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(Registrant's
Telephone Number, including Area Code)
Securities
registered under Section 12(b) of the Exchange Act: None
Securities
registered under Section 12(g) of the Exchange Act:
Common
Stock, par value $0.01
(Title of
Class)
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes r No x
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes r No x
Indicate
by check mark whether the issuer (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12
months (or for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days. x
Yes r
No
Indicate
by check mark if disclosure of delinquent filers in response to Item 405 of
Regulation S-K is not contained in this Form, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.r
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
the definitions of “large accelerated filer “,“accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
Large
accelerated filer r Accelerated
filer r
Non-accelerated filer r Smaller
Reporting Company x
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Securities Exchange Act). Yes r No x
As of
March 20, 2009, there were 2,717,691 shares of the Registrant's common stock par
value $0.01 per share ("Common Stock") outstanding. The aggregate market value
of the Common Stock held by non-affiliates of the Registrant at June 30, 2008,
based on the last sale price of such equity reported on the Nasdaq market, was
approximately $64.6 million.
Information
required by Part III, Items 10, 11, 12, 13 and 14, is incorporated by reference
to portions of the registrant’s definitive proxy statement for its 2009 annual
meeting of stockholders, which will be filed on or before April 30,2009.
This
report on Form 10-K contains forward-looking statements within the meaning of
the federal securities laws. All statements, other than statements of historical
facts, concerning, among other things, planned capital expenditures, potential
increases in oil and natural gas production, the number of anticipated wells to
be drilled in the future, future cash flows and borrowings, pursuit of potential
acquisition opportunities, our financial position, business strategy and other
plans and objectives for future operations, are forward-looking statements.
These forward-looking statements are identified by their use of terms and
phrases such as “may,”“expect,”“estimate,”“project,”“plan,”“believe,”“intend,”“achievable,”“anticipate,”“will,”“continue,”“potential,”“should,”“could” and similar terms and phrases. Although we believe that the expectations
reflected in these forward-looking statements are reasonable, they do involve
certain assumptions, risks and uncertainties. The actual results could differ
materially from those anticipated in these forward-looking statements. One
should consider carefully the statements under the “Risk Factors” section of
this report and other sections of this report that describe factors that could
cause our actual results to differ from those set forth in the forward-looking
statements, including, but not limited to, the following factors:
·
the
volatility in commodity prices for oil and natural gas, including
continued declines in prices;
·
the
possibility that the industry may be subject to future regulatory or
legislative actions (including any additional taxes and changes in
environmental regulation);
·
the
possibility that the United States economy is entering into a deflationary
period, which would negatively impact the price of commodities, including
oil and natural gas;
·
the
presence or recoverability of estimated oil and natural gas reserves and
the actual future production rates and associated
costs;
·
the
possibility that production decline rates for some of our oil and gas
producing properties are greater than we
expect;
·
our
ability to generate sufficient cash flow from operations, borrowings or
other sources to enable us to fully develop our undeveloped acreage
positions;
·
the
ability to replace oil and natural gas
reserves;
·
environmental
risks;
·
drilling
and operating risks;
·
exploration
and development risks;
·
competition,
including competition for acreage in oil and gas producing areas and for
experienced personnel;
·
management’s
ability to execute our plans to meet our
goals;
·
our
ability to retain key members of senior management and key technical
employees;
·
our
ability to obtain goods and services, such as drilling rigs and tubulars,
and access to adequate gathering systems and pipeline take-away capacity,
to execute our drilling program;
·
general
economic conditions, whether internationally, nationally or in the
regional and local market areas in which we do business, may be less
favorable than expected, including the possibility that the current
economic recession in the United States will be severe and prolonged,
which could adversely affect the demand for oil and natural gas and make
it difficult, if not impossible, to access financial
markets;
·
other
economic, competitive, governmental, legislative, regulatory, geopolitical
and technological factors that may negatively impact our business,
operations or pricing.
Finally,
our future results will depend upon various other risks and uncertainties,
including, but not limited to, those detailed in the section entitled “Risk
Factors” included in this report. All forward-looking statements are expressly
qualified in their entirety by the cautionary statements in this paragraph and
elsewhere in this document. Other than as required under the securities laws, we
do not assume a duty to update these forward-looking statements, whether as a
result of new information, subsequent events or circumstances, changes in
expectations or otherwise.
Isramco,
Inc., a Delaware corporation incorporated in 1982 (hereinafter, “we”, the
“Company” or “Isramco”), together with its wholly-owned subsidiaries, Isramco
Energy LLC (“Isramco Energy”), Isramco Resources, LLC (“Isramco Resources”) Jay
Petroleum, LLC ("Jay Petroleum"), Jay Management Company, LLC ("Jay Management")
and Field Trucking and Services, LLC (”FTS”) (collectively “Isramco” or the
“Company”), explore for, develop and produce natural gas and crude oil and
operated oil and gas properties in the United States. Isramco's principal
producing and exploring areas are further described in "Exploration, Development
and Production" below.
At
December 31, 2008, our estimated total proved oil, natural gas reserves and
natural gas liquids, as prepared by our independent reserve engineering firm,
Cawley, Gillespie & Associates, Inc., were approximately 8,213 thousand
barrels of oil equivalent (“MBOE”), consisting of 2,679 thousand barrels
(Bbls) of oil, and 25,696 million cubic feet (Mcf) of natural gas and 1,252
thousand barrels (Bbls) natural gas liquids. Approximately 97.6% of our proved
reserves were classified as proved developed. (see "Supplemental Information to
Consolidated Financial Statements").
Our
business strategy is to maximize the rate of return on investment of capital by
controlling operating and capital costs, acquiring of strategic oil and gas
properties and improvement of existing oil and gas properties. Over the course
of 2008, we have expanded our activities in the United States through a
combination of strategic acquisitions and continued development of existing
proved properties. An additional important goal for implementing our business
strategy is to maintain the lowest possible operating cost structure, among
other things, by serving as operator of a substantial portion of our oil and
natural gas properties.
Exploration,
Development and Production
United
States
We,
through our wholly-owned subsidiaries, are involved in oil and gas exploration,
developing, production and operation of wells in the United States. We own
varying working interests in oil and gas wells in Louisiana, Texas, New Mexico,
Oklahoma, Wyoming, Utah and Colorado and currently serve as operator of
approximately 620 wells located mainly in Texas and New Mexico. The following is
a summary of significant developments during 2008 through the present, including
certain 2009 plans.
Acquisitions: On March 27,2008, we purchased from GFB Acquisition - I, L.P. (“GFB”) and Trans Republic
Resources, Ltd. (“Trans Republic,” and, together with GFB, the “Sellers”)
interests in certain oil and gas properties located in Texas, New Mexico, Utah,
Colorado and Oklahoma for an aggregate purchase price of approximately $102
million. The transaction included mainly operated oil and gas properties in
approximately 40 fields (approximately 490 Leases) in East Texas, Texas Gulf
Coast, Permian, Anadarko and San Juan Basins. Significant fields are
the Alabama Ferry Field in East Texas, the Bagley Field in West Texas and New
Mexico, and the Esperson Dome Field on the Texas Gulf Coast.
On March2, 2007, we purchased certain oil and gas properties located in Texas and New
Mexico from Five States Energy Company, LLC (“Five States”) for a purchase price
of $92 million.
Israel
In 2007
we closed our branch office in Israel in order to focus on our expanding
presence in the United States. However, we have retained certain
interests in various oil and gas leases and licenses, which are discussed
below.
Matan License. In January
2009, Noble Energy, Inc. (“Noble”) completed the Tamar # 1 (“Tamar”) well at a
depth of 16,076 feet and in approximately 5,500 feet of water depth. This
well is located offshore Israel and is operated by Noble Energy, Inc.
After analysis of all the post drilling and production test data, Noble
estimates the gross mean resources potential of Tamar to be 5 trillion cubic
feet of natural gas. Performance modeling indicates that the well can be
ultimately completed to achieve a production rate of over 150 million cubic feet
per day. We own an overriding royalty interest of 1.4375% in this well, which
will increase to 2.7375% after payout.
Noble and
its other partners have announced that they intend to retain the rights to the
Atwood Hunter drilling rig in order to drill two additional wells, one of which
is an exploration well, the Dalit # 1 well, which was spudded on March 6, 2009.
The second well is an appraisal well (Tamar # 2) to be drilled to further define
the resources available in the Tamar structure and to obtain information that
will be important in the planning of the development for this
field.
Med Yavne Lease. Based on the
gas finds known as "Or 1" and "Or South", a 30 year lease, which covers 53
square kilometers (approximately 13,100 acres) offshore Israel, was granted to
us in June 2000 (hereinafter: the "Med Yavne Lease"). The operator of the Med
Yavne Lease was BG International Limited, a member of the British Gas Group
("BG"). BG resigned as the operator of the Lease and relinquished of its working
interests in the Lease, and the partners appointed I.O.C Israel Oil Company as
the successor operator.
According
to the operator's estimates, which are based on the results of the drillings in
the Or 1, and on a 3D seismic survey performed in the area of the
lease, the recoverable gas reserves of Or 1 reserve are estimated at 35 billion
cubic feet. In January 2008 and in January 2009, Isramco received an opinion
from a consulting firm in the United States that performed a techno-economic
examination for the development of the Or 1 reserve. The opinion indicates that,
under certain assumptions, development of the reserve by connection to a nearby
platform (at a distance of seven miles) and from there via an existing
transportation pipeline to the coast, may be economically feasible. It is the
intention of the partners in Med Yavne Lease to cooperate with independent third
parties to jointly develop Or 1 reserve with their gas reserve.
Our
participation interest of the Med Yavne Lease is 0.7052 %
Hof Licenses. In February
2008 the Petroleum Commissionaire of Israel granted to us a license that covers
100,000 acres offshore Israel.
According to the license terms the participants in the license need to
drill one well in the license’s area by August 2009. We have sold 80% of the
working interest in the license in return for a 20% carried working interest (up
to investment of $4,000,000 in the license).
Med Ashdod 2. In February
2008 the Petroleum Commissionaire has granted us a license which covers 100,000
acres offshore Israel. According to the License terms the participants to the
licenses need to sign a drilling contract by no later than November 2009.
According to Israeli Petroleum law, the Petroleum
Commissionaire sent a default notice in that notified us of the
default and demanded that we cure the default within 60 days from the date of
the notice. Pursuant to the Israeli Petroleum law, the operator has appealed
this determination to the Minister of Infrastructure of Israel.
Our
participation interest of the Med Ashdod Lease is 0.35%
The table
below sets forth the working interests of Isramco and all related and unrelated
participants in the lease and licenses in Israel, the total acreage and the
expiration dates of each of the licenses and the lease as of December 31,2008.
(1) All
of the oil and gas assets are subject to a 12.5% Overriding Royalty due to the
Government of Israel under the Israeli Petroleum Law.
(2) The
expiration dates are subject to the fulfillment of applicable provisions of the
Israel Petroleum Law and Regulations, and the conditions and work obligations of
each of the above leases.
Overriding Royalties. We hold
Overriding Royalties in certain oil and gas assets. Additionally, we are
entitled to receive from certain participant in the Med Yavne lease overriding
royalties equal to 2% of each such participant's rights to any oil/gas produced
within those leases. The table below sets forth the Overriding Royalties held by
us:
From the
Limited Partnership, on the first 10% of the Limited Partnership's share of the
following leases
Before
Payout
After
Payout
Med
Yavne Lease ,Michal ,Mathan Licenses from the first 10% working interests
of Isramco Negev 2 LP (1)*
1
%
13
%
Michal
& Matan Licenses 28.75% working interests of from Isramco Negev 2,
LP
5.0
%
5.0
%
(1) A
30-year lease covering an area of approximately 53 square kilometers (including
the area of the gas discovery) was granted in June 2000.
Acquisition
Related Financing Activities
GFB
Acquisition Financing.
To fund
the oil and gas properties acquired in March 2008 from the Sellers we obtained
loans in the aggregate principal amount of $102.9 million as described
below:
In
February and March, 2008 we obtained loans from J.O.E.L. Jerusalem Oil
Exploration, Ltd. (“JOEL”), a related party, in the aggregate principal amount
of $48.9 million, repayable at the end of 4 months at an interest
rate of the London Interbank Offered Rate (LIBOR) plus 1.25% per
annum. Pursuant to a loan agreement signed in June 2008, the maturity
date of this loan was extended to June 30, 2015. Interest accrues at a per annum
rate of LIBOR plus 6%. Principal and interest are due and payable in
four equal annual installments, commencing on June 30, 2012. At any time we can
make prepayments without premium or penalty. Mr. Jackob Maimon, Isramco’s
president and director is a director of JOEL and Mr. Haim Tsuff, Isramco’s Chief
Executive Officer and Chairman, is a controlling shareholder of
JOEL.
We
entered into a Senior Secured Revolving Credit Agreement, dated as of
March 27, 2008, as subsequently amended, (the “Senior Credit Agreement”),
with Bank of Nova Scotia, as administrative agent for the lenders form time to
time (the “Lenders”) and Capital One, N.A as a syndication agent for the
Lenders. The Senior Credit Agreement provides for a $150 million credit facility
with an increased borrowing base of $54 million that will be re-determined from
time to time, and adjusted based on the Company’s oil and gas properties,
reserves, other indebtedness and other relevant factors. Owing to the general
deterioration in economic conditions, during the fourth quarter of 2008, the
lenders reduced the borrowing base to $45 million.
Amounts
outstanding under the Senior Credit Agreement bear interest at specified margins
over the LIBOR of 1.25% to 2.00% for LIBOR loans or at specified margins over
the Base Rate (as defined in the Senior Credit Agreement) of 0.25% to 1.25% for
base rate loans. Such margins will fluctuate based on the utilization of the
borrowing base. Borrowings under the Senior Credit Agreement are secured by
first lien and security interest on the real and personal property of Isramco
Resources, one of our subsidiaries.
The
Senior Credit Agreement contains customary financial and other covenants,
including minimum working capital levels of not less than 1.0 to 1.0, leverage
ratio of not greater than 3.5 to 1.0 and minimum coverage of interest of not
less than 2.5 to 1.0. In addition, the Company is subject to covenants limiting
dividends and other restricted payments, transactions with affiliates, changes
of control, asset sales, and liens on properties. At December 31, 2008, the
Company was in compliance with all of its debt covenants under the Senior Credit
Agreement.
We
utilize derivative contracts to hedge against the variability in cash flows
associated with the forecasted sale of our anticipated future oil and natural
gas production. We generally hedge a substantial, but varying, portion of our
anticipated oil and natural gas production for the next 39 months. We do not use
derivative instruments for trading purposes. We have elected not to apply hedge
accounting to our derivative contracts, which would potentially allow us to not
record the change in fair value of our derivative contracts in the consolidated
statements of operations. We carry our derivatives at fair value on our
consolidated balance sheets, with the changes in the fair value included in our
consolidated statements of operations in the period in which the change occurs.
Our results of operations would potentially have been significantly different
had we elected and qualified for hedge accounting on our derivative
contracts.
As of
December 31, 2008 we had swap contracts for volume of 771,724 barrels of
crude oil during 39 months, commencing January 2009, and swap contracts for
volume of 4,779,618 MMBTU of natural gas during 39 months commencing January
2009.
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 of our Scotia debt (as defined in Note 8, “Long-term
Debt”) to a fixed rate obligation, thereby reducing the exposure to market rate
fluctuations. We have elected to designate these positions for hedge accounting
and therefore the unrealized gains and losses are recorded in accumulated other
comprehensive loss. The Company measures hedge effectiveness by assessing the
changes in the fair value or expected future cash flows of the hedged
item.
Our open
interest rate positions, as described above, are as follows:
National
amount (in thousands)
Start
Date
Maturity
Date
Weighted-Average
Interest
Rate
32,000
April
2009
February
2011
3.63%
6,000
April
2009
February
2011
2.90%
Competitive
Conditions in the Business
The oil
and natural gas industry is highly competitive and we compete with a substantial
number of other companies that have greater financial and other
resources. Many of these companies explore for, produce and market oil and
natural gas, as well as carry on refining operations and market the resultant
products on a worldwide basis. The primary areas in which we encounter
substantial competition are in locating and acquiring attractive producing oil
and natural gas properties, obtaining purchasers and transporters of the oil and
natural gas we produce and hiring and retaining key employees. Furthermore,
competitive conditions may be substantially affected by various forms of energy
legislation and/or regulation considered from time to time by the government of
the United States. It is not possible to predict the nature of any such
legislation or regulation which may ultimately be adopted or its effects upon
our future operations. Such laws and regulations may substantially increase
the costs of exploring for, developing or producing oil and natural gas and may
prevent or delay the commencement or continuation of a given
operation.
Through
our wholly-owned subsidiary Jay Management Company, LLC ("Jay Management"), we
operate a substantial portion of our oil and natural gas properties. As the
operator of a property, the Company makes full payment of the costs associated
with each property and seeks reimbursement from the other working interest
owners in the property for their share of those costs. Isramco’s joint interest
partners consist primarily of independent oil and natural gas producers. If the
oil and natural gas exploration and production industry in general were
adversely affected, the ability of the Company’s joint interest partners to
reimburse the Company could be adversely affected.
The
purchasers of the Company’s oil and natural gas production consist primarily of
independent marketers, major oil and natural gas companies and gas pipeline
companies. The Company has not experienced any significant losses from
uncollectible accounts. The Company does not believe the loss of any one of its
purchasers would materially affect the Company’s ability to sell the oil and
natural gas it produces. The Company believes other purchasers are
available in the Company’s areas of operations.
Seasonality
of Business
Weather
conditions affect the demand for, and prices of, natural gas and can disrupt our
overall business plans. Demand for natural gas is typically higher in the
fourth and first quarters resulting in higher natural gas prices. Due to
these seasonal fluctuations, results of operations for individual quarterly
periods may not be indicative of the results that may be realized on an annual
basis.
Operational
Risks
Oil and
natural gas exploration and development involves a high degree of risk that even
a combination of experience, knowledge and careful evaluation may not be able to
overcome. There is no assurance that we will discover or acquire additional
oil and natural gas in commercial quantities. Oil and natural gas
operations also involve the risk that well fires, blowouts, equipment failure,
human error and other circumstances may cause accidental leakage of toxic or
hazardous materials, such as petroleum liquids or drilling fluids, into the
environment, or cause significant injury to persons or property. Such
hazards may also cause damage to or destruction of wells, producing formations,
production facilities and pipeline or other processing facilities. In such
event, substantial liabilities to third parties or governmental entities may be
incurred, the satisfaction of which could substantially reduce available cash
and possibly result in loss of oil and natural gas
properties.
We carry
insurance against such hazards. However, as is common in the oil and
natural gas industry, we will not insure fully against all risks associated with
our business, either because such insurance is not available or because we
believe the premium costs are prohibitive. A loss not fully covered by
insurance could have a materially adverse effect on our financial position and
results of operations. For further discussion on risks, see Item 1A.
Risk Factors.
Regulations
Domestic
exploration for and the production, sale and transportation of oil and natural
gas are extensively regulated at the federal, state and local
levels. Legislation affecting the oil and natural gas industry is under
constant review for amendment or expansion, frequently increasing the regulatory
burden. Numerous departments and agencies, both federal and state, are
authorized by statute to issue, and have issued, extensive rules and regulations
applicable to the oil and natural gas industry. Compliance with these
regulations is costly. In addition, there are substantial penalties
for failure to comply. To add to the difficulty in compliance, the
interpretation and enforcement of these regulations is not always constant or
uniform.
State
regulatory authorities have established rules and regulations requiring permits
for drilling operations, drilling bonds and reporting requirements applicable to
exploration and production operations. All states in which we operate also
have statutes and regulations concerning conservation matters, including the
conditions and requirements applicable to the unitization or pooling of oil and
natural gas properties, establishment of maximum rates of production from oil
and natural gas wells and the number of wells which may be drilled in a certain
area or formation. Production operations are also affected by changing tax
and other laws.
As a
member of the oil and gas industry, we are subject to extensive and evolving
environmental laws and regulations. These regulations are administered by
the United States Environmental Protection Agency and various other federal,
state, and local environmental, zoning, health and safety agencies, many of
which periodically examine our operations to monitor compliance with such laws
and regulations. Among other subjects, these regulations address the
release of waste materials into the environment and the transportation, storage
and disposal of petroleum products and generally are designed to protect the
environment and human, animal and plant health. Compliance with these
regulatory requirements affects our operations and costs.
In recent
years, environmental regulations have increasingly taken a cradle to grave
approach to waste management, regulating and creating liabilities for the waste
at its inception to final disposition. Our oil and natural gas exploration,
development and production operations are subject to numerous environmental
programs, including solid and hazardous waste management, water protection, air
emission controls and situs controls affecting wetlands, coastal operations and
antiquities. Further, each state in which we operate has its own unique laws and
regulations governing solid waste disposal, water and air pollution, along with
regulations governing the environmental effects of oil and natural gas
exploration, development and production operations.
Environmental
regulatory programs typically focus on permitting, construction and operations
of a facility. Many factors, including public perception, can materially
impact the ability to secure an environmental construction or operation
permit. Once a permit is received and a facility is operational,
enforcement measures can result in the imposition of significant civil penalties
for any regulatory violations regardless of intent or effort to
comply. Under appropriate circumstances, an administrative agency can issue
a cease and desist order requiring suspension of operations.
New
programs and changes in existing programs are anticipated, some of which include
naturally occurring radioactive materials (“NORM”), oil and natural gas
exploration and production waste management, underground injection of waste
material and emissions of certain gases, commonly referred to as “greenhouse
gases” including carbon dioxide and methane, which according to recent studies
may be contributing to the warming of the Earth’s atmosphere. In response to
these studies, President Obama has expressed support for, and it is anticipated
that the current session of Congress will consider, legislation to restrict or
regulate emissions of greenhouse gases. Many states, either individually or
through multi-state regional initiatives, have already begun implementing legal
measures to reduce emissions of greenhouse gases, primarily through the planned
development of emission inventories or regional greenhouse gas cap and trade
programs. Depending on the particular program, we could be required to purchase
and surrender allowances for greenhouse gas emissions resulting from our
operations. In this regard, the Environmental Protection Agency may
regulate greenhouse gas emissions even if Congress does not adopt new
legislation specifically addressing emissions of greenhouse gases. In July 2008,
EPA released an “Advance Notice of Proposed Rulemaking” regarding possible
future regulation of greenhouse gas emissions under the Clean Air Act. Although
the notice did not propose any specific, new regulatory requirements for
greenhouse gases, it indicates that federal regulation of greenhouse gas
emissions could occur in the near future even if Congress does not adopt new
legislation specifically addressing emissions of greenhouse gases.
We are
also subject to federal and state Hazard Communications and Community Right to
Know statutes and regulations. These regulations govern record keeping and
reporting of the use and release of hazardous substances. We believe we are
in compliance with these requirements in all material respects.
We may be
required in the future to make substantial expenditures to comply with
environmental laws and regulations. Other than to note that the regulation
of the oil and gas industry and the cost of compliance are likely to increase in
the future, the specific additional changes in operating procedures and
expenditures required to comply with future laws dealing with the protection of
the environment cannot be predicted.
Employees
As of
December 31, 2008, we had 16 full-time employees. We hire independent
contractors on an as needed basis. We have no collective bargaining
agreements with our employees. We believe that our employee relationships
are satisfactory.
In
addition to the other information contained in this Annual Report on Form 10-K,
investors should consider carefully the following risk factors, which may not be
the only risks we face, as our business and operations may also be subject to
risks that we do not yet know of, or that we currently believe are immaterial.
If any of the events or circumstances described below actually occurs, our
business, financial condition or results of operations could be materially and
adversely affected and the trading price of our common stock could
decline.
Crude
oil and natural gas prices are volatile and a substantial reduction in these
prices could adversely affect our results and the price of our common
stock.
Our
revenues, operating results and future rate of growth depend highly upon the
prices we receive for our crude oil and natural gas production. Historically,
the markets for crude oil and natural gas have been volatile and are likely to
continue to be volatile in the future. The markets and prices for crude oil and
natural gas depend on factors beyond our control. These factors include demand
for crude oil and natural gas, which fluctuates with changes in market and
economic conditions, and other factors, including:
·
worldwide
and domestic supplies of crude oil and natural gas;
·
actions
taken by foreign oil and gas producing
nations;
·
the
level of global crude oil and natural gas inventories;
·
the
price and level of foreign imports;
·
the
price and availability of alternative fuels;
·
the
availability of pipeline capacity and
infrastructure;
·
the
availability of crude oil transportation and refining
capacity;
·
weather
conditions;
·
electricity
dispatch;
·
domestic
and foreign governmental regulations and taxes;
and
Significant
declines in crude oil and natural gas prices for an extended period may have the
following effects on our business:
·
limiting
our financial condition, liquidity, ability to finance planned capital
expenditures and results of operations;
·
reducing
the amount of crude oil and natural gas that we can produce
economically;
·
causing
us to delay or postpone some of our capital projects;
·
reducing
our revenues, operating income and cash
flows;
·
reducing
the carrying value of our crude oil and natural gas properties;
or
·
limiting
our access to sources of capital, such as equity and long-term
debt.
Oil
and gas drilling is a speculative activity and risky.
We are
engaged in the business of oil and natural gas exploration, production and
operations and the development of productive oil and gas wells. Our growth will
be materially dependent upon the success of our future drilling program.
Drilling for oil and gas involves numerous risks, including the risk that no
commercially productive oil or natural gas reservoirs will be encountered. The
cost of drilling, completing and operating wells is substantial and uncertain,
and drilling operations may be curtailed, delayed or cancelled as a result of a
variety of factors beyond our control, including unexpected drilling conditions,
pressure or irregularities in formations, equipment failures or accidents,
adverse weather conditions, compliance with governmental requirements and
shortages or delays in the availability of drilling rigs or crews and the
delivery of equipment. Although we believe that the use of 3-D seismic data and
other advanced technology should increase the probability of success of our
wells and should reduce average finding costs through elimination of prospects
that might otherwise be drilled solely on the basis of 2-D seismic data and
other traditional methods, drilling remains an inexact and speculative activity.
In addition, the use of 3-D seismic data and such technologies requires greater
pre-drilling expenditures than traditional drilling strategies and we could
incur losses because of such expenditures. Our future drilling activities may
not be successful and, if unsuccessful, such failure could have an adverse
effect on our future results of operations and financial condition. Although we
may discuss drilling prospects that have been identified or budgeted for, we may
ultimately not lease or drill these prospects within the expected time frame, or
at all. We may identify prospects through a number of methods, some of which do
not include interpretation of 3-D or other seismic data. The drilling and
results for these prospects may be particularly uncertain. The final
determination with respect to the drilling of any scheduled or budgeted wells
will be dependent on a number of factors, including (i) the results of
exploration efforts and the acquisition, review and analysis of the seismic
data, (ii) the availability of sufficient capital resources and the other
participants for the drilling of the prospects, (iii) the approval of the
prospects by other participants after additional data has been compiled, (iv)
economic and industry conditions at the time of drilling, including prevailing
and anticipated prices for oil and natural gas and the availability of drilling
rigs and crews, (v) our financial resources and results (vi) the availability of
leases and permits on reasonable terms for the prospects and (vii) the payment
of royalties to lessors. There can be no assurance that these projects can be
successfully developed or that the wells discussed will, if drilled, encounter
reservoirs of commercially productive oil or natural gas. There are numerous
uncertainties in estimating quantities of proved reserves, including many
factors beyond our control.
Failure
to fund continued capital expenditures could adversely affect our
properties.
Our
acquisition, exploration, and development activities require substantial capital
expenditures. Historically, we have funded our capital expenditures through a
combination of cash flows from operations and loans from commercial banks and
related parties. Future cash flows are subject to a number of variables, such as
the level of production from existing wells, prices of crude oil and natural
gas, and our success in finding, developing and producing new reserves. If
revenues were to decrease as a result of lower crude oil and natural gas prices
or decreased production, and our access to capital were limited, we would have a
reduced ability to replace our reserves, resulting in a decrease in production
over time. If our cash flows from operations are not sufficient to meet our
obligations and fund our capital budget, we may not be able to access debt,
equity or other methods of financing on an economic basis to meet these
requirements, particularly in the current economic environment. If we are not
able to fund our capital expenditures, interests in some properties might be
reduced or forfeited as a result.
The
current recession could have a material adverse impact on our financial
position, results of operations and cash flows.
The oil
and gas industry is cyclical in nature and tends to reflect general economic
conditions. Economic analysts have stated that the U.S. and other
world economies are in a recession that could last well into 2009 and
beyond. The recession may lead to significant fluctuations in demand
and pricing for our crude oil and natural gas production, such as the decline in
commodity prices that occurred during 2008 and into 2009. Our
profitability will likely be significantly affected by decreased demand and
lower commodity prices. Due to lower commodity prices, we recorded
asset impairment charges during fourth quarter 2008. If commodity
prices continue to decline, there could be additional impairments of our
operating assets. Our future access to capital, as well as that of
our partners and contractors, could be limited due to tightening credit markets
that could inhibit development of our property interests. Some of our
longer-term projects require significant investment and may be delayed due to
capital constraints. See Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations.
Our
proved reserves are estimates. Any material inaccuracies in our reserve
estimates or assumptions underlying our reserve estimates could cause the
quantities and net present value of our reserves to be overstated or
understated.
There are
numerous uncertainties inherent in estimating quantities of proved reserves,
including many factors beyond our control that could cause the quantities and
net present value of our reserves to be overstated. The reserve information
included or incorporated by reference in this report represents estimates
prepared by our internal engineers. The procedures and methods for estimating
the reserves by our internal engineers were reviewed by an independent petroleum
engineering firm. Estimation of reserves is not an exact science. Estimates of
economically recoverable oil and natural gas reserves and of future net cash
flows necessarily depend upon a number of variable factors and assumptions, any
of which may cause these estimates to vary considerably from actual results,
such as:
·
historical
production from an area compared with production from similar producing
areas;
·
assumed
effects of regulation by governmental
agencies;
·
assumptions
concerning future oil and natural gas prices, future operating costs and
capital expenditures; and
·
estimates
of future severance and excise taxes, workover and remedial
costs.
Estimates
of reserves based on risk of recovery and estimates of expected future net cash
flows prepared or
audited
by different engineers, or by the same engineers at different times, may vary
substantially. Actual
production,
revenues and expenditures with respect to our reserves will likely vary from
estimates, and the
variance
may be material. The net present values referred to in this report should not be
construed as the current market value of the estimated oil and natural gas
reserves attributable to our properties. In accordance with SEC requirements,
the estimated discounted future net cash flows from proved reserves are
generally based on prices and costs as of the date of the estimate, while actual
future prices and costs may be materially higher or lower.
Unless
we replace our reserves, our reserves and production will decline, which would
adversely affect our financial condition, results of operations and cash
flows.
In
general, the volume of production from oil and natural gas properties declines
as reserves are depleted. Our reserves will decline as they are produced unless
we acquire properties with proved reserves or conduct successful development and
exploration activities. Thus, our future oil and natural gas production and,
therefore, our cash flow and income are highly dependent upon our level of
success in finding or acquiring additional reserves. However, we cannot assure
you that our future acquisition, development and exploration activities will
result in any specific amount of additional proved reserves or that we will be
able to drill productive wells at acceptable costs.
The
successful acquisition of producing properties requires an assessment of a
number of factors. These factors include recoverable reserves, future oil and
natural gas prices, operating costs and potential environmental and other
liabilities, title issues and other factors. Such assessments are inexact and
their accuracy is inherently uncertain. In connection with such assessments, we
perform a review of the subject properties that we believe is thorough. However,
there is no assurance that such a review will reveal all existing or potential
problems or allow us to fully assess the deficiencies and capabilities of such
properties. We cannot assure you that we will be able to acquire properties at
acceptable prices because the competition for producing oil and natural gas
properties is intense and many of our competitors have financial and other
resources that are substantially greater than those available to
us.
There
is a possibility that we will lose the leases to our oil and gas
properties.
Our oil
and gas revenues are generated through leases to the oil and gas properties.
These leases are conditioned on the performance of certain obligations,
primarily the obligation to produce oil and/or gas or engage in operations
designed to result in the production of oil and gas. If production
ceases and operations are not commenced within a specified time, the lease may
be lost. The loss of our leases may have a material impact on our
revenues.
In the
case of Israeli based properties, we have licenses that, subject to certain
conditions, may result in leases being granted. The leases are
subject to certain obligations and are renewable at the discretion of various
governmental authorities. As such, we may not be able to fulfill our
obligations under the leases, which may result in the modification, or
cancellation of such leases or such leases may not be renewed or may be renewed
on terms different from the current leases. The modification or
cancellation of our leases may have a material impact on our
revenues.
Our
business is highly competitive.
The oil
and natural gas industry is highly competitive in many respects, including
identification of attractive oil and natural gas properties for acquisition,
drilling and development, securing financing for such activities and obtaining
the necessary equipment and personnel to conduct such operations and activities.
In seeking suitable opportunities, we compete with a number of other companies,
including large oil and natural gas companies and other independent operators
with greater financial resources, larger numbers of personnel and facilities,
and with more expertise. There can be no assurance that we will be able to
compete effectively with these entities.
Our
business may be affected by oil and gas price volatility.
Our
revenues, profitability and future growth and the carrying value of our
properties depend substantially on prevailing oil and natural gas prices. Prices
also affect the amount of cash flow available for capital expenditures and our
ability to borrow and raise additional capital. The amount we will be able to
borrow under our Senior Credit Agreements will be subject to periodic
redetermination based in part on current oil and natural gas prices and on
changing expectations of future prices. Lower prices may also reduce the amount
of oil and natural gas that we can economically produce and have an adverse
effect on the value of our properties.
Historically,
the markets for oil and natural gas have been volatile, and they are likely to
continue to be volatile in the future. Among the factors that can cause
volatility are:
·
the
domestic and foreign supply of, and demand for oil and natural
gas;
·
the
ability of members of the Organization of Petroleum Exporting Countries
(OPEC) and other producing countries to agree upon and maintain oil prices
and production levels;
·
political
instability, armed conflict or terrorist attacks, whether or not in oil or
natural gas producing regions;
·
the
growth of consumer product demand in emerging markets, such as India and
China;
·
labor
unrest in oil and natural gas producing
regions;
·
weather
conditions, including hurricanes and other natural occurrences that affect
the supply and/or demand of oil and natural
gas;
·
the
price and availability of alternative and competing
fuels;
·
the
price and level of foreign imports of oil, natural gas and NGLs;
and
·
worldwide
economic conditions.
Our commercial lenders have liens on
substantially all of our oil and gas assets in the United States and could
foreclose in the event that we default under our credit facilities.
Under the
terms of our credit facilities with our commercial lenders, our lenders have a
first priority lien on substantially all of our oil and gas assets in the United
States. If we default under the credit facility, our lender would be
entitled to, among other things, foreclose on our assets in order to satisfy our
obligations under the credit facility.
Our
hedging activities may prevent us from benefiting fully from price increases and
may expose us to other risks.
In order
to manage our exposure to price risks in the marketing of our oil and natural
gas production, we have entered into oil and natural gas price hedging
arrangements with respect to a portion of our anticipated production and we may
enter into additional hedging transactions in the future. While intended to
reduce the effects of volatile oil and natural gas prices, such transactions may
limit our potential gains and increase our potential losses if oil and natural
gas prices were to rise substantially over the price established by the hedge.
In addition, such transactions may expose us to the risk of loss in certain
circumstances, including instances in which:
·
our
actual production is less than hedged
volumes;
·
there
is a widening of price differentials between delivery points for our
production and the delivery point assumed in the hedge arrangement;
or
·
the
counterparties to our hedging agreements fail to perform under the
contracts.
The
current economic crisis may have a negative impact on the liquidity of the
counterparties to our hedging arrangements, which increases the risk of those
counterparties failing to perform under those agreements. If those parties do
fail to perform, we will be exposed to the price risks we had sought to mitigate
and our operating results, financial position and cash flows may be materially
and adversely affected. As of December 31, 2008 approximately 78%, 80%, 71% and
12% of our forecasted oil production and natural gas liquids hedged for 2009,
2010, 2011 and 2012 respectively and approximately 81%, 82%, 39% and 12% of our
forecasted gas production hedged for the same time frame.
We
have no means to market our oil and gas production without the assistance of
third parties.
The
marketability of our production depends upon the proximity of our reserves to,
and the capacity of, facilities and third party services, including oil and
natural gas gathering systems, pipelines, trucking or terminal facilities, and
processing facilities. The unavailability or lack of capacity of such services
and facilities could impair or delay the production of new wells or the delay or
discontinuance of development plans for properties. A shut-in, delay or
discontinuance could adversely affect our financial condition. In addition,
regulation of oil and natural gas production transportation in the United States
or in other countries may affect its ability to produce and market our oil and
natural gas on a profitable basis.
The
unavailability or high cost of drilling rigs, equipment, supplies, personnel and
oil field services could adversely affect our ability to execute our exploration
and development plans on a timely basis and within our budget.
Our
industry is cyclical and, from time to time, there is a shortage of drilling
rigs, equipment, supplies and/or qualified personnel. During these periods, the
costs and delivery times of rigs, equipment and supplies are substantially
greater. In addition, the demand for, and wage rates of, qualified drilling rig
crews rise as the number of active rigs in service increases. Increasing levels
of exploration and production in response to strong prices of oil and natural
gas may increase the demand for oilfield services, and the costs of these
services may increase, while the quality of these services may
suffer.
Our
oil and natural gas activities are subject to various risks that are beyond our
control.
Our
operations are subject to many risks and hazards incident to exploring and
drilling for, producing, transporting, marketing and selling oil and natural
gas. Although we may take precautionary measures, many of these risks and
hazards are beyond our control and unavoidable under the circumstances. Many of
these risks or hazards could materially and adversely affect our revenues and
expenses, the ability of certain of our wells to produce oil and natural gas in
commercial quantities, the rate of production and the economics of the
development of, and our investment in the prospects in which we have or will
acquire an interest. Any of these risks and hazards could materially and
adversely affect our financial condition, results of operations and cash flows.
Such risks and hazards include:
·
human
error, accidents, labor force and other factors beyond our control that
may cause personal injuries or death to persons and destruction or damage
to equipment and facilities;
·
blowouts,
fires, hurricanes, pollution and equipment failures that may result in
damage to or destruction of wells, producing formations, production
facilities and equipment;
·
unavailability
of materials and equipment;
·
engineering
and construction delays;
·
unanticipated
transportation costs and delays;
·
unfavorable
weather conditions;
·
hazards
resulting from unusual or unexpected geological or environmental
conditions;
·
environmental
regulations and requirements;
·
accidental
leakage of toxic or hazardous materials, such as petroleum liquids or
drilling fluids, into the
environment;
·
changes
in laws and regulations, including laws and regulations applicable to oil
and natural gas activities or markets for the oil and natural gas
produced;
·
fluctuations
in supply and demand for oil and natural gas causing variations of the
prices we receive for our oil and natural gas production;
and
·
the
availability of alternative fuels and the price at which they become
available.
We
do not insure against all potential losses and could be materially and adversely
affected by unexpected liabilities.
The
exploration for, and production of, natural gas and crude oil can be hazardous,
involving natural disasters and other unforeseen occurrences such as blowouts,
fires and loss of well control, which can damage or destroy wells or production
facilities, injure or kill people, and damage property and the environment.
Moreover, our onshore operations are subject to customary perils, including
hurricanes and other adverse weather conditions. We maintain insurance against
many, but not all, potential losses or liabilities arising from our operations
in accordance with what we believe are customary industry practices and in
amounts and at costs that we believe to be prudent and commercially practicable.
The occurrence of any of these events and any costs or liabilities incurred as a
result of such events would reduce the funds available to us for our
exploration, development and production activities and could, in turn, have a
material adverse effect on our business, financial condition and results of
operations.
If
we are unable to satisfy the requirements of Section 404 of the Sarbanes-Oxley
Act, or our internal control over financial reporting is not effective, the
reliability of our financial statements may be questioned and our share price
may suffer.
Section
404 of the Sarbanes-Oxley Act requires any company subject to the reporting
requirements of the U.S. securities laws to do a comprehensive evaluation of its
internal control over financial reporting. To comply with this statute, we are
required to document and test our internal controls over financial reporting and
our management is required to issue a report concerning our internal controls
over financial reporting in this Annual Report on Form 10-K for the
effectiveness of our fiscal year ended December 31, 2008. Our independent
auditors will be required to issue an opinion on the effectiveness of our
internal controls over financial reporting for our annual report on Form 10-K
for our fiscal year ending December 31, 2009. The rules governing the standards
that must be met for management to assess our internal controls over financial
reporting are complex and require significant documentation, testing and
possible remediation to meet the detailed standards under the
rules. We have discovered certain deficiencies in the design and/or
operation of our internal controls that could adversely affect our ability to
record, process, summarize and report financial data. We have invested and will
continue to invest significant resources in this process. We are
uncertain as to what impact this conclusion that deficiencies exist in our
internal controls over financial reporting would have on the trading price of
our common stock.
Governmental
and environmental regulations could adversely affect our business.
Our
business is subject to federal, state and local laws and regulations on
taxation, the exploration for and development, production and marketing of oil
and natural gas and safety matters. Many laws and regulations require drilling
permits and govern the spacing of wells, rates of production, prevention of
waste, unitization and pooling of properties and other matters. These laws and
regulations have increased the costs of planning, designing, drilling,
installing, operating and abandoning our oil and natural gas wells and other
facilities. In addition, these laws and regulations, and any others that are
passed by the jurisdictions where we have production, could limit the total
number of wells drilled or the allowable production from successful wells, which
could limit our revenues.
Our
operations are also subject to complex environmental laws and regulations
adopted by the various jurisdictions in which we have or expect to have oil and
natural gas operations. We could incur liability to governments or third parties
for any unlawful discharge of oil, natural gas or other pollutants into the air,
soil or water, including responsibility for remedial costs. We could potentially
discharge these materials into the environment in any of the following
ways:
·
from
a well or drilling equipment at a drill
site;
·
from
gathering systems, pipelines, transportation facilities and storage
tanks;
·
damage
to oil and natural gas wells resulting from accidents during normal
operations; and
·
blowouts,
hurricanes and explosions.
Assets
we acquire may prove to be worth less than we paid because of uncertainties in
evaluating recoverable reserves and potential liabilities.
Our
recent growth is due significantly to acquisitions of producing properties and
underdeveloped leaseholds. We expect acquisitions may also contribute to our
future growth. Successful acquisitions require an assessment of a number of
factors, including estimates of recoverable reserves, exploration potential,
future oil and natural gas prices, operating and capital costs and potential
environmental and other liabilities. Such assessments are inexact and their
accuracy is inherently uncertain. In connection with our assessments, we perform
a review of the acquired properties which we believe is generally consistent
with industry practices. However, such a review will not reveal all existing or
potential problems. In addition, our review may not permit us to become
sufficiently familiar with the properties to fully assess their deficiencies and
capabilities. We do not inspect every well. Even when we inspect a well, we do
not always discover structural, subsurface and environmental problems that may
exist or arise in the future. We are generally not entitled to contractual
indemnification for preclosing liabilities, including environmental liabilities.
Normally, we acquire interests in properties on an “as is” basis with limited
remedies for breaches of representations and warranties. Because of these
factors, we may not be able to acquire oil and natural gas properties that
contain economically recoverable reserves or be able to complete such
acquisitions on acceptable terms.
Title
to the properties in which we have an interest may be impaired by title
defects.
We
generally conduct due diligence to review title on significant properties that
we drill or acquire. However, there is no assurance that we will not suffer a
monetary loss from title defects or title failure. Additionally, undeveloped
acreage has greater risk of title defects than developed acreage. Generally,
under the terms of the operating agreements affecting our properties, any
monetary loss is due to title defects is to be borne by all parties to any such
agreement in proportion to their interests in such property. If there are any
title defects or defects in assignment of leasehold rights in properties in
which we hold an interest, we will suffer a financial loss.
We
depend on the skill, ability and decisions of third party operators to a
significant extent.
The
success of the drilling, development and production of the oil and natural gas
properties in which we have or expect to have a non-operating working interest
is substantially dependent upon the decisions of such third-party operators and
their diligence to comply with various laws, rules and regulations affecting
such properties. The failure of any third-party operator to make decisions,
perform their services, discharge their obligations, deal with regulatory
agencies, and comply with laws, rules and regulations, including environmental
laws and regulations in a proper manner with respect to properties in which we
have an interest could result in material adverse consequences to our interest
in such properties, including substantial penalties and compliance costs. Such
adverse consequences could result in substantial liabilities to us or reduce the
value of our properties, which could negatively affect our results of
operations.
We
depend substantially on the continued presence of key personnel for critical
management decisions and industry contacts.
Our
success depends upon the continued contributions of our executive officers and
key employees, particularly with respect to providing the critical management
decisions and contacts necessary to manage and maintain growth within a highly
competitive industry. Competition for qualified personnel can be intense,
particularly in the oil and natural gas industry, and there are a limited number
of people with the requisite knowledge and experience. Under these conditions,
we could be unable to attract and retain these personnel. The loss of the
services of any of our executive officers or other key employees for any reason
could have a material adverse effect on our business, operating results,
financial condition and cash flows.
Our
operations in Israel may be adversely affected by economic and political
developments.
We have
interests in oil and gas leases and in oil and gas licenses in the waters off
Israel. These interests may be adversely affected by political and
economic developments, including the following:
·
war,
terrorist acts and civil
disturbances,
·
changes
in taxation policies,
·
laws
and policies of the US and Israel affecting foreign investment, taxation,
trade and business conduct,
·
foreign
exchange restrictions,
·
international
monetary fluctuations and changes in the value of the US dollar, such as
the decline of the US dollar and
·
other
hazards arising out of Israeli governmental sovereignty over areas in
which we own oil and gas interests.
Rapid
growth may place significant demands and resources.
We
experienced rapid growth in operations occasioned by the purchase of
approximately 650 producing oil and gas wells in March 2007 from Five States
Energy Company, LLC and approximately 590 producing oil and gas wells from GFB
and Trans Republic in March 2008. We expect that significant
expansion of our operations will continue. The rapid growth has placed, and the
anticipated future growth will continue to place, a significant demand on our
managerial, operational and financial resources due to:
·
the
need to manage relationships with various strategic partners and other
third parties;
·
difficulties
in hiring and retaining skilled personnel necessary to support our
business;
·
the
need to merge the operations of the acquired properties into our existing
operations, accounting and management
systems;
·
the
need to train and manage a growing employee base;
and
·
pressures
for the continued development of our financial and information management
systems.
If we
have not made adequate allowances for the costs and risks associated with our
expansion or if its systems, procedures or controls are not adequate to support
our operations, our business could be adversely impacted.
Members
of Isramco’s management team own a significant amount of common stock, giving
them influence or control in corporate transactions and other matters, and the
interests of these individuals could differ from those other
shareholders.
Members of our management
team beneficially own approximately 51.3% of our outstanding shares of common
stock as of March 20, 2009. As a result, these shareholders are in a position to
significantly influence or control the outcome of matters requiring a
shareholder vote, including the election of directors, the adoption of an
amendment to our articles of incorporation or bylaws and the approval of mergers
and other significant corporate transactions.
Our
stock price is volatile and could continue to be volatile and has limited
liquidity; Accordingly, investors may not be able to sell any significant number
of shares of our stock at prevailing market prices.
Investor
interest in our common stock may not lead to the development of an active or
liquid trading market. The market price of our common stock has fluctuated in
the past and is likely to continue to be volatile and subject to wide
fluctuations. In addition, the stock market has experienced extreme price and
volume fluctuations. The stock prices and trading volumes for our stock has
fluctuated widely and the average daily trading volume of our stock
continues to be limited and may continue for reasons that may be
unrelated to business or results of operations. General economic, market and
political conditions could also materially and adversely affect the market price
of our common stock and investors may be unable to resell their shares of common
stock at or above their purchase price. As a result of the limited
trading in our stock, it may be difficult for investors to sell their shares in
the public market at any given time at prevailing prices.
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.
From time
to time, we are involved in disputes and other legal actions arising in the
ordinary course of business. In management's opinion, none of these other
disputes and legal actions is expected to have a material impact on our
consolidated financial position or results of operations.
ITEM 5. Market
for registrant’s common equity and related stockholder
matters
Approximately
342 stockholders of record as of December 31, 2008 held our common
stock. In many instances, a registered stockholder is a broker or other
entity holding shares in street name for one or more customers who beneficially
own the shares.
Our
common stock is listed on the Nasdaq Capital Market under the symbol "ISRL". The
following table sets forth for the periods indicated, the reported high and low
closing prices for our common stock.
High
Low
2008
First
Quarter
$
49.45
$
30.00
Second
Quarter
50.00
31.06
Third
Quarter
60.00
36.62
Fourth
Quarter
46.47
19.20
2007
First
Quarter
$
33.16
$
32.66
Second
Quarter
42.91
42.73
Third
Quarter
45.89
37.27
Fourth
Quarter
47.47
47.37
We have
never paid cash dividends on our common stock. We intend to retain earnings for
use in the operation and expansion of our business and therefore do not
anticipate declaring cash dividends on our common stock in the foreseeable
future. Any future determination to pay dividends on common stock will be at the
discretion of the board of directors and will be dependent upon then existing
conditions, including other factors, as the board of directors deems
relevant.
ITEM 7. Management discussion and analysis of financial condition and
results of operations
THE
FOLLOWING COMMENTARY SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED
FINANCIAL STATEMENTS AND RELATED NOTES CONTAINED ELSEWHERE IN THIS FORM 10-K.
THE DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS THAT INVOLVE RISKS AND
UNCERTAINTIES. THESE STATEMENTS RELATE TO FUTURE EVENTS OR OUR FUTURE FINANCIAL
PERFORMANCE. IN SOME CASES, YOU CAN IDENTIFY THESE FORWARD-LOOKING STATEMENTS BY
TERMINOLOGY SUCH AS "MAY,""WILL,""SHOULD,""EXPECT,""PLAN,""ANTICIPATE,""BELIEVE,""ESTIMATE,""PREDICT,""POTENTIAL,""INTEND," OR "CONTINUE," AND
SIMILAR EXPRESSIONS. THESE STATEMENTS ARE ONLY PREDICTIONS. OUR ACTUAL RESULTS
MAY DIFFER MATERIALLY FROM THOSE ANTICIPATED IN THESE FORWARD-LOOKING STATEMENTS AS A RESULT OF A VARIETY
OF FACTORS, INCLUDING, BUT NOT LIMITED TO, THOSE SET FORTH UNDER "RISK FACTORS"
AND ELSEWHERE IN THIS FORM 10-K.
Overview
We are an
independent oil and natural gas company engaged in the exploration, development
and production of oil and natural gas properties located onshore in the United
States. Our properties are primarily located in Texas, New Mexico and Oklahoma.
We act as an operator of certain of these properties. Historically, we have
grown through acquisitions, with a focus on properties within our core operating
areas that we believe have significant development and exploration opportunities
and where we can apply our technical experience and economies of scale to
increase production and proved reserves while lowering lease operating
costs.
Our
financial results depend upon many factors, but are largely driven by the volume
of our oil and natural gas production and the price that we receive for that
production. Our production volumes will decline as reserves are depleted unless
we expend capital in successful development and exploration activities or
acquire additional properties with existing production. The amount we realize
for our production depends predominantly upon commodity prices, which are
affected by changes in market demand and supply, as impacted by overall economic
activity, weather, pipeline capacity constraints, inventory storage levels,
basis differentials and other factors, and secondarily upon our commodity price
hedging activities. Accordingly, finding and developing oil and natural gas
reserves at economical costs is critical to our long-term success. Our future
drilling plans are subject to change based upon various factors, some of which
are beyond our control, including drilling results, oil and natural gas prices,
the availability and cost of capital, drilling and production costs,
availability of drilling services and equipment, gathering system and pipeline
transportation constraints and regulatory approvals. To the extent these factors
lead to reductions in our drilling plans and associated capital budgets in
future periods, our financial position, cash flows and operating results could
be adversely impacted.
At
December 31, 2008, our estimated total proved oil, natural gas reserves and
natural gas liquids, as prepared by our independent reserve engineering firm,
Cawley, Gillespie & Associates, Inc., were approximately 8,213 thousand
barrels of oil equivalent (MBOE), consisting of 2,679 thousand barrels
(Bbls) of oil, and 25,696 million cubic feet (MMcf) of natural gas and 1,252
thousand barrels (Bbls) natural gas liquids. Approximately 97.6% of our proved
reserves were classified as proved developed.
The
discussion and analysis of our financial condition and results of operations are
based upon our consolidated financial statements, which have been prepared in
accordance with accounting principles generally accepted in the United States.
The preparation of our consolidated financial statements requires us to make
estimates and assumptions that affect our reported results of operations and the
amount of reported assets, liabilities and proved oil and natural gas reserves.
Some accounting policies involve judgments and uncertainties to such an extent
that there is reasonable likelihood that materially different amounts could have
been reported under different conditions, or if different assumptions had been
used. Actual results may differ from the estimates and assumptions used in the
preparation of our consolidated financial statements. Described below are the
most significant policies we apply in preparing our consolidated financial
statements, some of which are subject to alternative treatments under accounting
principles generally accepted in the United States. We also describe the most
significant estimates and assumptions we make in applying these
policies.
Oil
and Natural Gas Activities
Accounting
for oil and natural gas activities is subject to unique rules. Two generally
accepted methods of accounting for oil and natural gas activities are
available - successful efforts and full cost. The most significant
differences between these two methods are the treatment of unsuccessful
exploration costs and the manner in which the carrying value of oil and natural
gas properties are amortized and evaluated for impairment. The successful
efforts method requires unsuccessful exploration costs to be expensed as they
are incurred upon a determination that the well is uneconomical while the full
cost method provides for the capitalization of these costs. Both methods
generally provide for the periodic amortization of capitalized costs based on
proved reserve quantities. Impairment of oil and natural gas properties under
the successful efforts method is based on an evaluation of the carrying value of
individual oil and natural gas properties against their estimated fair value,
while impairment under the full cost method requires an evaluation of the
carrying value of oil and natural gas properties included in a cost center
against the net present value of future cash flows from the related proved
reserves, using period-end prices and costs and a 10% discount rate. We account
for our natural gas and crude oil exploration and production activities under
the successful efforts method of accounting.
Proved
Oil and Natural Gas Reserves
Estimates
of our proved reserves included in this report are prepared in accordance with
accounting principles generally accepted in the United States and SEC
guidelines. Our engineering estimates of proved oil and natural gas reserves
directly impact financial accounting estimates, including depreciation,
depletion and amortization and impairment expense. Proved oil and natural gas
reserves are the estimated quantities of oil and natural gas reserves that
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under period-end economic and
operating conditions. The process of estimating quantities of proved reserves is
very complex, requiring significant subjective decisions in the evaluation of
all geological, engineering and economic data for each reservoir. The accuracy
of a reserve estimate is a function of: (i) the quality and quantity of
available data; (ii) the interpretation of that data; (iii) the
accuracy of various mandated economic assumptions and (iv) the judgment of
the persons preparing the estimate. The data for a given reservoir may change
substantially over time as a result of numerous factors, including additional
development activity, evolving production history and continual reassessment of
the viability of production under varying economic conditions. Changes in oil
and natural gas prices, operating costs and expected performance from a given
reservoir also will result in revisions to the amount of our estimated proved
reserves.
Depreciation,
Depletion and Amortization
Our rate
of recording depreciation, depletion and amortization expense (DD&A) is
primarily dependent upon our estimate of proved reserves, which is utilized in
our unit-of-production method calculation. If the estimates of proved reserves
were to be reduced, the rate at which we record DD&A expense would increase,
reducing net income. Such a reduction in reserves may result from lower market
prices, which may make it non-economic to drill for and produce higher cost
reserves.
Impairment
We review
our property and equipment in accordance with Statements of Financial Accounting
Standards (SFAS) No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets (SFAS 144). SFAS 144 requires us to
evaluate property and equipment as an event occurs or circumstances change that
would more likely than not reduce the fair value of the property and equipment
below the carrying amount. If the carrying amount of property and equipment is
not recoverable from its undiscounted cash flows, then we would recognize an
impairment loss for the difference between the carrying amount and the current
fair value. Further, we evaluate the remaining useful lives of property and
equipment at each reporting period to determine whether events and circumstances
warrant a revision to the remaining depreciation periods.
Asset
Retirement Obligations
We have
significant obligations to remove tangible equipment and facilities associated
with our oil and gas wells and to restore land at the end of oil and gas
production operations. Our removal and restoration obligations are most often
associated with plugging and abandoning wells. Estimating the future restoration
and removal costs is difficult and requires us to make estimates and judgments
because most of the removal obligations we have will be take effect in the
future. Additionally, these operations are subject to private contracts and
government regulations that often have vague descriptions of what is required.
Asset removal technologies and costs are constantly changing, as are regulatory,
political, environmental, safety and public relations
considerations. Inherent in the present value calculations are
numerous assumptions and judgments including the ultimate removal cost amounts,
inflation factors, credit adjusted discount rates, timing of obligations and
changes in the legal, regulatory, environmental and political
environments.
Accounting
for Derivative Instruments and Hedging Activities
We
utilize derivative contracts to hedge against the variability in cash flows
associated with the forecasted sale of our anticipated future oil and natural
gas production. We generally hedge a substantial, but varying, portion of our
anticipated oil and natural gas production for the next 39 months. We do not use
derivative instruments for trading purposes. We have elected not to apply hedge
accounting to our derivative contracts, which would potentially allow us to not
record the change in fair value of our derivative contracts in the statement of
operations. We carry our derivatives at fair value on our consolidated balance
sheets, with the changes in the fair value included in our statements of
operations in the period in which the change occurs. Our results of operations
would potentially have been significantly different had we elected and qualified
for hedge accounting on our derivative contracts.
The
Company follows SFAS No. 109, Accounting for Income Taxes,
which requires recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been included in the
consolidated financial statements or tax returns. Under this method, deferred
tax assets and liabilities are computed using the liability method based on the
differences between the financial statement and tax basis of assets and
liabilities using enacted tax rates in effect for the year in which the
differences are expected to reverse.
A
valuation allowance is provided, if necessary, to reserve the amount of net
operating loss and net deferred tax assets which the Company may not be able to
use because of the expiration of maximum carryover periods allowed under
applicable tax codes.
Liquidity
and Capital Resources
Our
primary sources of cash during 2008 were cash flows from operating activities,
availability under our Senior Credit Agreement, and loans from related
parties. The capital markets, as they relate to us, have been adversely
impacted by the current financial crisis, concerns about overall deflation and
its effect on commodity prices, the possibility of a deepening world recession
that may extend for a long period into the future, a lack of liquidity in the
banking system and the unavailability and cost of credit. Continued
volatility in the capital markets could adversely impact our ability to replace
our reserves, and eventually, our production levels.
Our
future capital resources and liquidity may depend, in part, on our success in
developing the leasehold interests that we acquired. Cash is required to fund
capital expenditures necessary to offset inherent declines in production and
proven reserves, which is typical in the capital-intensive oil and gas
industry. Future success in growing reserves and production will be highly
dependent on capital resources available and the success of finding and
acquiring additional reserves. We expect to fund our future capital requirements
through internally generated cash flows and borrowings under our Senior Credit
Agreements. Long-term cash flows are subject to a number of variables including
the level of production and prices, our commodity price hedging activities as
well as various economic conditions that have historically affected the oil and
natural gas industry. Oil and natural gas prices have continued to fall
after December 31, 2008. If these prices hold for a prolonged period of
time or continue to fall, our ability to fund capital expenditures, reduce debt,
meet financial obligations and become profitable may be materially
impacted.
Current
maturities of long-term debt, short-term debt and bank
overdraft
22,544
3,706
347
Total
debt
146,098
64,287
17,347
Stockholders’
equity
25,034
25,471
34,744
Debt
to capital ratio
85
%
72
%
33
%
At
year-end 2008, our total debt was $146,098 thousand compared to total debt of
$64,287 thousand at year-end 2007 and $17,347 thousand at year-end 2006. As of
December 31, 2008, current debt included $21,000 thousand as current maturities
of the Revolving Credit Facility. However, the Company is not obligated to repay
this facility prior to the due date, except for such payments as may be required
under the Credit Agreement in the event of a redetermination and reduction of
the borrowing base. As of December 31, 2008, $19,750 thousand of the $21,000
thousand was due to the decision of management to continue reducing the debt
below the borrowing base. As of December 31, 2007, current debt
included $3,000 thousand as current maturities, which again was due to
management’s decision to continue payments to reduce debt below the borrowing
base.
Cash
Flow
Our
primary sources of cash in 2008, 2007 and 2006 were from operating and financing
activities. Proceeds from loans obtained from related parties, proceeds from
Senior Credit Agreement and cash received from operations were offset by
repayments of our Senior Credit Agreement, repayments of loans from related
parties and cash used in investing activities to fund acquisition activities.
Operating cash flow fluctuations were substantially driven by changes in
commodity prices and changes in our production volumes. Working capital was
substantially influenced by these variables. Fluctuation in commodity prices and
our overall cash flow may result in an increase or decrease in our future
capital expenditures or influence our ability to reduce our long-term loans.
Prices for oil and natural gas have historically been subject to seasonal
influences characterized by peak demand and higher prices in the winter heating
season; however, the impact of other risks and uncertainties have influenced
prices throughout recent years. See “Results of Continuing Operations” below for
a review of the impact of prices and volumes on sales.
Operating Activities, Net cash
flows provided by (used
in) operating activities were $17,001 thousands, ($662) thousands and $7,233
thousands for the years ended December 31, 2008, 2007 and 2006,
respectively. Key drivers of net operating cash flows are commodity prices,
increasing of production volumes primarily due to the two acquisitions we had
during 2007 and 2008 and operating costs.
Because
of significant declines in oil and natural gas prices, net cash flows provided
by operating activities declined significantly in the fourth quarter 2008
compared to the third quarter.
Investing Activities, The
primary component of cash used in investing activities is capital spending for
the acquisitions in 2008 and 2007. Cash used in investing activities was $97,753
thousand, $63,656 thousand and $24,041 thousand for the years ended
December 31, 2008, 2007 and 2006, respectively.
In 2008,
we spent $98,673 thousand on acquisition of oil and gas properties and capital
expenditures. We participated in the drilling of 3 gross wells in 2008. We spent
an additional $369 thousand on other property and equipment during
2008.
In 2007,
we spent $86,056 thousands on acquisition of oil and gas properties and capital
expenditures. Our acquisitions were partially funded by the remaining restricted
cash that we had deposited in 2006. We participated in the drilling of 2 gross
wells in 2007. We spent an additional $67 thousand on other property and
equipment during 2007.
In 2006,
we spent $9,737 thousand on capital expenditures. We participated with XTO
Energy, Inc, the operator, in drilling of 16 gross wells in 2006, mainly to the
Barnett shale formation in Parker County, Texas.
Financing Activities, The primary component of
cash provided by financing activities is proceeds from long-term loans obtained
from related parties ($45,658) and Senior Credit
Agreements
($54,000) and offset by repayments of long-term loans and repayments of Senior
Credit Agreements ($16,800). Net cash flows provided by financing activities
were $82,681 thousands, $64,957 thousands and $16,181 thousands for the years
ended December 31, 2008, 2007 and 2006, respectively.
Weighted
average number of shares outstanding-basic and diluted
2,717,691
2,717,691
2,717,691
Operating
Results
Adjusted
EBITDAX (*)
$
53,277
$
5,303
$
8,389
Total
proved reserves (MBOE)
8,213
8,329
257
Annual
sales volumes (MBOE)
821
455.5
48
Average
cost per MBOE:
Production
(including transportation and taxes)
$
24.66
$
16.47
$
23.31
General
and administrative
$
3.31
$
6.37
$
41.85
Depletion
$
21.59
$
13.48
$
9.48
(*)Adjusted
EBITDAX (earnings before interest, taxes, depreciation and amortization) for a
description of Adjusted EBITDAX, which is not a Generally Accepted Accounting
Principles (GAAP) measure, and a reconciliation of Adjusted EBITDAX to income
from continuing operations before income taxes, which is presented in accordance
with GAAP.
Financial
Results
Income from continuing
operations our net income from continuing operations for 2008 totaled
$3,229 thousand, or $1.19 per share, compared to net loss from continuing
operations for 2007 of $(6,411) thousands, or $(2.36) per share. We had income
from continuing operations for 2006 of $6,569, or $2.42 per share. The increase
in income from continuing operations for 2008 compared to 2007 was primarily due
to GFB acquisition which result in an increase of natural gas, oil and natural
gas liquids sales, higher commodity prices and gain on derivative contracts,
partially offset by higher cost and expenses including impairment of oil and gas
properties, higher interest expenses and income tax. The decrease in the net
income in 2007 compared to 2006 is primarily attributable to an increase in net
loss on derivative contracts ,an impairment as results of the sale of the land
in Israel, increase of impairment of oil and gas assets due to low production of
gas wells drilled to the Barnett Shale, an increase in interest expenses and
compensation for legal settlement recorded in 2006, all of which partially
offset by increasing of oil and gas operating income due to Five States
acquisition, realized gain on sale of investment in High –Tech company and
income tax benefit.
Our sales
revenues for 2008 increased by 149% when compared to 2007 due to the GFB
acquisition which resulted in higher sales volumes of natural gas, oil and
natural gas liquids and due to higher oil, natural gas and natural gas liquids
prices. The increase in 2007 compared to 2006 was primarily due to Five States
acquisition and was additionally due to higher commodity prices.
Total
natural gas liquids sales revenues (thousands)
$
6,036
$
3,923
54
%
$
-
The
company’s natural gas sales volumes increased by 62%, crude oil sales volumes by
167% and natural gas liquids sales volumes by 44% in 2008 compared to 2007
primarily due to GFB acquisition. The company’s natural gas sales volumes
increased by 628%, crude oil sales volumes by 644% in 2007 compared to 2006
primarily due to Five States acquisition.
Our
average natural gas price for 2008 increased by 28% or $1.81 per Mcf when
compared to 2007 and increased by 0.5% or $0.03 when compared 2007 to 2006. Our
average crude oil price for 2008 increased by 37% or $26 per Bbl when compared
to 2007 and increased by 16% or $9.9 when compared 2007 to 2006. Our average
natural gas liquids price for 2008 increased by 7% or $2.6 per Bbl when compared
to 2007.
The
following table provides a summary of the effects of changes in volumes and
prices on Isramco’s sales revenues for the year ended December 31, 2008 compared
to 2007 and 2006.
In
thousands
Natural
Gas
Oil
Natural
gas liquids
2006
sales revenues
$
1,371
$
796
$
-
Changes
associated with sales volumes
8,611
5,125
3,923
Changes
in prices
48
953
-
2007
sales revenues
10,030
6,874
3,923
Changes
associated with sales volumes
6,184
11,467
1,737
Changes
in prices
4,533
6,708
376
2008
sales revenues
$
20,747
$
25,049
$
6,036
Operating
Expenses
Years
Ended December 31,
In
thousands except percentages
2008
2007
D vs.
2008
2006
D vs.
2007
Lease
operating expense, transportation and taxes
$
20,242
$
7,500
170
%
$
1,119
570
%
Depreciation,
depletion and amortization
17,723
6,139
189
455
1,249
Impairments
of oil and gas assets
22,093
3,203
590
668
379
Impairments
of other properties
-
928
-
-
-
Accretion
expense
847
219
287
71
208
Exploration
costs
-
292
-
125
134
Operator
expense
-
-
-
330
-
General
and administrative
2,714
2,902
(6
)
2,009
44
$
63,619
$
21,183
200
%
$
4,777
343
%
During
2008, our operating expenses increased by 200% when compared to 2007 due to the
following factors:
·
Lease
operating expense, transportation and taxes increased by 170%, or $12,742
thousand, in 2008 when compared to 2007 due to approximately $10,800
thousand in additional operating expenses, transportation and taxes
attributable to the properties acquired in the GFB acquisition. The
remaining increase is attributable to higher commodity prices that
affected the taxes paid during 2008 and to the fact that, in 2007, we
recorded only 10 months of operating expense, transportation and taxes
associated with the properties acquired in Five States acquisition,
compared to 12 months during 2008.
·
Depreciation,
Depletion &Amortization (DD&A) of the cost of proved oil and gas
properties is calculated using the unit-of-production method. Our DD&A
rate and expense are the composite of numerous individual field
calculations. There are several factors that can impact our composite
DD&A rate and expense, including but not limited to field production
profiles, drilling or acquisition of new wells, disposition of existing
wells, and reserve revisions (upward or downward) primarily
related to well performance and commodity prices, and impairments. Changes
to these factors may cause our composite DD&A rate and expense to
fluctuate from year to year. DD&A increased by 189%, or
$11,584 thousand, in 2008 when compared to 2007 primarily due to
approximately $8,520 thousand DD&A which was related to the oil and
gas properties acquired in GFB acquisition. The remaining increase is
attributed to lower commodity prices at year-end 2008 that impacted the
estimated total reserves, which are the basis for the depletion
calculation.
·
Impairments
of oil and gas assets of $22,093 thousand in 2008 were primarily a result
of lower commodity prices in general and low volume of oil and gas
produced in few of our North Texas fields and in the wells in which the
Company participated in the Barnett Shale formation in Parker County,
Texas, in particular. The impairments of $3,203 thousand in
2007 were primarily the result of the low volume of gas produced in the
wells that the Company participated on the Barnett Shale formation in
Parker County.
·
Impairment
of other properties in 2007 of $928 thousand was attributed to undeveloped
real estate located in Israel.
·
In
2007, we incurred $292 thousand in exploration costs mainly incurred for a
3D seismic survey covering the company’s leases in Wise
County.
·
General
and administrative expenses decreased by 6%, or $188 thousand, in 2008
when compared to 2007 primarily due to the closure of the Israeli branch
on December 31, 2007. This decrease was partially offset by increases in
compensation and benefit expenses associated with additional employees
required in connection with the GFB acquisition. The GFB acquisition also
increased the volume of the activities and, as a result, the indirect
expenses of those activities.
During
2007, our operating expenses increased by 343% when compared to 2006 due to the
following factors:
·
Lease
operating expense, transportation and taxes increased by 570%, or $6,381
thousand, in 2007 when compared to 2006 due to approximately $5,745
thousand in additional operating expenses, transportation and taxes
attributable to the properties acquired in the Five States acquisition.
The remaining increase is attributed to higher commodity prices that
affected the taxes paid during
2007.
·
Depreciation,
Depletion & Amortization (DD&A) of the cost of proved oil and gas
properties is calculated using the unit-of-production method. Our DD&A
rate and expense are the composite of numerous individual field
calculations. There are several factors that can impact our
composite DD&A rate and expense, including but not limited to field
production profiles, drilling or acquisition of new wells, disposition of
existing wells, and reserve revisions (upward or downward) primarily
related to well performance and commodity prices, and
impairments. Changes to one or more of these factors may cause
our composite DD&A rate and expense to fluctuate from year to
year. DD&A increased by 1,249%, or $5,684 thousand, in 2007 when
compared to 2006 primarily due to approximately $4,558 thousand DD&A
which was related to the oil and gas properties acquired in Five States
acquisition. The remaining increase is attributed to low volume of
gas produced in wells in which the Company participated in the Barnett
Shale formation in Parker County, which affected the estimated total
reserves, which in turn are the basis for the depletion
calculation.
·
The
impairments of $3,203 thousand in 2007 were primarily the result of the
low volume of gas produced in the wells that the Company participated on
the Barnett Shale formation in Parker
County.
·
Impairment
of other properties in 2007 of $928 thousands was attributed to
undeveloped real estate located in
Israel.
·
In
2007, we incurred $292 thousand in exploration costs mainly incurred for a
3D seismic survey covering the company’s leases in Wise County, compared
to $125 thousand in 2006, mainly incurred for geological and geophysical
consulting relating to the operation in United
States.
·
General
and administrative expenses increased by 44%, or $893 thousand, in 2007
when compared to 2006 primarily due to increases in compensation and
benefit expenses associated with additional employees required in
connection with the Five States acquisition. This acquisition also
increased the volume of the activities and, as a result, the indirect
expenses of those activities.
Interest
expense. Isramco’s interest expense for 2008 increased by 55%,
or $3,511 thousand, compared to 2007. This increase is primarily
attributable to interest on loans we obtained from banks and related parties for
funding the GFB acquisition. The increase was partially offset by the
lower average outstanding balance of loans which we obtained to fund the Five
States acquisition in 2007 and decreases in average LIBOR rates in
2008. Isramco’s interest expense for 2007 increased by $6,498
thousand compared to 2006. This increase was primarily due to the
loans we obtained from banks and related parties for funding the Five States
acquisition. For additional information, see Debt above.
Realized gain on sale of investment
and other. In April 2007, IsramTech, a wholly owned subsidiary
of the Company, sold part of its equity interests in High –Tech Company for
aggregate consideration of $1,700 thousand (net of commission). As a
result of this transaction, the Company recorded a one-time non-recurring net
gain of $1,621 thousand.
Net loss (gain) on derivative
contracts. We enter into derivative commodity instruments to economically
hedge our exposure to price fluctuations on our anticipated oil and natural gas
production. Consistent with the prior year, we have elected not to designate any
positions as cash flow hedges for accounting purposes. Accordingly, we recorded
the net change in the mark-to-market value of these derivative contracts in the
consolidated statement of operations.
At
December 31, 2008, we had a $23 million derivative asset, of which $12
million was classified as current. We recorded a net derivative gain of $24.7
million ($32.6 million unrealized gain partially offset by a $7.9 million loss
from net cash payments on settled contracts) for the year ended
December 31, 2008 compared to a net derivative loss of $8.6 million ($11.3
million unrealized loss and a $2.7 million net gain for cash received on settled
contracts) for the year ended December 31, 2007. This increase in our net
derivative gain is primarily attributable to the recent decrease in the forward
strip pricing used to value our derivatives and additional SWAP contracts we
entered in 2008.
At
December 31, 2007, we had a $9.4 million derivative liability, of which
$3.1 million was classified as current. We recorded a net derivative loss of
$8.6 million ($11.3 million unrealized loss and a $2.7 million net gain for cash
received on settled contracts) for the year ended December 31, 2007
compared to a derivative gain of $2.6 for the year ended December 31, 2006.
This decrease is due to the increase in commodity prices and additional SWAP
contracts we entered in 2007.
The
Company’s tax expense changed from a benefit of $5,192 thousand in 2007 to an
expense of $377 thousand in 2008. The overall increase is the result of
increased profitability from continuing operations due to the Company’s
acquisition of oil and gas properties in 2007 and 2008. The variance in the tax
rate from the statutory 34%, used in the US, is due mainly to the refund of 2007
taxes paid by the US branch in Israel, deferred state tax items (net of federal
benefit) and other return to accrual items on the US consolidated income tax
return.
Recently
Issued Accounting Pronouncements
We
discuss recently adopted and issued accounting standards in Item 8.
Consolidated Financial Statements and Supplementary Data–Note 1, “Summary of
Significant Accounting Policies.”
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The
information called for by this Item 8 is included following the "Index to
Financial Statements" contained in this Annual Report on Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
Disclosure
controls and procedures are controls and other procedures of a registrant
designed to ensure that information required to be disclosed by the registrant
in the reports that it files or submits under the Exchange Act is properly
recorded, processed, summarized, and reported, within the time periods specified
in the Securities and Exchange Commission's ("SEC") rules and forms. Disclosure
controls and procedures include processes to accumulate and evaluate relevant
information and communicate such information to a registrant's management,
including its Chief Executive Officer and Chief Financial Officer, as
appropriate, to allow for timely decisions regarding required
disclosures.
We
evaluated the effectiveness of the design and operation of our disclosure
controls and procedures as of December 31, 2007, as required by Rule 13a-15 of
the Exchange Act. As described below, under "Management's Report on Internal
Control Over Financial Reporting," material weaknesses were identified in our
internal control over financial reporting as of December 31,2007. The material weaknesses identified in the annual report on Form
10-K for the year ended December 31, 2007 began with the acquisition of the Five
States properties in March 2007, and related primarily to the shortage of
support and resources in our accounting department. Based on the evaluation
described above, our Chief Executive Officer and Chief Financial Officer
concluded that, as of December 31, 2007, our disclosure controls and procedures
were not effective to ensure (i) that information required to be disclosed by us
in the reports we file or submit under the Exchange Act is recorded, processed,
summarized, and reported, within the time periods specified in the SEC's rules
and forms, and (ii) information required to be disclosed by us in our reports
that we file or submit under the Exchange Act is accumulated and communicated to
our management, including our Chief Executive Officer and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure.
We again
evaluated the effectiveness of the design and operation of our disclosure
controls and procedures as of December 31, 2008, as required by Rule 13a-15 of
the Exchange Act. As described below, under "Management's Report on Internal
Control Over Financial Reporting," continuing material weaknesses were
identified in our internal control over financial reporting as of December 31,2008. As noted above, the material weaknesses identified in this
reporting began with the acquisition of the Five States properties in March
2007. These weaknesses have not been fully addressed, largely due to
the inability of the Company to attract and retain experienced, skilled
personnel, and were exacerbated by the acquisition of additional properties from
GFB and TransRepublic in March 2008. As in 2007, the material
weakness primarily related to the shortage of support and resources in our
accounting department. Based on the evaluation described above, our Chief
Executive Officer and Chief Financial Officer concluded that, as of December 31,2008, our disclosure controls and procedures were still not effective to ensure
(i) that information required to be disclosed by us in the reports we file or
submit under the Exchange Act is recorded, processed, summarized, and reported,
within the time periods specified in the SEC's rules and forms, and (ii)
information required to be disclosed by us in our reports that we file or submit
under the Exchange Act is accumulated and communicated to our management,
including our Chief Executive Officer and Chief Financial Officer, as
appropriate, to allow timely decisions regarding required
disclosure.
MANAGEMENT'S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING; CHANGES IN INTERNAL
CONTROLS OVER FINANCIAL REPORTING.
Management’s
Report on Internal Control Over Financial Reporting
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting. Our internal control over financial reporting
is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of our financial statements for
external reporting purposes in accordance with generally accepted accounting
principles.
Internal
control over financial reporting cannot provide absolute assurance of achieving
financial reporting objectives because of its inherent limitations. Internal
control over financial reporting is a process that involves human diligence and
compliance and is subject to lapses in judgment and breakdowns resulting from
human failures. Internal control over financial reporting also can be
circumvented by collusion or improper management override. Because of such
limitations, there is a risk that material misstatements may not be prevented or
detected on a timely basis by internal control over financial reporting.
However, these inherent limitations are known features of the financial
reporting process. Therefore, it is possible to design into the process
safeguards to reduce, though not eliminate, this risk.
A
“material weakness” in internal control over financial reporting (as defined in
Auditing Standard No. 2 of the Public Company Accounting Oversight Board) is a
significant deficiency, or combination of significant deficiencies, that results
in more than a remote likelihood that a material misstatement of the annual or
interim financial statements will not be prevented or detected. A “significant
deficiency” is a control deficiency, or combination of control deficiencies,
that adversely affects a company's ability to initiate, authorize, record,
process, or report external financial data reliably in accordance with generally
accepted accounting principles, such that there is more than a remote likelihood
that a misstatement of the company's annual or interim financial statements that
is more than inconsequential will not be prevented or detected.
Management
assessed the effectiveness of the Company's internal control over financial
reporting as of December 31, 2008, the end of the fiscal period covered by this
report and determined that the internal controls in place as of the assessment
were not sufficient. Specifically, management assessed the effectiveness of our
internal control over financial reporting as of December 31, 2008, using the
criteria set forth by the Committee of Sponsoring Organizations of the Treadway
Commission ("COSO") in Internal Control--Integrated Framework. In assessing the
effectiveness of our internal control over financial reporting, management
identified the following material weaknesses in internal control over financial
reporting as of December 31, 2008:
Material weaknesses in the Company's Control
Environment. Our control environment did not sufficiently promote
effective internal control over financial reporting throughout the organization.
Specifically, we had a shortage of support and resources in our accounting
department, which resulted in inadequate: (i) documentation and communication of
our accounting policies and procedures; and (ii) internal audit processes of our
accounting policies and procedures.
As a
result of the material weaknesses described above, our management concluded that
we did not maintain effective internal control over financial reporting as of
December 31, 2008, based on the criteria established by COSO.
Management
believes that our rapid growth since the acquisition in March 2007 of
approximately 650 producing oil and gas wells is primarily responsible for the
circumstances in which the material weaknesses described above resulted. The
March 2007 transaction, whereby our activities and revenues grew by a factor of
almost 1,000%, required that we fundamentally re-organize the Company and its
operations. In addition, in February 2008, we concluded the GFB Acquisition,
which added approximately 590 producing properties to our company. In
March 2008 and October 2008, we took over operations on a substantial number of
these properties. In this connection, while we sold our Israeli based
businesses to concentrate exclusively on our oil and gas exploration activities
in the United States and to focus our resources on overseeing our expansion, the
need for competent and experienced accounting personnel was both greater than we
anticipated and much more difficult to satisfy than we expected. Adding to our
difficulty was the “boom” in the oil and gas industry that began in roughly late
2007 and concluded in the fall of 2008. This “boom” created an
extremely competitive market for experienced oil and gas personnel, which made
the location and employment of competent individuals very expensive, time
consuming and difficult. This market remains tight, and very
competitive.
In this
regard, the accounting system utilized by Five States, the seller of the
properties we acquired in March, 2007, differed from the system used by GFB and
TransRepublic, the sellers of the properties we acquired in February,
2008, and both systems differed from the system we utilized prior to these
acquisitions. Despite the expenditure of significant time and
expense, integration of the three accounting systems has been more difficult,
and time consuming, than anticipated.
Our
efforts in this regard have been further complicated by the difficulty in
integrating three different operational systems into one. Each of the sellers
had its own method of operating which encompassed issues such as payroll, field
operations, and even the identification of the wells. It has been more difficult
than we anticipated to reconcile these differences.
Finally,
the efforts and resources that we invested in completing the above-described
transactions themselves adversely affected the time and other resources that we
were able in investing in our internal control compliance efforts.
We have
retained Deloitte & Touche, a registered accounting firm, to assist in our
internal control compliance efforts, including establishing new internal audit
procedures appropriate for a rapidly growing business and selection of
appropriate accounting controls software. During 2009, we plan to
implement a number of remediation measures to address the material weaknesses
described above. Our remediation plans include:
1. We
plan to hire additional personnel to assist us with documenting and
communicating our accounting policies and procedures to ensure the proper and
consistent application of those policies and procedures throughout the Company.
In 2008, in recognition of the weaknesses identified in the 2007 financial
statements, we hired a controller and two accountants. We are planning to hire
more accountants and other professional staff. The selection process
for a replacement has begun and is expected to be completed during the second or
third quarter of 2009.
2. We
plan to implement formal processes requiring periodic self-assessments,
independent tests, and reporting of our personnel's adherence to our accounting
policies and procedures.
3. We
plan to (i) continue to require additional training for our current accounting
personnel; (ii) to hire additional accounting personnel to enable the allocation
of job functions among a larger group of accounting staff; and (iii)
to consider restructuring our accounting department, each to increase the
likelihood that our accounting personnel will have the resources, experience,
skills, and knowledge necessary to effectively perform the accounting system
functions assigned to them.
4. We
plan to implement a new accounting system with automatic control checkpoints for
day-to-day business processes. In this regard, we have acquired the new
accounting software and have begun the process of transferring data from our
existing system to the new system. We have also had key members of
our staff trained in the new system. We anticipate that the data
transfer will be completed by June 30, 2009. At this point, we plan
to run our existing and new systems concurrently to ensure that the new system
performs satisfactorily. We plan to be utilizing the new system by
September 30, 2009.
To date
we have spent in excess of $150 thousand in our efforts to create a fully
integrated accounting and compliance system, and we anticipate that an
expenditure of approximately $150 thousand will be required in 2009 to complete
this task. In this regard, management recognizes that many of these
enhancements require continual monitoring and evaluation for effectiveness. The
development of these actions is an iterative process and will evolve as the
Company continues to evaluate and improve our internal controls over financial
reporting.
Management
has been involved in these activities and will continue to review progress on
these activities on a consistent and ongoing basis at the Chief Executive
Officer and Chief Financial Officer level, in conjunction with our Audit
Committee. We also plan to take additional steps to elevate Company awareness
about and communication of these important issues through formal channels such
as Company meetings, departmental meetings, and training.
Changes
in Internal Controls Over Financial Reporting
As
described above, there have been material changes in our internal control over
financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange
Act of 1934) during 2008 that have materially affected, or are reasonably likely
to materially affect, our internal control over financial
reporting. The Management and the Audit Committee of the Company's
Board of Directors have developed the remedial measures to address the internal
control deficiencies identified above and will continue to take action as
required to remedy these deficiencies. The Company will monitor the
effectiveness of planned actions and will make any other changes and take such
other actions as management or the Audit Committee determines to be
appropriate.
This
annual report does not include an attestation report of the Company’s registered
public accounting firm regarding internal control over financial
reporting. Management’s report was not subject to attestation by the
Company’s registered public accounting firm pursuant to temporary rules of the
SEC that permit the company to provide only management’ report in this annual
report.
The
information called for by items 10, 11, 12 13 and 14 will be contained in the
Company's definitive proxy statement which the Company intends to file within
120 days after the end of the Company's fiscal year ended December 31, 2008 and
such information is incorporated herein by reference.
GLOSSARY
"Limited
Partnership" means Isramco-Negev 2 Limited Partnership, a Limited Partnership
founded pursuant to a Limited Partnership Agreement made on the 2nd and 3rd days
of March, 1989 (as amended on September 7, 1989, July 28, 1991, March 5, 1992
and June 11, 1992) between the Trustee on part as Limited Partner and Isramco
Oil and Gas Ltd., as General Partner on the other part.
"Overriding
Royalty" means a percentage interest over and above the base royalty and is free
of all costs of exploration and production, which costs are borne by the Grantor
of the Overriding Royalty Interest and which is related to a particular
Petroleum License.
"Payout" means
the defined point at which one party has recovered its prior costs.
"Petroleum"
means any petroleum fluid, whether liquid or gaseous, and includes oil, natural
gas, natural gasoline, condensates and related fluid hydrocarbons, and also
asphalt and other solid petroleum hydrocarbons when dissolved in and producible
with fluid petroleum.
"Israel
Petroleum Law"
The
Company's business in Israel is subject to regulation by the State of Israel
pursuant to the Petroleum Law, 1952. The administration and implementation of
the Petroleum Law is vested in the Minister of National Infrastructure (the
"Minister") and an Advisory Council.
The
following includes brief statements of certain provisions of the Petroleum Law
in effect at the date of this Prospectus. Reference is made to the copy of the
Petroleum Law filed as an exhibit to the Registration Statement referred to
under "Additional Information" and the description which follows is qualified in
its entirety by such reference.
The
holder of a preliminary permit is entitled to carry out petroleum exploration,
but not test drilling or petroleum production, within the permit areas. The
Commissioner determines the term of a preliminary permit and it may not exceed
eighteen (18) months. The Minister may grant the holder a priority right to
receive licenses in the permit areas and for the duration of such priority right
no other Party will be granted a license or lease in such areas.
Drilling
for petroleum is permitted pursuant to a license issued by the Commissioner. The
term of a license is for three (3) years, subject to extension under certain
circumstances for an additional period up to four (4) years. A license holder is
required to commence test drilling within two (2) years from the grant of a
license (or earlier if required by the terms of the license) and not to
interrupt operations between test drillings for more than four (4) months. If
any well drilled by the Company is determined to be a Commercial discovery prior
to expiration of the license, the Company will be entitled to receive a
Petroleum Lease granting it the exclusive right to explore for and produce
petroleum in the lease area. The term of a lease is for thirty (30) years,
subject to renewal for an additional term of twenty (20) years.
The
Company, as a lessee, will be required to pay the State of Israel the royalty
prescribed by the Petroleum Law which is presently, and at all times since 1952
has been, 12.5% of the petroleum produced from the leased area and saved,
excluding the quantity of petroleum used in operating the leased
area.
The
Minister may require a lessee to supply at the market price such quantity of
petroleum as, in the Minister's opinion, is required for domestic consumption,
subject to certain limitations.
As a
lessee, the Company will also be required to commence drilling of a development
well within six (6) months from the date on which the lease is granted and,
thereafter, with due diligence to define the petroleum field, develop the leased
area, produce petroleum therefore and seek markets for and market such
petroleum.
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.
10.2 LOAN
AGREEMENT, dated as of February 27, 2007, between ISRAMCO, INC., and NAPHTHA
ISRAEL PETROLEUM CORP., LTD., filed as an Exhibit to the 10-Q for the quarter
ended March 31, 2007 and incorporated herein by reference., filed as an Exhibit
to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by
reference.
10.5 LOAN
AGREEMENT, dated as of February 26, 2007, between ISRAMCO, INC., and
J.O.E.L JERUSALEM OIL EXPLORATION, LTD., filed as an Exhibit to the
10-Q for the quarter ended March 31, 2007 and incorporated herein by
reference.
10.6
CREDIT AGREEMENT dated as of March 2, 2007 among ISRAMCO ENERGY, L.L.C., each of
the lenders that is a signatory hereto or which becomes a signatory hereto; and
WELLS FARGO BANK, N. A., a national banking association, as agent for the
Lenders., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007
and incorporated herein by reference.
10.7
GUARANTY AGREEMENT, dated as of March 2, 2007 by ISRAMCO, Inc. in favor of Wells
Fargo Bank, N.A., as administrative agent (the "ADMINISTRATIVE AGENT") for the
lenders that are or become parties to the Credit Agreement referred to in Item
10.6., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and
incorporated herein by reference.
10.8
PLEDGE AGREEMENT, dated as of March 2, 2007 by Isramco, Inc. in favor of Wells
Fargo Bank, N.A., as administrative agent for itself and the lenders (the
"LENDERS") which are parties to the Credit Agreement referred to in Item 10.6,
filed as an Exhibit to the 10-Q for the quarter ended March 31,2007 and incorporated herein by reference.
10.10
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.
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.
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.
We have
audited the accompanying consolidated balance sheets of Isramco, Inc.
(“Isramco”) as of December 31, 2008 and 2007, and the related consolidated
statements of operations, changes in shareholders' equity, and cash flows for
each of the three years ended December 31, 2008. These consolidated financial
statements are the responsibility of Isramco's management. Our responsibility is
to express an opinion on these consolidated financial statements based on our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatement. The Company
is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audits included consideration of
internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Company’s internal control
over financial reporting. Accordingly, we express no such opinion. An audit also
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our
opinion, the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Isramco, Inc., as of
December 31, 2008 and 2007, and the consolidated results of its operations and
its cash flows for each of the three years ended December 31, 2008, in
conformity with accounting principles generally accepted in the United States of
America.
Basis
of Presentation and Principles of Consolidation
Isramco
Inc. and subsidiaries (“Isramco” or the “Company”) are primarily engaged in the
acquisition, development, production and exploration of oil and natural gas
properties located, mainly in onshore United States of America (“United
States”). The Company operates in one segment, oil and natural gas exploration
and exploitation. The consolidated financial statements include the accounts of
all majority-owned, controlled subsidiaries. Investments in unconsolidated
affiliates, in which Isramco is able to exercise significant influence, are
accounted for using the equity method. All intercompany accounts and
transactions have been eliminated. Certain prior year amounts have been
reclassified to conform to the current year presentation.
Use
of Estimates
The
preparation of the Company’s consolidated financial statements in conformity
with accounting principles generally accepted in the United States of America
requires the Company’s management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities, if any, at the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the
respective reporting periods. These estimates include oil and natural gas
reserve quantities that form the basis for the calculation of amortization of
oil and natural gas properties. Management emphasizes that reserve
estimates are inherently imprecise and that estimates of more recent reserve
discoveries are more imprecise than those for properties with long production
histories. Actual results may differ from the estimates and assumptions
used in the preparation of the Company’s consolidated financial
statements.
Cash
and Cash Equivalents.
Isramco
records as cash equivalents all highly liquid short-term investments with
original maturities of three months or less.
Allowance
for Doubtful Accounts
The
Company establishes provisions for losses on accounts receivable if it
determines that it will not collect all or part of the outstanding balance. The
Company regularly reviews collectibility and establishes or adjusts the
allowance as necessary using the specific identification method. There is no
significant allowance for doubtful accounts as of December 31, 2008 or
2007.
Oil
and Gas Operations.
Isramco
accounts for its natural gas and crude oil exploration and production activities
under the successful efforts method of accounting.
Oil and
gas lease acquisition costs are capitalized when incurred. Unproved properties
with individually significant acquisition costs are assessed on a lease-by-lease
basis, and any impairment in value is recognized. Lease rentals are expensed as
incurred.
Oil and
gas exploration costs, other than the costs of drilling exploratory wells, are
charged to expense as incurred. The costs of drilling exploratory wells are
capitalized pending determination of whether they have discovered proved
commercial reserves. Exploratory drilling costs are capitalized when drilling is
complete if it is determined that there is economic producibility supported by
either actual production, a conclusive formation test. If proved commercial
reserves are not discovered, such drilling costs are expensed. In some
circumstances, it may be uncertain whether proved commercial reserves have been
found when drilling has been completed. Such exploratory well drilling costs may
continue to be capitalized if the reserve quantity is sufficient to justify its
completion as a producing well and sufficient progress in assessing the reserves
and the economic and operating viability of the project is being made. A
significant portion of the property costs reflected in the accompanying
consolidated balance sheets are from acquisitions of proved properties from
other oil and gas company (see Note 2). Costs to develop proved reserves,
including the costs of all development wells and related equipment used in the
production of natural gas and crude oil, are capitalized.
Depreciation,
depletion and amortization of the cost of proved oil and gas properties are
calculated using the unit-of-production method. The reserve base used to
calculate depreciation, depletion and amortization is the sum of proved
developed reserves and proved undeveloped reserves for leasehold acquisition
costs and the cost to acquire proved properties. With respect to lease and well
equipment costs, which include development costs and successful exploration
drilling costs, the reserve base includes only proved developed reserves.
Estimated future dismantlement, restoration and abandonment costs, net of
salvage values, are taken into account.
Assets
are grouped in accordance with paragraph 30 of Statement of Financial Accounting
Standards (SFAS) No. 19, "Financial Accounting and Reporting
by Oil and Gas Producing Companies." The basis for grouping is a
reasonable aggregation of properties with a common geological structural feature
or stratigraphic condition, such as a reservoir or field.
Amortization
rates are updated to reflect: 1) the addition of capital costs, 2) reserve
revisions (upwards or downwards) and additions, 3) property acquisitions and/or
property dispositions and 4) impairments.
Isramco
accounts for impairments under the provisions of SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." When circumstances indicate that an asset
may be impaired, Isramco compares expected undiscounted future cash flows at a
producing field level to the unamortized capitalized cost of the asset. If the
future undiscounted cash flows, based on Company and third party 's estimate of
future crude oil and natural gas prices, operating costs, anticipated production
from proved reserves and other relevant data, are lower than the unamortized
capitalized cost, the capitalized cost is reduced to fair value. Fair value is
calculated by discounting the future cash flows at an appropriate risk-adjusted
discount rate.
In 2008,
2007 and 2006, we reported impairment charge of $22,093 thousand, $3,203
thousand and $668 thousand, respectively, relating to our oil and gas
properties.
Property,
Plant and Equipment Other than Oil and Natural Gas Properties
Other
operating property and equipment are stated at the lower of cost or fair market
value. Provision for depreciation and amortization is calculated using the
straight-line method over the estimated useful lives of the respective
assets. The cost of normal maintenance and repairs is charged to operating
expense as incurred. Material expenditures, which increase the life of an asset,
are capitalized and depreciated over the estimated remaining useful life of the
asset. The cost of properties sold, or otherwise disposed of, and the
related accumulated depreciation or amortization are removed from the accounts
and any gains or losses are reflected in current operations. On December 31,2007, we sold undeveloped real estate located in Israel to related party (for
further information see Note 5 “closure of the Israeli branch
office”).
In 2007,
we reported an impairment charge of $928 thousand to undeveloped real estate
located in Israel.
In 2006,
we reported an impairment charge of $2,200 thousand to the vessel included in
discontinued operation.
Marketable
Securities
Statement
of Financial Accounting Standard No. 115 (SFAS No. 115),”Accounting for Certain Investments
in Debt and Equity Securities”, requires Isramco to classify its debt and
equity securities in one of three categories: trading, available-for-sale and
held-to-maturity. Trading securities are bought and held principally for the
purposes of selling them in the near term. Held-to-maturity securities are those
securities in which Isramco has both the ability and intent to hold the security
until maturity. All other securities not included in trading or held-to-maturity
are classified as available-for-sale.
Trading
and available-for-sale securities are recorded at fair market value. Isramco
holds no held-to-maturity securities. Unrealized holding gains and losses on
trading securities are included in earnings. Unrealized holding gains or losses,
net of the related tax effects, on available-for-sale securities are excluded
from earnings and are reported net of applicable taxes as accumulated other
comprehensive income, a separate component of shareholders' equity, until
realized.
Asset
Retirement Obligation
In August
2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 143, Accounting for
Asset Retirement Obligations (SFAS 143). SFAS 143 requires that the
fair value of an asset retirement cost, and corresponding liability, should be
recorded as part of the cost of the related long-lived asset and subsequently
allocated to expense using a systematic and rational method. Upon adoption,
the Company recorded an asset retirement obligation to reflect the Company’s
legal obligations related to future plugging and abandonment of its oil and
natural gas wells. The Company estimated the expected cash flow associated
with the obligation and discounted the amount using a credit-adjusted, risk-free
interest rate. At least annually, the Company reassesses the obligation to
determine whether a change in the estimated obligation is necessary. The
Company evaluates whether there are indicators that suggest the estimated cash
flows underlying the obligation have materially changed. Should those
indicators suggest the estimated obligation may have materially changed the
Company will accordingly update its assessment. Additional retirement
obligations increase the liability associated with new oil and natural gas wells
as these obligations are incurred.
Concentrations
of Credit Risk
The
Company through its wholly-owned subsidiary Jay Management Company, LLC ("Jay
Management") operates a substantial portion of its oil and natural gas
properties. As the operator of a property, the Company makes full payments for
costs associated with the property and seeks reimbursement from the other
working interest owners in the property for their share of those costs. The
Company’s joint interest partners consist primarily of independent oil and
natural gas producers. If the oil and natural gas exploration and production
industry in general were adversely affected, the ability of the Company’s joint
interest partners to reimburse the Company could be adversely
affected.
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.
Revenues
from the sale of oil and natural gas are recognized when the products are sold
to a purchaser at a fixed or determinable price, delivery has occurred and title
has transferred, and collectibility of the revenue is reasonably assured. The
Company follows the entitlement method of accounting for recording oil and gas
revenues under that method, any revenues received in excess of the Company's
share is treated as a liability. If revenues received are less than Company's
share, the deficiency is recorded as an asset. The Company's imbalance position
was not significant in terms of volumes or values at December 31, 2008 and
2007.
Price
Risk Management Activities
The
Company follows SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities (SFAS 133), as amended. From time
to time, the Company may hedge a portion of its forecasted oil and natural gas
production. Derivative contracts entered into by the Company have consisted
of transactions in which the Company hedges the variability of cash flow related
to a forecasted transaction. The Company has elected to not designate any
of its positions for hedge accounting. Accordingly, the Company records the net
change in the mark-to-market valuation of these positions, as well as payments
and receipts on settled contracts, in “net gain (loss) on derivative contracts”
on the consolidated statements of operations.
In 2008,
2007 and 2006, we recorded gain (loss) of $24.7 million, $(8.6) million and $2.6
million, respectively, related to our derivative instruments. Fair values are
derided principally from market quoted and other independent third-party
quotes.
During
the second quarter of 2008, we made the decision to mitigate a portion of our
interest rate risk with interest rate swaps. These swap instruments reduce our
exposure to market rate fluctuations by converting variable interest rates to
fixed interest rates. These interest rate swaps convert a portion of our
variable rate interest of our Scotia debt (as defined in Note 8, “Long-term
Debt”) to a fixed rate obligation, thereby reducing the exposure to market rate
fluctuations. We have elected to designate thesepositions for hedge accounting
and therefore the unrealized gains and losses are recorded in accumulated other
comprehensive loss. The Company measures hedge effectiveness by assessing the
changes in the fair value or expected future cash flows of the hedged
item.
Income
Taxes
The
Company accounts for income taxes using the asset and liability method wherein
deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between financial statement carrying
amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax
rates expected to apply to taxable income in the years in which temporary
differences are expected to be recovered or settled. Deferred tax assets
are reduced by a valuation allowance if, based on the weight of available
evidence, it is more likely than not that some portion or all of the deferred
tax assets will not be realized.
In July
2006, the Financial Accounting Standards Board (FASB) issued Financial
Interpretation (FIN) 48, Accounting for Uncertainty in Income
Taxes—an Interpretation of FASB 109 (FIN 48). FIN 48 created a single
model to address accounting for the uncertainty in income tax positions and
prescribes a minimum recognition threshold a tax position must meet before
recognition in the financial statements.
The
Company adopted the provisions of FIN 48 effective January 1, 2007 which
did not have a material impact on the Company’s operating results, financial
position or cash flows. The Company did not record a cumulative effect
adjustment related to the adoption of FIN 48.
Tax
audits may be ongoing at any point in time. Tax liabilities are recorded based
on estimates of additional taxes which may be due upon the conclusion of these
audits. Estimates of these tax liabilities are made based upon prior experience
and are updated for changes in facts and circumstances. However, due to the
uncertain and complex application of tax regulations, it is possible that the
ultimate resolution of audits may result in liabilities which could be
materially different from these estimates.
Translation
of Foreign Currencies
Foreign
currency is translated in accordance with SFAS No. 52, Foreign currency translation,
which provides the criteria for determining the functional currency for entities
operating in foreign countries. Isramco has determined its functional currency
is the United States (U.S.) dollar since all of its contracts are in U.S.
dollars. Adjustments resulting from the process of translating foreign
functional currency financial statements into U.S. dollars are included in
accumulated other comprehensive income in stockholders’ equity. Foreign currency
transaction gains and losses are included in current income. The functional
currency of our Israeli subsidiaries is the New Israeli Shekel.
Earnings
per Share
Isramco
follows SFAS No. 128, Earnings
per Share, for computing and presenting earnings per share, which
requires, among other things, dual presentation of basic and diluted loss per
share on the face of the consolidated statement of operations. Basic EPS is
computed by dividing income available to common shareholders by the weighted
average number of common shares outstanding for the period. Diluted EPS reflects
the potential dilution that could occur if securities or other contracts to
issue common shares were exercised or converted into common shares or resulted
in the issuance of common shares that then shared in the earnings of the entity.
For the year ended December 31, 2008, Isramco's stock options were
anti-dilutive.
Environmental
Isramco
is subject to extensive federal, state, local and foreign environmental laws and
regulations. These laws, which are constantly changing, regulate the discharge
of materials into the environment and may require Isramco to remove or mitigate
the environmental effects of the disposal or release of petroleum or chemical
substances at various sites. Liabilities for expenditures of no capital nature
are recorded when environmental assessment and/or remediation is probable, and
the costs can be reasonably estimated. No significant amounts for environmental
liabilities were recorded at December 31, 2008 and 2007.
In
January 2006, the Company adopted SFAS No. 123(R), Share-Based Payment (SFAS
123(R)). SFAS 123(R) revises SFAS No. 123, Accounting for Stock-Based
Compensation (SFAS 123), and focuses on accounting for share-based
payments for services provided by employee to employer. The statement requires
companies to expense the fair value of employee stock options and other
equity-based compensation at the grant date. The statement does not require a
certain type of valuation model, and either a binomial or Black-Scholes model
may be used. The Company used the modified prospective application method as
detailed in SFAS 123(R).
Prior to
adopting SFAS 123(R), the Company adopted SFAS No. 123, Accounting for Stock-Based
Compensation (SFAS 123) prospectively, using the fair value recognition
method to all employee and director awards granted, modified or settled after
January 1, 2003. Prior to the adoption, the Company elected to follow
Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to
Employees (APB 25) and related interpretations in accounting for its
employee stock options. There
Recently
Issued Accounting Standards and Developments
On
December 31, 2008, the Securities and Exchange Commission (SEC) issued the
final rule, “Modernization of Oil and Gas Reporting” (“Final Rule”). The Final
Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements
and is effective for annual reports on Forms 10-K for years ending on or after
December 31, 2009. The revisions are intended to provide investors with a
more meaningful and comprehensive understanding of oil and gas reserves to help
investors evaluate their investments in oil and gas companies. The amendments
are also designed to modernize the oil and gas disclosure requirements to align
them with current practices and technological advances. Revised requirements in
the Final Rule include, but are not limited to:
·
Oil
and gas reserves must be reported using a 12-month average of the closing
prices on the first day of each of such months, rather than a single day
year-end price:
·
Companies
will be allowed to report, on a voluntary basis, probable and possible
reserves, previously prohibited by SEC rules;
and
·
Easing
the standard for the inclusion of proved undeveloped reserves (PUDs) and
requiring disclosure of information indicating any progress toward the
development of PUDs.
We are
currently evaluating the potential impact of adopting the Final Rule. The SEC is
discussing the Final Rule with the FASB and IASB staffs to align accounting
standards with the Final Rule. These discussions may delay the required
compliance date. Absent any change in such date, we will begin complying with
the disclosure requirements in our annual report on Form 10-K for the year ended
December 31, 2009. Voluntary early compliance is not
permitted.
In March
2008, the FASB issued SFAS 161, Disclosures about Derivative
Instruments and Hedging Activities. SFAS 161 is effective beginning
January 1, 2009 and required entities to provide expanded disclosures about
derivative instruments and hedging activities including (1) the ways in
which an entity uses derivatives, (2) the accounting for derivatives and
hedging activities, and (3) the impact that derivatives have (or could
have) on an entity’s financial position, financial performance, and cash flows.
SFAS 161 requires expanded disclosures and does not change the accounting for
derivatives. Isramco is currently evaluating the impact of SFAS 161, but we do
not expect the adoption of this standard to have a material impact on our
financial results.
In
February 2007, the FASB issued SFAS 159, The Fair Value Option for
Financial Assets and Financial Liabilities Including an Amendment of FASB
Statement No. 115 (SFAS 159), which permits entities to choose to
measure many financial instruments and certain other items at fair value (Fair
Value Option). Election of the Fair Value Option is made on an
instrument-by-instrument basis and is irrevocable. At the adoption date,
unrealized gains and losses on financial assets and liabilities for which the
Fair Value Option has been elected would be reported as a cumulative adjustment
to beginning retained earnings. Following the election of the Fair Value Option
for certain financial assets and liabilities, the Company would report
unrealized gains and losses due to changes in fair value in earnings at each
subsequent reporting date. The Company adopted SFAS 159 effective
January 1, 2008 which did not have a material impact on the Company’s
operating results, financial position or cash flows as the Company did not elect
the Fair Value Option for any of its financial assets or
liabilities.
In
September 2006, the FASB issued SFAS 157, Fair Value Measurements (SFAS
157), which defines fair value, establishes a framework for measuring fair
value, and expands disclosures about fair value measurements. This pronouncement
applies to other standards that require or permit fair value measurements.
Accordingly, this statement does not require any new fair value measurements.
The Company adopted the provisions of SFAS 157 on January 1, 2008. See
“Fair Value Measurements” below for more details.
In
September 2006, the FASB issued SFAS 157 which defines fair value, establishes a
framework for measuring fair value, and expands disclosures about fair value
measurements. The provisions of SFAS 157 are effective January 1, 2008. The
FASB has also issued Staff Position (FSP) SFAS 157-2 (FSP No. 157-2), which
delays the effective date of SFAS 157 for nonfinancial assets and liabilities,
except for items that are recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually), until fiscal years
beginning after November 15, 2008. Effective January 1, 2008, the
Company adopted SFAS 157 as discussed above and has elected to defer the
application thereof to nonfinancial assets and liabilities in accordance with
FSP No. 157-2. Non-recurring nonfinancial assets and nonfinancial
liabilities for which the Company has not applied the provisions of SFAS 157
include those measured at fair value in goodwill impairment testing, asset
retirement obligations initially measured at fair value, and those initially
measured at fair value in a business combination.
In
October 2008, the FASB issued FSP SFAS 157-3, Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not
Active (FSP No. 157-3), which clarifies the application
of SFAS No. 157 in an inactive market and illustrates how an entity would
determine fair value when the market for a financial asset is not active. The
guidance provided by FSP No. 157-3 did not have a material impact on the
Company’s consolidated operating results, financial position or cash
flows.
The
Company utilizes derivative contracts to economically hedge against the
variability in cash flows associated with the forecasted sale of its anticipated
future oil and natural gas production. The Company generally economically hedges
a substantial, but varying, portion of anticipated oil and natural gas
production for the next 24-39 months. Derivatives are carried at fair value on
the consolidated balance sheets, with the changes in the fair value included in
the consolidated statements of operations for the period in which the change
occurs.
Periodically,
the Company utilizes marketable securities to invest a portion of its cash on
hand. These securities are carried at fair value on the consolidated
balance sheets; with the changes in the fair value net of tax included in the
accumulated other comprehensive income for the period in which the change
occurs.
As
defined in SFAS 157, fair value is the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date (exit price). The Company utilizes market
data or assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique. These inputs can be readily observable, market
corroborated, or generally unobservable. The Company classifies fair value
balances based on the observability of those inputs. SFAS 157 establishes a fair
value hierarchy that prioritizes the inputs used to measure fair value. The
hierarchy gives the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (level 1 measurement) and the lowest
priority to unobservable inputs (level 3 measurement).
The three
levels of the fair value hierarchy defined by SFAS 157 are as
follows:
Level 1 –
Quoted prices are available in active markets for identical assets or
liabilities as of the reporting date. Active markets are those in which
transactions for the asset or liability occur in sufficient frequency and volume
to provide pricing information on an ongoing basis. Level 1 primarily consists
of financial instruments such as exchange-traded derivatives, marketable
securities and listed equities.
Level 2 –
Pricing inputs are other than quoted prices in active markets included in level
1, which are either directly or indirectly observable as of the reported date.
Level 2 includes those financial instruments that are valued using models or
other valuation methodologies. These models are primarily industry-standard
models that consider various assumptions, including quoted forward prices for
commodities, time value, volatility factors, and current market and contractual
prices for the underlying instruments, as well as other relevant economic
measures. Substantially all of these assumptions are observable in the
marketplace throughout the full term of the instrument, can be derived from
observable data or are supported by observable levels at which transactions are
executed in the marketplace. Instruments in this category generally include
non-exchange-traded derivatives such as commodity swaps, interest rate swaps,
options and collars.
Level 3 –
Pricing inputs include significant inputs that are generally less observable
from objective sources. These inputs may be used with internally developed
methodologies that result in management’s best estimate of fair
value.
The
following table sets forth by level within the fair value hierarchy the
Company’s financial assets and liabilities that were accounted for at fair value
as of December 31, 2008. As required by SFAS 157, financial assets and
liabilities are classified in their entirety based on the lowest level of input
that is significant to the fair value measurement. The Company’s assessment of
the significance of a particular input to the fair value measurement requires
judgment, and may affect the valuation of fair value assets and liabilities and
their placement within the fair value hierarchy levels.
Derivatives
listed above include swaps that are carried at fair value. The fair value
amounts in current period earnings associated with the Company’s derivatives
resulted from Level 2 fair value methodologies; that is, the Company is able to
value the assets and liabilities based on observable market data for similar
instruments. This observable data includes the forward curve for commodity
prices based on quoted market prices and prospective volatility factors related
to changes in the forward curves.
As of
December 31, 2008, the Company’s derivative contracts were placed at major
financial institutions with investment grade credit ratings which are believed
to have a minimal credit risk. As such, the Company is exposed to credit risk to
the extent of nonperformance by the counterparties in the derivative contracts
discussed above; however, the Company does not anticipate such
nonperformance.
Marketable
securities listed above are carried at fair value. The fair value amounts on the
Company’s balances associated with the Company’s marketable securities resulted
from Level 1 fair value methodologies; that is, the Company is able to value the
assets based on quoted fair values for identical instruments.
2. Acquisitions
GFB
Acquisition
On March27, 2008, we purchased from GFB Acquisition - I, L.P. (“GFB”) and
Trans Republic Resources, Ltd. (“Trans Republic,” and, together with GFB, the
“Sellers”) interests in certain oil and gas properties located in Texas, New
Mexico, Utah, Colorado and Oklahoma for an aggregate purchase price of
approximately $102 million. The transaction included mainly operated oil and gas
properties in approximately 40 fields (approximately 490 Leases) in East Texas,
Texas Gulf Coast, Permian, Anadarko and San Juan Basins
The
following table summarizes the preliminary estimated fair values of assets that
we acquired and the liabilities assumed in connection with the acquisition of
these properties:
As
of December 31
2008
(In
thousands)
Oil
and gas properties (after adjustments)
$
105,982
Asset
retirement obligation
(8,480
)
Net
asset acquired
$
97,502
Five
States Acquisition
On March2, 2007, Isramco purchased certain oil and gas properties located in Texas and
New Mexico from Five States Energy Company, LLC for an aggregate preliminary
purchase price of $92 million (before adjustments as defined in the
agreement). Although the acquisition was closed on March 2, 2007, the
effective dated of the purchase was determined to be October 1, 2006 (the
“Effective Date”). Accordingly, the Company is entitled to the net revenues,
less direct operating expenses, of the acquired properties from the Effective
Date through the Acquisition Date. This will result in an adjustment to the
preliminary purchase price. These financial statements reflect the assets
acquired and operations related to those assets from the Acquisition Date
through December 31, 2007. According to an engineering report prepared by an
independent consulting company relating to the properties purchased, the
estimated proved developed producing reserves are 1,447,161 net barrels of oil
and 20,078,174 net MMCF's of natural gas and 1,305,705 net of liquid products.
Additionally, pursuant to an agreement between Sigma Energy Corporation
("Sigma"), an unrelated party that originated the transaction with Five States,
Isramco and Isramco Energy, Isramco Energy paid to Sigma on March 2, 2007, the
amount of $300 thousand and after Payout (as defined in the Agreement with
Sigma), IEN undertook to assign to Sigma a direct ownership interests equal to
3.75% of the interests acquired by Isramco Energy under the Purchase
Agreement
The
following table summarizes the preliminary estimated fair values of assets that
we acquired and the liabilities assumed in connection with the acquisition of
these properties:
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.
3. Transactions
with Affiliates and Related Parties
There is
no operation in Israel in 2008.
Until
December 31, 2007, we acted as operator for joint venture with related parties
in Israel engaged in the exploration of oil and gas for which it receives
operating fees equal to the greater of 6% of the actual direct costs or minimum
monthly fees of $6,000.
Operator
fees earned and related operator expenses are as follows (in
thousands):
Year
ended December 31
2007
2006
Operator
fees:
Gad
1
$
-
$
-
Med
Ashdod Lease
18
69
Operator
income
$
18
$
69
Operator
expenses
$
-
$
330
In
December 2003, we entered into a consulting agreement with Doron Avraham, at
that time the Vice President of the Isramco. Pursuant to this agreement, we
agreed to pay the consultant the sum of $15 thousand per month plus expenses in
consideration for the services that he provides to Isramco. The consulting
agreement expired in November 2007.
We paid
I.O.C. - Israel Oil Company, Ltd. (“I.O.C”) $226 thousand and $235 thousand for
the years ended December 31, 2007 and 2006, respectively, for rent and office,
secretarial and computer services. I.O.C is fully owned by Naphtha Israel
Petroleum Corp. Naphtha is the sole shareholder of Naphtha Holdings, Ltd., which
is the record holder of 48.4% of our outstanding common stock and which may be
deemed to be controlled by Haim Tsuff, the Chairman of the Board of Directors
and Chief Executive Officer of Isramco.
Isramco
Oil and Gas Ltd. (“IOG”), a wholly-owned subsidiary of Isramco (on December 31,2007 we sold IOG to related party, for further information see Note 5 “closure
of the Israeli branch office”) was the general partner of Isramco-Negev 2
Limited Partnership, from which we received management fees and expense
reimbursements of approximately $480 thousand for each of the years ended
December 31, 2007 and 2006.
On
November 17, 2008, the Company and Goodrich Global, Ltd. (“Goodrich”) entered
into an Amended and Restated Agreement, as subsequently amended on November 24,2008 (“Restated Agreement”). The Restated Agreement replaced the consulting
agreement originally entered into in May 1996. Under the the Restated
Agreement, the Company pays to Goodrich $360,000 per annum in installments of
$30,000 per month, in addition to reimbursing Goodrich for all reasonable
expenses incurred in connection with services rendered on behalf of the
Company. Goodrich is entitled to receive, with respect to each
completed fiscal year beginning with the fiscal year scheduled to end on
December 31, 2008, an amount in cash equal to five percent (5%) of the Company’s
pre-tax recorded profit (the “Supplemental Payment”). The Supplemental payment
is to be made within ten (10) business days after the filing with the
Securities and Exchange Commission of the Company’s Annual Report on Form 10-K
for such fiscal year. For purposes of the Restated Agreement,
“profit” means the pre – tax recorded profit as specified in the Company’s
annual report on Form 10-K, but excluding unrealized gain or loss on derivative
transactions. The Restated Agreement has an initial term through May 31, 2011;
provided that the term of the Restated Agreement will be deemed to have been
automatically extended for an additional three year period unless the Company
furnishes Goodrich, by March 3, 2011, with written notice of its election to not
extend the term of such agreement. The Restated Agreement contains certain
customary confidentiality and non-compete provisions. If the Restated Agreement
is terminated by the Company other than for cause, then Goodrich is entitled to
receive the equivalent of payments due through the then remaining term of the
agreement. In the year ended December 31, 2008 we paid Goodrich the total amount
of $310 thousand.
In
November 1999, we entered into a consulting agreement with Worldtech Inc., a
Mauritus company of which Jackob Maimon is the President. Jackob Maimon is a
director of Isramco. Pursuant to this consulting agreement, we pay the
consultant $240 thousand per annum in installments of $20 thousand per month
plus expenses in consideration of the services that he provides to the Company.
The agreement expired in May 2008.
4. Investments
in Affiliate
Isramco
Oil and Gas Ltd. (“IOG”), a wholly-owned subsidiary of Isramco, was the general
partner of the Isramco Negev 2 Limited Partnership (the “Limited Partnership”).
The daily management of the Limited Partnership is under the control of the
general partner; however, matters involving the rights of the Limited
Partnership unit holders are subject to supervision of a supervisor, appointed
to supervise the Limited Partnership activities, and in some instances the
approval of the Limited Partnership unit holders. Through IOG, we own a 0.05%
interest in the Limited Partnership, which is accounted for by the equity method
of accounting.
On
December 31, 2007, Isramco sold IOG, including the participation unit in Isramco
Negev 2 LP, to related party (for further information see Note 5 “closure of the
Israeli branch office”). As of December 31, 2006, Isramco owned 345,309,522
units or 8.17% of the issued Limited Partnership units of the Limited
Partnership, Isramco Negev 2. Summarized financial information of
Isramco Negev 2 Limited Partnership is as follows (amounts in
thousands):
On
December 31, 2007, Isramco sold the participation unit in IOC Dead Sea 2 LP to
related party (for further information see Note 5 “closure of the Israeli branch
office”). As of December 31, 2006, Isramco owned 7,877,248 of units (24.97%% of
the issued Partnership units) of the I.N.O.C Dead Sea Limited Partnership.
Summarized financial information of I.N.O.C. Dead Sea Limited Partnership is as
follows (amounts in thousands):
On
December 31, 2007, Isramco and I.O.C- Israel Oil Company Ltd, an Israeli company
and related party ("IOC"), entered into an agreement pursuant to which the
Company sold and transferred to IOC its Israeli based activities and assets
currently conducted and managed by the Company's Israel branch office (the
"Branch Office") and its own shares in Isramco Oil & Gas (the general
partner of Negev 2 LP), for aggregate consideration of approximately $13.6
million. Following the sale of these assets, the Company no longer conducts
operations in Israel though it will continue to hold interests in certain oil
and gas assets offshore Israel. The decision was taken in light of the Company's
expanding oil and gas operations in the United States and management's decision
that it is in the Company's best interests to focus on the oil and gas
operations in the United States and terminate activities in Israel which, prior
to the sale transaction reported hereunder, comprised a relatively insignificant
component of the Company's overall operations.
The
principal assets transferred to IOC include participation units in the Israeli
oil and gas limited partnerships Isramco Negev 2 ("Negev") and INOC Dead Sea
("Dead Sea"), both of which were held by the Branch Office. The participation
units of both Negev and Dead Sea trade on the Tel Aviv Stock Exchange. The sale
of the units was completed through a private non-market transaction with IOC
where the sale price of the Negev and Dead Sea units was established at,
respectively, a 7% and 10% discount to the closing sale price of these units on
the Tel Aviv Stock Exchange on December 30, 2007. The discounts were established
by an independent appraiser. The Branch Office also transferred to IOC all
operating activities at the Branch Office, including employees, fixed assets,
marketable securities and certain rights and liabilities, as well as the
Company's holdings of Isramco Oil and Gas Ltd. and title to undeveloped real
estate located in Israel.
IOC is a
wholly-owned subsidiary of Naphtha Israel Petroleum Corp, Ltd. ("Naphtha").
Naphtha holds 100% of Naphtha Holdings Ltd., which holds approximately 48% of
the Company's issued and outstanding stock.
Since
this is a transaction between entities under common control, the Company
recorded the loss of approximately $3,046 million from the transaction, as a
reduction of shareholders’ equity (additional paid in capital).
The
proceeds of the sale were used by the Company to repay a loan that
Naphtha advanced to the Company in March 2007 for purposes of enabling the
Company to complete the acquisition from Five States of certain oil and gas
properties in the United States.
6. Marketable
Securities
For the
year ended December 31, 2008, 2007 and 2006, we had net unrealized gains on
marketable securities of $0, $0 and $1,054 thousand, respectively. Sales of
marketable securities resulted in realized gains of $0, $52 thousand and $1,177
thousand for the years ended December 31, 2008, 2007 and 2006,
respectively.
Available-for-sale
securities, which are primarily traded on the Tel-Aviv Stock Exchange and on the
OTC Bulletin Board, consist of the following (in thousands):
The
Company enters into derivative commodity contracts to economically hedge its
exposure to price fluctuations on a portion of its anticipated oil and natural
gas production. It is the Company’s policy to enter into derivative contracts
only with counterparties that are creditworthy financial institutions deemed by
management as competent and competitive market makers. Each of the
counterparties to the Company’s derivative contracts is a lender in the
Company’s Senior Credit Agreement. The Company did not post collateral under any
of these contracts as they are secured under the Senior Credit
Agreement.
At
December 31, 2008, the Company has entered into swaps agreements. A swap
requires the Company to make a payment to, or receive receipts from, the
counterparty based upon the differential between a specified fixed price and a
price related to those quoted on the New York Mercantile Exchange (NYMEX) for
each respective period.
At
December 31, 2008, the Company had 18 open positions summarized in the
tables below: 7 natural gas swap arrangements and 11 crude oil swap
arrangements. Derivative commodity contracts settle based on NYMEX West Texas
Intermediate and Henry Hub prices, which may differ from the actual price
received by the Company. During 2008, 2007 and 2006 the Company did not elect to
designate any positions as cash flow hedges for accounting purposes, and
accordingly, recorded the net change in the mark-to-market valuation of these
contracts, as well as all payments and receipts on settled contracts, in current
earnings as a component of other income and expenses on the consolidated
statements of operations.
At
December 31, 2008, the Company had a $23 million derivative asset, which
$12 million was classified as current. For the year ended December 31,2008, the Company recorded a net derivative gain of $24.7 million ($32.6 million
unrealized gain partially offset by a $7.9 million loss from net cash payments
on settled contracts).
As of
December 31, 2007, the Company had a $9.4 million derivative liability,
which $3.1 million was classified as current. For the year ended
December 31, 2007the 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).
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
Rate
32,000
April
2009
February
2011
3.63%
6,000
April
2009
February
2011
2.90%
8. Long-Term
Debt and Interest Expense
Long-Term
Debt as December 31 consisted of the following (in thousands):
2008
2007
Libor
+ 2% Bank Revolving Credit Facility due 2011
17,950
27,000
Libor
+ 2% Bank Revolving Credit Facility due 2012
The
Company entered into the Senior Secured Revolving Credit Agreement, dated as of
March 27, 2008 and Amended and Restated as of December 19, 2008 (the
“Senior Credit Agreement”), between the Company, each of the lenders from time
to time party thereto (the “Lenders”), Bank of Nova Scotia, as administrative
agent for the Lenders and Capital One, N.A as a syndication agent for the
Lenders. The Senior Credit Agreement provides for a $150 million facility due in
2012 with an increased borrowing base of $54 million that will be redetermined
from time to time, and adjusted based on the Company’s oil and gas properties,
reserves, other indebtedness and other relevant factors. During the fourth
quarter of 2008, the lenders reduced the borrowing base to $45
million.
Amounts
outstanding under the Senior Credit Agreement will bear interest at specified
margins over the LIBOR of 1.25% to 2.00% for LIBOR loans or at specified margins
over the Base Rate (as defined in the agreement) of 0.25% to 1.25% for base rate
loans. Such margins will fluctuate based on the utilization of the borrowing
base. Borrowings under the Senior Credit Agreement are secured by first lien and
security interest on the real and personal property of Isramco
Resources.
The
Senior Credit Agreement contains customary financial and other covenants,
including minimum working capital levels of not less than 1.0 to 1.0, leverage
ratio of not greater than 3.5 to 1.0 and minimum coverage of interest of not
less than 2.5 to 1.0. In addition, the Company is subject to covenants limiting
dividends and other restricted payments, transactions with affiliates, changes
of control, asset sales, and liens on properties. At December 31, 2008, the
Company was in compliance with all of its debt covenants under the Senior Credit
Agreement.
The
Company entered into the Senior Secured Revolving Credit Agreement, dated as of
March 2, 2007 as Amended and Restated as of June 15, 2007 (the “Senior
Credit Agreement”), between the Company, each of the lenders from time to time
party thereto (the “Lenders”), Wells Fargo Bank, N.A, as administrative agent
for the Lenders and. The Senior Credit Agreement provides for a $150 million
facility due in 2011with an increased borrowing base of $35.3 million that will
be redetermined from time to time, and adjusted based on the Company’s oil and
gas properties, reserves, other indebtedness and other relevant factors. During
the second quarter of 2007, the Lenders reduced the borrowing base to $27
million.
Amounts
outstanding under the Senior Credit Agreement will bear interest at specified
margins over the LIBOR of 1.25% to 2.00% for LIBOR loans or at specified margins
over the Base Rate (as defined in the agreement) of 0.25% to 1.25% for base rate
loans. Such margins will fluctuate based on the utilization of the borrowing
base. Borrowings under the Senior Credit Agreement will be secured by a
guarantee from Isramco and a pledge by Isramco of the shares of Isramco
Energy.
The
Senior Credit Agreement contains customary financial and other covenants,
including minimum working capital levels of not less than 1.0 to 1.0, leverage
ratio of not greater than 3.5 to 1.0 and minimum coverage of interest of not
less than 2.5 to 1.0. In addition, the Company is subject to covenants limiting
dividends and other restricted payments, transactions with affiliates, changes
of control, asset sales, and liens on properties. At December 31, 2008, the
Company was in compliance with all of its debt covenants under the Senior Credit
Agreement.
Related
party Debt
In
connection with GFB Acquisition (see Note 2), we obtained the following
financing from related party:
In
February and March, 2008 we obtained loans from JOEL, a related party, in the
aggregate principal amount of $48.9 million, repayable at the end of 4 months at
an interest rate of LIBOR plus 1.25% per annum. Pursuant to a loan agreement
signed in June 2008, the maturity date of this loan was extended for an
additional period of seven years. Interest accrues at a per annum rate of LIBOR
plus 6%. Principal and interest are due and payable in four equal annual
installments, commencing on June 30, 2012. At any time we can make prepayments
without premium or penalty.
Mr.
Jackob Maimon, Isramco’s president and director is a director of JOEL and Mr.
Haim Tsuff, Isramco’s Chief Executive Officer and Chairman, is a controlling
shareholder of JOEL.
In
connection with the Company’s purchase in February 2007 (See Note 2) of certain
oil and gas interests mainly in New Mexico and Texas, the Company obtained loans
in the total principle amount of $42 million from Naphtha Israel Petroleum Corp.
Ltd., (“Naphtha Petroleum”) with terms and conditions as below:
Pursuant
to a Loan Agreement dated as of February 27, 2007 (the "Loan Agreement"),
Isramco obtained $18.5 million. The outstanding principal amount of the loan
accrues interest at per annum rate equal to the London Inter-bank Offered Rate
(LIBOR) plus 5.5%, not to exceed 11% per annum. Interest is payable at the end
of each loan year. Principal plus any accrued and unpaid interest are due and
payable on February 26, 2014. Interest after the maturity date accrues at the
per annum rate of LIBOR plus 12% until paid in full. At any time, Isramco is
entitled to prepay the outstanding amount of the loan without penalty or
prepayment. To secure its obligations that may be incurred under the Loan
Agreement, Jay Petroleum, LLC, a wholly – owned subsidiary of Isramco, agreed to
guarantee the indebtedness. Naphtha can accelerate the loan and exercise its
rights under the collateral upon the occurrence any one or more of the following
events of default: (i) Isramco's failure to pay any amount that may become due
in connection with the loan within five (5) days of the due date (whether by
extension, renewal, acceleration, maturity or otherwise) or fail to make any
payment due under any hedge agreement entered into in connection with the
transaction, (ii) Isramco's material breach of any of the representations or
warranties made in the loan agreement or security instruments or any writing
furnished pursuant thereto, (iii) Isramco's failure to observe any undertaking
contained in transaction documents if such failure continues for 30 calendar
days after notice, (iv) Isramco's insolvency or liquidation or a bankruptcy
event or(v) Isramco's criminal indictment or conviction under any law pursuant
to which such indictment or conviction can lead to a forfeiture by Isramco of
any of the properties securing the loan.
Mr.
Jackob Maimon, Isramco's President at the time and a director is a director of
Naphtha Petroleum and Mr. Haim Tsuff, Isramco's Chief Executive Officer and
Chairman is a controlling shareholder of Naphtha Petroleum.
Pursuant
to a Loan Agreement dated as of February 27, 2007 (the "Second Loan Agreement")
Isramco obtained a loan from Naphtha Petroleum, in the principal amount of $11.5
million, repayable at the end of seven years. Interest accrues at a per annum
rate of LIBOR plus 6%. Principal is due and payable in four equal installments,
commencing on the fourth anniversary of the date of the loan. Interest is
payable annually upon each anniversary date of this Loan. At any time Isramco
can make prepayments without premium or penalty. The Second Loan is not secured.
The other terms of the Second Loan Agreement are identical to the terms of the
Loan Agreement.
Pursuant
to a Loan Agreement dated as of February 27, 2007 (the "Third Loan Agreement ")
Isramco obtained a loan from Naphtha Petroleum, in the principal amount of $12
million, repayable at the end of five years. Interest accrues at a per annum
rate of LIBOR plus 6%. Principal is due and payable in four equal annual
installments, commencing on the second anniversary of the loan. Accrued interest
is payable in equal annual installments. At any time Isramco can make
prepayments without premium or penalty. The Third Loan is not secured. The other
terms of the Third Loan Agreement are identical to the terms of the Loan
Agreement. Pursuant to a Loan Agreement dated as of February 26, 2007 Isramco
obtained a loan from JOEL Jerusalem Oil Exploration Ltd, a related party
("JOEL"), in the principal amount of $7 million, repayable at the end of 3
months (that was extended until July 11, 2007). Interest accrues at a per annum
rate of 5.36%. On July 2007, the Company and JOEL reached an agreement to revise
the period of the Loan to seven years and the interest rate to LIBOR plus 6%.
Mr. Jackob Maimon, Isramco's president at the time and a current director is a
director of JOEL and Mr. Haim Tsuff, Isramco's Chief Executive Officer and
Chairman is a controlling shareholder of JOEL.
Effective
February 1, 2009, each of the loans from I.O.C. – Israel Oil Company, Inc. and
Naphtha Israel Petroleum Corp., Ltd., to the Corporation was amended and
restated to extend the payment deadlines arising and after February, 2009, by
two years.
Aggregate
maturities required on long-term debt at February 1, 2009 are due in future
years as follows (in thousands):
2009
$
21,000
2010
1,400
2011
19,350
2012
44,875
2013
19,500
Thereafter
38,429
Total
$
144,554
Interest
expense (income)
The
following table summarizes the amounts included in interest expense for the
years ended December 31, 2008, 2007 and 2006:
Current
debt, long-term debt and other - banks corporation
$
3,369
$
1,624
$
(318)
Long-term
debt – related parties
6,486
4,720
164
$
9,855
$
6,344
$
(154
)
9. Income
Taxes
Isramco
operates through its various subsidiaries in the United States (“U.S.);
accordingly, income taxes have been provided based upon the tax laws and rates
of the U.S. as they apply to Isramco’s current ownership structure.
Isramco
accounts for income taxes pursuant to SFAS No. 109, Accounting for Income Taxes,
which requires recognition of deferred income tax liabilities and assets for the
expected future tax consequences of events that have been recognized in
Isramco’s financial statements or tax returns. Isramco provides for deferred
taxes on temporary differences between the financial statements and tax basis of
assets using the enacted tax rates that are expected to apply to taxable income
when the temporary differences are expected to reverse.
Isramco
adopted FIN 48, effective January 1, 2007. Isramco recognizes
interest and penalties related to unrecognized tax benefits within the provision
for income taxes on continuing tax benefits. There are no unrecognized tax
benefits that if recognized would affect the tax rate. There was no interest or
penalties recognized as of the date of adoption or for the twelve months ended
December 31, 2008. The Company files tax returns in the U.S. and
states in which it has operations and is subject to taxation. Tax years
subsequent to 2005 remain open to examination by taxing
authorities.
The
income tax provision differs from the amount of income tax determined by
applying the Federal Income Tax Rate to pre-tax income from continuing
operations for the years ended December 31, 2008, 2007 and 2006 due to the
following:
Deferred
tax assets at December 31, 2008 and 2007 are comprised primarily of net
operating loss carryforwards and book impairment from write downs of assets.
Deferred tax liabilities consist primarily of the difference between book and
tax basis depreciation, depletion and amortization (DD&A). Book basis in
excess of tax basis for oil and gas properties and equipment primarily results
from differing methodologies for recording property costs and depreciation,
depletion and amortization under United States generally accepted accounting
principles and income tax reporting. There is a net deferred tax asset and it is
management’s opinion that a valuation allowance is not needed.
The
principal components of Isramco's deferred tax assets and liabilities as of
December 31 were as follows (in thousands):
The
principal components of Isramco's Income Tax Provision for the years indicated
below were as follows (in thousands):
2008
2007
2006
Current
income tax:
Federal
$
276
$
1,427
$
(167
)
Foreign
(659
)
741
400
State
114
-
150
Total
current income tax
$
(269
)
$
2,168
$
383
Deferred
income tax
Federal
$
884
$
7,360
$
343
Foreign
-
-
-
State
(238
)
-
-
Total
deferred income tax
$
646
$
7,360
$
343
Provision
for income tax
$
377
$
(5,192
)
$
726
At
December 31, 2008, the Company has U.S. tax loss carry forwards of approximately
$16,586 thousand, which will expire in various amounts beginning in 2029 and
ending in 2030.
10. Earnings
Per Share
The
following table sets forth the computation of Net Income Per Share Available to
Common Stockholders for the years ended December 31 (in thousands, except per
share data):
2008
2007
2006
Numerator
for Basic and Diluted Earnings per Share -
Net
Income (loss) from continuing operations
$
3,229
$
(6,411
)
$
6,569
Net
Income (loss)
-
-
$
3,842
Denominator
for Basic Earnings per Share -
Weighted
Average Shares
2,717,691
2,717,691
2,717,691
Potential
Dilutive Common Shares -
-
-
-
Adjusted
Weighted Average Shares
2,717,691
2,717,691
2,717,691
Net
Income Per Share Available to Common Stockholders – Basic and
Diluted
The 1993
stock option plan (the 1993 Plan) was approved at the annual meeting of
shareholders held in August 1993. As of December 31, 2007, 20,050 shares of
common stock were reserved for issuance under the 1993 Plan. Options granted
under the 1993 Plan may be either incentive stock options under the Internal
Revenue Code or options that do not qualify as incentive stock options. Options
granted under the 1993 Plan may be exercised for a period of up to ten years
from the grant date. The exercise price for an incentive stock option may not be
less than 100% of the fair market value of Isramco's common stock on the date of
grant. All the options granted under the 1993 Plan to date were fully vested on
the date of grant. The administrator of the 1993 Plan may set the exercise price
for a nonqualified stock option at less than 100% of the fair market value of
Isramco's common stock on the date of grant.
No stock
options were granted during 2008, 2007 and 2006. Shares of common stock reserved
for future issuance under the 1993 plan are 20,050 shares. There are no granted
stock options outstanding under the 1993 Plan as of balance sheet
date.
12. Supplemental
Cash Flow Information
Cash paid
for interest and income taxes was as follows for the years ended
December 31 (in thousands):
2008
2007
2006
Interest
$
7,014
$
3,284
$
217
Income
taxes
$
80
$
174
$
76
The
consolidated statements of cash flows for the year ended December 31, 2008
exclude the following non-cash transactions:
·
Asset
retirement obligation from acquired properties and additional revision to
current properties of $12.3 million included in the oil and gas
properties
The
consolidated statements of cash flows for the year ended December 31, 2007
exclude the following non-cash transactions:
·
Property
and equipment of $700 thousand included in accounts
payable
·
Sale
of assets, liabilities and rights in total amount of $13.6 million against
loan from related party
·
Asset
retirement obligation from acquired properties of $2.1 million included in
the oil and gas properties
13. Concentrations
of Credit Risk
Financial
instruments, which potentially expose Isramco to concentrations of credit risk,
consist primarily of trade accounts receivable and oil and gas derivative
assets. Isramco's customer base includes several of the major United States oil
and gas operating and production companies. Although Isramco is directly
affected by the well-being of the oil and gas production industry, management
does not believe a significant credit risk existed as of December 31, 2008. The
fair value of oil and gas derivatives contracts will be significantly impacted
by the change in oil and gas future prices. Isramco continues to monitor and
review credit exposure of its marketing counter-parties.
Isramco
maintains deposits in banks, which may exceed the amount of federal deposit
insurance available. Management periodically assesses the financial condition of
the institutions and believes that any possible deposit loss is
minimal.
A
significant portion of Isramco's cash and cash equivalents is invested in
marketable securities. Substantially all marketable securities owned by Isramco
are held by banks in Israel and Switzerland.
From time
to time, the Company may be a plaintiff or defendant in a pending or threatened
legal proceeding arising in the normal course of its business. All known
liabilities are accrued based on the Company’s best estimate of the potential
loss. In the opinion of management, Isramco's ultimate liability, if any, in
these pending actions would not have a material adverse effect on the financial
position, operating results or liquidity of Isramco.
15. Asset
retirement obligation
If a
reasonable estimate of the fair value of an obligation to perform site
reclamation, dismantle facilities or plug and abandon wells can be made, the
Company records a liability (an asset retirement obligation or ARO) on the
consolidated balance sheet and capitalizes the asset retirement cost in oil and
natural gas properties in the period in which the retirement obligation is
incurred. In general, the amount of an ARO and the costs capitalized will be
equal to the estimated future cost to satisfy the abandonment obligation using
current prices that are escalated by an assumed inflation factor up to the
estimated settlement date, which is then discounted back to the date that the
abandonment obligation was incurred using an assumed cost of funds for the
company. After recording these amounts, the ARO is accreted to its future
estimated value using the same assumed cost of funds and the additional
capitalized costs are depreciated on a unit-of-production basis.
The
following table presents the reconciliation of the beginning and ending
aggregate carrying amount legal obligations associated with the retirement of
oil and gas properties at December 31 (in thousands):
2008
2007
Liability
for asset retirement obligation at the beginning of the
year
$
2,670
$
356
Liabilities
Incurred
8,480
2,050
Liabilities
Settled
(17
)
-
Accretion
847
219
Revisions
(*)
3,753
45
Liability
for asset retirement obligation at the end of the
year
$
15,733
$
2,670
(*) In
2008, management revised the asset retirement obligation liabilities to reflect
the increase the costs of fulfilling such obligations and the decrease in the
estimated life of the wells.
16. Geographical
Segment Information
In 2008,
all activities are within the United States.
Isramco's operations for 2007 involve
one industry segment - the exploration, development, and production of oil and
natural gas. Prior to 2007, Isramco operated in two industry segments - oil and
gas activities and leasing its cruise line vessel. Its current oil and gas
activities are concentrated in the United States and Israel (on December 31,2007the 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 gas
2007
Sales
and other operating revenues
$
20,916
$
1,840
$
22,756
Costs
and operating expenses
19,796
1,387
21,183
Operating
profit (loss)
$
1,120
$
453
$
1,573
Interest
income
(
434
)
Interest
expense
6,778
Gain
on marketable securities and net gain in investee
(
52
)
Realized
gain on sale of investment and capital gain
In March
2004, Isramco purchased a luxury cruise liner for aggregate consideration of
$8.05 million. Isramco, through its wholly owned subsidiary, Magic 1 Cruise Line
Corp., a British Virgin Island corporation (“Magic I Corp.”), leased the vessel
to European based tour operator from April 2005 through October 2005 and from
April 6, 2006 through November 5, 2006. In December 2006, Isramco sold all of
the outstanding share capital of Magic 1 Corp. to an unrelated third party for
total consideration of approximately $2.15 million The sale included the
assumption by the purchaser of a loan in the principal amount of $3.3 million.
Following the sale, Isramco is no longer engaged in the cruising
business.
Results
of operation from discontinued operation for the year ended December
31,
18. Supplementary
Oil and Gas Information (Unaudited)
The
following supplemental information regarding the oil and gas activities of
Isramco for 2008, 2007 and 2006 is presented pursuant to the disclosure
requirements promulgated by the Securities and Exchange Commission and SFAS No.
69, "Disclosures About Oil and Gas Producing Activities." Capitalized costs
relating to oil and gas activities and costs incurred in oil and gas property
acquisition, exploration and development activities for each year are shown
below.
CAPITALIZED
COST OF OIL AND GAS PRODUCING ACTIVITIES (IN THOUSANDS)
As
of December 31
2008
2007
United
States
United
States
Unproved
properties not being amortized
$
-
$
3,603
Proved
property being amortized
219,945
105,337
Accumulated
depreciation, depletion amortization and impairment
(56,109
)
(16,291
)
Net
capitalized costs
163,833
93,649
COSTS
INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT
ACTIVITIES (IN THOUSANDS)
As
of December 31
2008
2007
2006
United
States
Property
acquisition costs—proved and unproved properties
$
97,502
$
86,284
$
1,609
Exploration
costs
$
-
$
269
$
125
Development
costs
$
1,167
$
2,691
$
4,652
OIL
AND GAS RESERVES
Oil and
gas proved reserves cannot be measured exactly. The engineers interpreting the
available data, as well as price and other economic factors, base reserve
estimates on many variables related to reservoir performance, which require
evaluation. The reliability of these estimates at any point in time depends on
both the quality and quantity of the technical and economic data, the production
performance of the reservoirs as well as extensive engineering judgment.
Consequently, reserve estimates are subject to revision, as additional data
become available during the producing life of a reservoir. When a commercial
reservoir is discovered, proven reserves are initially determined based on
limited data from the first well or wells. Subsequent data may better define the
extent of the reservoir and additional production performance, well tests and
engineering studies will likely improve the reliability of the reserve estimate.
The evolution of technology may also result in the application of improved
recovery techniques such as supplemental or enhanced recovery projects, or both,
which have the potential to increase reserves beyond those envisioned during the
early years of a reservoir's producing life.
The
following table represents Isramco's net interest in estimated quantities of
proved developed and undeveloped reserves of crude oil, condensate, natural gas
liquids and natural gas and changes in such quantities at December 31, 2008,
2007 and 2006, and for the years then ended. Net proved reserves are the
estimated quantities of crude oil and natural gas which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Proved developed reserves are proved reserve volumes that can be
expected to be recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves are proved reserve volumes that
are expected to be recovered from new wells on undrilled acreage or from
existing wells where a significant expenditure is required for recompilation.
All of Isramco's proved reserves are in the United States. Isramco's oil and gas
reserves are priced at $5.62 and $44.60 per barrel per Mcf, respectively, at
December 31, 2008.
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOW
The
standardized measure of discounted future net cash flows relating to Isramco's
proved oil and gas reserves is calculated and presented in accordance with
Statement of Financial Accounting Standards No. 69. Accordingly, future cash
inflows were determined by applying year-end oil and gas prices to Isramco's
estimated share of the future production from proved oil and gas
reserves.
Future
production and development costs were computed by applying year-end costs to
future years. Applying year-end statutory tax rates to the estimated net future
cash flows derived future income taxes. A prescribed 10% discount factor was
applied to the future net cash flows.
In
Isramco's opinion, this standardized measure is not a representative measure of
fair market value. The standardized measure is intended only to assist financial
statement users in making comparisons among companies.
2008
2007
2006
Future
cash inflows
$
277,008,941
$
450,981,415
$
18,208,000
Future
development costs
(511,810
)
(3,502,500
)
(866,000
)
Future
production costs
(146,421,245
)
(178,384,211
)
(7,170,000
)
Future
income tax expenses
-
(63,983,746
)
(2,976,000
)
Future
net cash flows before 10% discount
130,075,886
205,110,958
7,196,000
10%Annual
discount for estimated timing of cash flows
(56,698,274
)
(108,345,218
)
(2,875,000
)
Standardized
measure discounted future net cash flows
$
73,377,612
$
96,765,740
$
4,321,000
CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The
principal sources of change in the standardized measure of discounted future net
cash flows for the years ended December 31, 2008, 2007 and 2006 were as
follows:
2008
2007
2006
Beginning
of the year
$
96,765,740
$
4,321,000
$
10,695,000
Sales
and transfers of oil and gas produced, net of production
costs
(31,469,183
)
(13,267,315
)
(1,048,000
)
Net
changes in prices and production costs
(144,454,304
)
6,084,956
(5,629,000
)
Net
changes in income taxes
28,376,801
(8,075,637
)
4,961,000
Changes
in estimated future development costs, net of current development
costs
