ITEM 1. BUSINESS
Overview
Isramco, Inc., a Delaware corporation incorporated in 1982 (hereinafter, “we”, the “Company” or “Isramco”), together with its wholly-owned subsidiaries, Isramco Energy LLC (“Isramco Energy”), Isramco Resources, LLC (“Isramco Resources”), Jay Petroleum, LLC ("Jay Petroleum"), Jay Management Company, LLC ("Jay Management") and Field Trucking and Services, LLC (”FTS”) (collectively “Isramco” or the “Company”), explore for, develop and produce natural gas and crude oil and operate oil and gas properties in the United States. Isramco's principal producing and exploring areas are further described in "Exploration, Development and Production" below.
At December 31, 2010, 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 9,031 thousand barrels of oil equivalent (“MBOE”), consisting of 3,318 thousand barrels (Bbls) of oil, and 23,701 million cubic feet (Mcf) of natural gas and 1,763 thousand barrels (Bbls) natural gas liquids. Approximately 97% of our proved reserves were classified as proved developed producing (See Note 16 Supplemental Oil and Gas Information to Consolidated Financial Statements to our consolidated financial statements). We maintain operational control of approximately 77% of our proved reserves. Full year 2010 production averaged 2.3 MBOE/d compared to 2.42 MBOE/d in 2009.
Our business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs, acquiring strategic oil and gas properties and improving of existing oil and gas properties. Over the course of 2010, we have expanded our activities in the United States through continued development of existing proved properties. An additional important goal for implementing our business strategy is to maintain the lowest possible operating cost structure, among other things, by serving as operator of a substantial portion of our oil and natural gas properties.
Exploration, Development and Production
United States
We, through our wholly-owned subsidiaries, are involved in oil and gas exploration, developing, production and operation of wells in the United States. We own varying working interests in oil and gas wells in Louisiana, Texas, New Mexico, Oklahoma, Wyoming, Utah and Colorado and currently serve as operator of approximately 589 wells located mainly in Texas and New Mexico. The following is a summary of significant developments during 2010 through the present, including certain 2011 plans.
Acquisitions: On March 27, 2008, we purchased from GFB Acquisition - I, L.P. (“GFB”) and Trans Republic Resources, Ltd. (“Trans Republic,” and, together with GFB, the “Sellers”) interests in certain oil and gas properties located in Texas, New Mexico, Utah, Colorado and Oklahoma for an aggregate purchase price of approximately $102 million. The transaction included mainly operated oil and gas properties in approximately 40 fields (approximately 490 Leases) in East Texas, Texas Gulf Coast, Permian, Anadarko and San Juan Basins. Significant fields are the Alabama Ferry Field in East Texas, the Bagley Field in West Texas and New Mexico, and the Esperson Dome Field on the Texas Gulf Coast.
On March 2, 2007, we purchased certain oil and gas properties located in Texas and New Mexico from Five States Energy Company, LLC (“Five States”) for a purchase price of $92 million.
Divestiture: In December, 2010, we completed the sale of our interests in certain properties located in Wise and Parker Counties, Texas, for approximately $2.2 million in cash. As of December 31, 2009, we had approximately 5 MBOE of proved reserves associated with these properties. Production from these properties as of the sale date was approximately 0.029 MBOE /d.
Israel
In 2007 we closed our branch office in Israel in order to focus on our expanding presence in the United States. However, we retained certain interests in various oil and gas leases, which are discussed below.
Tamar and Dalit Leases- We own an overriding royalty interest of 1.5375% in the Tamar and Dalit gas Leases, located offshore Israel, which will increase to 2.7375% after payout. In January 2009, Noble Energy Mediterranean Ltd. (“Noble”), the operator of the Leases, completed the Tamar # 1 (“Tamar”) well at a depth of 16,076 feet and in approximately 5,500 feet of water.
Following the Tamar #1 well Noble and its other partners drilled two additional wells. One was an exploration well, the Dalit # 1 well that was spudded on March 6, 2009. The second well was an appraisal well known as the Tamar #2 that was drilled to further define the resources available in the Tamar structure and to obtain information that will be important in the planning of the development for this field. On April 15, 2009, Noble announced flow test results from the Dalit natural gas discovery in the Michal license. The tests, which yielded a flow rate of 33 Mmcf/d of natural gas, were limited by the testing equipment available on the drilling rig.
On July 7, 2009, Noble announced the results from its Tamar #2 appraisal well. This well was, drilled to a total depth of 16,880 feet in 5,530 feet of water and is located approximately 3.5 miles northeast of the original discovery, Tamar #1. It was drilled on the flank of the structure with the intent of confirming reservoir quality and continuity, the appraisal well was also designed to confirm the projected gas/water contact.
According to the public documents filed by Noble, specifically, its Form 10-Q Quarterly Report filed July 30, 2009, the results of these operations were successful.
The government of Israel is currently considering proposals to impose a tax or charge upon oil and gas revenues, including revenues from oil and gas produced from the Tamar well. As currently proposed, such oil and gas revenues would be subject to a sliding scale of taxation, beginning with the imposition of a 20% charge on oil and gas revenues at such time as total revenues received equal 1.5 times the costs expended and increasing in steps to a 50% charge imposed at such time as revenues received equal 1.5 times the costs expended. The current proposal provides some relief for oil and gas revenues received from reservoirs developed before January 2014 by delaying the imposition of the charges; i.e. the 20% charge would become effective at such time as total revenues received equal 2 times the costs expended and the maximum 50% charge would not become effective until revenues received equaled 2.8 times costs expended.
Isramco’s overriding royalty would be subject to the above taxation at such time, and at the same rates, as the revenues attributable to the operating interest. Obviously the imposition of such charges would significantly decrease the amount of any revenues ultimately received as a result of the Corporation’s Israeli oil and gas interests.
The Israeli Petroleum Commissioner granted the partners two leases that are to expire on December 2038, covering Tamar and Dalit gas fields
Med Yavne Lease. Based on the gas finds known as "Or 1", a 30 year lease covering 53 square kilometers (approximately 13,100 acres) offshore Israel, was granted in June 2000 (the "Med Yavne Lease"). The original operator of the Med Yavne Lease was BG International Limited, a member of the British Gas Group ("BG"). BG resigned as the operator of the Lease and relinquished of its working interests in the Med Yavne Lease, and the partners appointed I.O.C - Israel Oil Company Ltd ("IOC") as the successor operator.
The operator performed a 3D seismic survey in the area of the Med Yavne lease. In January 2008 and in January 2009, IOC received an opinion from a consulting firm in the United States that performed a techno-economic examination of the development of the Or 1 reserve. This opinion indicates that, under certain assumptions, development of the Or 1 reserves by connection to a nearby platform (at a distance of seven miles) and from there via an existing transportation pipeline to the coast of Israel may be economically feasible. It is the intention of the partners in Med Yavne Lease to cooperate with independent third parties to jointly develop Or 1 reserves with the third party gas reserves.
Our participation interest of the Med Yavne Lease is 0.7052 %
All oil and gas assets in Israel are subject to a 12.5% Overriding Royalty payable to the Government of Israel under the Israeli Petroleum Law.
The expiration date of any Lease is subject to the fulfillment of applicable provisions of the Israel Petroleum Law and Regulations and the conditions and work obligations of each of the above leases.
Overriding Royalties. We hold Overriding Royalties in certain oil and gas assets. Additionally, we are entitled to receive from certain participants in the Med Yavne Lease overriding royalties equal to 2% of each such participant's rights to any oil/gas produced within those leases. The table below sets forth the Overriding Royalties held by us:
(1) A 30-year lease covering an area of approximately 53 square kilometers (including the area of the gas discovery) was granted in June 2000.
Derivative Instruments and Hedging Activities
We utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our anticipated future oil and natural gas production. We generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next 48 and 15 months, respectively. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivative contracts, which would potentially allow us to not record the change in fair value of our derivative contracts in the consolidated statements of operations. We carry our derivatives at fair value on our consolidated balance sheets, with the changes in the fair value included in our consolidated statements of operations in the period in which the change occurs. Our results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivative contracts.
As of December 31, 2010 we had swap contracts for a volume of 523,209 barrels of crude oil during 48 months, commencing January 2010, and swap contracts for a volume of 939,042 MMBTU of natural gas during 15 months commencing January 2010.
Hereunder are the open swap contracts positions as of December 31, 2010:
(*) Mcf = MMBTU
On March 9, 2011, pursuant to an agreement with Wells Fargo, the derivative contracts between Isramco and Wells Fargo were terminated and the Company signed new swap contracts with Macquarie Bank, N.A. for an aggregate volume of 336,780 barrels of crude oil during the 46 month period commencing March 2011.
During the second quarter of 2009, we made the decision to mitigate a portion of our interest rate risk with interest rate swaps. These swap instruments reduce our exposure to market rate fluctuations by converting variable interest rates to fixed interest rates.
Under these swaps, we make payments to, or receive payments from, the counterparties based upon the differential between a specified fixed price and a price related to the three-month LIBOR. These interest rate swaps convert a portion of our variable rate interest on our Scotia debt (as defined in Note 6, “Long-term Debt and Interest Expense”) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. We have elected to designate these positions for hedge accounting and therefore the unrealized gains and losses are recorded in accumulated other comprehensive loss. The Company measures hedge effectiveness by assessing the changes in the fair value or expected future cash flows of the hedged item.
Our open interest rate positions, as described above, are as follows:
Competitive Conditions in the Business
The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring attractive producing oil and natural gas properties, obtaining purchasers and transporters of the oil and natural gas we produce and hiring and retaining key employees. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.
Markets and Major Customers
Through our wholly-owned subsidiary Jay Management Company, LLC ("Jay Management"), we operate a substantial portion of our oil and natural gas properties. As the operator of a property, the Company makes full payment of the costs associated with each property and seeks reimbursement from the other working interest owners in the property for their share of those costs. Isramco’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general were adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected.
The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. The Company has not experienced any significant losses from uncollectible accounts. The Company does not believe the loss of any one of its purchasers would materially affect the Company’s ability to sell the oil and natural gas it produces. The Company believes other purchasers are available in the Company’s areas of operations.
Seasonality of Business
Weather conditions affect the demand for, and prices of, natural gas and can disrupt our overall business plans. Demand for natural gas is typically higher in the fourth and first quarters resulting in higher natural gas prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
Operational Risks
Oil and natural gas exploration and development involves a high degree of risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will discover or acquire additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other circumstances may cause accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids, into the environment, or cause significant injury to persons or property. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in loss of oil and natural gas properties.
We carry insurance against such hazards. However, as is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business, either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations. For further discussion on risks, see Item 1A.
ITEM 1A. RISK FACTORS
In addition to the other information contained in this Annual Report on Form 10-K, investors should consider carefully the following risk factors, which may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could be materially and adversely affected and the trading price of our common stock could decline.
Oil, natural-gas and NGLs prices are volatile. A substantial or extended decline in prices could adversely affect our financial condition and results of operations.
Prices for oil, natural gas and NGLs ((Natural Gas Liquids) can fluctuate widely. Our revenues, operating results and future growth rates are highly dependent on the prices we receive for our oil, natural gas and NGLs. Historically, the markets for oil, natural gas and NGLs have been volatile and may continue to be volatile in the future. For example, in recent years market prices for natural gas in the United States have declined substantially from the highs achieved in 2008 and the rapid development of shale plays throughout North America has contributed significantly to this trend. Factors influencing the prices of oil, natural gas and NGLs are beyond our control. These factors include, among others:
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the worldwide military and political environment, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities or further acts of terrorism in the United States, or elsewhere;
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worldwide and domestic supplies of crude oil and natural gas;
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actions taken by foreign oil and gas producing nations;
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the level of global crude oil and natural gas inventories;
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the price and level of foreign imports of oil, natural gas and NGLs;
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the effect of worldwide energy conservation efforts;
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the price and availability of alternative and competing fuels;
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the availability of pipeline capacity and infrastructure;
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the availability of crude oil transportation and refining capacity;
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weather conditions;
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electricity dispatch;
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domestic and foreign governmental regulations and taxes; and
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the overall economic environment.
The long-term effect of these and other factors on the prices of oil, natural gas and NGLs are uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:
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limiting our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;
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reducing the amount of oil, natural gas and NGLs that we can produce economically;
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causing us to delay or postpone some of our capital projects;
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reducing our revenues, operating income and cash flows;
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reducing the carrying value of our crude oil and natural gas properties;
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reducing the amounts of our estimated proved oil and natural-gas reserves;
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reducing the standardized measure of discounted future net cash flows relating to oil and natural-gas reserves; and
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limiting our access to sources of capital, such as equity and long-term debt.
Our domestic operations are subject to governmental risks that may impact our operations.
Our domestic operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, tribal, local and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies, price or gathering-rate controls, hydraulic fracturing and environmental protection regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including environmental and tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, currently proposed federal legislation, that, if adopted, could adversely affect our business, financial condition and results of operations, includes the following:
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Climate Change. In the recently concluded session of Congress, climate-change legislation establishing a “cap-and-trade” plan for green-house gases (GHGs) was approved by the U.S. House of Representatives.. The U.S. Environmental Protection Agency (EPA) has also taken recent action related to GHGs. EPA has made findings and issued regulations that require the establishment and reporting of an inventory of greenhouse gas emissions and that could lead to the imposition of restrictions on greenhouse gas emissions from stationary sources such as ours. While it is not possible at this time to predict whether or when the Congress may act on climate-change legislation, legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the natural gas and oil that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas and oil.
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Taxes. The U.S. President’s Fiscal Year 2012 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural-gas exploration and development, and (iii) implementing certain international tax reforms.
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Hydraulic Fracturing. In the recently concluded session of Congress, legislation amending the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural-gas industry in the hydraulic-fracturing process was considered. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. It is not possible at this time to predict whether or when the current session of Congress may act on hydraulic-fracturing legislation. Such legislation, if adopted, could establish an additional level of regulation and permitting at the federal level.
The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.
The U.S. Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission (the CFTC) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the new legislation, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the legislation and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.
Oil and gas drilling is a speculative activity and risky.
We are engaged in the business of oil and natural gas exploration, production and operations and the development of productive oil and gas wells. Our growth will be materially dependent upon the success of our future drilling program. Drilling for oil and gas involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs or crews and the delivery of equipment. Although we believe that the use of 3-D seismic data and other advanced technology should increase the probability of success of our wells and should reduce average finding costs through elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic data and other traditional methods, drilling remains an inexact and speculative activity. In addition, the use of 3-D seismic data and such technologies requires greater pre-drilling expenditures than traditional drilling strategies and we could incur losses because of such expenditures. Our future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse effect on our future results of operations and financial condition. Although we may discuss drilling prospects that have been identified or budgeted for, we may ultimately not lease or drill these prospects within the expected time frame, or at all. We may identify prospects through a number of methods, some of which do not include interpretation of 3-D or other seismic data. The drilling and results for these prospects may be particularly uncertain. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including (i) the results of exploration efforts and the acquisition, review and analysis of the seismic data, (ii) the availability of sufficient capital resources and the other participants for the drilling of the prospects, (iii) the approval of the prospects by other participants after additional data has been compiled, (iv) economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews, (v) our financial resources and results (vi) the availability of leases and permits on reasonable terms for the prospects and (vii) the payment of royalties to lessors. There can be no assurance that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas. There are numerous uncertainties in estimating quantities of proved reserves, including many factors beyond our control.
Failure to fund continued capital expenditures could adversely affect our properties.
Our acquisition, exploration, and development activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations and loans from commercial banks and related parties. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of crude oil and natural gas, and our success in finding, developing and producing new reserves. If revenues were to decrease as a result of lower crude oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves, resulting in a decrease in production over time. If our cash flows from operations are not sufficient to meet our obligations and fund our capital budget, we may not be able to access debt, equity or other methods of financing on an economic basis to meet these requirements, particularly in the current economic environment. If we are not able to fund our capital expenditures, interests in some properties might be reduced or forfeited as a result.
Poor general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy.
These factors, combined with volatile oil, natural-gas and NGLs prices, declining business and consumer confidence, and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, or if an economic recovery is slow or prolonged, demand for petroleum products could continue to diminish or stagnate, which could impact the price at which we can sell our oil, natural gas and NGLs, affect our vendors’, suppliers’ and customers’ ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition.
Estimates of proved oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.
This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
At December 31, 2010, 100% of our estimated reserves were classified as proved developed.
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 oil and gas leases. These leases are conditioned on the performance of certain obligations, primarily the obligation to produce oil and/or gas or engage in operations designed to result in the production of oil and gas. If production ceases and operations are not commenced within a specified time, the lease may be lost. The loss of our leases may have a material impact on our revenues.
In the case of Israeli-based properties, we have interests in licenses that, subject to certain conditions, may result in leases being granted. The leases are subject to certain obligations and are renewable at the discretion of various governmental authorities. As such, if the parties responsible for operations are not able to fulfill their obligations under the leases, the leases may be modified, cancelled, not renewed, or renewed on terms different from the current leases. The modification or cancellation of our leases could eliminate our interests and may have a material impact on our revenues.
Our business is highly competitive.
The oil and natural gas industry is highly competitive in many respects, including identification of attractive oil and natural gas properties for acquisition, drilling and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities. In seeking suitable opportunities, we compete with a number of other companies, including large oil and natural gas companies and other independent operators with greater financial resources, larger numbers of personnel and facilities, and with more expertise. There can be no assurance that we will be able to compete effectively with these entities.
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:
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the domestic and foreign supply of, and demand for oil and natural gas;
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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;
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political instability, armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;
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the growth of consumer product demand in emerging markets, such as India and China;
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labor unrest in oil and natural gas producing regions;
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weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;
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the price and availability of alternative and competing fuels;
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the price and level of foreign imports of oil, natural gas and NGLs; and
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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 a credit facility.
Our hedging activities may prevent us from benefiting fully from price increases and may expose us to other risks.
In order to manage our exposure to price risks in the marketing of our oil and natural gas production, we have entered into oil and natural gas price hedging arrangements with respect to a portion of our anticipated production and we may enter into additional hedging transactions in the future. While intended to reduce the effects of volatile oil and natural gas prices, such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:
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our actual production is less than hedged volumes;
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there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or
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the counterparties to our hedging agreements fail to perform under the contracts.
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a sudden unexpected event materially impacts oil and natural-gas prices.
The credit risk of financial institutions could adversely affect us.
We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, insurance companies and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions through our derivative transactions. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.
We have no means to market our oil and gas production without the assistance of third parties.
The marketability of our production depends upon the proximity of our reserves to, and the capacity of, facilities and third party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or lack of capacity of such services and facilities could impair or delay the production of new wells or the delay or discontinuance of development plans for properties. A shut-in, delay or discontinuance could adversely affect our financial condition. In addition, regulation of oil and natural gas production transportation in the United States or in other countries may affect its ability to produce and market our oil and natural gas on a profitable basis.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies and/or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production in response to strong prices of oil and natural gas may increase the demand for oilfield services, and the costs of these services may increase, while the quality of these services may suffer.
Our oil and natural gas activities are subject to various risks that are beyond our control.
Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and natural gas. Although we may take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce oil and natural gas in commercial quantities, the rate of production and the economics of the development of, and our investment in the prospects in which we have or will acquire an interest. Any of these risks and hazards could materially and adversely affect our financial condition, results of operations and cash flows. Such risks and hazards include:
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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;
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blowouts, fires, hurricanes, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;
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unavailability of materials and equipment;
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engineering and construction delays;
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unanticipated transportation costs and delays;
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unfavorable weather conditions;
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hazards resulting from unusual or unexpected geological or environmental conditions;
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environmental regulations and requirements;
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accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids, into the environment;
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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;
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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
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the availability of alternative fuels and the price at which they become available.
We do not insure against all potential losses and could be materially and adversely affected by unexpected liabilities.
The exploration for, and production of, natural gas and crude oil can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, fires and loss of well control, which can damage or destroy wells or production facilities, injure or kill people, and damage property and the environment. Moreover, our onshore operations are subject to customary perils, including hurricanes and other adverse weather conditions. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. The occurrence of any of these events and any costs or liabilities incurred as a result of such events would reduce the funds available to us for our exploration, development and production activities and could, in turn, have a material adverse effect on our business, financial condition and results of operations.
Governmental and environmental regulations could adversely affect our business.
Our business is subject to federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing of oil and natural gas and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste, unitization and pooling of properties and other matters. These laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and natural gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our revenues.
Our operations are also subject to complex environmental laws and regulations adopted by the various jurisdictions in which we have or expect to have oil and natural gas operations. We could incur liability to governments or third parties for any unlawful discharge of oil, natural gas or other pollutants into the air, soil or water, including responsibility for remedial costs. We could potentially discharge these materials into the environment in any of the following ways:
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from a well or drilling equipment at a drill site;
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from gathering systems, pipelines, transportation facilities and storage tanks;
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damage to oil and natural gas wells resulting from accidents during normal operations; and
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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 growth is primarily due to acquisitions of producing properties and underdeveloped leaseholds. We expect acquisitions may also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise in the future. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. Because of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.
Our ability to sell our natural-gas and crude-oil production could be materially harmed if we fail to obtain adequate services such as transportation.
The marketability of our production depends in part upon the availability, proximity and capacity of pipeline facilities and tanker transportation. If any of the pipelines or tankers become unavailable, we would be required to find a suitable alternative to transport the gas and oil, which could increase our costs and/or reduce the revenues we might obtain from the sale of the gas and oil.
Title to the properties in which we have an interest may be impaired by title defects.
We generally conduct due diligence to review title on significant properties that we drill or acquire. However, there is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is due to title defects is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
We depend on the skill, ability and decisions of third party operators to a significant extent.
The success of the drilling, development and production of the oil and natural gas properties in which we have or expect to have a non-operating working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of any third-party operator to make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and comply with laws, rules and regulations, including environmental laws and regulations in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could negatively affect our results of operations.
We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.
Our success depends upon the continued contributions of our executive officers and key employees, particularly with respect to providing the critical management decisions and contacts necessary to manage and maintain growth within a highly competitive industry. Competition for qualified personnel can be intense, particularly in the oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience. Under these conditions, we could be unable to attract and retain these personnel. The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse effect on our business, operating results, financial condition and cash flows.
Our operations in Israel may be adversely affected by economic and political developments.
We have interests in oil and gas leases and in oil and gas licenses in the waters off Israel. These interests may be adversely affected by political and economic developments, including the following:
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war, terrorist acts and civil disturbances,
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changes in taxation policies,
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laws and policies of the US and Israel affecting foreign investment, taxation, trade and business conduct,
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foreign exchange restrictions,
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international monetary fluctuations and changes in the value of the US dollar, such as the decline of the US dollar and
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other hazards arising out of Israeli governmental sovereignty over areas in which we own oil and gas interests.
Members of Isramco’s management team own a significant amount of common stock, giving them influence or control in corporate transactions and other matters, and the interests of these individuals could differ from those other shareholders.
Members of our management team beneficially own approximately 60.6% of our outstanding shares of common stock as of March 11, 2011. As a result, these shareholders are in a position to significantly influence or control the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of an amendment to our certificate of incorporation or bylaws and the approval of mergers and other significant corporate transactions.
Our stock price is volatile and could continue to be volatile and has limited liquidity; Accordingly, investors may not be able to sell any significant number of shares of our stock at prevailing market prices.
Investor interest in our common stock may not lead to the development of an active or liquid trading market. The market price of our common stock has fluctuated in the past and is likely to continue to be volatile and subject to wide fluctuations. In addition, the stock market has experienced extreme price and volume fluctuations. The stock prices and trading volumes for our stock has fluctuated widely and the average daily trading volume of our stock continues to be limited and may continue for reasons that may be unrelated to business or results of operations. General economic, market and political conditions could also materially and adversely affect the market price of our common stock and investors may be unable to resell their shares of common stock at or above their purchase price. As a result of the limited trading in our stock, it may be difficult for investors to sell their shares in the public market at any given time at prevailing prices.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Oil and Gas Exploration and Production - Properties and Reserves
Reserve Information. For estimates of Isramco's net proved reserves of natural gas, crude oil and natural gas liquids, see Note 16 to Consolidated Financial Statements, Supplemental Oil and Gas Information,.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Note 16 to Consolidated Financial Statements, Supplemental Oil and Gas Information, represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas, crude oil and condensate and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. For related discussion, see ITEM 1A. Risk Factors.
We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for us to conduct business in the future.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
We disclosed information in our quarterly report for the three months ended September 30, 2010 relating to two putative shareholder derivative petitions that were filed by individual shareholders of the Company in the District Court of Harris County, Texas. These petitions each named certain of our officers and directors as defendants. Each of these suits claims that the shareholders were damaged as a result of various breaches of fiduciary duty, self dealing and other wrongdoing in connection with the Restated Agreement between the Company and Goodrich, primarily on the part of the Company’s Chairman and Chief Executive Officer, Haim Tsuff, and Jackob Maimon. On or about April 6, 2010, a third complaint was filed in the 295th District Court of Harris County, Texas by Yuval Ran, who claimed to be a shareholder, against certain of our officers and directors and several corporate parties controlled by Haim Tsuff. As with the prior suits, this complaint alleged various breaches of duty, self dealing and other wrongdoing in connection with the Restated Agreement between the Company and Goodrich, primarily on the part of the Company’s Chairman and Chief Executive Officer, Haim Tsuff, and Jackob Maimon (Jackob Maimon is a former President and a director who resigned from all positions held with us on June 29, 2010). In addition, this suit alleged claims relating to other transactions between the Company and entities controlled by Haim Tsuff, including but not limited to the loan transactions between the Company and related parties, the lease and sale of a cruise ship, and the closure of the Company’s Israel branch office. The third complaint was transferred to the 55th Judicial District Court of Harris County, Texas, by order signed April 20, 2010, and consolidated with the above-referenced first and second complaints by order signed May 21, 2010, into a single case, called “Lead Cause No. 2009-34535; In Re Isramco, Inc. Shareholder Derivative Litigation; In the 55th Judicial District Court of Harris County, Texas (the “Derivative Litigation”).
Subsequently, on or about September 7, 2010, the plaintiffs in the first two actions jointly filed an amended petition, which included some, but not all, of the claims alleged in the third complaint; and on or about October 4, 2010, the Court granted the motion to withdraw as plaintiff filed by the plaintiff in the third complaint On October 6, 2010, the parties attempted to mediate the case but no settlement was immediately forthcoming. Although the Company disputes the allegations of the plaintiffs and believes them to be without merit, subsequently, the derivative plaintiffs, the Company and the other defendants reached a tentative settlement of this litigation. This settlement, which requires court approval, is pending.
We also disclosed information in our quarterly report for the three months ended September 30, 2010 relating to an additional putative shareholder derivative complaint that was filed by an individual shareholder, Yuval Lapiner, on July 7, 2010 in the Delaware Chancery Court in Wilmington, Delaware, naming certain of our officers and directors as defendants. The claims asserted in this case are essentially the same damage claims as asserted in the lawsuit filed in April 2010 and described above. The Company filed motions in the Chancery Court to Dismiss or Stay the lawsuit and, by order dated October 20, 2010, the case was dismissed. The plaintiff did not appeal.
From time to time, we are involved in disputes and other legal actions arising in the ordinary course of business. In management's opinion, none of these other disputes and legal actions is expected to have a material impact on our consolidated financial position or results of operations.
ITEM 4.
ITEM 4. (Removed and Reserved)
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock is listed on the Nasdaq Capital Market under the symbol "ISRL". The following table sets forth for the periods indicated, the reported high and low closing prices for our common stock . As of March 8, 2011, there were approximately 277 holders of record of our common stock.
We have never paid cash dividends on our common stock. We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future. Any future determination to pay dividends on common stock will be at the discretion of the board of directors and will be dependent upon then existing conditions, including other factors, as the board of directors deems relevant.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Not applicable
ITEM 7.
ITEM 7. MANAGEMENT DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THE FOLLOWING COMMENTARY SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES CONTAINED ELSEWHERE IN THIS FORM 10-K. THE DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS THAT INVOLVE RISKS AND UNCERTAINTIES. THESE STATEMENTS RELATE TO FUTURE EVENTS OR OUR FUTURE FINANCIAL PERFORMANCE. IN SOME CASES, YOU CAN IDENTIFY THESE FORWARD-LOOKING STATEMENTS BY TERMINOLOGY SUCH AS "MAY," "WILL," "SHOULD," "EXPECT," "PLAN," "ANTICIPATE," "BELIEVE," "ESTIMATE," "PREDICT," "POTENTIAL," "INTEND," OR "CONTINUE," AND SIMILAR EXPRESSIONS. THESE STATEMENTS ARE ONLY PREDICTIONS. OUR ACTUAL RESULTS MAY DIFFER MATERIALLY FROM THOSE ANTICIPATED IN THESE FORWARD-LOOKING STATEMENTS AS A RESULT OF A VARIETY OF FACTORS, INCLUDING, BUT NOT LIMITED TO, THOSE SET FORTH UNDER "RISK FACTORS" AND ELSEWHERE IN THIS FORM 10-K.
Overview
We are an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas properties located onshore in the United States. Our properties are primarily located in Texas, New Mexico and Oklahoma. We act as the operator of certain of these properties. Historically, we have grown through acquisitions, with a focus on properties within our core operating areas that we believe have significant development and exploration opportunities and where we can apply our technical experience and economies of scale to increase production and proved reserves while lowering lease operating costs.
Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire additional properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors, and secondarily upon our commodity price hedging activities. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success. Our future drilling plans are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. To the extent these factors lead to reductions in our drilling plans and associated capital budgets in future periods, our financial position, cash flows and operating results could be adversely impacted.
At December 31, 2010, 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 9,031 thousand barrels of oil equivalent (“MBOE”), consisting of 3,318 thousand barrels (Bbls) of oil, and 23,701 million cubic feet (Mcf) of natural gas and 1,763 thousand barrels (Bbls) natural gas liquids. Approximately 97% of our proved reserves were classified as proved developed producing (See Note 16 to Consolidated Financial Statements, Supplemental Oil and Gas Information). We maintain operational control of approximately 77% of our proved reserves. Full year 2010 production averaged 2.3 MBOE/d compared to 2.42 MBOE/d in 2009.
Critical accounting policies
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the most significant estimates and assumptions we make in applying these policies.
Oil and Natural Gas Activities
Accounting for oil and natural gas activities is subject to unique rules. Two generally accepted methods of accounting for oil and natural gas activities are available - successful efforts and full cost. The most significant differences between these two methods are the treatment of unsuccessful exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed as they are incurred upon a determination that the well is uneconomical, while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and natural gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using period-end prices and costs and a 10% discount rate. We account for our natural gas and crude oil exploration and production activities under the successful efforts method of accounting.
Proved Oil and Natural Gas Reserves
Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization and impairment expense. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir will also result in revisions to the amount of our estimated proved reserves.
Our policies and procedures regarding internal controls over the recording of our oil and natural gas reserves are structured to objectively and accurately estimate our oil and natural gas reserve quantities and present values in compliance with both accounting principles generally accepted in the United States and the SEC’s regulations. Compliance with these rules and regulations is the responsibility of our senior engineer, who is also our principal engineer.
Our controls over reserve estimates include retention of Cawley, Gillespie & Associates, Inc as our independent petroleum engineers. We provide Cawley, Gillespie & Associates, Inc. information concerning our oil and natural gas properties, including production profiles, prices and costs, and they prepare their independent estimates of the oil and natural gas reserves attributable to our properties. All of the information regarding reserves in this annual report on Form 10-K is derived from the report of Cawley, Gillespie & Associates, Inc, which is included as an exhibit to this annual report.
We maintain an internal staff of petroleum engineers and an attorney experienced in petroleum land titles who work closely with Cawley Gillespie to ensure the integrity, accuracy and timeliness of the data furnished to Cawley, Gillespie & Associates, Inc for their reserves estimation process. Our senior engineer reviews and approves the reserve information compiled by our internal staff. Our technical teams and representatives of Cawley, Gillespie & Associates, Inc also jointly review our properties and discuss the methods and assumptions used by Cawley, Gillespie & Associates, Inc in the preparation of their year end reserve estimates.
Depreciation, Depletion and Amortization
Our rate of recording depreciation, depletion and amortization expense (DD&A) is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it non-economic to drill for and produce higher cost reserves.
Impairment
We review our property and equipment in accordance with Accounting Standards Codification (ASC) 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires us to evaluate property and equipment as an event occurs or circumstances change that would more likely than not reduce the fair value of the property and equipment below the carrying amount. If the carrying amount of property and equipment is not recoverable from its undiscounted cash flows, then we would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, we evaluate the remaining useful lives of property and equipment at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods.
Asset Retirement Obligations
We have significant obligations to remove tangible equipment and facilities associated with our oil and gas wells and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are most often associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations we have will be take effect in the future. Additionally, these operations are subject to private contracts and government regulations that often have vague descriptions of what is required. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate removal cost amounts, inflation factors, credit adjusted discount rates, timing of obligations and changes in the legal, regulatory, environmental and political environments.
Accounting for Derivative Instruments and Hedging Activities
We utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our anticipated future oil and natural gas production. We generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next 48 and 15 months, respectively. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivative contracts, which would potentially allow us to not record the change in fair value of our derivative contracts in the consolidated statements of operations. We carry our derivatives at fair value on our consolidated balance sheets, with the changes in the fair value included in our consolidated statements of operations in the period in which the change occurs. Our results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivative contracts.
Income Taxes
The Company follows ASC 740, Income Taxes, (ASC 740), which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax assets and liabilities are computed using the liability method based on the differences between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.
A valuation allowance is provided, if necessary, to reserve the amount of net operating loss and net deferred tax assets which the Company may not be able to use because of the expiration of maximum carryover periods allowed under applicable tax codes.
Liquidity and Capital Resources
Our primary historical sources of capital and liquidity are internally generated cash flows from operations, availability under our senior credit agreements with our unrelated bank lenders with Bank of Nova Scotia and Wells Fargo (“Senior Credit Agreements”) and loans from various related party lenders (“Related Party Loans”) and asset dispositions. We continuously monitor our liquidity and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources and drilling success.
Note 6 to our Consolidated Financial Statements, Long-Term Debt and Interest Expense, describes the Senior Credit Agreements and Related Party Loans. Our Senior Credit Agreements originally provided a total $300 million in credit facilities. As of December 31, 2010, the combined total credit available borrowing base available for was approximately $45 million. On March 3, the Company terminated its relationship with Wells Fargo and paid its debt to Wells Fargo, further reducing the total credit available to approximately $4.5 million at that date. The borrowing base which relates to our oil and natural gas properties is redetermined on a semi-annual basis (with the Company and the lenders each having the right to one unscheduled redetermination per year) and adjusted based on our oil and natural gas properties, reserves, other indebtedness and other relevant factors. See Note 6 to Consolidated Financial Statements, Long-Term Debt and Interest Expense.
Our ability to utilize the full amount of our borrowing capacity is influenced by a variety of factors, including redeterminations of our borrowing base and covenants under our Senior Credit Agreements. Our Senior Credit Agreements contain 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, 2010, the Company was in compliance with all of its debt covenants under the Senior Credit Agreements.
Our future capital resources and liquidity may depend, in part, on our success in developing the leasehold interests that we have acquired. Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success in finding and acquiring additional reserves. We expect to fund our future capital requirements through internally generated cash flows and borrowings under our Senior Credit Agreements. Long-term cash flows are subject to a number of variables, including the level of production and prices and our commodity price hedging activities as well as various economic conditions that have historically affected the oil and natural gas industry.
Debt
At year-end 2010, our total debt was $116,429,000, compared to total debt of $124,670,000 at year-end 2009 and $146,098,000 at year-end 2008. As of December 31, 2010, current debt included $14,350,000 as current maturities of the Senior Credit Facilities. However, the Company is not obligated to repay the facilities prior to the due date, except for such payments as may be required under the Senior Credit Agreements in the event of a redetermination and reduction of the borrowing base. As of December 31, 2010, the $4,900,000 included as current maturities was due to the decision by management to continue reducing our debt below the borrowing base. As of December 31, 2009, current debt included $12,000,000 as current maturities, which again was due to management’s decision to continue payments to reduce debt below the borrowing base.
On March 3, 2011, the Company entered into a Loan Agreement with IOC pursuant to which it borrowed the sum of $11 million. The loan bears interest at a rate of 10% per annum and is payable in quarterly payments of interest only until March 3, 2012, when all accrued interest and principal is due and payable. The loan may be prepaid at any time without penalty. The loan is unsecured. The purpose of the loan was to provide funds to Isramco for the payment of amounts due under the Wells Fargo Senior Credit Facility at maturity. On March 3, 2011 Isramco paid the outstanding principal balance due under the Wells Fargo Senior Credit Agreement. Subsequently, on March 9, 2011, pursuant to an agreement with Wells Fargo, the derivative contracts between Isramco and Wells Fargo were terminated at a cost to the Company of approximately $7,000,000. Concurrently, the Company entered into new derivative contracts for 336,780 barrels of crude oil during the 46 month period commencing March 2011 with Macquarie Bank, N.A.
Off-Balance Sheet Arrangements
At December 31, 2010, we did not have any off-balance sheet arrangements.
Cash Flow
Our primary source of cash in 2010 and 2009 was from operating activities. Our primary sources of cash in 2008 were from operating and financing activities. In 2010 and 2009, cash received from operations was offset by repayments of borrowings under our Senior Credit Agreements and cash used in payments on addition to oil and gas properties, net of any divestiture activities. In 2008, Proceeds from loans obtained from related parties, proceeds from the Senior Credit Agreements and cash received from operations were offset by repayments of our Senior Credit Agreements, repayments of loans from related parties and cash used in investing activities to fund continued enhancement of operations acquisition activities.
Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Working capital was substantially influenced by these variables. Fluctuation in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal fluctuations characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See Results of Operations below for a review of the impact of prices and volumes on sales.
Operating Activities, Net cash flows provided by operating activities were $12,063,000, $21,519,000 and $18,886,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Key drivers of net operating cash flows are commodity prices, production volumes, hedging activities and operating cost.
Net cash provided by operating activities decreased in 2010 compared to 2009 primarily due to a reduction in working capital of $4,549,000, higher lease operating expenses and expenses related to our well plugging and abandonment obligations. The reduction in net cash proceeds from our commodity price hedging activities of $8,308,000 was offset by increased oil and natural gas revenues of $8,561,000. The increase in revenues was primarily attributable to higher average oil and gas prices for the year ended December 31, 2010 of $77.26/bbl and $4.71/mcf, compared to $58.52/bbl and $3.48/mcf for the year ended December 31, 2009. However, we are unable to predict future production levels or future commodity prices, and, therefore, we cannot predict future levels of net cash provided by operating activities.
Net cash provided by operating activities increased in 2009 compared to 2008 primarily due to an 8% increase in our average daily production volumes and gain from net cash received on settled derivative contracts which was partially offset by the 58%, 40% and 31% decrease in natural gas, oil and natural gas liquids prices, respectively.
Investing Activities, The primary driver of cash used in investing activities in 2010 and 2009 is capital spending. The primary component of cash used in investing activities in 2008 was capital spending for acquisitions and development. Cash used in investing activities was $1,437,000, $332,000 and $97,753,000 for the years ended December 31, 2010, 2009 and 2008, respectively.
In 2010, we spent an additional $3,454,000 on capital expenditures. We spent an additional $157,000 on other property and equipment during 2010. We participated in the drilling of 3 gross wells in 2010. In December, 2010, we completed the sale of our interests in certain properties in Wise and Parker Counties, Texas, for approximately $2.2 million.
In 2009, we spent an additional $645,000 on capital expenditures and other property and equipment.
In 2008, we spent $98,673,000 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 $369,000 on other property and equipment during 2008.
Financing Activities, The primary component of cash used in financing activities in 2010 and 2009 was payment on long-term debt ($7,875,000) and ($21,250,000). In 2008, the primary component of cash provided by financing activities was proceeds from long-term loans obtained from related parties ($43,773,000) and Senior Credit Agreements ($54,000,000), offset by repayments of long-term loans and repayments of Senior Credit Agreements ($16,800,000). Net cash flows provided by financing activities were ($7,876,000), ($21,421,000) and $80,796,000 for the years ended December 31, 2010, 2009 and 2008, respectively.
Results of Continuing Operations
(1)
See Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a Generally Accepted Accounting Principles (GAAP) measure, and a reconciliation of Adjusted EBITDAX to income from operations before income taxes, which is presented in accordance with GAAP.
Financial Results
Net Income (loss) Our net loss for 2010 totaled ($2,787,000) a, or ($1.03) per share, compared to a net loss for 2009 of ($13,579,000), or ($5.00) per share. The decrease in net loss was primarily due to higher natural gas, oil and NGLs sales revenues due to higher prices, the impact of derivatives, lower depreciation, depletion and amortization expenses and lower interest expense. This was partially offset by a decrease in sales volumes of natural gas, oil and natural gas liquids (“NGLs”) caused by adverse weather conditions in Texas that restricted our ability to access, repair and maintain our wells in the first quarter of 2010, along with the natural decline in production, and higher lease operating expenses. Our net loss for 2009 totaled ($13,579,000), or ($5.00) per share, compared to net income for 2008 of $3,229,000, or $1.19 per share. This decrease was primarily due to sustained lower natural gas, oil and NGLs sales revenues due to lower prices and impact of derivatives, which were partially offset by increases in sales volumes of natural gas, oil and natural gas liquids (“NGL”), lower lease operating expenses, lower depreciation, depletion, amortization and impairment expenses and tax benefit.
Revenues, Volumes and Average Prices
Sales Revenues
Our sales revenues for the year ended December 31, 2010 increased by 28% when compared to same period of 2009, mainly due to higher natural gas, oil and condensate and NGLs commodity prices. Our sales revenues for the year ended December 31, 2009 decreased by 41% when compared to same period of 2008, mainly due to lower natural gas, oil and condensate and NGLs commodity prices.
Volumes and Average Prices
The Company’s natural gas sale volumes decreased by 10%, crude oil sale volumes by 1% and natural gas liquid sale volumes by 0% in 2010 compared to 2009. This decrease was primarily caused by adverse weather conditions in Texas that restricted our ability to access, repair and maintain our wells in the first quarter of 2010, along with the natural decline in production. The Company’s natural gas sales volumes increased by 5%, crude oil sales volumes by 14% and natural gas liquids sales volumes by 8% in 2009 compared to 2008, primarily due to fact that in 2008 we recorded 9 months of production associated with the properties acquired in the GFB acquisition, which in turn was partially offset by the natural decline in our production.
Our average natural gas price for 2010 increased by 35% or $1.23 per Mcf, when compared to 2009 and decreased by 58%, or $4.80, when 2009 is compared to 2008. Our average crude oil price for 2010 increased by 32% or $18.74 per Bbl, when compared to 2009 and decreased by 40%, or $38.58, when 2009 is compared to 2008. Our average natural gas liquids price for 2010 increased by 28%, or $8.14 per Bbl, when compared to 2009 and decreased by 31%, or $12.77 per Bbl, when 2009 is compared to 2008.
Analysis of Oil and Gas Operations Sales Revenues
The following table provides a summary of the effects of changes in volumes and prices on Isramco’s sales revenues for the year ended December 31, 2010 compared to 2009 and 2008.
Adjusted EBITDAX.
To assess the operating results of Isramco, management analyzes income from operations before income taxes, interest expense, exploration expense, unrealized gain (loss) on derivative contracts and DD&A expense and impairments (“Adjusted EBITDAX”). Adjusted EBITDAX is not a GAAP measure. Isramco’s definition of Adjusted EBITDAX excludes exploration expense because exploration expense is not an indicator of operating efficiency for a given reporting period, but rather is monitored by management as a part of the costs incurred in exploration and development activities. Similarly, Isramco excludes DD&A expense and impairments from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Isramco’s financing methods or capital structure. Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make payments on its long term loans. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations.
However, Adjusted EBITDAX, as defined by Isramco, may not be comparable to similarly titled measures used by other companies. Therefore, Isramco’s consolidated Adjusted EBITDAX should be considered in conjunction with income (loss) from operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect income from continuing operations and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Isramco’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) from operations before income taxes.
Operating Expenses
During 2010, our operating expenses decreased by 2% when compared to 2009 due to the following factors:
·
Lease operating expense, transportation cost and taxes increased by 27%, or $4,243,000, in 2010 when compared to 2009. This increase was the result of the costs associated with a plan we initiated in January 2010 to workover a number of our wells, along with the incremental costs involved in operating older, more mature fields that require additional repair and maintenance as well as the increasing costs of environmental remediation expenditures. Finally, the higher oil and gas sale prices we received had the effect of increasing the taxes paid during 2010. On a per unit basis, lease operating expenses (excluding transportation and taxes) increased by $5.33 per MBOE to $18.32 per MBOE in 2010, from $12.99 per MBOE in 2009.
·
Depreciation, Depletion &Amortization (DD&A) of the cost of proved oil and gas properties is calculated using the unit-of-production method. Our DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact our composite DD&A rate and expense, including but not limited to field production profiles, drilling or acquisition of new wells, disposition of existing wells, and reserve revisions (upward or downward) primarily related to well performance and commodity prices, and impairments. Changes to these factors may cause our composite DD&A rate and expense to fluctuate from period to period. Our DD&A decreased by 21%, or $3,226,000, in 2010 when compared to 2009 primarily due to higher prices (per MBOE) that impacted our estimated total reserves, which are the basis for the depletion calculation and the impact of a 2009 impairment of $5,751,000 on the depletable base used to calculate DD&A. On a per unit basis, depletion expense decreased by $2.90 per MBOE to $14.44 per MBOE in 2010 from $17.34 per MBOE in 2009.
·
Impairments of oil and gas assets of $1,751,000 in 2010 were primarily a result of lower natural gas prices in general and the low volume of gas produced in a few of our Central Texas fields.
·
General and administrative expenses increased by 25%, or $1,010,000, in 2010 when compared to 2009, primarily due to attorney’s fees and expenses related to certain derivative litigation pending in Harris County, Texas.
During 2009, our operating expenses decreased by 34% when compared to 2008 due to the following factors:
·
Lease operating expense, transportation and taxes decreased by 23%, or $4,591,000, in 2009 when compared to 2008 primarily as a result of cost savings programs initiated in response to the reduction in oil and gas prices experienced from 2008 into 2009. Cost savings were achieved through operating efficiencies, deferral of certain workovers and vendor negotiations. Additional reductions were due to lower commodity prices that affected the taxes paid during 2009. This decrease was partially offset by the fact that, in 2008, we recorded only 9 months of operating expense, transportation and taxes associated with the properties acquired in GFB acquisition, compared to 12 months during 2009. On a per unit basis, lease operating expenses (excluding transportation and taxes) decreased by $4.60 per MBOE to $12.99 per MBOE in 2009 from $17.59 per MBOE in 2008.
·
Depreciation, Depletion &Amortization (DD&A) of the cost of proved oil and gas properties is calculated using the unit-of-production method. Our DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact our composite DD&A rate and expense, including but not limited to field production profiles, drilling or acquisition of new wells, disposition of existing wells, and reserve revisions (upward or downward) primarily related to well performance and commodity prices, and impairments. Changes to these factors may cause our composite DD&A rate and expense to fluctuate from period to period. DD&A decreased by 13%, or $2,355,000, in 2009 when compared to 2008 primarily due to higher prices (per MBOE) that impacted our estimated total reserves, which are the basis for the depletion calculation, and the impact of a 2008 impairment of $22,093,000 on the depletable base used to calculate DD&A, which was partially offset by higher production. On a per unit basis, depletion expense decreased by $4.25 per MBOE to $17.34 per MBOE in 2009 from $21.59 per MBOE in 2008.
·
Impairments of oil and gas assets of $5,751,000 in 2009 were primarily a result of lower natural gas prices in general and the low volume of gas produced in a few of our Central Texas fields.
·
General and administrative expenses increased by 52%, or $1,399,000, in 2009 when compared to 2008, primarily due to increases in compensation and benefit expenses associated with hiring additional employees required as a result of the GFB acquisition and assuming operation of approximately 350 additional wells in October 2008. The GFB acquisition also increased the volume of the activities and, as a result, the indirect expenses of the activities. In addition, the Company incurred increased legal expenses in 2009 due to a number of factors. The Company was required to pay an award of $288,000 in attorney’s fees as a result of an adverse court decision in a case filed by the Company in 2001. The Company was the subject of two derivative lawsuits filed in 2009. Also in 2009 the Company instituted lawsuits against several entities to recover damages relating to its investments in Barnett Shale operations and to the operation of the properties acquired in the Five States acquisition.
Other expenses (income)
Interest expense. Isramco’s interest expense decreased by 17%, or $1,573,000, for the year ended December 31, 2010 compared to the same period of 2009. This decrease is primarily due to the lower average outstanding balance of the loans which we obtained to fund the Five States acquisition in 2007 and the GFB acquisition in 2008, and to decreases in average LIBOR rates during 2010. The decrease was partially offset by the payments on interest rate swaps. Isramco’s interest expense decreased by 6%, or $636,000, for the year ended December 31, 2009 compared to the same period of 2008. This decrease is primarily due to the lower average outstanding balance of the loans which we obtained to fund the Five States acquisition in 2007 and the GFB acquisition in 2008, and to decreases in average LIBOR rates in 2009. The decrease was partially offset by the payments on interest rate swaps.
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, 2010, the Company had a $2.5 million derivative asset, of which $2.2 million was classified as current and a $3.5 million derivative liability, of which $1.1 million was classified as current. For the year ended December 31, 2010, the Company recorded a net derivative gain of $1.86 million (a $4.7 million unrealized loss offset by a $6.6 million gain from net cash received on settled contracts).
At December 31, 2009, the Company had a $5.6 million derivative asset, of which $3.4 million was classified as current and a $1.8 million derivative liability, of which $0.1 million was classified as current. For the year ended December 31, 2009, the Company recorded a net derivative loss of $4.4 million (a $19.3 million unrealized loss partially offset by a $14.9 million gain from net cash received on settled contracts).
At December 31, 2008, the Company had a $23 million derivative asset, of which $12 million was classified as current. For the year ended December 31, 2008, the Company recorded a net derivative gain of $24.7 million (a $32.6 million unrealized gain partially offset by a $7.9 million loss from net cash payments on settled contracts).
Income Tax
Income tax benefit for the year ended December 31, 2010 decreased by $9 million from the prior year. The decreased in our income tax benefit from the prior year was primarily due to our pre-tax loss of $4.6 million for the year ended December 31, 2010 compared to our pre-tax loss of $23.7 million in 2009. The effective tax rates for the years ended December 31, 2010, 2009 and 2008 were 40%, 42.6% and 10.5%, respectively.
Recently Issued Accounting Pronouncements
We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data-Note 1, “Summary of Significant Accounting Policies.”
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Derivative Instruments and Hedging Activity
We are exposed to various risks, including energy commodity price risk. If oil and natural gas prices decline significantly our ability to finance our capital budget and operations could be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have adopted a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The type of derivative instrument that we typically utilize is swaps. The total volumes which we hedge through the use of our derivative instruments vary from period to period.
We are exposed to market risk on our open derivative contracts of non-performance by our counterparties. However, we do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings. Each of the counterparties to our derivative contracts is a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement. Please refer to Item 8.
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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
MANAGEMENT’S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES.
In accordance with Rules 13a-15(f) and 15d-15(f), of the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2010 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted 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
Management has assessed, and our independent registered public accounting firm, MaloneBailey, LLP, has audited, our internal control over financial reporting as of December 31, 2010. The unqualified reports of management and MaloneBailey, LLP thereon are included in Item 8 of this Annual Report on Form 10-K and are incorporated by reference herein.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There has been no change in our internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, during the three months ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None
PART III
The information called for by items 10, 11, 12 13 and 14 will be contained in the Company's definitive proxy statement which the Company intends to file within 120 days after the end of the Company's fiscal year ended December 31, 2010 and such information is incorporated herein by reference.
GLOSSARY
"Limited Partnership" means Isramco-Negev 2 Limited Partnership, a Limited Partnership founded pursuant to a Limited Partnership Agreement made on the 2nd and 3rd days of March, 1989 (as amended on September 7, 1989, July 28, 1991, March 5, 1992 and June 11, 1992) between the Trustee on part as Limited Partner and Isramco Oil and Gas Ltd., as General Partner on the other part.
"Overriding Royalty" means a percentage interest over and above the base royalty and is free of all costs of exploration and production, which costs are borne by the Grantor of the Overriding Royalty Interest and which is related to a particular Petroleum License.
"Payout" means the defined point at which one party has recovered its prior costs.
"Petroleum" means any petroleum fluid, whether liquid or gaseous, and includes oil, natural gas, natural gasoline, condensates and related fluid hydrocarbons, and also asphalt and other solid petroleum hydrocarbons when dissolved in and producible with fluid petroleum.
"Israel Petroleum Law"
The Company's business in Israel is subject to regulation by the State of Israel pursuant to the Petroleum Law, 1952. The administration and implementation of the Petroleum Law is vested in the Minister of National Infrastructure (the "Minister") and an Advisory Council.
The following includes brief statements of certain provisions of the Petroleum Law in effect at the date of this Prospectus. Reference is made to the copy of the Petroleum Law filed as an exhibit to the Registration Statement referred to under "Additional Information" and the description which follows is qualified in its entirety by such reference.
The holder of a preliminary permit is entitled to carry out petroleum exploration, but not test drilling or petroleum production, within the permit areas. The Commissioner determines the term of a preliminary permit and it may not exceed eighteen (18) months. The Minister may grant the holder a priority right to receive licenses in the permit areas and for the duration of such priority right no other Party will be granted a license or lease in such areas.
Drilling for petroleum is permitted pursuant to a license issued by the Commissioner. The term of a license is for three (3) years, subject to extension under certain circumstances for an additional period up to four (4) years. A license holder is required to commence test drilling within two (2) years from the grant of a license (or earlier if required by the terms of the license) and not to interrupt operations between test drillings for more than four (4) months. If any well drilled by the Company is determined to be a Commercial discovery prior to expiration of the license, the Company will be entitled to receive a Petroleum Lease granting it the exclusive right to explore for and produce petroleum in the lease area. The term of a lease is for thirty (30) years, subject to renewal for an additional term of twenty (20) years.
The Company, as a lessee, will be required to pay the State of Israel the royalty prescribed by the Petroleum Law which is presently, and at all times since 1952 has been, 12.5% of the petroleum produced from the leased area and saved, excluding the quantity of petroleum used in operating the leased area.
The Minister may require a lessee to supply at the market price such quantity of petroleum as, in the Minister's opinion, is required for domestic consumption, subject to certain limitations.
As a lessee, the Company will also be required to commence drilling of a development well within six (6) months from the date on which the lease is granted and, thereafter, with due diligence to define the petroleum field, develop the leased area, produce petroleum therefore and seek markets for and market such petroleum.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) Exhibits
3.1
Certificate of Incorporation of Registrant with all amendments filed as an Exhibit to the S-l Registration Statement, File No. 2-83574.
3.2
Amendment to Certificate of Incorporation filed March 17, 1993, filed as an Exhibit with the S-l Registration Statement, File No. 33-57482.
3.3
By-laws of Registrant with all amendments, filed as an Exhibit to the S-l Registration Statement, File No. 2-83570.
4.1
First Amended and Restated Promissory Note dated as of February 27, 2007, issued to NAPHTHA ISRAEL PETROLEUM CORP., LTD. in the principal amount of $18,500,000 filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
4.2
First Amended and Restated Promissory Note dated as of February 27, 2007, issued to NAPHTHA ISRAEL PETROLEUM CORP., LTD. in the principal amount of $11,500,000 filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
4.3
First Amended and Restated Promissory Note dated as of February 27, 2007, issued to and I.O.C. ISRAEL OIL COMPANY, LTD. in the principal amount of $12,000,000 filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
4.4
Promissory Note dated as of February 27, 2007, issued to and J.O.E.L JERUSALEM OIL EXPLORATION, LTD. in the principal amount of $7,000,000, filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
4.5
Promissory Note dated as of May 25, 2008, issued to and J.O.E.L JERUSALEM OIL EXPLORATION, LTD. in the principal amount of $48,900,000 filed as an Exhibit to the 10-K for the year ended December 31, 2009 and incorporated herein by reference.
10.1
Purchase and Sale Agreement, dated as of February 16, 2007, among Five States Energy Company, L.L.C. and each of the other parties listed as a party "Seller" on the signature pages thereof and ISRAMCO, Inc., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
10.2
LOAN AGREEMENT, dated as of February 27, 2007, between ISRAMCO, INC., and NAPHTHA ISRAEL PETROLEUM CORP., LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
10.3
LOAN AGREEMENT, dated as of February 27, 2007, between ISRAMCO, INC., and NAPHTHA ISRAEL PETROLEUM CORP., LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
10.4
LOAN AGREEMENT, dated as of February 27, 2007, Between ISRAMCO, INC., and I.O.C. ISRAEL OIL COMPANY, LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
10.5
LOAN AGREEMENT, dated as of February 26, 2007, between ISRAMCO, INC., and J.O.E.L JERUSALEM OIL EXPLORATION, LTD., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
10.6
CREDIT AGREEMENT dated as of March 2, 2007 among ISRAMCO ENERGY, L.L.C., each of the lenders that is a signatory hereto or which becomes a signatory hereto; and WELLS FARGO BANK, N. A., a national banking association, as agent for the Lenders., filed as an Exhibit to the 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference.
10.7
GUARANTY AGREEMENT, dated as of March 2, 2007 by ISRAMCO, Inc. in favor of Wells Fargo Bank, N.A., as administrative agent (the "ADMINISTRATIVE AGENT") for the lenders that are or become parties to the Credit Agreement referred to in Item 10.