US ENERGY CORP - Quarter Report: 2010 September (Form 10-Q)

form10_q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarter ended September 30, 2010 or

o	Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
	For the transition period from ___________ to ____________

Commission File Number: 0-6814

U.S. ENERGY CORP.

(Exact name of registrant as specified in its charter)

Wyoming		83-0205516
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

877 North 8th West, Riverton, WY		82501
(Address of principal executive offices)		(Zip Code)

Registrant's telephone number, including area code:		(307) 856-9271

Not Applicable

(Former name, address and fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has 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 Company 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 Regulations 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 definitions of “large accelerated filer,” “accelerated filer” and ‘smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o

Non-accelerated filer x (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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

At November 5, 2010, there were issued and outstanding 26,981,263 shares of the Company’s common stock, $.01 par value.

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U.S. ENERGY CORP. and SUBSIDIARIES

INDEX

		Page No.
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements.

	Condensed Consolidated Balance Sheets as of September 30, 2010 (unaudited) and December 31, 2009 (unaudited)	4-5

	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009 (unaudited)	6

	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009 (unaudited)	7-8

	Notes to Condensed Consolidated Financial Statements (unaudited)	9-21

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22-39

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39

Item 4.	Controls and Procedures	40

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	41-42

Item 1A.	Risk Factors	42

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43

Item 3.	Defaults Upon Senior Securities	43

Item 4.	Submission of Matters to a Vote of Security Holders	43

Item 5.	Other Information	43

Item 6.	Exhibits and Reports on Form 8-K	43

	Signatures	44

	Certifications	See Exhibits

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INDEX

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

U.S. ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
(Unaudited)
(In thousands)

	September 30,		December 31,
	2010		2009
CURRENT ASSETS:
Cash and cash equivalents	$	10,414	$	33,403
Marketable securities
Held to maturity - treasuries		29,242		22,059
Available for sale securities		1,110		1,178
Accounts receivable
Trade		3,942		3,882
Reimbursable project costs		2		2
Income taxes		353		353
Other current assets		1,203		1,223
Total current assets		46,266		62,100

INVESTMENT		2,910		2,958

PROPERTIES AND EQUIPMENT:
Oil & gas properties under full cost method, net		43,831		26,002
Undeveloped mining claims		22,003		21,969
Commercial real estate, net		22,512		23,200
Property, plant and equipment, net		9,540		9,301
Net properties and equipment		97,886		80,472

OTHER ASSETS		1,740		1,193
Total assets	$	148,802	$	146,723

The accompanying notes are an integral part of these statements.

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INDEX

U.S. ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
(Unaudited)
(In thousands, except shares)

	September 30,		December 31,
	2010		2009
CURRENT LIABILITIES:
Accounts payable	$	4,442	$	6,500
Accrued compensation		1,515		1,748
Commodity risk management liability		586		--
Current portion of long-term debt		200		200
Other current liabilities		711		224
Total current liabilities		7,454		8,672

LONG-TERM DEBT, net of current portion		600		600

DEFERRED TAX LIABILITY		7,685		7,345

ASSET RETIREMENT OBLIGATIONS		293		211

OTHER ACCRUED LIABILITIES		838		762

SHAREHOLDERS' EQUITY:
Common stock, $.01 par value; unlimited shares
authorized; 26,856,290 and 26,418,713
shares issued, respectively		269		264
Additional paid-in capital		120,646		118,998
Accumulated surplus		10,647		9,485
Unrealized gain on marketable securities		370		386
Total shareholders' equity		131,932		129,133
Total liabilities and shareholders' equity	$	148,802	$	146,723

The accompanying notes are an integral part of these statements.

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INDEX

U.S. ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except per share data)

	Three months ended September 30,						Nine months ended September 30,
	2010			2009			2010			2009
REVENUES:
Oil and gas	$	6,303		$	691		$	20,230		$	2,119
Unrealized (loss) on
risk management activities		(586	)		--			(586	)		--
Real estate		646			686			1,893			2,165
		6,363			1,377			21,537			4,284

OPERATING EXPENSES:
Oil and gas		4,399			544			11,678			2,143
Impairment of oil and gas properties		--			405			--			1,468
Real estate		562			507			1,717			1,517
Water treatment plant		347			379			1,155			1,398
Mineral holding costs		9			--			61			--
General and administrative		1,920			1,838			6,755			5,675
		7,237			3,673			21,366			12,201

OPERATING INCOME (LOSS):		(874	)		(2,296	)		171			(7,917	)

Other income and (expenses)
Gain/(loss) on sale of assets		--			(46	)		115			(41	)
Equity gain/(loss) in
unconsolidated investment		(52	)		(339	)		1,090			(505	)
Gain on sale of marketable securities		26			--			34			--
Miscellaneous income		60			5			61			14
Interest income		30			88			91			264
Interest expense		(16	)		(20	)		(51	)		(78	)
		48			(312	)		1,340			(346	)

INCOME (LOSS) BEFORE INCOME TAX:		(826	)		(2,608	)		1,511			(8,263	)

Income taxes:
Current (provision for) benefit from		--			(3	)		--			210
Deferred (provision for) benefit from		591			867			(349	)		1,077
		591			864			(349	)		1,287

NET INCOME (LOSS)	$	(235	)	$	(1,744	)	$	1,162		$	(6,976	)

NET INCOME (LOSS) PER SHARE
Basic	$	(0.01	)	$	(0.09	)	$	0.04		$	(0.33	)

Diluted	$	(0.01	)	$	(0.09	)	$	0.04		$	(0.33	)

Weighted average shares outstanding
Basic		26,855,513			21,288,841			26,693,710			21,416,869

Diluted		26,855,513			21,288,841			27,743,396			21,416,869

The accompanying notes are an integral part of these statements.

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INDEX

U.S. ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

	Nine months ended September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	1,162		$	(6,976	)
Adjustments to reconcile net income (loss) to net cash
provided by operations
Depreciation, depletion and amortization		8,763			2,918
Change in fair value of commodity price
risk management activities, net		586			--
Accretion of discount on treasury investment		(61	)		(160	)
Impairment of oil and gas properties		--			1,468
Gain on sale of marketable securities		(34	)		--
Equity (gain)/loss from Standard Steam		(1,090	)		505
Change in deferred income taxes		349			(1,077	)
(Gain)/loss on sale of assets		(115	)		41
Noncash compensation		1,101			1,283
Noncash services		48			50
Net changes in assets and liabilities		1,546			4,802
NET CASH PROVIDED BY
OPERATING ACTIVITIES		12,255			2,854

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition and development of oil and gas properties	$	(29,013	)	$	(9,078	)
Net (investment in) redemption of treasury investments		(7,122	)		24,088
Net distribution from (investment in) Standard Steam		1,138			(877	)
Acquisition and development of mining properties		(34	)		(10	)
Mining property option payment		--			1,000
Development of real estate		--			(91	)
Acquisition of property and equipment		(704	)		(249	)
Proceeds from sale of property and equipment		118			5
Proceeds from sale of marketable securities		77			--
Net change in restricted investments		(207	)		4,682
NET CASH (USED IN) PROVIDED
BY INVESTING ACTIVITIES		(35,747	)		19,470

The accompanying notes are an integral part of these statements.

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INDEX

U.S. ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

	Nine months ended September 30,
	2010			2009
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock, net	$	503		$	--
Repayments of debt		--			(17,688	)
Stock buyback program		--			(1,399	)
NET CASH PROVIDED BY (USED IN)
FINANCING ACTIVITIES		503			(19,087	)

NET (DECREASE) INCREASE IN
CASH AND CASH EQUIVALENTS		(22,989	)		3,237

CASH AND CASH EQUIVALENTS
AT BEGINNING OF PERIOD		33,403			8,434

CASH AND CASH EQUIVALENTS
AT END OF PERIOD	$	10,414		$	11,671

SUPPLEMENTAL DISCLOSURES:
Income tax received	$	--		$	(5,753	)

Interest paid	$	15		$	34

NON-CASH INVESTING AND FINANCING ACTIVITIES:

Unrealized gain	$	370		$	143

Acquisition and development of oil and gas
properties through accounts payable	$	1,894		$	--

Acquisition and development of oil and gas
through asset retirement obligation	$	70		$	--

The accompanying notes are an integral part of these statements.

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INDEX

U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

1) Basis of Presentation

The accompanying unaudited condensed financial statements for the periods ended September 30, 2010 and September 30, 2009 have been prepared by U.S. Energy Corp. (“USE” or the “Company”) in accordance with generally accepted accounting principles (“GAAP”) in the United States of America. The financial statements at September 30, 2010 include the Company’s wholly owned subsidiary Energy One LLC (“Energy One”) which owns the majority of the Company’s oil and gas assets. The Condensed Balance Sheet at December 31, 2009 was derived from audited financial statements. In the opinion of the Company, the accompanying condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the financial position of the Company for the reported periods. Entities in which the Company holds at least 20% ownership or in which there are other indicators of significant influence are generally accounted for by the equity method, whereby the Company records its proportionate share of the entities’ results of operations. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. The unaudited condensed financial statements should be read in conjunction with the Company's December 31, 2009 Annual Report on Form 10-K. Subsequent events have been evaluated for financial reporting purposes through the date of the filing of this Form 10-Q. See Note 12.

2) Summary of Significant Accounting Policies

For detailed descriptions of our significant accounting policies, please see Form 10-K for the year ended December 31, 2009 (Note B pages 84 to 92).

We follow accounting standards set by the Financial Accounting Standards Board, commonly referred to as the “FASB.” The FASB sets generally accepted accounting principles (GAAP) that we follow to ensure we consistently report our financial condition, results of operations, and cash flows.

The FASB recognized the complexity of its standard-setting process and embarked on a revised process in 2004 that culminated in the release on July 1, 2009, of the FASB Accounting Standards Codification, sometimes referred to as the Codification or ASC. The Codification does not change how the Company accounts for its transactions or the nature of related disclosures made. However, when referring to guidance issued by the FASB, the Company refers to topics in the ASC. The above change was made effective by the FASB for periods ending on or after September 15, 2009.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include oil and gas reserves used for depletion and impairment considerations and the cost of future asset retirement obligations. Due to inherent uncertainties, including the future prices of oil and gas, these estimates could change in the near term and such changes could be material.

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INDEX

U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

Oil and Gas Properties

USE follows the full cost method in accounting for its oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from property disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves. Excluded from amounts subject to depletion are costs associated with unproved properties.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated average prices per barrel of oil and per MMbtu of natural gas at the first day of each month in the 12-month period prior to the end of the reporting period and costs, adjusted for contract provisions, financial derivatives that hedge our oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, reduced by the (iv) income tax effects related to differences between the book and tax basis of the natural gas and crude oil properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs. At September 30, 2010, the book value of our oil and gas properties did not exceed the cost center ceiling.

Derivative Instruments

The Company uses derivative instruments, typically fixed-rate swaps and costless collars to manage price risk underlying its oil and gas production. The Company may also use puts, calls and basis swaps in the future. All derivative instruments are recorded in the consolidated balance sheets at fair value. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty. Although the Company does not designate any of its derivative instruments as a cash flow hedge, such derivative instruments provide an economic hedge of our exposure to commodity price risk associated with forecasted future oil and gas production. These contracts are accounted for using the mark-to-market accounting method and accordingly, the Company recognizes all unrealized and realized gains and losses related to these contracts currently in earnings and are classified as gain (loss) on derivative instruments, net in our consolidated statements of operations.

The Company’s Board of Directors sets all risk management policies and reviews the status and results of derivative activities, including volumes, types of instruments and counterparties on a quarterly basis. These policies require that derivative instruments be executed only by the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with approved counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. See Note 5, Commodity Price Risk Management, for further discussion.

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INDEX

U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

Revenue Recognition

USE records natural gas and oil revenue under the sales method of accounting. Under the sales method, we recognize revenues based on the amount of oil or natural gas sold to purchasers, which may differ from the amounts to which we are entitled to based on our interest in the properties. Natural gas balancing obligations as of September 30, 2010 were not significant.

Revenues from real estate operations are reported on a gross revenue basis and are recorded at the time the service is provided.

Recent Accounting Pronouncements

As of September 30, 2010, there have been no recent accounting pronouncements currently relevant to USE in addition to those discussed on pages 90 to 92 of our Annual Report on Form 10-K for the year ended December 31, 2009. We continue to review current outstanding statements from the FASB and do not believe that any of those statements will have a material effect on our financial statements when adopted.

3) Properties and Equipment

Land, buildings, improvements, machinery and equipment are carried at cost. Depreciation of buildings, improvements, machinery and equipment is provided principally by the straight-line method over estimated useful lives ranging from 3 to 45 years.

Components of Property and Equipment as of September 30, 2010 and December 31, 2009 are as follows:

U.S. Energy Corp.
Components of Properties & Equipment

	(In thousands)
	September 30,			December 31,
	2010			2009
Oil & Gas properties
Unproved	$	2,795		$	3,993
Wells in progress		2,534			1,367
Proved		50,083			24,595
		55,412			29,955
Less accumulated depreciation
depletion and amortization		(11,581	)		(3,953	)
Net book value		43,831			26,002

Mining properties		22,003			21,969

Commercial real estate		24,622			24,600
Less Accumulated depreciation		(2,110	)		(1,400	)
Net book value		22,512			23,200

Building, land and equipment		14,621			14,196
Less accumulated depreciation		(5,081	)		(4,895	)
Net book value		9,540			9,301
Totals	$	97,886		$	80,472

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INDEX

U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

Oil and Gas Exploration Activities

We participate in oil and gas projects as a non-operating working interest owner and have active agreements with several oil and gas exploration and production companies. Our working interest varies by project, but typically ranges from approximately 5% to 65%. These projects may result in numerous wells being drilled over the next three to five years.

Williston Basin, North Dakota

From August 24, 2009 to September 30, 2010, we have drilled and completed 11 gross initial Bakken Formation wells (4.89 net) and 1 gross Three Forks formation well (0.17 net) under the Drilling Participation Agreement with Brigham Oil & Gas, L.P. (“Brigham”) a Delaware limited partnership, wholly-owned by Brigham Exploration Company (a Delaware corporation). One gross initial Bakken formation well (0.20 net) and 2 infill Bakken formation wells (0.63 net) were in progress at September 30, 2010. Three additional gross initial wells (0.93 net) are expected to be drilled during the balance of 2010. Brigham operates all of the wells.

During the first nine months of 2010, USE completed 6 gross wells (2.08 net) with our percentage of the net costs of $14.1 million. Two gross wells (0.63 net) were drilled and awaiting completion at September 30, 2010 with net costs to us of $1.9 million. One additional gross well (0.20 net) was being drilled at September 30, 2010 with net costs to the Company of $538,000.

If the state of North Dakota allows three wells per formation in each spacing unit, the Company could ultimately drill 45 Bakken formation and 45 Three Forks formation wells for a total of 90 wells. The drilling of each well typically takes 30 days while the completion typically takes 21-28 days.

U.S. Gulf Coast

During the first nine months of 2010, we drilled 7 gross wells (0.94 net) in the U.S. Gulf Coast. One gross well (0.50 net) was successfully completed and is currently producing, 2 gross wells (0.15 net) were in progress at September 30, 2010, 1 gross well (0.05 net) was completed, but not producing and 3 gross wells (0.24 net) have been plugged and abandoned. Our net investment in these wells through September 30, 2010 was $7.6 million. See Note 12, Subsequent Events.

We are also actively pursuing the potential of acquiring additional exploration, development or production stage oil and gas properties or companies. To further this effort, we have engaged an investment banker to assist in finding, evaluating and if necessary, financing the potential acquisition of such assets.

Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at September 30, 2010 and December 31, 2009 which were not included in the amortized cost pool were $5.3 and $5.4 million, respectively. These costs consist of wells in progress, seismic costs that are being analyzed for potential drilling locations and land costs, all related to unproved properties. No capitalized costs related to unproved properties are included in the amortization base at September 30, 2010 and December 31, 2009. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are proved, drilled or abandoned.

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INDEX

U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

Ceiling Test Analysis - We perform a quarterly ceiling test for each of our oil and gas cost centers, which in 2010, there was only one. The reserves used in the ceiling test and the ceiling test itself incorporate assumptions regarding pricing and discount rates over which management has no influence in the determination of present value. In arriving at the ceiling test for the quarter ended September 30, 2010, we used $77.34 per barrel for oil and $4.41 per MMbtu for natural gas (and adjusted for property specific gravity, quality, local markets and distance from markets) to compute the future cash flows of our producing properties. The discount factor used was 10%.

At September 30, 2010, the ceiling was in excess of the net capitalized costs as adjusted for related deferred income taxes and no impairment was required. Management will continue to review our unproved properties based on market conditions and other changes and if appropriate, unproved property amounts may be reclassified to the amortized base of properties within the full cost pool. During the nine months ended September 30, 2009, we recorded a $1.5 million impairment.

Wells in Progress - Wells in progress represent the costs associated with wells that have not reached total depth or have not been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation. The costs for these wells are then transferred to proved property when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods.

Mineral Properties

We capitalize all costs incidental to the acquisition of mineral properties. Mineral exploration costs are expensed as incurred. When exploration work indicates that a mineral property can be economically developed as a result of establishing proved and probable reserves, costs for the development of the mineral property as well as capital purchases and capital construction are capitalized and amortized using units of production over the estimated recoverable proved and probable reserves. Costs and expenses related to general corporate overhead are expensed as incurred. All capitalized costs are charged to operations if we subsequently determine that the property is not economical due to permanent decreases in market prices of commodities, excessive production costs or depletion of the mineral resource.

Mineral properties at September 30, 2010 and December 31, 2009 reflect capitalized costs associated with our Mount Emmons molybdenum property near Crested Butte, Colorado. We have entered into an agreement with Thompson Creek Metals Company USA (“TCM”) to develop this property. TCM may earn up to a 75% interest in the project for the investment of $400 million.

Our carrying balance in the Mount Emmons property at September 30, 2010 and December 31, 2009 is as follows:


	(In thousands)
Costs associated with Mount Emmons
at December 31, 2009	$	21,969
Development costs during the nine months
ended September 30, 2010		34
	$	22,003

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INDEX

U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

Real Estate

We evaluate our long-lived assets, which consist of commercial real estate, for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. Impairment calculations are generally based on market appraisals. If estimated future cash flows, on an undiscounted basis, are less than the carrying amount of the related asset, an asset impairment is considered to exist. Changes in significant assumptions underlying future cash flow estimates may have a material effect on our financial position and results of operations. We do not obtain appraisals on an ongoing basis for the property. We however did obtain an appraisal in 2009. At September 30, 2010 and December 31, 2009, management determined that no impairment existed on our long-lived asset as the 2009 appraised value exceeded construction and carrying value, rental rates remained strong and costs remain within projected limits.

4) Asset Retirement Obligations

We account for our asset retirement obligations under FASB ASC 410-20, "Asset Retirement Obligations." We record the fair value of the reclamation liability on our inactive mining properties and our operating oil and gas properties as of the date that the liability is incurred. We review the liability each quarter and determine if a change in estimate is required as well as accrete the discounted liability on a quarterly basis for the future liability. Final determinations are made during the fourth quarter of each year. We deduct any actual funds expended for reclamation during the quarter in which it occurs.

The following is a reconciliation of the total liability for asset retirement obligations:


	(In thousands)
	September 30,		December 31,
	2010		2009
Beginning asset retirement obligation	$	211	$	144
Accretion of discount		12		12
Liabilities incurred		70		55
Ending asset retirement obligation	$	293	$	211

Mining properties	$	136	$	128
Oil & Gas Wells		157		83
Ending asset retirement obligation	$	293	$	211

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INDEX

U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

5) Commodity Price Risk Management

Through our wholly-owned affiliate Energy One LLC (“Energy One”), we have entered into two commodity derivative contracts (“economic hedges”) with BNP Paribas, a costless collar and a fixed price swap, as described below. U.S. Energy Corp. is a guarantor of Energy One under the economic hedges. The objective of utilizing the economic hedges is to reduce the effect of price changes on a portion of its future oil production, achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The use of these derivative instruments limits the downside risk of adverse price movements. However, there is a risk that such use may limit our ability to benefit from favorable price movements. Energy One may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the its existing positions.

Energy One's commodity derivative contracts as of September 30, 2010 are summarized below:


			Quantity
Settlement Period	Counterparty	Basis	(Bbl/d)	Strike Price
Crude Oil Costless Collars
10/1/10 - 9/30/11	BNP Parabis	WTI	200	Put: $75.00
				Call: $83.25

Crude Oil Swap
10/1/10 - 9/30/11	BNP Parabis	WTI	200	Fixed: $79.05

The following table details the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category:

		Fair Value at
Underlying	Location on	September 30,
Commodity	Balance Sheet	2010
Crude oil derivative contract	Current liability	$	256,000

Crude oil derivative contract	Current liability		330,000
		$	586,000

Unrealized gains and losses resulting from derivatives are recorded at fair value on the condensed consolidated balance sheet and changes in fair value are recognized in the unrealized gain (loss) on risk management activities line on the condensed consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives will be recorded in the commodity price risk management activities line on the condensed consolidated statement of income. There were no realized gains or losses recorded for the nine months ending September 30, 2009.

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INDEX

U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

6) Fair Value

We adopted Financial Accounting Standards Board Accounting Standards Codification Topic 820 “Fair Value Measurements and Disclosures” (FASB ASC 820) on January 1, 2008, as it relates to financial assets and liabilities. We adopted FASB ASC 820 on January 1, 2009, as it relates to nonfinancial assets and liabilities. FASB ASC 820 establishes a fair value hierarchy that prioritizes the inputs USE uses to measure fair value. The three levels of the fair value hierarchy defined by FASB ASC 820 are as follows:

·	Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

·	Level 2 — Pricing inputs, other than quoted prices within Level 1, which are either directly or indirectly observable.

·	Level 3 — Pricing inputs that are unobservable requiring the Company to use valuation methodologies that result in management’s best estimate of fair value.

Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. As of September 30, 2010, we held $30.4 million of investments in government securities and marketable securities. The fair value of the investments is reflected on the balance sheet as detailed below. The fair value of our other accrued liabilities are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. The fair values of the other accrued liabilities that are reflected on the balance sheet are detailed below.

	(In thousands)
			Fair Value Measurements at September 30, 2010 Using
	September 30,		Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	2010		(Level 1)		(Level 2)		(Level 3)

Available for sale securities	$	1,110	$	1,110	$	--	$	--

Total assets	$	1,110	$	1,110	$	--	$	--

Commodity risk management liability	$	586	$	--	$	586	$	--
Other accrued liabilities		838		--		--		838

Total liabilitities	$	1,424	$	--	$	586	$	838

The other accrued liabilities are the long term portion of the executive retirement program.

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INDEX

U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

The following table summarizes, by major security type, the fair value and any unrealized gain of our investments. The unrealized gain is recorded on the condensed consolidated balance sheets as other comprehensive income, a component of shareholders’ equity.

	(In thousands)
September 30, 2010
	Less Than 12 Months				12 Months or Greater				Total
			Unrealized				Unrealized				Unrealized
Description of Securities	Fair Value		Gain		Fair Value		Gain		Fair Value		Gain

Available for sale securities	$	1,110	$	206	$	--	$	--	$	1,110	$	206

Total	$	1,110	$	206	$	--	$	--	$	1,110	$	206

Our other financial instruments include cash and cash equivalents, accounts receivable, accounts payable, other current liabilities and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable and other current liabilities approximate fair value because of their immediate or short-term maturities. The carrying value of the long-term debt approximates its fair market value since interest rates have remained generally unchanged from the issuance of the long-term debt. The following is the estimated fair value and carrying value of our other financial instruments at each of these dates:

	(In thousands)
	September 30, 2010
Description	Carry Amount		Fair Value

Long-term debt	$	800	$	800

7) Long-term debt

At September 30, 2010, long term debt consists of debt related to the purchase of land which bears an interest rate of 6% per annum. The debt is due in four equal annual payments of $200,000, plus accrued interest. The next payment is due on January 2, 2011.

8) Shareholders’ Equity

Common Stock

During the three and nine months ended September 30, 2010, USE issued 21,584 and 437,577 shares of common stock, respectively. These shares consist of (a) 60,000 shares issued to officers of the Company pursuant to the 2001 Stock Compensation Plan; (b) 236,367 shares issued as a result of warrants being exercised and (c) 141,210 shares as a result of the exercise of options by employees of the Company.

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INDEX

U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

The following table details the changes in common stock during the nine months ended September 30, 2010:


(Amounts in thousands, except for share amounts)
					Additional
	Common Stock				Paid-In
	Shares		Amount		Capital

Balance December 31, 2009		26,418,713	$	264	$	118,998
2001 stock compensation plan		60,000		1		337
Exercise of employee stock options		141,210		1		(201	)
Exercise of stock warrants		236,367		3		700
Expense of employee options vesting		--		--		764
Stock options issued to outside directors		--		--		45
Expense of company warrants issued		--		--		3
Balance September 30, 2010		26,856,290	$	269	$	120,646

Stock Option Plans

The Board of Directors adopted, and the shareholders approved, the U.S. Energy Corp. 2001 Incentive Stock Option Plan (the "2001 ISOP") for the benefit of the Company's employees. The 2001 ISOP reserves for issuance shares of the Company’s common stock equal to 25% of the Company’s shares of common stock issued and outstanding at any time. The 2001 ISOP has a term of 10 years.

During the three and nine months ended September 30, 2010, we recognized $257,000 and $764,000, respectively, in compensation expense related to employee options. We will recognize an additional $1.2 million in expense over the remaining vesting life of the outstanding options of 1.2 years. We compute the fair values of options granted using the Black-Scholes pricing model. 141,210 shares of common stock were issued as a result of the exercise of 360,984 options held by officers and employees during the nine months ended September 30, 2010.

Warrants to Others

From time to time we issue stock purchase warrants to non-employees for services. During the nine months ended September 30, 2010, we issued 10,000 warrants to an independent director. The warrants were issued at the closing price of $5.04 on the date of grant, vest over a three year period and expire ten years from the date of grant. The options were valued under Black-Scholes using a risk free interest rate of 2.235%, expected life of 6 years and expected volatility of 63.79%. During the nine months ended September 30, 2010 we issued 236,367 shares of common stock as the result of the exercise of outstanding warrants.

During the three and nine months ended September 30, 2010, we recorded $18,000 and $48,000, respectively, in expense for warrants issued to third parties. We will recognize an additional $87,000 in expense over the vesting period of the outstanding warrants.

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

The following table represents the activity in employee stock options and non-employee stock purchase warrants for the nine months ended September 30, 2010:

	September 30, 2010
	Employee Stock Options					Stock Purchase Warrants
				Weighted					Weighted
				Average					Average
				Exercise					Exercise
	Options			Price		Warrants			Price

Outstanding balance at December 31, 2009		3,711,114		$	3.64		581,367		$	2.91
Granted		-		$	-		10,000		$	5.04
Forfeited		-		$	-		(20,000	)	$	2.52
Expired		-		$	-		-		$	-
Exercised		(360,984	)	$	2.84		(236,367	)	$	2.97
Outstanding at September 30, 2010		3,350,130		$	3.72		335,000		$	2.95
Exercisable at September 30, 2010		2,742,631		$	3.61		291,667		$	2.93

Weighted Average Remaining Contractual Life - Years					5.13					4.29

Aggregate intrinsic value of options / warrants outstanding				$	3,286,000				$	538,000

9)Income Taxes

USE uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time.

The deferred income tax liability for an oil and gas exploration company is dependent on many variables such as estimating the economic lives of depleting oil and gas reserves and commodity prices. Accordingly, the liability is subject to continual recalculation, revision of the numerous estimates required, and may change significantly in the event of such things as major acquisitions, divestitures, product price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.

10) Segment Information

As of September 30, 2010, we had three reportable segments: Oil and Gas, Real Estate Operations, and Maintenance of Mineral Properties.

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

A summary of results of operations for the three and nine months ended September 30, 2010, and 2009, and total assets as of September 30, 2010 and December 31, 2009 by segment are as follows:

	(Unaudited)
	(In thousands)
	For the three months						For the nine months
	ended September 30,						ended September 30,
	2010			2009			2010			2009
Revenues:
Oil and gas	$	5,717		$	691		$	19,644		$	2,119
Real estate		646			686			1,893			2,165
Total revenues:		6,363			1,377			21,537			4,284

Operating expenses:
Oil and gas	$	4,399		$	949		$	11,678		$	3,611
Real estate		562			507			1,717			1,517
Mineral properties		356			379			1,216			1,398
Total operating expenses:		5,317			1,835			14,611			6,526

Interest expense
Oil and gas	$	--		$	--		$	--		$	--
Real estate		--			--			--			19
Mineral properties		12			15			36			45
Total interest expense:		12			15			36			64

Operating income/(loss)
Oil and gas	$	1,318		$	(258	)	$	7,966		$	(1,492	)
Real estate		84			179			176			629
Mineral properties		(368	)		(394	)		(1,252	)		(1,443	)
Operating income/(loss)		1,034			(473	)		6,890			(2,306	)

Other revenues and expenses:		(1,860	)		(2,135	)		(5,379	)		(5,957	)

Income/(loss) before
income taxes	$	(826	)	$	(2,608	)	$	1,511		$	(8,263	)

Depreciation expense:
Oil and gas	$	2,976		$	475		$	7,627		$	1,795
Real estate		266			262			797			783
Mineral properties		18			13			54			41
Corporate		95			98			285			299
Total depreciation expense		3,355			848			8,763			2,918

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)


	(In thousands)
	September 30,		December 31,
	2010		2009
Assets by segment
Oil and Gas properties	$	53,965	$	30,016
Real estate		22,760		23,450
Mineral properties		22,021		21,998
Corporate assets		50,056		71,259
Total assets	$	148,802	$	146,723

11) Equity Income in Unconsolidated Investment

We recorded an equity gain from our unconsolidated investment in Standard Steam, LLC. (“SST”) during the nine months ended September 30, 2010 of $1.1 million, and an equity loss of $52,000 from SST for the quarter ended September 30, 2010. The gain came as a result of the sale of two of the geothermal properties owned by SST and the negotiation of discounts on previously recorded accounts payable.

12) Subsequent Events

On October 13, 2010 we were notified by BNP Paribas that the redetermination as of June 30, 2010 increased the Borrowing Base under the Credit facility from $12.0 million to $18.5 million until the next scheduled redetermination date which will be based on the December 31, 2010 financial statements, reserve reports and production.

On October 22, 2010 the decision was made by Houston Energy and all participating entities, including the Company, to plug and abandon the Wolf #1 well in Gains County, Texas. The Company’s portion of drilling costs in the Wolf #1 as of the decision date was $192,000.

On November 1, 2010 USE entered into an acquisition, exploration and development agreement with private Denver, Colorado-based Cirque Resources LP ("Cirque") to acquire a 40% working interest in an oil and gas prospect located in Kern County, California.

Under the terms of the agreement, USE has committed to pay approximately $2.5 million to earn a 40% working interest in approximately 6,200 net acres and to carry Cirque for a component of its drilling cost in a commitment well. Cirque is the operator of the project and the commitment well is planned to be spud in the fourth quarter of 2010. All subsequent wells will be drilled on a heads up basis. The prospect is a Miocene target in the San Joaquin basin with an expected total drilling depth of approximately 13,000 feet. The commitment well is targeting up to 300 feet of layered Stevens Sands in a stratigraphic trap on the flank of a prolific oil producing field in the basin.

On November 3, 2010, the Brad Olson 9-16 #2H, the first Bakken infill well completed under the Drilling Participation Agreement (“DPA”) with Brigham produced approximately 2,472 barrels of oil and 1.47 MMCF of natural gas per day or 2,717 BOE/D during an early 24-hour initial flow back period. The well was completed with swell packers and 32 fracture stimulation stages. U.S. Energy’s initial working interest in this well is approximately 31% (~25% net revenue interest). Oil and gas sales from this well have commenced.

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ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is Management's Discussion and Analysis of significant factors that have affected liquidity, capital resources and results of operations during the three and nine months ended September 30, 2010 and 2009. The following also updates information as to our financial condition provided in our 2009 Annual Report on Form 10-K. Statements in the following discussion may be forward-looking and involve risk and uncertainty. The following discussion should also be read in conjunction with our condensed financial statements and notes thereto.

General Overview

Our primary objective is to acquire and develop oil and gas producing properties in the continental United States. Our business is currently focused in the Williston Basin and onshore U.S. Gulf Coast, however, we do not intend to limit our focus to these geographic areas only. We continue to focus on increasing production, reserves, revenues and cash flow from operations while maintaining low levels of debt. Our liquidity and access to financing under our recently established Senior Secured Revolving Credit Facility (see Liquidity and Capital Resources below) allows us to seek additional oil and gas opportunities in the U.S.

We currently explore for and produce oil and gas through a non-operator business model. As a non-operator, we rely on our operating partners to propose, permit and manage wells. Before a well is spud, the operator is required to provide all oil and gas interest owners in the designated well unit the opportunity to participate in the drilling costs and revenues of the well on a pro-rata basis. After the well is completed, our operating partners also transport, market and account for all production. This model provides us with operator and geologic area diversification. We also are actively seeking the acquisition of an operating company that will allow us to operate properties on our own behalf.

Additionally, we are involved in the exploration for and development of minerals (molybdenum) through our ownership of the Mt. Emmons Molybdenum Project in Colorado; geothermal energy through our investment in Standard Steam Trust and commercial real estate operations.

On July 30, 2010, we established a Senior Secured Revolving Credit Facility (the “Credit Facility”) to borrow up to $75 million from a syndicate of banks, financial institutions and other entities, including BNP Paribas (“BNPP”). The Facility may be used to further our short and mid-terms goals of increasing and improving our investment in oil and gas and is discussed further in capital and resources portion of this discussion. The initial Borrowing Base under the Credit Facility was $12.0 million. On October 13, 2010 we were notified by BNP Paribas that the redetermination as of June 30, 2010 increased the Borrowing Base under the Credit facility to $18.5 million until the next scheduled redetermination date which will be based on the December 31, 2010 financial statements, reserve reports and production.

Under our agreement with Brigham, we have committed to complete the three wells in progress at September 30, 2010 and drill and complete an additional three wells in the Williston Basin during the fourth quarter of 2010. Additional wells maybe drilled and completed under our other drilling participation agreements with PetroQuest Energy, Houston Energy, Yuma Exploration and any new agreements that may be signed during the balance of 2010.

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On September 3, 2010, through our wholly-owned affiliate Energy One LLC (“Energy One”), we entered into two commodity derivative contracts (“hedges”) with BNP Paribas, a costless collar and a fixed price swap, as described below. U.S. Energy Corp. is a guarantor of Energy One under the hedges. The objective of utilizing the hedges is to reduce the effect of price changes on a portion of our future oil production, achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The use of these derivative instruments limits the downside risk of adverse price movements. However, there is a risk that such use may limit our ability to benefit from favorable price movements. Energy One may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the its existing positions.

Factors that could affect the income from operations in the balance of 2010 on wells:

·	Lower working interests

·	Lower market prices for oil and gas

·	Higher drilling costs

·	Higher lease operating expenses

·	Steeper decline rates than currently anticipated

·	Mechanical and geological problems with the wells

2010 Drilling Projects

Williston Basin, North Dakota

From August 24, 2009 to September 30, 2010, the Company has drilled and completed 11 gross initial Bakken Formation wells (4.89 net) and 1 gross Three Forks formation well (0.17 net) under the Drilling Participation Agreement with Brigham Oil & Gas, L.P. (“Brigham”) a Delaware limited partnership, wholly-owned by Brigham Exploration Company (a Delaware corporation). One gross initial Bakken formation well (0.20 net) and 2 infill Bakken formation wells (0.63 net) were in progress at September 30, 2010. Three additional gross initial wells (0.93 net) are expected to be drilled during the balance of 2010. Brigham operates all of the wells.

During the first nine months of 2010, the Company completed 6 gross wells (2.08 net) with net costs to the Company of $14.1 million. Two gross wells (0.63 net) were drilled and awaiting completion at September 30, 2010 with net costs to the Company of $1.9 million. One additional gross well (0.20 net) was being drilled at September 30, 2010 with net costs to the Company of $538,000.

U.S. Gulf Coast

During the first nine months of 2010, we drilled 4 gross wells (0.74 net) in the U.S. Gulf Coast. One well was deemed to be productive and completed, while the other 3 were non-productive and have been plugged and abandoned. In addition to these wells, 2 additional gross wells (0.15 net) were in progress at September 30, 2010.

We expect to drill up to 3 additional gross wells in the U.S. Gulf coast during the 4th quarter of 2010.

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INDEX

Liquidity and Capital Resources

At September 30, 2010, we had $10.4 million in cash and cash equivalents and $29.2 million in U.S. Treasuries with longer than 90-day maturities from date of purchase for a total of $39.6 million or $1.48 per outstanding common share. Our working capital (current assets minus current liabilities) was $38.8 million. As discussed below in Capital Resources and Capital Requirements, we project that our capital resources at September 30, 2010 will be sufficient to fund operations and capital projects through the balance of 2010.

The principal recurring trend which affects the Company is variable prices for commodities producible from our mineral properties, although the extent and grade of discovered minerals can mitigate or aggravate the impact of price swings. As commodities experience lower values in the market place, it is typically less expensive to acquire properties and hold them until prices rise to levels which either allow the properties to be sold or placed into production through joint venture partners, or for our own account. Availability of exploration drilling equipment and crews fluctuates with the market prices for oil and natural gas. When prices are low there is typically less exploration activity and the cost of drilling and completing wells is typically reduced. Conversely, when prices are high there is typically more exploration activity and the cost of drilling and completing wells typically increases.

Cash flows during the nine months ended September 30, 2010:

Operations provided $12.2 million, Investing Activities consumed $35.7 million and Financing Activities provided $503,000 for a net decrease in cash of $23.0 million during the nine months ended September 30, 2010. During the nine months ended September 30, 2009, Operations provided $2.8 million, Investing activities provided $19.5 million and Financing activities consumed $19.1 million for a net increase of $3.2 million.

Operating Activities:

Cash provided by operations for the period ended September 30, 2010 improved to $12.2 million as compared to cash provided in operations of $2.8 million for the same period of the prior year. This $9.4 million improvement year over year in cash from operating activities is predominantly a result of a $8.1 million increase in net income during the respective periods.

·	For a complete discussion of cash provided by Operations please refer to Results of Operations below.

Investing Activities:

·	Investing activities consumed cash through the acquisition and development of oil and gas properties, $29.0 million; treasury investments, $7.1 million; acquisition of property and equipment, $704,000; in restricted investments, $207,000; the development of mineral claims, $34,000.

·	Cash was provided by investing activities as a result of a capital distribution from Standard Steam Trust, LLC, (“SST”), $1.1 million, the sale of a commercial office property, $118,000, and $77,000 in proceeds from the sale of marketable securities.

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INDEX

Financing Activities:

·	We received $503,000 net for the issuance of shares related to the exercise of employee options and warrants to third party consultants.

Following is a discussion regarding our projected Capital Resources and Capital Requirements during the balance of 2010. For longer-range projections of capital resources and requirements, please refer to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

Capital Resources

Sources of capital during the balance of 2010 will be derived from the sale of oil and gas production from existing and anticipated oil and gas operations, receipts of cash for the rental of real estate properties and cash on hand. Additional sources of capital that may be used to expand operations include borrowings pursuant to our credit facility with BNP Paribas, long-term financing of the multifamily housing complex, and a $10 million line of credit with a commercial bank.

Oil and Gas Production

At September 30, 2010, we had sixteen producing wells. During the nine months ended September 30, 2010, we received on average $2.2 million per month from these producing wells with average operating cost of $205,000 per month, production taxes of $245,000 before non cash depletion expense, for average cash flows of $1.8 million per month from oil and gas production. We anticipate that cash flows from oil and gas operations will increase through the balance of 2010 as the remaining wells being drilled with Brigham Oil & Gas, L.P. (“Brigham”), begin to produce. Decreases in the price of oil and natural gas, increased operating costs, and declines in production rates however, could decrease these monthly cash flow amounts.

The decline of production from the existing Bakken wells and the back-in provision granted Brigham after pay back of drilling costs will decrease the amount of cash flow we receive from those wells. We anticipate drilling more Bakken and Three Forks wells with Brigham in the future and will continue to search for additional drilling opportunities to replace these oil reserves and cash flows.

The ultimate amount of cash that will be derived from the production of oil and gas will be determined by the price of oil and gas, the amount of production and production costs. The ultimate life of producing wells will likewise be impacted by market prices and costs of production. We plan to continue in the oil and gas exploration business and may also acquire additional oil and gas properties.

Cash on Hand

At September 30, 2010, we had $10.4 million in cash and cash equivalents and $29.2 million in U.S. Treasuries. We invest cash in interest bearing accounts, with the majority invested in U.S. Government Treasuries. During the past two years, this investment policy has insured the preservation of principal with a nominal yield.

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Real Estate

We own a 216 unit multi-family housing complex in Gillette, Wyoming that had an occupancy rate of 96% at September 30, 2010, up from 80% at December 31, 2009. We also have real estate rental income from property located in Riverton, Wyoming. Real Estate revenues are approximately $210,000 per month and net cash flow from real estate is approximately $108,000 per month.

Although the multi-family housing project is pledged as collateral for the $10 million line of credit, there is no debt against the property. We may seek long term financing on the multi-family housing property in the future to further our oil and gas exploration and development projects.

Commercial Bank

In January 2010, we entered into a $10.0 million line of credit with a commercial bank. No borrowings have been made under this line of credit as of the date of this report. The line of credit has a variable interest rate which is tied to a national market rate with a minimum interest rate of 5.5%. The line of credit is available until January 31, 2011 at which time it may be renewed depending on our financial strength and needs. The credit line is secured by the multifamily housing project and a corporate aircraft.

BNP Paribas Reserve Lending Facility

On July 30, 2010, we established a senior credit facility to borrow up to $75 million from a syndicate of banks, financial institutions and other entities, including BNPP. The Facility may be used to further our short and mid-terms goals of increasing our investment in oil and gas. As a result of establishing this credit facility we formed a wholly owned subsidiary, Energy One LLC (“Energy One”), to own the majority of our oil and gas properties as well as the BNPP senior credit facility.

From time to time until the expiration of the credit facility (July 30, 2014) if Energy One is in compliance with the Facility Documents, Energy One may borrow, pay, and re-borrow funds from the Lenders, up to an amount equal to the Borrowing Base, which was originally established at $12 million. On October 13, 2010, the Borrowing Base was redetermined using our June 30, 2010 financial statements, production reports and a reserve report for our Bakken wells to $18.5 million.

The Borrowing Base will be redetermined semi-annually, taking into account updated reserve reports. Any proposed increase in the Borrowing Base will require approval by all Lenders in the syndicate, and any proposed Borrowing Base decrease will require approval by Lenders holding not less than two-thirds of outstanding loans and loan commitments. As of September 30, 2010 we have not borrowed from the Facility.

Capital Requirements

Our direct capital requirements during the balance of 2010 are the funding of the drilling and completion of additional wells with Brigham in the Williston Basin, additional oil and gas exploration and development projects, acquisition of prospective oil and gas properties and/or existing production, operating and capital improvement costs of the water treatment plant at the Mount Emmons molybdenum project, operations at Remington Village, and general and administrative costs.

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Oil and Gas Exploration and Development

Bakken – Williston Basin, North Dakota

Under our agreement with Brigham, we have committed to complete the three wells in progress at September 30, 2010 and drill and complete an additional three wells in the Williston Basin during the fourth quarter of 2010. We project expenditures of $11.2 million for these combined activities. The actual amount expended on the six wells will vary from the budgeted amount as a result of larger or smaller ownership interests of Brigham. Other factors which can cause actual amounts spent to vary from budgeted amounts are drilling conditions, problems encountered on site and weather. The wells to be drilled during the fourth quarter of 2010 will be approximately 10,000 feet in depth with 10,000 foot laterals and each well is expected to be completed with 28 to 32 frac stages. Projected 8/8ths cost for each of the remaining wells is $7.8 million for the Bakken formation.

By electing to participate in all of the initial wells available to us, we have earned the rights to drill up to 13 additional wells in the Bakken formation and an additional 29 wells in the Three Forks formation, for a total of 60 wells. If the state of North Dakota allows two wells per formation in each spacing unit. The state of North Dakota could ultimately increase the spacing to three wells per 1,280 acre spacing unit. In the event that three wells per formation for each 1,280 spacing unit is granted, the total potential number of drilling locations could increase to 90. Working interests earned will vary according to Brigham’s initial working interest in each 1,280 acre drilling unit, after-payout provisions and the provisions governing each stage of the program. At our current and projected drilling rates, we expect that it will take four to six years to drill all of the wells in these units.

Gulf Coast

We have committed to spend $442,000 to drill an addition oil and gas well with Houston Energy L.P. (“Houston Energy”) during the remainder of 2010.

Other

We have budgeted $15.2 million during the balance of 2010 for the acquisition of either prospective oil and gas properties or existing production and the maintenance of oil and gas leases.

Mount Emmons Molybdenum Property

Under the terms of our agreement with Thompson Creek Metals Company USA (“TCM”), we are responsible for all costs associated with operating the water treatment plant at the Mount Emmons molybdenum property. Operating costs during the balance of 2010 are projected to be approximately $425,000. Included in the operating costs, we participate on a 50 – 50 basis with TCM to fund holding costs associated with a parcel of jointly purchased real estate in Colorado and other nominal project related maintenance and security costs at the mine site. Additionally, we project capital improvement expenditures of $150,000 at the water treatment plant which are expected to improve its efficiency. Actual future costs could be different from those estimates made above.

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Geothermal Energy Projects

We had an investment of $3.0 million in a geothermal company, SST, as of December 31, 2009, representing an ownership interest of 23.8%. This investment was increased by equity income of $1.0 million during the nine months ended September 30, 2010, and decreased from a capital distribution from SST of $1.1 million. Our net investment in SST at September 30, 2010 is $2.9 million. As a result of not funding a cash call in the first quarter of 2010, our ownership interest of SST was reduced from 23.8% to 22.8%.

SST plans to continue temperature gradient drilling and acquisition of additional prospective geothermal properties during 2010. We have not budgeted any capital resources for further investment in SST during 2010. We are not obligated to fund cash calls and will suffer further dilution if we elect not to fund.

Insurance

We have liability insurance coverage in amounts deemed sufficient and in line with industry standards for the location, stage, and type of operations in oil and gas, mineral property development (the Mt. Emmons molybdenum project), and the Remington Village housing complex. Payment of substantial liabilities in excess of coverage could require diversion of internal capital away from regular business, which could result in diminished operations. We have property loss insurance on all major assets equal to the approximate replacement value of the assets. We have also purchased additional liability insurance for our own account.

Reclamation Costs

At September 30, 2010, there were no reclamation projects at our mineral or oil and gas properties that will require the expenditure of cash reserves during the balance of 2010.

Results of Operations

Three Months Ended September 30, 2010 compared to 2009

We recorded a net loss after taxes of $235,000 or $0.01 per share basic and diluted, for the quarter ended September 30, 2010 as compared to a net loss after taxes of $1.7 million or $0.09 per share basic and diluted, during the quarter ended September 30, 2009.

We recognized $6.4 million in net revenues during the quarter ended September 30, 2010 as compared to revenues of $1.4 million during same period in the prior year. Our gross revenues of $6.9 million were partially offset by the unrealized loss of $586,000 in risk management activities. During the third quarter we entered into commodity derivate contracts and the present value of these contracts is recognized as unrealized changes to revenue until the contracts settle. Realized gains and losses resulting from the contract settlement of derivatives will be recorded in the commodity price risk management activities line on the condensed consolidated statement of income.

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INDEX

Tabular representation of the increases in revenues as well as the income (loss) from operations for the quarters ended September 30, 2010 and 2009 is as follows:


	(In thousands)
	For the three months ending						Increase
	September 30, 2010			September 30, 2009			(Decrease)
Revenues	$	6,949		$	1,377		$	5,572
Unrealized (loss) from
risk management activities		(586	)		--			(586	)
		6,363			1,377			4,986
Operating expenses		3,882			2,950			932
Depreciation, depletion and amortization		3,355			318			3,037
Impairment		--			405			(405	)
		7,237			3,673			3,564
Operating income (loss)	$	(874	)	$	(2,296	)	$	1,422

The significant increase in revenues, quarter to quarter, of $ 5.6 million is primarily the result of production of oil and gas in the Williston Basin. The increased expenses are a result of work over costs and depletion recognized on the increased oil and gas production during the quarter.

Oil and gas production from the Williston Basin has increased revenue trends and as additional wells are drilled and completed during the fourth quarter of 2010 as well as 2011 it is believed that this trend will continue. We experienced a 100% completion rate on wells drilled in the Williston Basin with good initial production results. Future wells may not perform as well. The multi stage frac completion techniques used to complete the Bakken wells are relatively new which makes long term production projections uncertain. We rely on professional third party reserve engineers to calculate our reserves.

Oil and gas operations produced net operating income of $1.3 million during the quarter ended September 30, 2010 as compared to a loss of $258,000 from oil and gas operations during the quarter ended September 30, 2009. We recorded a $405,000 impairment on our oil and gas properties during the quarter ended September 30, 2009. The following table details the results of operations from the oil and gas sector for the quarters ended September 30, 2010 and 2009:


	(In thousands)
	For the three months ending						Increase
	September 30, 2010			September 30, 2009			(Decrease)
Oil and gas revenues	$	6,303		$	691		$	5,612
Unrealized (loss) from
risk management activities		(586	)		--			(586	)
		5,717			691			5,026
Operating expenses		1,423			69			1,354
Depreciation, depletion and amortization		2,976			475			2,501
Impairment		--			405			(405	)
		4,399			949			3,450
Operating income (loss)	$	1,318		$	(258	)	$	1,576

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INDEX

The following table summarizes production volumes, average sales prices and operating revenues for the quarters ended September 30, 2010 and 2009 excluding the impact of derivative instruments:


	Three Months Ended
	September 30,						Increase
	2010			2009			(Decrease)
Production volumes
Oil and condensate (Bbls)		76,397			3,351			73,046
Natural gas (Mcf)		197,731			120,314			77,417
Natural gas liquids (Bbls)		5,317			3,504			1,813
Average sales prices
Oil and condensate (per Bbl)	$	67.14		$	72.81		$	(5.67	)
Natural gas (per Mcf)		4.82			2.95			1.87
Natural gas liquids (per Bbl)		41.56			26.26			15.30
Operating revenues (in thousands)
Oil and condensate	$	5,129		$	244		$	4,885
Natural gas		953			355			598
Natural gas liquids		221			92			129
Total operating revenue		6,303			691			5,612
Lease operating expense		(979	)		7			(986	)
Production taxes		(444	)		(76	)		(368	)
Impairment		-			(405	)		405
Gain before DD&A		4,880			217			4,663
DD&A		(2,976	)		(475	)		(2,501	)
Gain (Loss)	$	1,904		$	(258	)	$	2,162

Portions of our natural gas production are sent to gas processing plants to profitably extract from the gas various natural gas liquids (“NGL”) that are sold separately from the remaining natural gas. We sell some of our processed gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGL and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses.

Our other revenue producing sector is commercial real estate. A breakdown of the income from operations from commercial real estate is contained in the following table:

	(In thousands)
	For the three months ending				Increase
	September 30, 2010		September 30, 2009		(Decrease)
Real estate revenues	$	646	$	686	$	(40	)
Operating expenses		296		245		51
Interest expense		--		--		--
Depreciation, depletion and amortization		266		262		4
		562		507		55
Operating income	$	84	$	179	$	(95	)

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INDEX

The decline in revenues for the quarter ended September 30, 2010 as compared to the same period of the prior year is primarily as a result of lower rental rates at Remington Village. Occupancy rates were approximately 96% at September 30, 2010 and 91% at September 30, 2009. Operating expenses increased as a result of the multifamily housing project reaching maturity which added additional maintenance expense.

Mount Emmons Molybdenum Property - When we entered into the agreement with TCM, we agreed to pay all costs associated with the water treatment plant at the Mount Emmons molybdenum property and thereby recorded $347,000 in costs and expenses for that facility and $9,000 in holding costs of the Mt. Emmons molybdenum property during the quarter ended September 30, 2010. During the quarter ended September 30, 2009, we expended $379,000 in operating costs related to the water treatment plant.

General Administrative - General and administrative expenses increased by $82,000 during the quarter ended September 30, 2010 over those experienced during the quarter ended September 30, 2009. The increase is as a result of:

$337,000 accrual of a 2010 year-end bonus to all employees which is subject to meeting corporate and personal goals, meeting annual budget goals, increased share price and cash flow from operations. Under the Performance Compensation Plan (“PCP”) adopted by the Board of Directors, employees can earn from 33% to 100% of their base compensation as bonuses if the terms of the PCP are met. Any bonus earned for 2010 performance will be paid during the second quarter of 2011. The PCP is being reevaluated by the Board of Directors and is subject to change. Any change to the PCP may affect the accrued amounts. As of September 30, 2009 no accrual had been made as the controlling factor of positive cash flows from operations had not been met.

·	$82,000 increased payroll costs and $22,000 increase in other general and administrative costs

·	$389,000 decrease in professional services. During the quarter ended September 30, 2009 we incurred large professional services fees in connection with the closing of our drilling agreement with Brigham Exploration.

Other income and expenses - We recorded an equity loss of $52,000 from the investment in SST during the quarter ended September 30, 2010. We recorded an equity loss of $339,000 for the quarter ended September 30, 2009. Equity losses from the investment in SST are expected to continue until such time as SST properties are sold, equity losses reduce our investment to zero or we sell the investment.

Interest income decreased from $88,000 during the quarter ended September 30, 2009 to $30,000 during the quarter ended September 30, 2010. The decrease is a result of lower amounts of cash invested in interest bearing instruments during the quarter, and lower interest rates received on those investments.

Interest expense of $16,000 during the quarter ended September 30, 2010 and $20,000 during the quarter ended September 30, 2009 was related primarily to the financing of a property purchased with TCM near the Mount Emmons property.

We therefore recorded net loss after taxes of $235,000, or $0.01 per share basic and diluted, during the quarter ended September 30, 2010 as compared to a net loss after taxes of $1.7 million, or $0.09 per share basic and diluted, during the quarter ended September 30, 2009.

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INDEX

Nine Months Ended September 30, 2010 compared to 2009

We recorded net income after taxes of $1.2 million or $0.04 per share basic and diluted, for the nine months ended September 30, 2010 as compared to a net loss after taxes of $7.0 million, or $0.33 per share basic and diluted, during the nine months ended September 30, 2009.

We recognized $21.5 million in net revenues during the nine months ended September 30, 2010 as compared to revenues of $4.3 million during same period in the prior year. Tabular representation of the increases in revenues as well as the income (loss) from operations for the nine month periods ended September 30, 2010 and 2009 is as follows:


	(In thousands)
	For the nine months ending						Increase
	September 30, 2010			September 30, 2009			(Decrease)
Revenues	$	22,123		$	4,284		$	17,839
Unrealized (loss) from
risk management activities		(586	)		--			(586	)
		21,537			4,284			17,253
Operating expenses		12,603			8,345			4,258
Depreciation, depletion and amortization		8,763			2,388			6,375
Impairment		--			1,468			(1,468	)
		21,366			12,201			9,165
Operating income (loss)	$	171		$	(7,917	)	$	8,088

As with the three months ended September 30, 2010, the significant increase in revenues of $17.8 million for the nine months ended September 30, 2010 as compared to those revenues recorded during the prior year is primarily a result of production of oil and gas in the Williston Basin. The increased expenses are a result of the increases in lease operating, work over, and depletion costs recognized during the nine months ended September 30, 2010. During the nine months ended September 30, 2009, we recorded an impairment of $1.5 million on the oil and gas operations due to depressed gas prices and dry hole costs which had been capitalized. As a result of increased oil and gas prices during the first nine months of 2010 and additional reserves to amortize the full cost pool over, no impairment was required during the nine months ended September 30, 2010.

Oil and gas production from the Williston Basin has increased revenue trends and as additional wells are drilled and completed during the remainder of 2010 it is believed that this trend will continue. We have experienced a 100% completion rate on wells drilled in the Williston Basin with good initial production results. Future wells may not perform as well. The multi stage frac completion techniques used by the Company and Brigham are relatively new which makes long term production projections uncertain. We rely on professional third party reserve engineers to calculate our reserves.

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INDEX

Oil and gas operations produced net operating income of $8.0 million during the nine months ended September 30, 2010 as compared to a loss of $1.5 million from oil and gas operations during the nine months ended September 30, 2009. The following table details the results of operations from the oil and gas sector for the nine months ended September 30, 2010 and 2009:


	(In thousands)
	For the nine months ending						Increase
	September 30, 2010			September 30, 2009			(Decrease)
Oil and gas revenues	$	20,230		$	2,119		$	18,111
Unrealized (loss) from
risk management activities		(586	)		--			(586	)
		19,644			2,119			17,525
Operating expenses		4,051			348			3,703
Depreciation, depletion and amortization		7,627			1,795			5,832
Impairment		--			1,468			(1,468	)
		11,678			3,611			8,067
Operating income (loss)	$	7,966		$	(1,492	)	$	9,458

The following table summarizes production volumes, average sales prices and operating revenues for the nine month periods ended September 30, 2010 and 2009 excluding the impact of derivative instruments:

	Nine Months Ended
	September 30,						Increase
	2010			2009			(Decrease)
Production volumes
Oil and condensate (Bbls)		237,324			10,451			226,873
Natural gas (Mcf)		515,365			351,191			164,174
Natural gas liquids (Bbls)		11,451			4,507			6,944
Average sales prices
Oil and condensate (per Bbl)	$	71.32		$	58.85		$	12.47
Natural gas (per Mcf)		5.32			3.90			1.42
Natural gas liquids (per Bbl)		49.17			30.18			18.99
Operating revenues (in thousands)
Oil and condensate	$	16,925		$	615		$	16,310
Natural gas		2,742			1,368			1,374
Natural gas liquids		563			136			427
Total operating revenue		20,230			2,119			18,111
Lease operating expense		(1,847	)		(163	)		(1,684	)
Production taxes		(2,204	)		(185	)		(2,019	)
Impairment		-			(1,468	)		1,468
Gain before DD&A		16,179			303			15,876
DD&A		(7,627	)		(1,795	)		(5,832	)
Gain (Loss)	$	8,552		$	(1,492	)	$	10,044

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INDEX

Our other revenue producing sector is commercial real estate. A breakdown of the income from operations from commercial real estate is contained in the following table:


	(In thousands)
	For the nine months ending				Increase
	September 30, 2010		September 30, 2009		(Decrease)
Real estate revenues	$	1,893	$	2,165	$	(272	)
Operating expenses		920		734		186
Interest expense		--		19		(19	)
Depreciation, depletion and amortization		797		783		14
		1,717		1,536		181
Operating income	$	176	$	629	$	(453	)

The decline in revenues for the nine months ended September 30, 2010 as compared to the same period of the prior year is as a result of lower average rental rates, discounts given and occupancy rates during the nine months ended September 30, 2010. Occupancy rates were approximately 82% at September 30, 2009 and 96% at September 30, 2010. The occupancy rate has increased from 80% at December 31, 2009 to the current occupancy of 96%. Operating expenses increased as a result of the multifamily housing project reaching maturity which added additional expenses to the grounds maintenance and ongoing maintenance of apartment units when property damage occurs or tenants move out.

Mount Emmons Molybdenum Property - When we entered into the agreement with TCM, we agreed to pay all costs associated with the water treatment plant at the Mount Emmons molybdenum property and thereby recorded $1.2 million in costs and expenses for that facility and $61,000 in holding costs of the Mt. Emmons molybdenum property during the nine months ended September 30, 2010. During the nine months ended September 30, 2009, we expended $1.4 million in operating costs related to the water treatment plant.

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INDEX

General Administrative - General and administrative expenses increased by $1.1 during the nine months ended September 30, 2010 over those experienced during the nine months ended September 30, 2009. The increase is as a result of:

$980,000 - Accrual of a 2010 year-end bonus to all employees which is subject to meeting corporate and personal goals, meeting annual budget goals, increased share price and cash flow from operations. Under the Performance Compensation Plan (“PCP”) adopted by the board of directors, employees can earn from 33% to 100% of their base compensation as bonuses if the terms of the PCP are met. Any bonus earned for 2010 performance will be paid during the second quarter of 2011. The PCP is being reevaluated by the Board of Directors and is subject to change. Any change to the PCP may affect the accrued amounts. As of September 30, 2009 no accrual had been made under the PCP as the controlling factor of positive cash flow from operations had not been met; and

·	$189,000 - Noncash increase in stock compensation expense. The increase is primarily due to shares issued to officers pursuant to the 2001 Stock Compensation Plan being issued at a higher price than those issued in 2009.

Other income and expenses – As a result of the sale of two of Standard Steam Trust’s geothermal properties, we recorded an equity gain of $1.1 million from our investment in SST during the nine months ended September 30, 2010. We recorded an equity loss of $505,000 for the nine months ended September 30, 2009. Equity losses from the investment in SST are expected to continue until such time as additional SST properties are sold, equity losses reduce the investment to zero or we sell the investment.

We recorded a gain on sale of assets of $115,000 during the nine months ended September 30, 2010. The gain was primarily related to the sale of an office building that we previously held as rental property. We recorded a loss on sale of assets of $41,000 during the nine months ended September 30, 2009.

Interest income decreased from $264,000 during the nine months ended September 30, 2009 to $91,000 during the nine months ended September 30, 2010. The decrease is a result of lower amounts of cash invested in interest bearing instruments and lower interest received on those investments.

Interest expense of $51,000 during the nine months ended September 30, 2010 was related primarily to the financing of a property purchased with TCM near the Mount Emmons property. Interest expense of $78,000 during the nine months ended September 30, 2009 was related primarily to the construction loan for Remington Village which was fully repaid in January 2009 and the financing of a property purchased with TCM near the Mount Emmons property.

We therefore recorded net income after taxes of $1.2 million, or $0.04 per share basic and diluted, during the nine months ended September 30, 2010 as compared to a net loss after taxes of $7.0 million, or $0.33 per share basic and diluted, during the nine months ended September 30, 2009.

Critical Accounting Policies

For detailed descriptions of our significant accounting policies, please see pages 67 to 70 of our Annual Report on Form 10K for the year ended December 31, 2009.

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INDEX

Mineral Properties - We capitalize all costs incidental to the acquisition of mineral properties. Mineral exploration costs are expensed as incurred. When exploration work indicates that a mineral property can be economically developed as a result of establishing proved and probable reserves, costs for the development of the mineral property as well as capital purchases and capital construction are capitalized and amortized using units of production over the estimated recoverable proved and probable reserves. Costs and expenses related to general corporate overhead are expensed as incurred. All capitalized costs are charged to operations if we subsequently determine that the property is not economical due to permanent decreases in market prices of commodities, excessive production costs or depletion of the mineral resource.

Mineral properties at September 30, 2010 and December 31, 2009 reflect capitalized costs associated with the Mount Emmons molybdenum property near Crested Butte, Colorado. We entered into an agreement with TCM to develop this property. TCM may earn up to a 75% interest in the project for the investment of $400 million. We have received two of the six anticipated annual payments in the amount of $1.0 million each. These payments were applied as a reduction of our investment in the Mount Emmons property.

Molybdenum prices declined from a ten year high average price of $34.13 per pound in July 2008 to a ten-year low average price of $8.02 per pound in April 2009. During the first nine months of 2010, the spot price for molybdenum increased to a high of $19.00 per pound in April 2010 and was $14.75 per pound at September 30, 2010.

Oil and Gas Properties - We follow the full cost method in accounting for our oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from property disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves. Excluded from amounts subject to depletion are costs associated with unproved properties.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated average prices per barrel of oil and per MMbtu of natural gas at the first of each month in the 12-month period prior to the end of the reporting period and costs, adjusted for contract provisions, financial derivatives that hedge the oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, (iii) the lower of cost or market value of unproved properties included in the cost being amortized less (iv) income tax effects related to tax assets directly attributable to crude oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs.

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INDEX

Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at September 30, 2010 and December 31, 2009 which were not included in the amortized cost pool were $5.3 million and $5.4 million, respectively. These costs consist of wells in progress, seismic costs that are being analyzed for potential drilling locations as well as land costs and are related to unproved properties. No capitalized costs related to unproved properties are included in the amortization base at September 30, 2010 and December 31, 2009. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are proved, drilled or abandoned.

Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change. If oil or natural gas prices decline substantially, even for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of oil and gas properties could occur in the future.

Derivative Instruments - The Company uses derivative instruments, typically fixed-rate swaps and costless collars to manage price risk underlying its oil and gas production. The Company may also use puts, calls and basis swaps in the future. All derivative instruments are recorded in the consolidated balance sheets at fair value. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty. Although the Company does not designate any of its derivative instruments as a cash flow hedge, such derivative instruments provide an economic hedge of our exposure to commodity price risk associated with forecasted future oil and gas production. These contracts are accounted for using the mark-to-market accounting method and accordingly, the Company recognizes all unrealized and realized gains and losses related to these contracts currently in earnings and are classified as gain (loss) on derivative instruments, net in our consolidated statements of operations.

Long Lived Assets - Real Estate - We evaluate our long-lived assets, which consist of commercial real estate, for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. Impairment calculations are based on market appraisals. If rental rates decrease or costs increase to levels that result in estimated future cash flows, on an undiscounted basis, that are less than the carrying amount of the related asset, an asset impairment is considered to exist. Changes in significant assumptions underlying future cash flow estimates may have a material effect on our financial position and results of operations. We do not obtain appraisals on an ongoing basis for the property. However, we did obtain an appraisal in 2009. At September 30, 2010 and December 31, 2009, management determined that no impairment existed on the long-lived asset as the 2009 appraised value exceeded construction and carrying value and rental rates remained strong and costs within projected limits.

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INDEX

Asset Retirement Obligations - We account for asset retirement obligations under ASC 410-20. We record the fair value of the reclamation liability on inactive mining properties as of the date that the liability is incurred. We review the liability each quarter and determine if a change in estimate is required as well as accrete the liability on a quarterly basis for the future liability. Final determinations are made during the fourth quarter of each year. We deduct any actual funds expended for reclamation during the quarter in which it occurs.

Future Operations

Management intends to continue seeking investment opportunities in the oil and natural gas sector. Long term, we intend to be prepared to pay our share of the holding and development costs associated with the Mount Emmons property.

Effects of Changes in Prices

Mineral operations are significantly affected by changes in commodity prices. As prices for a particular mineral increase, values for prospects for that mineral typically also increase, making acquisitions of such properties more costly and sales potentially more valuable. Conversely, a price decline could enhance acquisitions of properties containing that mineral, but could also make sales of such properties more difficult. Operational impacts of changes in mineral commodity prices are common in the mining and oil and gas industries.

At September 30, 2010, we are receiving revenues from our oil and gas business. Our revenues, cash flows, future rate of growth, results of operations, financial condition and ability to finance projected acquisition of oil and gas producing assets are dependent upon prevailing prices of oil and gas.

Our multifamily housing revenues could be affected negatively if there was a sustained down turn in the price of coal, oil and natural gas which could affect the demand for housing in the Gillette, Wyoming area.

Forward Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices, declines in the values of our properties that have resulted in and may in the future result in additional ceiling test write downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for our participation in oil and gas properties and for future acquisitions, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters and the operating hazards attendant to the oil and gas and minerals business. In particular, careful consideration should be given to cautionary statements made in the Company’s Risk Factors included in our Annual Report on Form 10-K and quarterly reports on Form 10-Q filed with the SEC. The Company undertakes no duty to update or revise these forward-looking statements.

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INDEX

When used in this Form 10-Q, the words, “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Form 10-Q.

Off-Balance Sheet Arrangements

None.

Contractual Obligations

We had three divisions of contractual obligations at September 30, 2010: Debt to third parties of $800,000 with interest at 6% per annum, executive retirement of $991,000 and asset retirement obligations of $293,000. The debt will be paid over a period of four years in equal installments of $200,000 with interest with the next payment due on January 2, 2011. The executive retirement liability will be paid out over varying periods starting after the actual projected retirement dates of the covered executives. The asset retirement obligations will be retired during the next 34 years. The following table shows the scheduled debt payment, projected executive retirement benefits and asset retirement obligations:


	(In thousands)
	Payments due by period
			Less		One to		Three to		More than
			than one		Three		Five		Five
	Total		Year		Years		Years		Years
Long-term debt obligations	$	800	$	200	$	600	$	--	$	--

Executive retirement	$	991		153		480		251		108

Asset retirement obligation	$	293		--		--		26		266

Totals	$	2,084	$	353	$	1,080	$	277	$	374

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

None

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ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of September 30, 2010, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, completed an evaluation of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation the Chief Executive Officer and Chief Financial Officer concluded:

That the Company’s disclosure controls and procedures are designed to ensure (a) that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (b) that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure; and

ii.	That the Company’s disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting that occurred during the quarter ended September 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

Water Rights Litigation –Mount Emmons Molybdenum Property

1. Concerning the Application of the United States of America in the Gunnison River, Gunnison County, Case No. 99CW267. This case involves an application filed by the United States of America to appropriate 0.033 cubic feet per second of water for wildlife use and for incidental irrigation of riparian vegetation at the Mount Emmons Iron Bog Spring, located in the vicinity of Mount Emmons. MEMCO filed a Statement of Opposition to protect proposed mining operations against any adverse impacts by the water requirements of the Iron Bog on such operations. This case is pending while the parties attempt to reach a settlement on the proposed decree terms and conditions.

2. Concerning the Application of U.S. Energy, Case No. 2008CW81. On July 25, 2008, the Company filed an Application for Finding of Reasonable Diligence with the Water Court (“Water Diligence Application”) concerning the conditional water rights associated with Mount Emmons (Case No. 2008CW81). The conditional water decree (“Decree”) requires the Company to file its proposed plan of operations and associated permits with the Forest Service and BLM within six years of entry of the 2002 Decree, or within six years of the final determination in the Applicant’s pending patent application, whichever occurs later. The BLM issued the mineral patents on April 2, 2004. Although the issuance of the patents was appealed, on April 30, 2007, the United States Supreme Court made a final determination upholding BLM’s issuance of the mineral patents.

The Company believes that the deadline for filing the plan of operations specified by the Decree is April 30, 2013 (six years from the final determination of issuance of the mineral patents by the United States Supreme Court). The Forest Service has indicated that the deadline should be April 2, 2010 (six years from the issuance of the mineral patents by BLM). The United States, on behalf of the Forest Service and BLM, filed a Statement of Opposition on this specific issue only. Statements of Opposition were also filed by six other parties including the City of Gunnison, the Colorado Water Conservation Board, High Country Citizens’ Alliance, Crested Butte Land Trust and others for various reasons, including requesting the Company be put on strict proof as to demonstrating evidence of reasonable diligence in developing the conditional water rights.

On March 26, 2010, BLM and the Forest Service signed a Stipulation with the Company, which resolved their opposition to the Company’s Water Diligence Application. Pursuant to the Stipulation, the Company agreed to prepare, in consultation with the BLM and Forest Service, and file no later than April 2, 2010, an initial Plan of Operations in accordance with 36 C.F.R. Sec. 228.4(d). BLM, the Forest Service and the Company also agreed the filing of this Plan of Operations would satisfy the Decree. The Company filed the Plan of Operations on March 31, 2010.

On August 11, 2010, High Country Citizen’s Alliance, Crested Butte Land Trust and Star Mountain Ranch Association, Inc (“Opposers”) filed a Motion for Summary Judgment alleging that the Plan of Operations did not comply with the Forest Service regulations and did not satisfy certain Reality Check Limitations contained in the Water Rights Decree. On September 24, 2010, U.S. Energy filed a Response to the Motion for Summary Judgment responding that the Plan of Operations complied with the Forest Service and BLM’s regulations and satisfied the Reality Check Limitations contained in the Water Rights Decree. The U.S. Department of Justice also filed a response on behalf of the Forest Service and BLM that the Court cannot second guess the Forest Service’s determination that the Company’s Plan of Operations satisfied the Forest Service and BLM’s regulations. The Motion for Summary Judgment is pending.

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Appeal of Approval of Notice of Intent to Conduct Prospecting for the Mount Emmons Property

On March 8, 2008, High Country Citizens’ Alliance (‘HCCA”) filed a request for hearing before the Colorado Land Reclamation Board (“Board”) of the approval of a Notice of Intent to Conduct Prospecting Notice for the Mount Emmons molybdenum property (“NOI”), which was approved by the Division of Reclamation, Mining and Safety of the Colorado Department of Natural Resources (“DRMS”) on January 3, 2008. The NOI as approved provided for continued exploration of the molybdenum deposit to update, improve and verify, in accordance with current industry standards and legal requirements, mineralization data that was collected by Amax in the late 1970’s. On May 14, 2008, the Board denied HCCA’s Request for Hearing and also denied their Request for a Declaratory Order. Citing Colorado law, the Board determined that HCCA did not have standing or the right to appeal DRMS’s approval of the NOI under Colorado law. On August 28, 2008, HCCA appealed the Board’s decision in Denver District Court. Plaintiff: High Country Citizen’s Alliance v. Defendants: Colorado Mined Land Reclamation Board, Colorado Division of Reclamation Mining and Safety and U.S. Energy Corp., Case No.: 08CV6156 (District Court, 2d Jud. Dist., City and County of Denver). The Board has filed an answer with the Court. The DRMS and the Company (in conjunction with TCM) have both filed the responsive pleadings in addition to motions to dismiss the HCCA complaint.

No hearing date has yet been scheduled in the District Court of Colorado concerning the Colorado Division of Reclamation, Mining, and Safety’s issuance of a Notice of Intent to Conduct Prospecting to the Company for the Mount Emmons Property.

For information on other legal proceedings in which there have been no new developments since September 30, 2010, see Item 1, Part II of the Company’s Annual Report on Form 10-K filed on March 12, 2010.

ITEM 1A. Risk Factors

For more complete disclosure relating to the Company’s material risk factors which could materially affect the Company’s business, financial condition or future results, please see Part I, “Item 1A. Risk Factors” (pages 14 to 27) in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may materially adversely affect its business, financial condition and/or operating results.

Insurance may be insufficient to cover future liabilities. Our business is focused in three areas, each of which presents potential liability exposure: Oil and gas exploration and development; permitting and limited exploration of the Mt. Emmons molybdenum property; and a residential multi-family housing complex in Gillette, Wyoming. We also have potential exposure in connection with the Company’s corporate aircraft and general liability and property damage associated with the ownership of other corporate assets. We rely primarily on the operators of our oil and gas and mineral properties to obtain and maintain liability insurance for our working interest in the properties. We have purchased additional liability insurance for our own account. We maintain insurance policies for the liability of and damage to our multifamily housing complex, corporate aircraft and general corporate assets.

We also have separate policies for liability and environmental exposures for the water treatment plant at the Mt. Emmons project. These policies provide coverage for bodily injury and property damage as well as costs to remediate events adversely impacting the environment.

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We would be liable for claims in excess of coverage. If uncovered liabilities are substantial, payment thereof could adversely impact the Company’s cash on hand, resulting in possible curtailment of operations. As of the date of this Report, we know of no claims related to any of our properties.

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

During the nine months ended September 30, 2010, the Company issued a total of 60,000 shares of its common stock. The shares were issued as restricted securities in reliance on the exemption available to the Company under Section 4(2) of the Securities Act of 1933. These shares were issued as new issuances pursuant to the 2001 stock compensation plan.

ITEM 3. Defaults Upon Senior Securities

Not Applicable

ITEM 4. Submission of Matter to a Vote of Security Holders

None

ITEM 5. Other Information

Not Applicable

ITEM 6. Exhibits

(a)	Exhibits
	31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e)
	31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e)
	32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by 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 by Section 906 of the Sarbanes-Oxley Act of 2002

(b)	Reports on Form 8-K. The Company filed five reports on Form 8-K for the quarter ended September 30, 2010. The events reported were as follows:
	1.	The report filed on August 2, 2010, under Item 1.01 referenced the company establishing a Senior Secured Revolving Credit Facility to borrow up to $75 million.
	2.	The report filed on August 4, 2010, under Item 7.01 referenced an update on recent and planned drilling and completion activities in North Dakota.
	3.	The report filed on August 5, 2010, under Item 7.01 referenced results from a drilling prospects with PetroQuest Energy, L.L.C.; and update on drilling initiatives in Louisiana and Texas.
	4.	The report filed on August 9, 2010, under Item 7.01 referenced highlights and financial results for the second quarter 2010.
	5.	The report filed on August 10, 2010, under Item 7.01 referenced the announcement of initial production rate form its Sukut 28-33 #1H well.

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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.

	U.S. ENERGY CORP.
	(Registrant)



Date: November 5, 2010	By:	/s/ Keith G. Larsen
		KEITH G. LARSEN
		Chairman and CEO




Date: November 5, 2010	By:	/s/ Robert Scott Lorimer
		ROBERT SCOTT LORIMER
		Principal Financial Officer and
		Chief Accounting Officer

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