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ISRL > SEC Filings for ISRL > Form 10-K on 15-Mar-2013All Recent SEC Filings

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Form 10-K for ISRAMCO INC


15-Mar-2013

Annual Report


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

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

Overview

We are an independent oil and natural gas company engaged in the exploration, development, and production of oil and natural gas properties located onshore in the United States and an owner of various royalty interests offshore Israel. Our properties are primarily located in Texas, New Mexico and Oklahoma. We act as the operator of most of our U.S. properties. Historically, we have grown through acquisitions, with a focus on properties within our core operating areas that we believe have significant development and exploration opportunities and where we can apply our technical experience and economies of scale to increase production and proved reserves while lowering lease operating costs. In August, 2011 we created a new well service subsidiary that began operations in October 2011. As of December 2012, the subsidiary had 15 deployed well service rigs that operate primarily in Texas and New Mexico. The company provides a full range of well services such as well completion and wellbore maintenance, workover, plugging and abandonment services.


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Oil and Gas Exploration and Production Segment

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, quality, 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, 2012, our estimated total proved oil, natural gas reserves and natural gas liquids, as prepared by our independent reserve engineering firms, Netherland, Sewell & Associates, Inc and Cawley, Gillespie & Associates, Inc., were approximately 36,266 thousand barrels of oil equivalent ("MBOE"), consisting of 3,233 thousand barrels (MBbls) of oil, 186,837 million cubic feet (MMcf) of natural gas and 1,893 thousand barrels (MBbls) of natural gas liquids. Approximately 23% of our proved reserves were classified as proved developed (See Note 15 Supplemental Oil and Gas Information to Consolidated Financial Statements to our consolidated financial statements). Full year 2012 production averaged 2.17 MBOE/d compared to 2.16 MBOE/d in 2011.

Production Services Segment

The production service market is highly competitive. Competition is influenced by such factors as price, capacity, availability of work crews, and reputation and experience of the service provider. We believe that an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. We believe many of our larger customers place increased emphasis on the safety, performance and quality of the crews, equipment and services provided by their contractors. Although we believe customers consider all of these factors, price is often the primary factor in determining which service provider is awarded the work. However, in numerous instances, we secure and maintain work from large customers for which efficiency, safety, technology, size of fleet and availability of other services are of equal importance to price.

The demand for our services fluctuates, primarily in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven primarily by the supply of, and demand for, oil and natural gas. Generally, as supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in a lower oil and natural gas price environment, demand for service and maintenance generally decreases as oil and natural gas producers decrease their activity. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work. Oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we may experience a more rapid decline in demand for well maintenance services compared with demand for other types of oilfield services. Further, in a low commodity price environment, fewer well service rigs are needed for completions, as these activities are generally associated with drilling activity. The plugging and abandonment work is less affected by prices and generally driven by state regulations and have smaller variations in demand.

The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of U.S. oil and natural gas exploration, development and production activity, as well as the equipment capacity in any particular region.

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.


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Oil and Natural Gas Activities

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

Proved Oil and Natural Gas Reserves

Isramco estimates its proved oil and gas reserves as defined by the SEC and the FASB. This definition includes crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, government regulations, etc., i.e., at prices and costs as of the date the estimates are made. Prices include consideration of price changes provided only by contractual arrangements, and do not include adjustments based upon expected future conditions.
The Company's estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually by our independent reserve engineering firm, Cawley, Gillespie & Associates, Inc and Netherland, Sewell & Associates, Inc. and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions, and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A and could result in property impairments.

Depreciation, Depletion and Amortization

Our rate of recording depreciation, depletion and amortization expense (DD&A) is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it non-economic to drill for and produce higher cost reserves.
Our well service equipment and tools are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated depreciable lives of the assets using the straight-line method. We depreciate our operational assets over their depreciable lives to their salvage value, which is a fair value higher than the assets' value as scrap. When we scrap an asset, we accelerate the depreciation of the asset down to its salvage value. When we dispose of an asset, a gain or loss is recognized.

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.


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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 may generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next years. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivative contracts, which would potentially allow us to not record the change in fair value of our derivative contracts in the consolidated statements of operations. We carry our derivatives at fair value on our consolidated balance sheets, with the changes in the fair value included in our consolidated statements of operations in the period in which the change occurs. Our results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivative contracts.

Environmental Obligations, Litigation and Other Contingencies

Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental remediation, litigation, and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability is incurred and reasonable estimates of the liability can be made. Estimates of environmental liabilities are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change the Company's estimate of environmental-remediation costs, such as changes in laws and regulations, changes in the interpretation or administration of laws and regulations, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment, and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental or other contingent matters and actual costs may vary significantly from the Company's estimates. The Company's in-house legal counsel regularly assesses these contingent liabilities and, in certain circumstances, consults with third-party legal counsel or consultants to assist in forming the Company's conclusion.

Income Taxes

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

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

Liquidity and Capital Resources

Our primary source of liquidity was cash flow generated from our operating activities, loans from related party lender ("Related Party Loans") and net proceeds from sale of our investment in shares of JOEL Jerusalem Oil Exploration Ltd, ("JOEL") a related party. 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 5 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 under a credit facility from a group of lenders, under which Wells Fargo was the lead bank (the "Lenders"). The borrowing base under the facility was redetermined on a semi-annual basis and adjusted based on our oil and natural gas properties, reserves, other indebtedness and other relevant factors. During the fourth quarter of 2011 the Lenders reduced the borrowing base to zero. On April 27, 2012, The Company entered into an amendment to the Credit Agreement with Lenders, formalizing the election to pay the $20,000,000 borrowing base deficiency in six monthly installments of $3,333,333.33. As of June 29, 2012 the Company has fully paid all amounts owed and terminated the Senior Credit Facility with the Lenders.

The Company is also in negotiations for similar credit facilities with several other commercial lenders, to obtain a new credit facility on terms most favorable to the Company. The Company hopes to obtain a new credit facility that would replace its existing financing from affiliated parties and also provide additional financing for Company operations and investments. The Company is uncertain as to whether it will be successful in obtaining new replacement financing or, if it is obtained, the timetable upon which such facility will be closed and other material terms and conditions. The Company believes that the current source of its affiliate financing will remain flexible and additional funding will be made available if needed until a new credit facility can be obtained. See Note 5 to Consolidated Financial Statements, Long-Term Debt and Interest Expense.


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Our future capital resources and liquidity may depend, in part, on our success in developing the leasehold interests that we have acquired and from stream line operations of our well service operations. 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 from related parties and hopefully a new commercial credit facility. Long-term cash flows are subject to a number of variables, including the level of production and prices as well as various economic conditions that have historically affected the oil and natural gas industry. Our well service business requires capital to fund ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives and investments in new equipment and tools. We plan to fund these activities from Isramco's available operating cash flows, loans from related parties and financial institutions. We also plan to utilize revenue derived from our overriding interest in Tamar Field offshore Israel. (See Item 1A "Risk Factors").

Debt

                                                  As of December 31,
                                        2012              2011            2010
                                           (In thousands except percentage)
        Senior Credit Facilities     $         -       $         -     $   22,725
        Long - term debt - related
        party                             73,906            60,211         76,354
        Short - term debt -
        related party                          -             6,456              -
        Current maturities of
        long-term debt, short-term
        debt and bank overdraft           18,184            32,009         17,350
        Total debt                        92,090            98,676        116,429

        Stockholders' equity              18,815            18,548         18,537

        Debt to capital ratio                83%                84 %           86 %

(1) The amounts are excluded of accrued interest.

At year-end 2012, our total debt was $92,090,000, compared to total debt of $98,676,000 at year-end 2011 and $116,429,000 at year-end 2010. As of December 31, 2011, current debt included $20,000,000 as current maturities of the Senior Credit Facilities. During the fourth quarter of 2011 the Lenders reduced the borrowing base to zero. As of June 29, 2012 the Company has fully paid all amounts owed the Lenders under the terminated the Senior Credit Facility.

On March 3, 2011, the Company entered into a Loan Agreement with I. O. C. - Israel Oil Company, LTD., an affiliate of the Company ("IOC") pursuant to which it borrowed the sum of $11 million. The loan bears interest at a rate of 10% per annum and was payable in quarterly payments of interest only until March 3, 2012, when all accrued interest and principal was due and payable. The loan was repayable at any time without penalty and is unsecured. The purpose of the loan was to provide funds to Isramco for the payment of amounts due the Lenders under the Wells Fargo Senior Credit Facility at maturity. On March 3, 2011 Isramco paid the outstanding principal balance due under the Wells Fargo Senior Credit Agreement. Subsequently, on March 9, 2011, pursuant to an agreement with Wells Fargo, the derivative contracts between Isramco and Wells Fargo were terminated at a cost to the Company of approximately $7,000,000. Concurrently, the Company entered into new derivative contracts for 336,780 barrels of crude oil during the 46 month period commencing March 2011 with Macquarie Bank, N.A. During September 2011 Isramco paid $5,096,000 of principal and interest pursuant to Loan agreement with IOC.

In October 2011 the agreement with IOC, pertaining to a loan in the outstanding principal amount of $6,456,000 was renegotiated. The payoff of principal amount was extended by 6 months to September 9, 2012. Interest accrued per annum was determined on LIBOR+5.5% from initial 10%.

On March 29, 2012, the Company entered into a Loan Agreement with IOC pursuant to which it borrowed $3,500,000. The loan bears interest at a rate of Libor + 5.5% per annum and matures on March 29, 2013, when all accrued interest and principal is due and payable. The loan may be prepaid at any time without penalty or premium and the loan is unsecured. The purpose of the loan was to provide funds to Isramco for the payment of amounts were due to the Lenders under the Senior Credit Facility.


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On April 29, 2012, the Company entered into another Loan Agreement with IOC, pursuant to which it borrowed $10,000,000. The loan bears interest of Libor+5.5% per annum and matures on April 30, 2013, when all accrued interest and principal is due and payable. The loan may be prepaid at any time without penalty or premium. The loan was funded by IOC in three monthly installments starting April 2012. The loan is unsecured. The purpose of the loan was to provide funds to Isramco for the payment of amounts that were due to the Lenders under the Senior Credit Facility that was paid in full June 29, 2012.

On February 13, 2013, the Company entered into another Loan Agreement with IOC, pursuant to which it borrowed $1,500,000. The loan bears interest of Libor+5.5% per annum and matures on February 13, 2018, when all accrued interest and principal is due and payable. The loan may be prepaid at any time without penalty or premium. The loan is unsecured. The purpose of the loan was to provide funds to back up a Letter of Credit.

On March 1, 2013 all of the above mentioned Loan agreements and notes with IOC, except for the $1,500,000 loan agreement entered on February 13, 2013, were amended. The terms of all existing loans and notes between the Company and IOC were amended extending the maturity to December 31, 2018. In addition the payment schedule was changed on all of the loans and notes to require interest only payments on December 31, 2014, December 31, 2015, December 31, 2016, December 31, 2017 and final interest payment December 31, 2018 along with all outstanding principal paid in four equal installments with the first payment December 31, 2015 and an similar payment made December 31 in each of the following three years until the final payment on December 31, 2018. The other terms of the loan agreements and notes remained unchanged. In accordance with the amendment, as of December 31, 2012 the loans are classified as long-term on our balance sheet.

On March 1, 2013 the terms of all existing loans and note between the Company and Naphtha were also amended extending the maturity to December 31, 2018. The payment schedule was changed on the Naphtha loans and notes to require interest only payments December 31, 2013, December 31, 2014, December 31, 2015, December 31, 2016, December 31, 2017 and the final interest payment on December 31, 2018 with principal outstanding paid in four equal installments with the first payment December 31, 2015 and remaining three installments made on December 31 of each of the following three years with the final payment on December 31, 2018. The other terms of the loan agreement and note remained unchanged. In accordance with the amendment, as of December 31, 2012 the loans are classified as long-term on our balance sheet.

Off-Balance Sheet Arrangements

At December 31, 2012, we did not have any off-balance sheet arrangements.

Cash Flow

Our primary source of cash in 2012 was cash flow from operating activities, loans from related party and proceeds from sale of shares of marketable securities of JOEL to a related party. In 2012 cash received from operations, sale of marketable securities and proceeds from related party were used primarily to repay borrowings under our Senior Credit Facility and investing in . . .

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