ISRAMCO INC - FORM 10-Q - August 9, 2010

Attached files

file	filename
EX-31.1 - ISRAMCO INC	ex31-1.htm
EX-32.2 - ISRAMCO INC	ex32-2.htm
EX-31.2 - ISRAMCO INC	ex31-2.htm
EX-32.1 - ISRAMCO INC	ex32-1.htm

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, 2010

		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 o 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, 2010 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, 2010 and December 31, 2009	4
	Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2010 and 2009	5
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009	6
	Notes to Condensed Consolidated Financial Statements	7
Item 2.	Management’s discussion and analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	25
Item 4.	Controls and Procedures	26

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	27
Item 1A.	Risk Factors	27
Item 2	Changes in Securities and Use of Proceeds and Issuer Purchases of Equity Securities	27
Item 3.	Defaults upon senior securities	27
Item 4	(Removed and Reserved)	27
Item 5.	Other Information	27
Item 6.	Exhibits	27
	Signatures	28

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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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ISRAMCO INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)

	As of June 30, 2010			As of December 31, 2009
ASSETS
Current Assets:
Cash and cash equivalents	$	3,924		$	2,907
Accounts receivable, net		5,551			7,424
Restricted and designated cash		845			827
Deferred tax assets		2,428			3,644
Derivative asset		5,086			3,421
Prepaid expenses and other		742			656
Total Current Assets		18,576			18,879

Property and Equipment, at cost – successful efforts method:
Oil and Gas properties		221,873			220,138
Other		775			672
Total Property and Equipment		222,648			220,810
Accumulated depreciation, depletion and amortization		(84,027	)		(77,315	)
Net Property and Equipment		138,621			143,495

Marketable securities, at market		4,490			4,713
Debt cost		196			322
Derivative asset		2,995			2,158
Deferred tax assets and other		6,738			6,751
Total assets	$	171,616		$	176,318

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	7,908		$	9,798
Short term debt and bank overdraft		1,182			336
Current maturities of long-term debt		16,950			12,000
Derivative liability		223			693
Accrued interest and due to related party		9,017			4,677
Total current liabilities		35,280			27,504

Long-term debt		24,625			32,950
Accrued interest - related party		2,777			4,832
Long-term debt - related party		76,354			79,354

Other Long-term Liabilities:
Asset retirement obligations		16,463			16,248
Derivative liability – non-current		-			1,697
Total other long-term liabilities		16,463			17,945

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		(9,039	)		(11,362	)
Accumulated other comprehensive income		2,099			2,038
Treasury stock, 29,267 shares at cost		(164	)		(164	)
Total shareholders’ equity		16,117			13,733
Total liabilities and shareholders’ equity	$	171,616		$	176,318

See notes to the 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
	2010			2009			2010			2009

Revenues
Oil and gas sales	$	9,403		$	7,155		$	19,358		$	13,738
Office services		107			195			309			377
Other		17			49			25			291
Total revenues		9,527			7,399			19,692			14,406

Operating expenses
Lease operating expense, transportation and taxes		5,054			3,598			9,954			7,263
Depreciation, depletion and amortization		3,542			4,244			6,712			8,751
Accretion expense		204			204			408			414
Loss from plugging and abandonment of wells		342			-			688			-
General and administrative		1,002			835			1,901			1,714
Total operating expenses		10,144			8,881			19,663			18,142
Operating income (loss)		(617	)		(1,482	)		29			(3,736	)

Other expenses (income)
Interest expense, net		1,955			2,356			3,917			4,803
Net loss (gain) on derivative contracts		(4,036	)		8,385			(7,409	)		971
Total other expenses (income)		(2,081	)		10,741			(3,492	)		5,774

Loss before income taxes		1,464			(12,223	)		3,521			(9,510	)
Income tax (expense) benefit		(498	)		4,209			(1,198	)		3,286

Net Income (loss)	$	966		$	(8,014	)	$	2,323		$	(6,224	)


Earnings (loss) per share – basic and diluted:	$	0.36		$	(2.95	)	$	0.85		$	(2.29	)

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

See notes to the condensed consolidated financial statements.

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ISRAMCO INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended June 30
	2010			2009

Cash Flows From Operating Activities:
Net loss	$	2,323		$	(6,224	)
Adjustments to reconcile net loss to net cash provided by operating activities:

Depreciation, depletion, amortization and impairment		6,712			8,751
Accretion expense		408			414
Unrealized and realized gain on marketable securities		-			(250	)
Changes in deferred taxes		1,198			(3,403	)
Net unrealized loss on derivative contracts		(4,355	)		9,959
Amortization of debt cost		126			126
Changes in components of working capital and other assets and liabilities
Accounts receivable		1,873			(842	)
Prepaid expenses and other current assets		(87	)		68
Related party		151			74
Accrued interest - related party		(867	)		1,644
Accounts payable and accrued liabilities		(2,022	)		368
Net cash provided by operating activities		5,460			10,685

Cash flows from investing activities:
Addition to property and equipment, net		(1,896	)		(126	)
Restricted cash and deposit, net		(18	)		(67	)
Proceeds from sale of marketable securities		-			752
Net cash provided by (used in) investing activities		(1,914	)		559

Cash flows from financing activities:
Repayment on loans – related parties, net		-			(1,346	)
Proceeds from long-term debt		-			-
Repayment of long-term debt		(3,375	)		(9,250	)
Payments for financing cost		-			-
Borrowings (repayments) of short - term debt, net		846			(865	)
Net cash used in financing activities		(2,529	)		(11,461	)

Net increase (decrease) in cash and cash equivalents		1,017			(217	)
Cash and cash equivalents at beginning of period		2,907			3,141
Cash and cash equivalents at end of period	$	3,924		$	2,924

See notes to the 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, 2010 are not necessarily indicative of the results that may be expected for the year ended December 31, 2010. 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, 2009.

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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Reclassifications

Certain prior year amounts in the condensed consolidated financial statements have been reclassified to conform to current year presentations

Recently Issued Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not impact the Company’s operating results, financial position or cash flows, but did impact the Company’s disclosures on fair value measurements. See Note 6, “Fair Value Measurements.”

In February 2010, FASB issued ASU No. 2010-09, Amendments to Certain Recognition and Disclosure Requirements (ASU 2010-09). This update amends Subtopic 855-10 and gives a definition to SEC filer, and requires SEC filers to assess for subsequent events through the issuance date of the financial statements. This amendment states that an SEC filer is not required to disclose the date through which subsequent events have been evaluated for a reporting period. ASU 2010-09 becomes effective upon issuance of the final update. The Company adopted the provisions of ASU 2010-09 for the period ended March 31, 2010.

In April 2010, the FASB issued ASU No. 2010-12, Accounting for Certain Tax Effects of the 2010 Health Care Reform Acts (ASU 2010-12). This update clarifies questions surrounding the accounting implications of the different signing dates of the Health Care and Education Reconciliation Act (signed March 30, 2010) and the Patient Protection and Affordable Care Act (signed March 23, 2010). ASU 2010-12 states that the FASB and the Office of the Chief Accountant at the SEC would not be opposed to view the two Acts together for accounting purposes. The Company is currently assessing the impact, if any, the adoption of ASU 2010-12 will have on the Company’s disclosures, operating results, financial position and cash flows.

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
	2010			2009
Interest		$	4,648	$	3,053

Income taxes			-		52

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Note 3 - Derivative 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 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).

At June 30, 2009, the Company had a $13.1 million derivative asset, which $7.7 million was classified as current. For the six months ended June 30, 2009, 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).

Natural Gas

At June 30, 2010, the Company had the following natural gas swap positions:

	Swaps
Period	Volume in MMbtu’s		Price / Price Range		Weighted Average Price
July 2010 – December 2010		892,824		7.49-8.32		7.88
January 2011 – December 2011		764,820		8.22		8.22
January 2012 – March 2012		174,222		8.65		8.65

Crude Oil

At June 30, 2010, the Company had the following crude oil swap positions:

	Swaps
Period	Volume in Bbls		Price / Price Range		Weighted Average Price
July 2010 – December 2010		127,434		63.30-101.70		79.59
January 2011 – December 2011		240,336		79.50-91.05		86.55
January 2012 – December 2012		127,473		80.20-88.20		82.37
January 2013 – December 2013		89,400		85.15		85.15
January 2014 – December 2014		66,000		86.95		86.95

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During the second quarter of 2008, the Company decided to mitigate a portion of its interest rate risk with interest rate swaps. These swap instruments reduce the Company’s exposure to market rate fluctuations by converting variable interest rates to fixed interest rates.

Under these swaps, the Company makes payments to, or receives payments from, the counterparties based upon the differential between a specified fixed price and a price related to the one-month London Interbank Offered Rate (“LIBOR”). These interest rate swaps convert a portion of our variable rate interest applicable to our “Scotia” debt (as defined in Note 8, “Long-term Debt” in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. The Company has elected to designate these positions for hedge accounting and therefore the unrealized gains and losses are recorded in accumulated other comprehensive loss. The Company measures hedge effectiveness by assessing the changes in the fair value or expected future cash flows of the hedged item.

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

National amount (in thousands):		Start Date	Maturity Date	Weighted-Average Interest Rate
	11,000	April 2009	February 2011		3.63	%
	6,000	April 2009	February 2011		2.90	%

Note 4 - Long-Term Debt and Interest Expense

Long-Term Debt as of June 30, 2010 and December 31, 2009 consisted of the following (in thousands):

	As of June 30, 2010			As of December 31, 2009
Libor + 2% Bank Revolving Credit Facility due 2011		12,950			14,950
Libor + 2% Bank Revolving Credit Facility due 2012		28,625			30,000
Libor + 6% Related party Debt		12,000			12,000
Libor + 5.5% Related party Debt		954			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
		120,929			124,304
Less: Current Portion of Long-Term Debt		(19,950	)		(12,000	)
Total		100,979			112,304

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Senior Secured Revolving Credit Agreements

At June 30, 2010, the Company was in compliance with all of its debt covenants under its existing Credit Agreements.

Interest expense

The following table summarizes the amounts included in interest expense for the six month ended June 30, 2010 and 2009 (in thousands):

	Six Months Ended June 30
	2010		2009
Current debt, long-term debt and other - banks corporation	$	954	$	1,505
Long-term debt – related parties		2,963		3,298
	$	3,917	$	4,803

Note 5 - Comprehensive Gain Income (Loss)

	Three Months Ended June 30						Six Months Ended June 30
	2010			2009			2010			2009
Net income (loss)	$	966		$	(8,014	)	$	2,323		$	(6,224	)
Other comprehensive income (loss)
Available-for-sale securities, net of taxes		(535	)		675			(147	)		998
Change in unrealized gains on hedging instruments, net of taxes		105			93			208			41
Comprehensive income (loss)	$	536		$	(7,246	)	$	2,384		$	(5,185	)

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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 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, 2010 and December 31, 2009. 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, 2010.

	June 30, 2010
	Level 1		Level 2		Level 3		Total
Assets
Marketable securities	$	4,490	$	—	$	—	$	4,490
Commodity derivatives		—		8,081		—		8,081

Total	$	4,490	$	8,081	$	—	$	12,571

Liabilities
Interest rate derivatives		—		223		—		223

Total	$	—	$	223	$	—	$	223

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	December 31, 2009
	Level 1		Level 2		Level 3		Total
Assets
Marketable securities	$	4,713	$	—	$	—	$	4,713
Commodity derivatives		—		5,579		—		5,579

Total	$	4,713	$	5,579	$	—	$	10,292

Liabilities
Commodity derivatives	$	—		1,852	$	—	$	1,852
Interest rate derivatives		—		538		—		538

Total	$	—	$	2,390	$	—	$	2,390

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, 2010 and December 31, 2009, 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, while no assurance to this effect can be provided, 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 has evaluated subsequent events through August 9, 2010, which is the date the consolidated financial statements were issued.

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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 oil and gas 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, political issues, 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 and development plans are subject to change based upon various factors, some of which are beyond our control, including results of operations, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling and other services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. To the extent these factors lead to reductions in our operating 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 30, 2010 was cash flow from operating activities. The capital markets, as they relate to us, have been adversely impacted by the current financial crisis and concerns about the economic recession and its effect on commodity prices. Continued volatility in the capital markets could adversely impact our ability to replace our reserves, and eventually, our production levels.

Our future capital resources and liquidity may depend, in part, on our success in developing the leasehold interests that we have acquired. Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and gas industry. Future success in growing reserves and production will be highly dependent on 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. 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,
	2010			2009
Revolving Credit Facility	$	24,625		$	32,950
Long – term debt – related party		76,354			79,354
Current maturities of long-term debt, short-term debt and bank overdraft		21,132			12,366
Total debt		122,111			124,670

Stockholders’ equity		16,117			13,733

Debt to capital ratio		88.3	%		90	%

Under the credit facility available, we can borrow up to a maximum of $52,400 thousand, of which approximately $12,950 thousand is currently outstanding. Management currently believes that this availability is sufficient to provide the liquidity required to satisfy our anticipated working capital needs for 2010.

As of June 30, 2010, our total debt was $122,111 thousand, compared to total debt of $124,670 thousand at December 31, 2009. As of June 30, 2010, current debt included $16,950 thousand as current maturities of the Revolving Credit Facilities, of which $4,000 thousand was the result of management’s decision to continue payments to reduce debt below the borrowing base. As of December 31, 2009, current debt included $12,000 thousand as current maturities, of which $12,000 thousand was the result of management’s decision to continue payments to reduce debt below the borrowing base.

Cash Flow

Our primary sources of cash in the six months ended June 30, 2010 and 2009 were our operating activities. In the 2010 and 2009 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 and could influence our ability to reduce our long-term loans. Prices for oil and natural gas have historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have also influenced prices throughout recent years.

	Six months Ended June 30,
	2010			2009
	(In thousands)
Cash flows provided by operating activities	$	5,460		$	10,685
Cash flows provided by (used in) investing activities		(1,914	)		559
Cash flows used in financing activities		(2,529	)		(11,461	)
Net increase (decrease) in cash	$	1,017		$	(217	)

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Operating Activities, During the first six months of 2010, compared to the first six months of 2009, net cash flow provided by operating activities decreased by $5,225 thousand to $5,460 thousand. This decrease was primarily attributable to a reduction in working capital of $2,264 thousand, higher lease operating expenses and expenses related to our well plugging and abandonment obligations. The reduction in net cash proceeds from commodity price hedging activities of $5,994 thousand was offset by increased oil and natural gas revenues of $5,620.The increase in revenues was primarily attributable to higher average oil and gas prices for the six months ended June 30, 2010 of $75.68/bbl and $5.06/mcf, compared to $46.65/bbl and $3.58/mcf for the six months ended June 30, 2009.

Investing Activities, The primary driver of cash used in investing activities in 2010 is capital spending. Net cash flows provided by (used in) investing activities for the six months ended June 30, 2010 and 2009 were $(1,914) thousand and $559 thousand, respectively.

Financing Activities, Net cash flows used in financing activities were $(2,529) thousand and $(11,461) thousand for the six months ended June 30, 2010 and 2009, respectively. Excess cash flow from operations is used to repay borrowings under our Senior Credit Agreements to the extent available. During the first six months of 2010, we repaid borrowings of $3,375. During the first six months of 2009, we repaid borrowings of $9,250.

Results of Operations

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

Selected Data

	Three Months Ended June 30,
	2010			2009
	(In thousands except per share and MBOE amounts)
Financial Results
Oil and Gas sales	$	9,403		$	7,155
Other		124			244
Total revenues and other		9,527			7,399

Cost and expenses		10,144			8,881
Other expense (income)		(2,081	)		10,741
Income tax expenses (benefit)		498			(4,209	)
Net income (loss)		966			(8,014	)
Earnings per common share – basic and diluted	$	0.36		$	(2.95	)
Weighted average number of shares outstanding-basic and diluted		2,717,691			2,717,691

Operating Results
Adjusted EBITDAX (1)	$	4,795		$	7,373
Sales volumes (MMBOE)		213			223

Average cost per MBOE:
Production (including transportation and taxes)	$	23.69		$	16.17
General and administrative	$	4.7		$	3.75
Depletion	$	16.60		$	19.07

(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 2010, our net income was $966 thousand, or $0.36 per share. This compares to net loss of $(8,014) thousand, or $(2.95) per share, for the second quarter of 2009.

The increase in net income was primarily due to the impact of our hedging (derivative) position and higher natural gas, oil and NGLs sales revenues due to higher prices, lower depreciation, depletion and amortization expenses and lower interest expense. This was partially offset by a decrease in sales volumes of natural gas and natural gas liquids (“NGLs”) caused by the natural decline in production and higher lease operating expenses.

Revenues, Volumes and Average Prices

Sales Revenues

	Three Months Ended June 30,
In thousands except percentages	2010		2009		D vs. 2009
Gas sales	$	2,566	$	2,113		21	%
Oil sales		5,451		4,014		36
Natural gas liquid sales		1,386		1,028		35
Total	$	9,403	$	7,155		31	%

Our sales revenues for the three months ended June 30, 2010 increased by 31% compared to the same period of 2009 due to higher natural gas, oil and condensate and NGLs commodity prices.

Volumes and Average Prices

	Three Months Ended June 30,
	2010		2009		D vs. 2009
Natural Gas
Sales volumes Mmcf		591.93		653.75		(9	)%
Average Price per Mcf (1)	$	4.34	$	3.23		34
Total gas sales revenues (thousands)	$	2,566	$	2,113		21	%

Crude Oil
Sales volumes MBbl		73.81		71.08		4	%
Average Price per Bbl (1)	$	73.85	$	56.48		31
Total oil sales revenues (thousands)	$	5,451	$	4,014		36	%

Natural gas liquids
Sales volumes MBbl		40.90		42.46		(4	)%
Average Price per Bbl (1)	$	33.89	$	24.20		40
Total natural gas liquids sales revenues (thousands)	$	1,386	$	1,028		35	%

(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 9% and natural gas liquids sales volumes by 4% for the three months ended June 30, 2010 compared to the same period of 2009, primarily due to a natural decline in production. The company’s crude oil sales volumes increased by 4%, primarily due to workovers we did in some of our properties.

Our average natural gas price for the three months ended June 30, 2010 increased by 34% or $1.11 per Mcf when compared to the same period of 2009. Our average crude oil price for the three months ended June 30, 2010 increased by 31% or $17.37 per Bbl when compared to the same period of 2009. Our average natural gas liquids price for the three months ended June 30, 2010 increased by 40% or $9.69 per Bbl when compared to the same period of 2009.

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, 2010 compared to the same period of 2009.

In thousands	Natural Gas			Oil		Natural gas liquids
2009 sales revenues	$	2,113		$	4,014	$	1,028
Changes associated with sales volumes		(200	)		155		(38	)
Changes in prices		653			1,282		396
2010 sales revenues	$	2,566		$	5,451	$	1,386

Operating Expenses

	Three Months Ended June 30,
In thousands except percentages	2010		2009		D vs. 2009
Lease operating expense, transportation and taxes	$	5,054	$	3,598		40	%
Depreciation, depletion and amortization		3,542		4,244		(17	)
Accretion expense		204		204		-
Loss from plugging and abandonment of wells		342		-		-
General and administrative		1,002		835		20
	$	10,144	$	8,881		14	%

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During three months ended June 30, 2010, our operating expenses increased by 14% when compared to the same period of 2009 due to the following factors:

Lease operating expense, transportation cost and taxes increased by 40%, or $1,456 thousand, 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. Finally, the higher oil and gas sale prices we received increased the taxes paid during 2010. On a per unit basis, lease operating expenses (including transportation and taxes) increased by $7.52 per MBOE to $23.69 per MBOE in 2010 from $16.17 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 in these factors may cause our composite DD&A rate and expense to fluctuate from period to period. DD&A decreased by 17%, or $702 thousand, 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, lower oil and gas production, and the impact of a 2009 impairment of $5,751 thousand on the depletable base used to calculate DD&A. On a per unit basis, depletion expense decreased by $2.47 per MBOE to $16.60 per MBOE in 2010 from $19.07 per MBOE in 2009

·	General and administrative expenses increased by 20%, or $167 thousand, in 2010 when compared to 2009. This increase was primarily due to increased legal fees and expenses associated with certain legal proceedings.

Other expenses

	Three Months Ended June 30,
In thousands except percentages	2010			2009		D vs. 2009
Interest expense, net	$	1,955		$	2,356		(17	)%
Net loss (gain) on derivative contracts		(4,036	)		8,385		(148	)
	$	(2,081	)	$	10,741		(119	)%

Interest expense. Isramco’s interest expense decreased by 17%, or $401 thousand, for the second quarter of 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 Energy Company, LLC acquisition in 2007 and the GFB acquisition in 2008, and to decreases in average LIBOR rates during 2009. The decrease was partially offset by the payments on interest rate swaps.

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 the consolidated statement of operations.

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).

At June 30, 2009, the Company had a $13.1 million derivative asset, which $7.7 million was classified as current. For the three months ended June 30, 2009, the Company recorded a net derivative loss of $8.4 million ($12.8 million unrealized loss and a $4.4 million gain from net cash proceeds 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”). 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.

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 except percentages	2010			2009
Income from operations before income taxes	$	1,464		$	(12,223	)
Depreciation, depletion and amortization expense		3,542			4,244
Interest expense		1,955			2,356
Unrealized loss (gain) on derivative contract		(2,370	)		12,792
Accretion Expenses		204			204
Consolidated Adjusted EBITDAX	$	4,795		$	7,373

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Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Selected Data

	June 30,
	2010			2009
	(In thousands except per share and MBOE amounts)
Financial Results
Oil and Gas sales	$	19,358		$	13,738
Other		334			668
Total revenues and other		19,692			14,406

Cost and expenses		19,663			18,142
Other expense (income)		(3,492	)		5,774
Income tax expense (benefit)		1,198			(3,286	)
Net income (loss)		2,323			(6,224	)
Earnings per common share – basic and diluted	$	0.85		$	(2.29	)
Weighted average number of shares outstanding-basic and diluted		2,717,691			2,717,691

Operating Results
Adjusted EBITDAX (1)	$	10,203		$	14,417
Sales volumes (MMBOE)		412			454

Average cost per MBOE:
Production (including transportation and taxes)	$	24.15		$	15.98
General and administrative	$	4.61		$	3.77
Depletion	$	16.28		$	19.26

(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, in the six months ended June 30, 2010, our net income was $2,323 thousand, or $0.85 per share. This compares to net loss of $(6,224) thousand, or $(2.29) per share, for the same period of 2009.

The increase in net income was primarily due to the impact of derivatives, higher natural gas, oil and NGLs sales revenues due to higher prices, 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.

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Revenues, Volumes and Average Prices

Sales Revenues

	Six Months Ended June 30,
In thousands except percentages	2010		2009		D vs. 2009
Gas sales	$	5,948	$	4,776		25	%
Oil sales		10,529		6,977		51
Natural gas liquid sales		2,881		1,985		45
Total	$	19,358	$	13,738		41	%

Our sales revenues for the six months ended June 30, 2010 increased by 41% when compared to same period of 2009 due to higher natural gas, oil and condensate and NGLs commodity prices.

Volumes and Average Prices

	Six Months Ended June 30,
	2010		2009		D vs. 2009
Natural Gas
Sales volumes Mmcf		1,174.51		1,333.14		(12	)%
Average Price per Mcf (1)	$	5.06	$	3.58		41
Total gas sales revenues (thousands)	$	5,948	$	4,776		25	%

Crude Oil
Sales volumes MBbl		139.13		149.58		(7	)%
Average Price per Bbl (1)	$	75.68	$	46.65		62
Total oil sales revenues (thousands)	$	10,529	$	6,977		51	%

Natural gas liquids
Sales volumes MBbl		77.29		82.63		(6	)%
Average Price per Bbl (1)	$	37.28	$	24.02		55
Total natural gas liquids sales revenues (thousands)	$	2,881	$	1,985		45	%

(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 12%, crude oil sales volumes by 7% and natural gas liquids sales volumes by 6% for the six months ended June 30, 2010 compared to the same period of 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.

Our average natural gas price for the six months ended June 30, 2010 increased by 41%, or $1.48 per Mcf, when compared to the same period of 2009. Our average crude oil price for the six months ended June 30, 2010 increased by 62%, or $29.03 per Bbl, when compared to the same period of 2009. Our average natural gas liquids price for the six months ended June 30, 2010 increased by 55%, or $13.26 per Bbl, when compared to the same period of 2009.

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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, 2010 compared to the same period of 2009.

In thousands	Natural Gas			Oil			Natural gas liquids
2009 sales revenues	$	4,776		$	6,977		$	1,985
Changes associated with sales volumes		(568	)		(487	)		(128	)
Changes in prices		1,740			4,039			1,024
2010 sales revenues	$	5,948		$	10,529		$	2,881

Operating Expenses

	Six Months Ended June 30,
In thousands except percentages	2010		2009		D vs. 2009
Lease operating expense, transportation and taxes	$	9,954	$	7,263		37	%
Depreciation, depletion and amortization		6,712		8,751		(23	)
Accretion expense		408		414		(1	)
Loss from plug and abandonment		688		-		-
General and administrative		1,901		1,714		11
	$	19,663	$	18,142		8	%

During six months ended June 30, 2010, our operating expenses increased by 8% when compared to the same period of 2009 due to the following factors:

Lease operating expense, transportation cost and taxes increased by 37%, or $2,691 thousand, 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. Finally, the higher oil and gas sale prices we received increased the taxes paid during 2010. On a per unit basis, lease operating expenses (including transportation and taxes) increased by $8.17 per MBOE to $24.15 per MBOE in 2010 from $15.98 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 in these factors may cause our composite DD&A rate and expense to fluctuate from period to period. DD&A decreased by 23%, or $2,039 thousand, 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, lower oil and gas production, and the impact of a 2009 impairment of $5,751 thousand on the depletable base used to calculate DD&A. On a per unit basis, depletion expense decreased by $2.98 per MBOE to $16.28 per MBOE in 2010 from $19.26 per MBOE in 2009.

·	Accretion expense for asset retirement obligations slightly decreased by 1%, or $6 thousand, in 2010 when compared to 2009. The decrease reflects the impact of the plugging and abandonment of several of our wells.

·	General and administrative expenses increased by 11%, or $187 thousand, in 2010 when compared to 2009. This increase was primarily due to increased legal fees and expenses associated with certain legal proceedings.

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Other expenses

	Six Months Ended June 30,
In thousands except percentages	2010			2009		D vs. 2009
Interest expense, net	$	3,917		$	4,803		(18	)%
Net loss (gain) on derivative contracts		(7,409	)		971		(863	)
	$	(3,492	)	$	5,774		(160	)%

Interest expense. Isramco’s interest expense decreased by 18%, or $886 thousand, for the six months ended June 30, 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 2009. The decrease was partially offset by the payments on interest rate swaps

Adjusted EBITDAX.

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	Six Months Ended June 30,
In thousands except percentages	2010			2009
Income from operations before income taxes	$	3,521		$	(9,510	)
Depreciation, depletion and amortization expense		6,712			8,751
Interest expense		3,917			4,803
Unrealized loss (gain) on derivative contract		(4,355	)		9,959
Accretion Expenses		408			414
Consolidated Adjusted EBITDAX	$	10,203		$	14,417

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 varies 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. 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. At June 30, 2010, we had two open positions that convert a portion of our variable rate interest of our Scotia debt (as defined in Note 8, “Long-term Debt” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. 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.

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, 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.

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

	A derivative case styled “Cause No. 2010-21777; Yuval Ran v. Haim Tsuff, et al., In the 295th Judicial District Court for Harris County, Texas was filed on April 10, 2010. The case has not yet been served on any defendant. However, the case has been consolidated with the pending derivative cases (previously disclosed), which are now styled “Lead Cause No. 2009-34535; In Re Isramco, Inc. Shareholder Derivative Litigation; In the 55th Judicial District Court of Harris County, Texas. All claims are scheduled for non-binding mediation on October 6, 2010. The suit claims damages and alleges that various breaches of fiduciary duty, self dealing and other wrongdoing occurred, primarily on the part of Haim Tsuff and Jackob Maimon, in connection with the sale of the Company’s interest in various foreign assets. The Company believes the suit to be without merit and the Company and the other defendants intend to vigorously defend the lawsuit. Another derivative case was filed on July 7, 2010, styled “Case # 5612; Yuval Lapiner, Derivatively and on behalf of Isramco, Inc. v. Haim Tsuff, Jackob Maimon, Max Pridgeon, Michelle R. Cinnamon Flores, Marc E. Kalton, Frans Sluiter, I.O.C. -- Israel Oil Company, Ltd., Naphtha Israel Petroleum Corporation, Ltd., J.O.E.L. -- Jerusalem Oil Exploration, Ltd., Chesny Estates, Ltd., And Goodrich Global, Ltd.,. This case was filed in the Delaware Chancery Court in Wilmington, DE. The claims asserted in this case are essentially the same damage claims as asserted in the Yuval Ran case, described above. On July 27, 2010 the Company filed motions in the Chancery Court to Dismiss or Stay the lawsuit and is awaiting a ruling on such motions to determine whether the Delaware suit will be allowed to go forward. The Company believes the suit to be without merit and the Company and the other defendants intend to vigorously defend the lawsuit.

ITEM 1A.	Risk Factors
	None

ITEM 2.	Change in Securities & 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

Table of Contents

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, 2010	By:	/s/ HAIM TSUFF
		HAIM TSUFF
		CHIEF EXECUTIVE OFFICER
		(PRINCIPAL EXECUTIVE OFFICER)

Date: AUGUST 9, 2010	By:	/s/ EDY FRANCIS
		EDY FRANCIS
		CHIEF FINANCIAL OFFICER
		(PRINCIPAL FINANCIAL AND PRINCIPAL ACCOUNTING OFFICER)

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