ISRAMCO INC - FORM 10-Q - August 9, 2011

Attached files

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EX-32.1 - ISRAMCO INC	ex32-1.htm
EX-31.1 - ISRAMCO INC	ex31-1.htm
EX-31.2 - ISRAMCO INC	ex31-2.htm
EX-32.2 - ISRAMCO INC	ex32-2.htm
EXCEL - IDEA: XBRL DOCUMENT - ISRAMCO INC	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

	Check One
	x	Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended June 30, 2011

		or

	o	Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number 0-12500

ISRAMCO, INC

(Exact Name of registrant as Specified in its Charter)

Delaware		13-3145265
(State or other Jurisdiction of Incorporation or Organization)		I.R.S. Employer Number

2425 West Loop South, Suite 810, HOUSTON, TX 77027

(Address of Principal Executive Offices)

713-621-5946

(Registrant’s Telephone Number, Including Area Code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

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

Large accelerated filer o Accelerated filer x Non-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company o

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

The number of shares outstanding of the registrant’s Common Stock as August 9, 2011 was 2,717,691.

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TABLE OF CONTENTS

		Page
PART I - FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements (unaudited)	4
	Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010	4
	Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2011 and 2010	5
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010	6
	Notes to Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	24
Item 4.	Controls and Procedures	25

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	26
Item 1A.	Risk Factors	26
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	26
Item 3.	Defaults Upon Senior Securities	26
Item 4	(Removed and Reserved)	26
Item 5.	Other Information	26
Item 6.	Exhibits	26
	Signatures	27

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Forward Looking Statements

CERTAIN STATEMENTS MADE IN THIS QUARTERLY REPORT ON FORM 10-Q ARE “FORWARD-LOOKING STATEMENTS” WITHIN THE MEANING OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995. FORWARD-LOOKING STATEMENTS CAN BE IDENTIFIED BY TERMINOLOGY SUCH AS “MAY”, “WILL”, “SHOULD”, “EXPECTS”, “INTENDS”, “ANTICIPATES”, “BELIEVES”, “ESTIMATES”, “PREDICTS”, OR “CONTINUE” OR THE NEGATIVE OF THESE TERMS OR OTHER COMPARABLE TERMINOLOGY AND INCLUDE, WITHOUT LIMITATION, STATEMENTS BELOW REGARDING EXPLORATION AND DRILLING PLANS, FUTURE GENERAL AND ADMINISTRATIVE EXPENSES, FUTURE GROWTH, FUTURE EXPLORATION, FUTURE GEOPHYSICAL AND GEOLOGICAL DATA, GENERATION OF ADDITIONAL PROPERTIES, RESERVES, NEW PROSPECTS AND DRILLING LOCATIONS, FUTURE CAPITAL EXPENDITURES, SUFFICIENCY OF WORKING CAPITAL, ABILITY TO RAISE ADDITIONAL CAPITAL, PROJECTED CASH FLOWS FROM OPERATIONS, OUTCOME OF ANY LEGAL PROCEEDINGS, DRILLING PLANS, THE NUMBER, TIMING OR RESULTS OF ANY WELLS, INTERPRETATION AND RESULTS OF SEISMIC SURVEYS OR SEISMIC DATA, FUTURE PRODUCTION OR RESERVES, LEASE OPTIONS OR RIGHTS, PARTICIPATION OF OPERATING PARTNERS, CONTINUED RECEIPT OF ROYALTIES, AND ANY OTHER STATEMENTS REGARDING FUTURE OPERATIONS, FINANCIAL RESULTS, OPPORTUNITIES, GROWTH, BUSINESS PLANS AND STRATEGY. BECAUSE FORWARD-LOOKING STATEMENTS INVOLVE RISKS AND UNCERTAINTIES, THERE ARE IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE EXPRESSED OR IMPLIED BY THESE FORWARD-LOOKING STATEMENTS. ALTHOUGH THE COMPANY BELIEVES THAT EXPECTATIONS REFLECTED IN THE FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CANNOT GUARANTEE FUTURE RESULTS, PERFORMANCE OR ACHIEVEMENTS. MOREOVER, NEITHER THE COMPANY NOR ANY OTHER PERSON ASSUMES RESPONSIBILITY FOR THE ACCURACY AND COMPLETENESS OF THESE FORWARD-LOOKING STATEMENTS. THE COMPANY IS UNDER NO DUTY TO UPDATE ANY FORWARD-LOOKING STATEMENTS AFTER THE DATE OF THIS REPORT TO CONFORM SUCH STATEMENTS TO ACTUAL RESULTS.

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ITEM 1. Financial Statements

ISRAMCO INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)

	As of June 30, 2011			As of December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	1,707		$	5,657
Accounts receivable, net		5,726			6,110
Restricted and designated cash		2,889			889
Deferred tax assets		3,144			3,368
Derivative asset		1,664			2,156
Prepaid expenses and other		415			715
Total Current Assets		15,545			18,895

Property and Equipment, at cost – successful efforts method:
Oil and Gas properties		223,427			222,122
Other		1,319			922
Total Property and Equipment		224,746			223,044
Accumulated depreciation, depletion and amortization		(97,128	)		(91,208	)
Net Property and Equipment		127,618			131,836

Marketable securities, at market		20,943			16,099
Debt cost		-			70
Derivative asset		558			343
Deferred tax assets and other		4,769			4,635
Total assets	$	169,433		$	171,878
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	8,788		$	9,316
Bank overdraft		502			335
Current maturities of long-term debt		25,875			14,350
Derivative liability		-			1,133
Due to related party and accrued interest		36,023			9,371
Total current liabilities		71,188			34,505

Long-term debt		-			22,725

Due to related party and accrued interest		62,616			77,132

Other Long-term Liabilities:
Asset retirement obligations		16,925			16,577
Derivative liability – non-current		-			2,402
Total other long-term liabilities		16,925			18,979

Commitments and contingencies

Shareholders’ equity:
Common stock $0.0l par value; authorized 7,500,000 shares; issued 2,746,958 shares; outstanding 2,717,691 shares		27			27
Additional paid-in capital		23,194			23,194
Accumulated deficit		(17,154	)		(14,149	)
Accumulated other comprehensive income		12,801			9,629
Treasury stock, 29,267 shares at cost		(164	)		(164	)
Total shareholders’ equity		18,704			18,537
Total liabilities and shareholders’ equity	$	169,433		$	171,878

See notes to the unaudited condensed consolidated financial statements.

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ISRAMCO INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share amounts)

(Unaudited)

	Three Months Ended June 30						Six Months Ended June 30
	2011			2010			2011			2010

Revenues
Oil and gas sales	$	11,571		$	9,403		$	22,553		$	19,358
Office services		152			107			305			309
Other		24			17			39			25
Total revenues		11,747			9,527			22,897			19,692

Operating expenses
Lease operating expense, transportation and taxes		6,610			5,054			11,738			9,954
Depreciation, depletion and amortization		2,923			3,542			5,920			6,712
Accretion expense		210			204			418			408
Loss from plug and abandonment		57			342			170			688
General and administrative		927			1,002			2,012			1,901
Total operating expenses		10,727			10,144			20,258			19,663
Operating income (loss)		1,020			(617	)		2,639			29

Other expenses (income)
Interest expense, net		1,950			1,955			4,103			3,917
Net (gain) loss on derivative contracts		(2,931	)		(4,036	)		3,158			(7,409	)
Total other expenses (income)		(981	)		(2,081	)		7,261			(3,492	)

Income (Loss) before income taxes		2,001			1,464			(4,622	)		3,521
Income tax (expense) benefit		(700	)		(498	)		1,617			(1,198	)

Net Income (loss)	$	1,301		$	966		$	(3,005	)	$	2,323


Earnings (loss) per share – basic:	$	0.48		$	0.36		$	(1.11	)	$	0.85

Earnings (loss) per share – diluted:	$	0.48		$	0.36		$	(1.11	)	$	0.85

Weighted average number of shares outstanding basic:		2,717,691			2,717,691			2,717,691			2,717,691
Weighted average number of shares outstanding diluted:		2,717,691			2,717,691			2,717,691			2,717,691

See notes to the unaudited condensed consolidated financial statements.

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ISRAMCO INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended June 30
	2011			2010

Cash Flows From Operating Activities:
Net income (loss)	$	(3,005	)	$	2,323
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion, amortization and impairment		5,920			6,712
Accretion expense		418			408
Changes in deferred taxes		(1,617	)		1,198
Net unrealized gain on derivative contracts		(3,224	)		(4,355	)
Amortization of debt cost		126			126
Changes in components of working capital and other assets and liabilities
Accounts receivable		384			1,873
Prepaid expenses and other current assets		244			(87	)
Due to related party		2,089			(716	)
Accounts payable and accrued liabilities		(643	)		(2,022	)
Net cash provided by operating activities		692			5,460

Cash flows from investing activities:
Addition to property and equipment, net		(1,655	)		(1,896	)
Restricted cash and deposit, net		(2,000	)		(18	)
Net cash used in investing activities		(3,655	)		(1,914	)

Cash flows from financing activities:
Repayment on loans – related parties, net		(954	)		-
Proceeds on loans – related parties, net		11,000			-
Repayment of long-term debt		(11,200	)		(3,375	)
Borrowings of short - term debt, net		167			846
Net cash used in financing activities		(987	)		(2,529	)

Net increase (decrease) in cash and cash equivalents		(3,950	)		1,017
Cash and cash equivalents at beginning of period		5,657			2,907
Cash and cash equivalents at end of period	$	1,707		$	3,924

See notes to the unaudited condensed consolidated financial statements.

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Isramco Inc.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 - Financial Statement Presentation

As used in these financial statements, the terms “Company” and “Isramco” refer to Isramco, Inc. and its subsidiaries, Jay Petroleum, L.L.C. (“Jay Petroleum”), Jay Management Company L.L.C. (“Jay Management”), IsramTec Inc. (“IsramTec”), Isramco Resources LLC, Isramco Energy LLC and Field Trucking and Services, LLC (”FTS”).

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the SEC instructions to Form 10-Q. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of only normal recurring adjustments) considered necessary for a fair presentation have been included. Results for the six-month period ended June 30, 2011 are not necessarily indicative of the results that may be expected for the year ended December 31, 2011. For further information, refer to the consolidated financial statements and footnotes thereto included in Isramco’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Use of Estimates

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

Consolidated interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these condensed consolidated financial statements.

Risk Management Activities

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

Consolidation

The condensed consolidated financial statements include the accounts of Isramco and its wholly-owned subsidiaries: Jay Petroleum, Jay Management, IsramTec, Isramco Resources LLC and Isramco Energy LLC and FTS. Inter-company balances and transactions have been eliminated in consolidation.

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Recently Issued Accounting Pronouncements

There were no new accounting pronouncements that had a significant impact on the Company’s operating results or financial position.

Note 2 - Supplemental Cash Flow Information

Cash paid for interest and income taxes was as follows for the six months ended June 30 (in thousands):

	Six Months Ended June 30
	2011			2010
Interest		$	1,918	$	4,648

Income taxes			-		-

Note 3 - Derivative Contracts

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. The payment required for the termination of these contracts was approximately $7 million.

At June 30, 2011, the Company had a $2.2 million commodity derivative asset, of which $1.7 million was classified as current. For the six months ended June 30, 2011, the Company recorded a net derivative loss of $3.2 million ($3.2 million unrealized gain and a $6.4 million loss from net cash paid on settled contracts).

At June 30, 2010, the Company had a $8.1 million derivative asset, which $5.1 million was classified as current. For the six months ended June 30, 2010, the Company recorded a net derivative gain of $7.4 million ($4.3 million unrealized gain and a $3.1 million gain from net cash received on settled contracts).

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Natural Gas

At June 30, 2011, the Company had the following natural gas swap positions:

	Swaps
Period	Volume in MMbtu’s		Price / Price Range		Weighted Average Price
July 2011 – December 2011		382,410		8.22		8.22
January 2012 – March 2012		174,222		8.65		8.65

Crude Oil

At June 30, 2011, the Company had the following crude oil swap positions:

	Swaps
Period	Volume in Bbls		Price / Price Range		Weighted Average Price
July 2011 – December 2011		120,168		88.55-103.51		94.96
January 2012 – December 2012		127,473		88.20-103.51		99.67
January 2013 – December 2013		89,400		103.51		103.51
January 2014 – December 2014		66,000		103.51		103.51

Note 4 - Long-Term Debt and Interest Expense

Long-Term Debt as of June 30, 2011 and December 31, 2010 consisted of the following (in thousands):

	As of June 30, 2011			As of December 31, 2010
Libor + 2% Bank Revolving Credit Facility due 2011		-			9,450
Libor + 2% Bank Revolving Credit Facility due 2012		25,875			27,625
Libor + 6% Related party Debt		12,000			12,000
Libor + 5.5% Related party Debt		-			954
Libor + 6% Related party Debt		11,500			11,500
Libor + 6% Related party Debt		6,000			6,000
Libor + 6% Related party Debt		48,900			48,900
10% Related party Debt		11,000			-
		115,275			116,429
Less: Current Portion of Long-Term Debt		(55,100	)		(17,350	)
Total		60,175			99,079

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Senior Secured Revolving Credit Agreements

On March 3, 2011, the Company paid the outstanding principal balance of the Wells Fargo Senior Credit Facility. By agreement of the parties, the derivative contracts remained in place until March 9, 2011, when these contracts were novated and replaced by new derivative contracts, for the same volumes but at current market prices, with Macquarie Bank, N.A. In connection with this transaction, the Wells Fargo Senior Credit Facility was transferred to and assumed by Macquarie Bank, N.A. This facility currently has no outstanding principal or current availability. The credit facility was assigned and transferred to Macquarie Bank, N.A. in anticipation of the finalization of a successor credit facility pursuant to which all of the Company’s debt (including its related party debt) will be consolidated into a single facility at Macquarie Bank, N.A. In the event the parties are not successful in finalizing this transaction the facility will be terminated and all collateral related thereto will be released. The Company is also in negotiations for similar credit facilities with several other commercial lenders, to obtain terms most favorable to the Company. While optimistic of a positive outcome of our consolidation efforts, the Company is uncertain as to whether it will be successful in obtaining new replacement financing or, if is obtained, the timetable upon which such facility will be closed and other material terms and conditions.

At June 30, 2011, the Company was in compliance with all of its debt covenants under its existing Credit Agreements.

On July 28, 2011 the borrowing base available under the other credit facility with the bank of Nova Scotia (“Scotia”) was redetermined to $20,000,000. The redetermination of the borrowing base resulted in a borrowing base deficiency of $5.875 million under the terms of the credit facility. As a result of a payment made prior to August 9, 2011, the deficiency has been reduced to $3.5 million. The Company is following an agreed schedule to remedy the borrowing base deficiency during the third quarter of 2011.

Related Party Debt

On March 3, 2011, the Company entered into a Loan Agreement with Israel Oil Company, Ltd. (“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 which was March, 2011, and to terminate and re-set the commodity swap hedge arrangement.

Interest expense

The following table summarizes the amounts included in interest expense for the six month ended June 30, 2011 and 2010 (in thousands):

	Six Months Ended June 30
	2011		2010
Current debt, long-term debt and other - banks corporation	$	887	$	954
Long-term debt – related parties		3,216		2,963
	$	4,103	$	3,917

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Note 5 - Comprehensive Gain Income

	Three Months Ended June 30					Six Months Ended June 30
	2011		2010			2011			2010
Net income (loss)	$	1,301	$	966		$	(3,005	)	$	2,323
Other comprehensive income
Available-for-sale securities, net of taxes		3,292		(535	)		3,150			(147	)
Change in unrealized gains on hedging instruments, net of taxes		-		105			22			208
Comprehensive income	$	4,593	$	536		$	167		$	2,384

Note 6 - Fair Value of Financial Instruments

Pursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820) the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of June 30, 2011 and December 31, 2010. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for the six months ended June 30, 2011.

	June 30, 2011
	Level 1		Level 2		Level 3		Total
Assets
Marketable securities	$	20,943	$	—	$	—	$	20,943
Commodity derivatives		—		2,222		—		2,222

Total	$	20,943	$	2,222	$	—	$	23,165

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	December 31, 2010
	Level 1		Level 2		Level 3		Total
Assets
Marketable securities	$	16,099	$	—	$	—	$	16,099
Commodity derivatives		—		2,499		—		2,499

Total	$	16,099	$	2,499	$	—	$	18,598

Liabilities
Commodity derivatives	$	—		3,501	$	—	$	3,501
Interest rate derivatives		—		34		—		34

Total	$	—	$	3,535	$	—	$	3,535

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

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

As of June 30, 2011 and December 31, 2010, the Company’s derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance. Each of the counterparties to the Company’s derivative contracts is a lender in the Company’s Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreements.

Note 7 - Subsequent Events

The Company, through its wholly-owned subsidiary IsramTec, Inc. (“IsramTec”), was the holder of 730,582 unrestricted shares of Mediamind Technologies, Inc. (“Mediamind”), a publicly-traded company. On June 24, 2011, the Company, along with all the other shareholders of Mediamind, received a Tender Offer from DG Acquisition Corp. VII (“DG”), in its bid to merge with Mediamind. IsramTec accepted the terms of the Tender Offer of $22 per unrestricted share of Mediamind, which represents cash of $16,072,804. The merger closed on July 25, 2011.

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ITEM 2. Management’s 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 REPORT ON FORM 10-Q. 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 REPORT ON FORM 10-Q. ISRAMCO INC. DISCLAIMS ANY OBLIGATION TO UPDATE SUCH FORWARD LOOKING STATEMENTS.

Overview

Isramco, Inc. (“Isramco” or “we”) is 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 also 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.

Liquidity and Capital Resources

Our primary source of cash during the six months ended June 31, 2011 was cash flow from operating activities and loans from related party lender (“Related Party Loans”). 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.

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 the capital resources available and our 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 that remain to be obtained and negotiated. 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.

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Debt

	As of June 30,			As of December 31,
	2011			2010
Senior Credit Facilities	$	-		$	22,725
Long – term debt – related party		60,175			76,354
Current maturities of long-term debt, short-term debt and bank overdraft		55,602			17,350
Total debt		115,777			116,429

Stockholders’ equity		18,704			18,537

Debt to capital ratio		86	%		86	%

Under the existing credit facility available with Scotia, we can borrow up to a maximum of $20,000,000. Management currently believes that this availability is sufficient to provide the liquidity required to satisfy our anticipated working capital needs for 2011.

As of June 30, 2011, our total debt was $115,777,000, compared to total debt of $116,429,000 at December 31, 2010. As of June 30, 2011, current debt included $25,875,000 as current maturities of the Revolving Credit Facilities. 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.

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, which was March, 2011 and to terminate and re-set the commodity swap hedge arrangement. 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. The Company is actively pursuing a consolidation of all outstanding debt with Macquarie Bank and other commercial lenders.

Cash Flow

Our primary source of cash during the six months ended June 30, 2011 was cash flow from operating activities and loans from related party loans. Our primary source of cash during the six months ended June 30, 2010 was our operating activities. In 2011 cash received from operations and from related party was offset by repayments of borrowings under our Senior Credit Agreements and payments made on settled derivatives contracts. In 2010 period, cash received from operations were mainly offset by repayments made under our revolving credit facilities.

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.

	Six months Ended June 30,
	2011			2010
	(In thousands)
Cash flows provided by operating activities	$	692		$	5,460
Cash flows used in investing activities		(3,655	)		(1,914)
Cash flows used in financing activities		(987	)		(2,529	)
Net increase (decrease) in cash	$	(3,950)		$	1,017

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Operating Activities, During the first six months of 2011, compared to the first six months of 2010, net cash flow provided by operating activities decreased by $4,768,000 to $692,000. This decrease was primarily attributable to net cash paid on settled derivatives contracts of $7,007,000, higher lease operating expenses all of which were partially offset by increased oil and natural gas liquids (“NGLs”) revenues. The increase in revenues was primarily attributable to higher average oil and NGLs prices for the six months ended June 30, 2011 of $97.01/bbl and 45.41/bbl respectively, compared to $75.68/bbl and 37.28/bbl for the six month ended June 30, 2010.

Investing Activities, The primary driver of cash used in investing activities in 2011 is capital spending. Net cash flows used in investing activities for the six months ended June 30, 2011 and 2010 were $3,655,000 and $1,914,000 respectively.

Financing Activities, Net cash flows used in financing activities were $987,000 and $2,529,000 for the six months ended June 30, 2011 and 2010, respectively. Excess cash flow from operations and a loan from related party of $11,000,000 were used to repay borrowings under our Senior Credit Agreements to the extent available. During the first six months of 2011, we repaid borrowings of $12,154,000. During the first six months of 2010, we repaid borrowings of $3,375,000.

Results of Operations

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

Selected Data

	Three Months Ended June 30,
	2011			2010
	(In thousands except per share and MBOE amounts)
Financial Results
Oil and Gas sales	$	11,571		$	9,403
Other		176			124
Total revenues and other		11,747			9,527

Cost and expenses		10,727			10,144
Other income		(981	)		(2,081	)
Income tax benefit		700			498
Net income		1,301			966
Earnings per common share – basic and diluted	$	0.48		$	0.36
Weighted average number of shares outstanding-basic and diluted		2,717,691			2,717,691

Operating Results
Adjusted EBITDAX (1)	$	4,309		$	4,795
Sales volumes (MMBOE)		200			213

Average cost per MBOE:
Production (excluding transportation and taxes)	$	26.46		$	18.06
General and administrative	$	4.63		$	4.70
Depletion	$	14.60		$	16.60

(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.

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Financial Results

Net Income, in the second quarter of 2011, our net income was $1,301,000 or $0.48 per share. This compares to net income of $966,000 or $0.36 per share, for the second quarter of 2010.

This increase was primarily due to the increase of natural gas, oil and natural gas liquids ("NGLs") sales revenues which were partially offset by a higher lease operating.

Revenues, Volumes and Average Prices

Sales Revenues

	Three Months Ended June 30,
In thousands except percentages	2011		2010		D vs. 2010
Gas sales	$	3,008	$	2,566		17	%
Oil sales		6,894		5,451		26
Natural gas liquid sales		1,669		1,386		20
Total	$	11,571	$	9,403		23	%

Our sales revenues for the second quarter of 2011 increased by 23% when compared to same period in 2010, due to higher prices received for oil, gas, and NGLs. That was partially offset by decrease in volume produced.

Volumes and Average Prices

	Three Months Ended June 30,
	2011		2010		D vs. 2010
Natural Gas
Sales volumes Mmcf		564.27		591.93		(5	)%
Average Price per Mcf (1)	$	5.33	$	4.34		23
Total gas sales revenues (thousands)	$	3,008	$	2,566		17	%

Crude Oil
Sales volumes MBbl		68.40		73.81		(7	)%
Average Price per Bbl (1)	$	100.80	$	73.85		36
Total oil sales revenues (thousands)	$	6,894	$	5,451		26	%

Natural gas liquids
Sales volumes MBbl		37.71		40.90		(8	)%
Average Price per Bbl (1)	$	44.25	$	33.89		31
Total natural gas liquids sales revenues (thousands)	$	1,669	$	1,386		20	%

(1) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting

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The company’s natural gas sales volumes decreased by 5%, crude oil sales volumes decreased by 7% and natural gas liquids sales volumes by 8% for the second quarter of 2011 compared to the same period of 2010.

Our average natural gas price for the second quarter of 2011 increased by 23%, or $0.99 per Mcf, when compared to the same period of 2010. Our average crude oil price for the second quarter of 2011 increased by 36%, or $26.95 per Bbl, when compared to the same period of 2010. Our average natural gas liquids price for the second quarter of 2011 increased by 31%, or $10.36 per Bbl, when compared to the same period of 2010.

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 three months ended June 30, 2011 compared to the same period of 2010.

In thousands	Natural Gas			Oil			Natural gas liquids
2010 sales revenues	$	2,566		$	5,451		$	1,386
Changes associated with sales volumes		(120	)		(400	)		(108	)
Changes in prices		562			1,843			391
2011 sales revenues	$	3,008		$	6,894		$	1,669

Operating Expenses

	Three Months Ended June 30,
In thousands except percentages	2011		2010		D vs. 2010
Lease operating expense, transportation and taxes	$	6,610	$	5,054		31	%
Depreciation, depletion and amortization		2,923		3,542		(17	)
Accretion expense		210		204		3
Loss from plugging and abandonment of wells		57		342		(83)
General and administrative		927		1,002		(7	)
	$	10,727	$	10,144		6	%

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During three months ended June 30, 2011, our operating expenses increased by 6% when compared to the same period of 2010 due to the following factors:

Lease operating expense, transportation cost and taxes increased by 31%, or $1,556,000, in 2011 when compared to 2010. This increase was the result of the costs associated with a plan we initiated last year 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. In addition due to changes in regulatory requirements in Texas we incurred additional expenses regarding previously inactive wells in order to renew production in the future. Finally, the higher oil, gas and NGL sale prices we received increased the taxes paid during 2011. On a per unit basis, lease operating expenses (excluding transportation and taxes) increased by $8.40 per MBOE to $26.46 per MBOE in 2011 from $18.06 per MBOE in 2010.

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 in these factors may cause our composite DD&A rate and expense to fluctuate from period to period. DD&A decreased by 17%, or $(619,000), in 2011 when compared to 2010, 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 2010 impairment of $1,751,000 on the depletable base used to calculate DD&A, which were partially offset by increase in production volume that directly impacts the DD&A calculation. On a per unit basis, depletion expense decreased by $(2.00) per MBOE to $14.60 per MBOE in 2011 from $16.60 per MBOE in 2010.

·	Accretion expense for asset retirement obligations slightly increased by 3%, or $6,000, in 2011 when compared to 2010.
·	Loss from plugging and abandonment expenses decreased by 83%, or $285,000 in 2011 when compared to 2010 primarily due to work resulting in less complications during plugging operations.

·	General and administrative expenses decreased by 7%, or $75 thousand, in 2011 when compared to 2010.

Other expenses

	Three Months Ended June 30,
In thousands except percentages	2011			2010		D vs. 2010
Interest expense, net	$	1,950		$	1,955		(0	)%
Net gain on derivative contracts		(2,931	)		(4,036)		(27	)
	$	(981	)	$	(2,081)		(53	)%

Interest expense. There was no change in Isramco’s interest expense due to sustaining of similar average outstanding balance of the loans.

Net loss 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 our consolidated statement of operations.

At June 30, 2011, the Company had a $2.2 million commodity derivative asset, of which $1.7 million was classified as current. For the three months ended June 30, 2011, the Company recorded a net derivative gain of $2.9 million ($2.8 million unrealized gain and a $0.1 million gain from net cash received on settled contracts).

At June 30, 2010, the Company had a $8.1 million commodity derivative asset, of which $5.1 million was classified as current. For the three months ended June 30, 2010, the Company recorded a net derivative gain of $4 million ($2.3 million unrealized gain and a $1.7 million gain from net cash received on settled contracts).

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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.

	Three Months Ended June 30,
In thousands	2011			2010
Income from operations before income taxes	$	2,001		$	1,464
Depreciation, depletion and amortization expense		2,923			3,542
Interest expense		1,950			1,955
Unrealized loss (gain) on derivative contract		(2,775	)		(2,370	)
Accretion Expenses		210			204
Consolidated Adjusted EBITDAX	$	4,309		$	4,795

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Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Selected Data

	June 30,
	2011			2010
	(In thousands except per share and MBOE amounts)
Financial Results
Oil and Gas sales	$	22,553		$	19,358
Other		344			334
Total revenues and other		22,897			19,692

Cost and expenses		20,258			19,663
Other expense (income)		7,261			(3,492)
Income tax expense (benefit)		(1,617	)		1,198
Net income (loss)		(3,005	)		2,323
Earnings (loss) per common share – basic and diluted	$	(1.11	)	$	0.85
Weighted average number of shares outstanding-basic and diluted		2,717,691			2,717,691

Operating Results
Adjusted EBITDAX (1)	$	2,595		$	10,203
Sales volumes (MMBOE)		404			412

Average cost per MBOE:
Production (excluding transportation and taxes)	$	22.60		$	18.02
General and administrative	$	4.98		$	4.61
Depletion	$	14.65		$	16.28

(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 Loss, in the six months ended June 30, 2011, our net loss was $(3,005,000), or $1.11 per share. This compares to net income of $2,323,000, or $0.85 per share, for the same period of 2010.

Net Loss for six months ended on June 30, 2011 was primarily due decrease in sales volumes of natural gas, oil and natural gas liquids (“NGLs”) and the impact of derivatives and higher lease operating expenses. This was partially offset by a higher natural gas, oil and NGLs sales revenues due to higher prices, lower depreciation, and depletion and amortization expenses.

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Revenues, Volumes and Average Prices

Sales Revenues

	Six Months Ended June 30,
In thousands except percentages	2011		2010		D vs. 2010
Gas sales	$	5,563	$	5,948		(6	)%
Oil sales		13,501		10,529		28
Natural gas liquid sales		3,489		2,881		21
Total	$	22,553	$	19,358		17	%

Our sales revenues for the six months ended June 30, 2011 increased by 17% when compared to same period of 2010 due to higher prices received for oil and condensate and NGLs.

Volumes and Average Prices

	Six Months Ended June 30,
	2011		2010		D vs. 2010
Natural Gas
Sales volumes Mmcf		1,128.00		1,174.51		(4	)%
Average Price per Mcf (1)	$	4.93	$	5.06		(3	)
Total gas sales revenues (thousands)	$	5,563	$	5,948		(6	)%

Crude Oil
Sales volumes MBbl		139.17		139.13		0	%
Average Price per Bbl (1)	$	97.01	$	75.68		28
Total oil sales revenues (thousands)	$	13,501	$	10,529		28	%

Natural gas liquids
Sales volumes MBbl		76.83		77.29		(1	)%
Average Price per Bbl (1)	$	45.41	$	37.28		22
Total natural gas liquids sales revenues (thousands)	$	3,489	$	2,881		21	%

(1) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting

The company’s natural gas sales volumes decreased by 4%, natural gas liquids sales volumes by 1% and crude oil sales volumes remained at the same level for the six months ended June 30, 2011 compared to the same period of 2010.

Our average natural gas price for the six months ended June 30, 2011 decreased by 3%, or $(0.13) per Mcf, when compared to the same period of 2010. Our average crude oil price for the six months ended June 30, 2011 increased by 28%, or $21.33 per Bbl, when compared to the same period of 2010. Our average natural gas liquids price for the six months ended June 30, 2011 increased by 22%, or $8.13 per Bbl, when compared to the same period of 2010.

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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 six months ended June 30, 2011 compared to the same period of 2010.

In thousands	Natural Gas			Oil		Natural gas liquids
2010 sales revenues	$	5,948		$	10,529	$	2,881
Changes associated with sales volumes		(236	)		3		(17	)
Changes in prices		(149	)		2,969		625
2011 sales revenues	$	5,563		$	13,501	$	3,489

Operating Expenses

	Six Months Ended June 30,
In thousands except percentages	2011		2010		D vs. 2010
Lease operating expense, transportation and taxes	$	11,738	$	9,954		18	%
Depreciation, depletion and amortization		5,920		6,712		(12	)
Accretion expense		418		408		2
Loss from plug and abandonment		170		688		(75	)
General and administrative		2,012		1,901		6
	$	20,258	$	19,663		3	%

During six months ended June 30, 2011, our operating expenses increased by 3% when compared to the same period of 2010 due to the following factors:

Lease operating expense, transportation cost and taxes increased by 18%, or $1,784,000, in 2011 when compared to 2010. This increase was the result of the costs associated with a plan we initiated last year 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. In addition due to changes in regulatory requirements in Texas we incurred additional expenses regarding previously inactive wells in order to renew production in the future. Finally, the higher oil and NGL sale prices we received increased the taxes paid during 2011. On a per unit basis, lease operating expenses (excluding transportation and taxes) increased by $4.58 per MBOE to $22.60 per MBOE in 2011 from $18.02 per MBOE in 2010.

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 in these factors may cause our composite DD&A rate and expense to fluctuate from period to period. DD&A decreased by 12%, or $(792,000), in 2011 when compared to 2010, 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 2010 impairment of $1,751,000 on the depletable base used to calculate DD&A, which were partially offset by increase in production volume that directly impacts the DD&A calculation. On a per unit basis, depletion expense decreased by $(1.63) per MBOE to $14.65 per MBOE in 2011 from $16.28 per MBOE in 2010.

Accretion expense for asset retirement obligations slightly increased by 2%, or $10,000, in 2011 when compared to 2010.

·	Loss from plugging and abandonment expenses decreased by 75%, or $518 thousand, in 2011 when compared to 2010, primarily due to work resulting in less complications during plugging operations.

·	General and administrative expenses increased by 6%, or $111 thousand, in 2011 when compared to 2010 primarily due to higher professional services expenses.

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Other expenses (income)

	Six Months Ended June 30,
In thousands except percentages	2011		2010		D vs. 2010
Interest expense, net	$	4,103	$	3,917		5	%
Net loss (gain) on derivative contracts		3,158		(7,409)		(143	)
	$	7,261	$	(3,492)		(308	)%

Interest expense. Isramco’s interest expense increased by 5%, or $186,000, for the six months ended June 30, 2011 compared to the same period of 2010. This increase was primarily due to fees paid to Macquarie Bank, N.A in connection with assignment and transfer of Wells Fargo Senior Credit Facility which were partially offset by the lower average outstanding balance of the loans.

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 June 30, 2010, the Company had a $13.1 million derivative asset, which $7.7 million was classified as current. For the six months ended June 30, 2010, the Company recorded a net derivative loss of $1 million ($10 million unrealized loss and a $9 million gain from net cash proceeds on settled contracts).

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”). 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 and fund capital expenditures and make payments on its long term loans and Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations.

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	Six Months Ended June 30,
In thousands	2011			2010
Income (loss) from operations before income taxes	$	(4,622	)	$	3,521
Depreciation, depletion and amortization expense		5,920			6,712
Interest expense		4,103			3,917
Unrealized gain on derivative contract		(3,224	)		(4,355	)
Accretion Expenses		418			408
Consolidated Adjusted EBITDAX	$	2,595		$	10,203

The Consolidated Adjusted EBITDAX decreased due to settlement of oil and gas hedging positions in the approximate amount of $7,000,000 which were partially offset by increase in revenues from sales of natural gas, oil and natural gas liquids (“NGLs”) and decrease in depreciation, depletion and amortization expenses.

ITEM 3. 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.

We are also exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves. Periodically, we look to utilize interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates.

We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Item 1. Consolidated Financial Statements—Note 3, “Derivative contracts” for more details.

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ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.

In accordance with Exchange Act Rule 13a-15 and 15d-15, 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 June 30, 2011 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.

There were no changes in the Company’s internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II - Other Information

ITEM 1. Legal Proceedings

None

ITEM 1A. Risk Factors

None

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

None

ITEM 3. Default Upon Senior Securities

None

ITEM 4. Removed and Reserved

None

ITEM 5. Other Information

None

ITEM 6. Exhibits

Exhibits
31.1		Certification of Chief Executive Officer pursuant to Section 31 2 of Sarbanes-Oxley Act
31.2		Certification of Chief Financial Officer pursuant to Section 31 2 of Sarbanes-Oxley Act
32.1		Certification of Chief Executive and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 Of the Sarbanes-Oxley act of 2002
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 Of the Sarbanes-Oxley act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase
101.DEF*		XBRL Taxonomy Extension Definition Linkbase
101.LAB*		XBRL Taxonomy Extension Label Linkbase
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase

* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ISRAMCO, INC

Date: AUGUST 9, 2011	By:	/s/ HAIM TSUFF
		HAIM TSUFF
		CHIEF EXECUTIVE OFFICER
		(PRINCIPAL EXECUTIVE OFFICER)

Date: AUGUST 9, 2011	By:	/s/ EDY FRANCIS
		EDY FRANCIS
		CHIEF FINANCIAL OFFICER
		(PRINCIPAL FINANCIAL AND PRINCIPAL ACCOUNTING OFFICER)

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