2009 is based on the 12-month unweighted
average of the first of the month prices of the Henry Hub spot price. Gas prices
as of December 31, 2008 and 2007 are based on the respective year-end Henry
Hub spot market price. All prices are adjusted by lease for energy content,
transportation fees, and regional price differentials. All prices are held
constant in accordance with SEC guidelines. All proved reserves are located in
the United States.





Oil
      BBls
            
            
            Gas
      Mcf
            
            
            NGL
      BBlsDecember
      31, 2006
            
            
            115,975
            
            
            
            1,372,000
            
            
            
            2,163,661-Revisions
      of previous estimates
            
            
            358,044
            
            
            
            1,455,617
            
            
            
            838,595Acquisition
      of minerals in place
            
            
            1,625,855
            
            
            
            24,075,738
            
            
            
            1,425,600Sales
      of minerals in place
            
            
            -
            
            
            
            -
            
            
            
            -Production
            
            
            (96,793
            )
            
            
            (1,550,789
            )
            
            
            (100,534
            )December
      31, 2007
            
            
            2,003,081
            
            
            
            25,352,566
            
            
            
            2,163,661Revisions
      of previous estimates
            
            
            (2,276,616
            )
            
            
            (15,011,339
            )
            
            
            (766,418
            )Acquisition
      of minerals in place
            
            
            3,210,496
            
            
            
            17,862,776
            
            
            
            -Sales
      of minerals in placeProduction
            
            
            (257,967
            )
            
            
            (2,507,828
            )
            
            
            (145,240
            )December
      31, 2008
            
            
            2,678,994
            
            
            
            25,696,175
            
            
            
            1,252,003Revisions
      of previous estimates
            
            
            616,674
            
            
            
            1,378,468
            
            
            
            391,115Acquisition
      of minerals in place
            
            
            -
            
            
            
            -
            
            
            
            -Sales
      of minerals in place
            
            
            -
            
            
            
            -
            
            
            
            -Production
            
            
            (293,601)
            
            
            
            (2,622,389
            )
            
            
            (155,793
            )December
      31, 2009
            
            
            3,002,067
            
            
            
            24,452,254
            
            
            
            1,487,325




F-32
 Table of Contents




Isramco's
proved developed reserves are as follows:





Developed
            
            
            UndevelopedOil
      BBls
            
            
            Gas
      Mcf
            
            
            NGL
      BBls
            
            
            Oil
      BBls
            
            
            Gas
      Mcf
            
            
            NGL
      BBlsDecember
      31, 2009
            
            
            3,002,067
            
            
            
            24,452,254
            
            
            
            1,487,325
            
            
            
            -
            
            
            
            -
            
            
            
            -December
      31, 2008
            
            
            2,678,994
            
            
            
            25,696,175
            
            
            
            1,252,003
            
            
            
            -
            
            
            
            -
            
            
            
            -December
      31, 2007
            
            
            1,808,317
            
            
            
            23,338,079
            
            
            
            1,873,949
            
            
            
            194,764
            
            
            
            2,014,487
            
            
            
            289,711December
      31, 2006
            
            
            115,975
            
            
            
            1,372,000
            
            
            
            -
            
            
            
            5,876
            
            
            
            618,700
            
            
            
            -





Interest
in proved reserves of unconsolidated affiliates





Oil
      BBls
            
            
            Gas
      McfDecember
      31, 2006
            
            
            --
            
            
            
            1,979,000





STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOW





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





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





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





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





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





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




F-33
 Table of Contents





Under the
Standardized Measure, for the years ended December 31, 2008 and 2007 the
future cash inflows were estimated by applying year-end oil and natural gas
prices to the estimated future production of year-end proved reserves. Estimates
of future income taxes are computed using current statutory income tax rates
including consideration for estimated future statutory depletion and tax
credits. The resulting net cash flows are reduced to present value amounts
by applying a 10% discount factor. Use of a 10% discount rate and year-end
prices were required. At December 31, 2009, as specified by the SEC, the
prices for oil and natural gas used in this calculation were the unweighted
12-month average of the first day of the month (12-month unweighted average)
cash price quotes, except for volumes subject to fixed price
contracts.








2009
            
            
            2008
            
            
            2007Future
      cash inflows
            
            $
            294,721,432
            
            
            $
            277,008,941
            
            
            $
            450,981,415Future
      development costs
            
            
            (556,810
            )
            
            
            (511,810
            )
            
            
            (3,502,500
            )Future
      production costs
            
            
            (147,470,220
            )
            
            
            (146,421,245
            )
            
            
            (178,384,211
            )Future
      income tax expenses
            
            
            -
            
            
            
            -
            )
            
            
            (63,983,746
            )Future
      net cash flows before 10% discount
            
            
            146,694,402
            
            
            
            130,075,886
            
            
            
            205,110,95810%Annual
      discount for estimated timing of cash flows
            
            
            (68,284,971
            )
            
            
            (56,698,274
            )
            
            
            (108,345,218
            )Standardized
      measure discounted future net cash flows
            
            $
            78,409,431
            
            
            $
            73,377,612
            
            
            $
            96,765,739





CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS





The
following is a summary of the changes in the Standardized Measure of discounted
future net cash flows for the Company’s proved oil and natural gas reserves
during each of the years in the three year period ended December 31,
2009





2009
            
            
            2008
            
            
            2007Beginning
      of the year
            
            $
            73,377,612
            
            
            $
            96,765,740
            
            
            $
            4,321,000Sales
      and transfers of oil and gas produced, net of production
    costs
            
            
            (15,116,990
            )
            
            
            (31,469,183
            )
            
            
            (13,267,315
            )Net
      changes in prices and production costs
            
            
            4,638,711
            
            
            
            (144,454,304
            )
            
            
            6,084,956Net
      changes in income taxes
            
            
            -
            
            
            
            28,376,801
            
            
            
            (8,075,637
            )Changes
      in estimated future development costs, net of current development
      costs
            
            
            211,024
            
            
            
            (3,546,457
            )
            
            
            (3,395,813
            )Acquisition
      of minerals in place
            
            
            -
            
            
            
            124,894,615
            
            
            
            95,870,804Revision
      of previous estimates
            
            
            11,948,600
            
            
            
            (45,059,969
            )
            
            
            23,413,049Change
      of discount
            
            
            6,626,173
            
            
            
            23,513,947
            
            
            
            794,008Change
      in production rate and other
            
            
            (3,275,699
            )
            
            
            24,356,422
            
            
            
            (8,979,313
            )End
      of year
            
            $
            78,409,431
            
            
            $
            73,377,612
            
            
            $
            96,765,740





F-34
 Table of Contents







Unaudited
Quarterly Financial Information


(In Thousands, Except
Per Share Data)





Quarter
      Ended
            
            March
      31
            
            
            June
      30
            
            
            September
      30
            
            
            December
      312009Total
      Revenues
            
            $
            7,007
            
            
            $
            7,399
            
            
            $
            7,810
            
            
            $
            9,508Net
      Income (loss) before taxes
            
            $
            2,713
            
            
            $
            (12,223
            )
            
            $
            (3,236
            )
            
            $
            (10,923)Net
      Income (loss)
            
            $
            1,790
            
            
            $
            (8,014
            )
            
            $
            (2,018
            )
            
            $
            (5,337
            )Earnings
      (loss) per Common Share-Basic
      and Diluted
            
            $
            0.66
            
            
            $
            (2.95
            )
            
            $
            (0.74
            )
            
            $
            (1.96
            )2008Total
      Revenues
            
            $
            7,730
            
            
            $
            18,873
            
            
            $
            17,866
            
            
            $
            7,728Net
      Income (loss) before taxes
            
            $
            (11,586
            )
            
            $
            (47,905
            )
            
            $
            51,572
            
            
            $
            11,525Net
      Income (loss)
            
            $
            (7,646
            )
            
            $
            (32,186
            )
            
            $
            34,488
            
            
            $
            8,573Earnings
      (loss) per Common Share-Basic
      and Diluted
            
            $
            (2.81
            )
            
            $
            (11.84
            )
            
            $
            12.69
            
            
            $
            3.152007Total
      Revenues
            
            $
            3,122
            
            
            $
            7,215
            
            
            $
            5,355
            
            
            $
            7,064Net
      Income (loss) before taxes
            
            $
            (2,807
            )
            
            $
            1,936
            
            
            $
            (970
            )
            
            $
            (9,761
            )Net
      Income (loss)
            
            $
            (1,766
            )
            
            $
            1,198
            
            
            $
            (647
            )
            
            $
            (5,196
            )Earnings
      (loss) per Common Share-Basic
      and Diluted
            
            $
            (0.65
            )
            
            $
            0.44
            
            
            $
            (0.24
            )
            
            $
            (1.91
            )










F-35
 Table of Contents