Edgar Filing: US ENERGY CORP

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, 2009 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 x

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES o NO x

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

At November 6, 2009, there were issued and outstanding 21,349,058 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 Balance Sheet as of September 30, 2009 (unaudited) and December 31, 2008	4-5

	Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008 (unaudited)	6-7

	Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008 (unaudited)	8-9

	Notes to Condensed Financial Statements (unaudited)	10-22

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22-35

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35-36

Item 4.	Controls and Procedures	36

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	37-38

Item 1A.	Risk Factors	38-40

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 3.	Defaults Upon Senior Securities	41

Item 4.	Submission of Matters to a Vote of Security Holders	41

Item 5.	Other Information	41

Item 6.	Exhibits	42

	Signatures	43

	Certifications	See Exhibits

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

U.S. ENERGY CORP.
CONDENSED BALANCE SHEETS
ASSETS
(Amounts in thousands)

	September 30,		December 31,
	2009		2008
	(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	11,671	$	8,434
Marketable securities
Held to maturity - treasuries		27,224		51,152
Available for sale securities		1,170		576
Accounts receivable
Trade		408		600
Reimbursable project costs		2		442
Income taxes		353		5,896
Restricted investments		--		4,929
Other current assets		570		738
Total current assets		41,398		72,767

INVESTMENT		3,827		3,455

PROPERTIES AND EQUIPMENT:
Oil & gas properties under full cost method, net		13,723		7,906
Undeveloped mining claims		22,967		23,950
Commercial real estate, net		23,433		23,998
Property, plant and equipment, net		9,374		9,639
Net properties and equipment		69,497		65,493

OTHER ASSETS		1,161		916
Total assets	$	115,883	$	142,631

The accompanying notes are an integral part of these statements.

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U.S. ENERGY CORP.
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
(Amounts in thousands)

	September 30,		December 31,
	2009		2008
	(Unaudited)
CURRENT LIABILITIES:
Accounts payable	$	243	$	898
Accrued compensation		585		682
Short term construction debt		--		16,813
Current portion of long-term debt		200		875
Other current liabilities		246		715
Total current liabilities		1,274		19,983

LONG-TERM DEBT, net of current portion		800		1,000

DEFERRED TAX LIABILITY		7,869		8,945

ASSET RETIREMENT OBLIGATIONS		153		144

OTHER ACCRUED LIABILITIES		717		726

SHAREHOLDERS' EQUITY:
Common stock, $.01 par value; unlimited shares
authorized; 21,289,058 and 21,935,129
shares issued, respectively		213		219
Additional paid-in capital		93,790		93,951
Accumulated surplus		10,687		17,663
Unrealized gain on marketable securities		380		--
Total shareholders' equity		105,070		111,833
Total liabilities and shareholders' equity	$	115,883	$	142,631

The accompanying notes are an integral part of these statements.

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U.S. ENERGY CORP.
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
(Amounts in thousands, except per share data)

	Three months ended September 30,						Nine months ended September 30,
	2009			2008			2009			2008
OPERATING REVENUES:
Real estate	$	686		$	497		$	2,165		$	995
Oil & gas		593			67			1,912			--
Management fees and other		5			5			14			52
		1,284			569			4,091			1,047

OPERATING COSTS AND EXPENSES:
Real estate		507			311			1,517			712
Oil and gas		446			--			1,936			--
Impairment of oil and gas properties		405			--			1,468			--
Water treatment plant		379			326			1,398			724
Mineral holding costs		--			883			--			1,558
General and administrative		1,838			1,697			5,675			5,969
		3,575			3,217			11,994			8,963

OPERATING LOSS		(2,291	)		(2,648	)		(7,903	)		(7,916	)

OTHER INCOME & (EXPENSES):
Gain on sales of assets		(46	)		12			(41	)		(17	)
Equity loss		(339	)		--			(505	)		--
Interest income		88			324			264			1,175
Interest expense		(20	)		(146	)		(78	)		(254	)
		(317	)		190			(360	)		904

LOSS BEFORE PROVISION
FOR INCOME TAXES AND
DISCONTINUED OPERATIONS		(2,608	)		(2,458	)		(8,263	)		(7,012	)

INCOME TAXES:
Current benefit from (provision for)		(3	)		1,881			210			4,003
Deferred benefit from (provision for)		867			(819	)		1,077			(1,563	)
		864			1,062			1,287			2,440

LOSS FROM CONTINUING
OPERATIONS		(1,744	)		(1,396	)		(6,976	)		(4,572	)

DISCONTINUED OPERATIONS
Loss from discontinued operations		--			(211	)		--			(502	)
Gain on sale of discontinued
operations (net of taxes)		--			5,408			--			5,408
		--			5,197			--			4,906

NET (LOSS) INCOME	$	(1,744	)	$	3,801		$	(6,976	)	$	334

The accompanying notes are an integral part of these statements.

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U.S. ENERGY CORP.
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
(Amounts in thousands, except per share data)

	Three months ended September 30,						Nine months ended September 30,
	2009			2008			2009			2008
PER SHARE DATA
Basic and diluted loss
from continuing operations	$	(0.09	)	$	(0.06	)	$	(0.33	)	$	(0.19	)
Basic and diluted gain
from discontinued operations		--			0.22			--			0.20
Basic and diluted (loss) gain per share	$	(0.09	)	$	0.16		$	(0.33	)	$	0.01

BASIC AND DILUTED WEIGHTED
AVERAGE SHARES OUTSTANDING		21,288,841			23,505,340			21,416,869			23,629,490

Diluted loss
from continuing operations	$	(0.09	)	$	(0.06	)	$	(0.33	)	$	(0.19	)
Diluted earnings
from discontinued operations		--			0.22			--			0.20
Diluted (loss) earnings per share	$	(0.09	)	$	0.16		$	(0.33	)	$	0.01

DILUTED WEIGHTED AVERAGE
SHARES OUTSTANDING		21,288,841			23,505,340			21,416,869			23,629,490

The accompanying notes are an integral part of these statements.

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U.S. ENERGY CORP.
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
(Amounts in thousands)

	For the nine months ended September 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(6,976	)	$	334
Gain on the sale of SGMI stock		--			(5,407	)
Loss from discontinued operations		--			501
Loss from continuing operations		(6,976	)		(4,572	)
Reconcile net loss to net cash used in operations
Depreciation, depletion & amortization		2,918			688
Accretion of discount on treasury investment		(160	)		(992	)
Impairment of oil and gas properties		1,468			--
Equity loss from Standard Steam		505			--
Income tax receivable		5,543			(3,399	)
Deferred income taxes		(1,077	)		1,563
Loss on sale of assets		41			17
Noncash compensation		1,283			2,135
Noncash services		50			24
Net changes in assets and liabilities		(741	)		187
NET CASH PROVIDED BY
(USED IN) OPERATING ACTIVITIES		2,854			(4,349	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Net investment in treasury investments	$	24,088		$	(67,569	)
Investment in Standard Steam		(877	)		--
Acquisition & development of real estate		(91	)		(11,001	)
Acquisition of oil & gas properties		(9,078	)		(4,534	)
Acquisition & development of mining properties		(10	)		(518	)
Minining property option payment		1,000			--
Acquisition of property and equipment		(249	)		(56	)
Proceeds from sale of property and equipment		5			1,097
Net change in restricted investments		4,682			1,704
NET CASH PROVIDED BY
(USED IN) INVESTING ACTIVITIES		19,470			(80,877	)

The accompanying notes are an integral part of these statements.

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CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
(Amounts in thousands)

	For the nine months ended September 30,
	2009			2008
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock	$	--		$	1,528
Tax benefit from the exercise of stock options		--			171
Proceeds from short-term construction debt		--			10,945
Repayments of debt		(17,688	)		(57	)
Stock buyback program		(1,399	)		(2,832	)
NET CASH (USED IN) PROVIDED BY
FINANCING ACTIVITIES		(19,087	)		9,755

Net cash used in operating
activities of discontinued operations		--			(76	)
Net cash provided by investing
activities of discontinued operations		--			4,402
Net cash used in financing
activities of discontinued operations		--			--

NET INCREASE (DECREASE) IN
CASH AND CASH EQUIVALENTS		3,237			(71,145	)

CASH AND CASH EQUIVALENTS
AT BEGINNING OF PERIOD		8,434			72,292

CASH AND CASH EQUIVALENTS
AT END OF PERIOD	$	11,671		$	1,147

SUPPLEMENTAL DISCLOSURES:
Income tax received	$	(5,753	)	$	(945	)

Interest paid	$	34		$	48

NON-CASH INVESTING AND FINANCING ACTIVITIES:

Unrealized gain/(loss)	$	143		$	(459	)

The accompanying notes are an integral part of these statements.

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U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

1) Basis of Presentation

The accompanying unaudited condensed financial statements for the periods ended September 30, 2009 and September 30, 2008 have been prepared by U.S. Energy Corp. (“USE” or the “Company”) in accordance with U.S. generally accepted accounting principles. The Condensed Balance Sheet at December 31, 2008 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. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. The unaudited condensed financial statements should be read in conjunction with the Company's December 31, 2008 Annual Report on Form 10-K.

Subsequent events known to the Company’s principal executive officer or principal financial officer prior to the first issuance of the financial statements are evaluated for incorporation in the financial statements and notes thereto. These financial statements were first issued on November 6, 2009 at the time of filing this Form 10-Q with the SEC.

2) Summary of Significant Accounting Policies

For detailed descriptions of the Company’s significant accounting policies, please see Form 10-K for the year ended December 31, 2008 (Note B pages 72 to 79).

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. References to GAAP issued by the FASB in these footnotes are to the FASB Accounting Standards Codification,™ sometimes referred to as the Codification or ASC. The FASB finalized the Codification effective for periods ending on or after September 15, 2009. Prior FASB standards like FASB Statement No. 128, “Earnings per Share,” are no longer being issued by the FASB. For further discussion of the Codification see “FASB Codification Discussion” in Management’s Discussion and Analysis of Financial Condition and Results of Operations (commonly referred to as MD&A) elsewhere in this report.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 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 natural gas, these estimates could change in the near term and such changes could be material.

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U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

(Continued)

Oil and Gas Properties

The Company 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 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 unevaluated 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 year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge the Company’s 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, less (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.

Revenue Recognition

The Company records natural gas and oil revenue under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Company is entitled based on its interest in the properties. Natural gas balancing obligations as of September 30, 2009 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.

Management fees are recorded when the service is provided. Management fees are for operating and overseeing services performed on mineral properties in which the Company participates with joint venture or industry partners.

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U.S. ENERGY CORP. & SUBSIDIARIES

Notes to Condensed Financial Statements (Unaudited)

(Continued)

Recent Accounting Pronouncements

On December 31, 2008, the SEC adopted major revisions to its rules governing oil and gas company reporting requirements. These new rules will permit the use of new technologies to determine proved reserves and allow companies to disclose their probable and possible reserves to investors. The current rules limit disclosure to only proved reserves. The new rules require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of its reserve estimates, and to file reports when a third party is relied upon to prepare or audit its reserve estimates. The new rules also require that the net present value of oil and gas reserves reported and used in the full cost ceiling test calculation be based upon an average price for the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted. The Company is in the process of assessing the impact of these new requirements on its financial position, results of operations and financial disclosures.

As of September 30, 2009, there have been no recent accounting pronouncements currently relevant to the Company in addition to those discussed on pages 78 to 79 of our Annual Report on Form 10-K for the year ended December 31, 2008. The Company continues to review current outstanding statements from the Financial Accounting Standards Board (“FASB”) and does not believe that any of those statements will have a material effect on the financial statements of the Company 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.

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U.S. ENERGY CORP. & SUBSIDIARIES

Notes to Condensed Financial Statements (Unaudited)

(Continued)

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

Components of Properties & Equipment
(Amounts in thousands)

	September 30,			December 31,
	2009			2008
Oil & Gas properties
Unevaluated	$	3,231		$	2,968
Well in progress		8,087			--
Evaluated		4,582			5,320
		15,900			8,288
Less accumulated depreciation
depletion and amortization		(2,177	)		(382	)
Net book value	$	13,723		$	7,906

Mining properties	$	22,967		$	23,950

Commercial real estate	$	24,599		$	24,467
Less accumulated depreciation
depletion and mortization		(1,166	)		(469	)
Net book value	$	23,433		$	23,998

Building, land and equipment	$	14,131			14,399
Less accumulated depreciation
depletion and amortization		(4,757	)		(4,760	)
Net book value	$	9,374		$	9,639
Totals	$	69,497		$	65,493

Mineral Properties

The Company capitalizes 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 the Company subsequently determines 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, 2009 and December 31, 2008 reflect capitalized costs associated with the Company’s Mount Emmons molybdenum property near Crested Butte, Colorado. The Company has 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. The Company received the first of six anticipated annual payments in the amount of $1.0 million in January 2009. This payment was applied as a reduction of the Company’s investment in the Mount Emmons property.

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U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

(Continued)

Oil and Gas Exploration Activities

The Company participates in oil and gas projects as a non-operating working interest owner and has 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.

On August 24, 2009, the Company and Brigham Oil & Gas, L.P. (“Brigham”) a Delaware limited partnership wholly-owned by Brigham Exploration Company (a Delaware corporation), entered into a Drilling Participation Agreement (the “DPA”). The DPA provides for the Company and Brigham to jointly explore for oil in the Bakken and Three Forks formations, in up to fifteen 1,280 acre spacing units (19,200 gross acres) in a portion of Brigham’s Rough Rider prospect in Williams and McKenzie Counties, North Dakota. The terms of the DPA call for the drilling of up to 15 initial Bakken wells in 15 separate 1,280 acre spacing units. Under the terms of the DPA, the Company has committed to drilling six initial wells (and earning subsequent working interests in six 1,280 acre spacing units) and will have the option to commit to drilling four additional wells (and earning subsequent working interests in four additional 1,280 acre spacing units) after receiving notification of the initial production (IP) rates from four of the first six initial wells drilled. If the Company elects to drill the four additional wells, it will then have an option to participate and earn working interests in five additional wells and 1,280 acre spacing units after receiving notification of the IP for the fifth and sixth initial wells drilled in the first six well program. Upon the drilling and completion of the first or initial well in each 1,280 acre spacing unit, the Company will earn 36% of Brigham’s original working interest in the remaining acreage (or drilling locations) in each 1,280 acre unit. If the Company participates in the drilling of the initial wells in all fifteen 1,280 acre spacing units, it will earn working interests in 19,200 gross acres in the Rough Rider project area.

The Company has agreed to participate for 65% of Brigham’s original working interest in each initial well drilled in the first six well program. Upon receiving a pooled payout of all of the costs and expenses incurred to drill and complete the six initial wells in the six initial 1,280 acre spacing units, the Company will assign back 35% of its 65% of Brigham’s original working interest in the first well in each 1,280 acre spacing unit to Brigham. Following that, the Company will own 42.25% of Brigham’s original working interest in the initial well in each 1,280 acre spacing unit. If the Company elects to participate in the second group of four wells and spacing units, it will also be entitled to a pooled payout similar to the first six well program. If the Company elects to participate in the third group of five wells and spacing units, it will be entitled to an initial well by initial well per spacing unit payout before a 27.7% back in assignment to Brigham.

At September 30, 2009, two wells were in progress with net costs to date of $6,858,000. The drilling of wells three through six in the first group of six initial wells is anticipated to be completed in the fourth quarter of 2009. The drilling of each well typically takes 30 days while the completion typically takes 21-28 days. Brigham will operate all of the wells. If the Company elects to participate in all 15 initial wells and earns subsequent working interests in each 1,280 acre spacing unit, the Company will have earned the rights to drill up to 30 total wells in the Bakken formation and an additional 30 wells in the Three Forks formation, for a total of 60 wells, based on the current spacing in North Dakota. If the spacing is ultimately increased to three wells per 1,280 acre spacing unit, the potential number of drilling locations could increase to 90.

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U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

(Continued)

The Company’s expenditures are anticipated to approximate $18.4 million for the first six initial well program. If working interest owners other than Brigham and the Company do not participate in the wells, that amount could increase. In the second groups of four and five wells that the Company could elect to participate in respectively, Brigham will have the option to participate at a range of 15-50% in those wells. Prior to USE’s election to participate in the well groups, Brigham must notify the Company of its participation percentage. If Brigham participates 15% in those well groups, the Company can participate for 85% of Brigham’s original working interest. If Brigham participates 50% in those well groups, the Company can participate for 50% of Brigham’s original working interest. Each participation amount for both Brigham and the Company will be subject to dilution or expansion based on other working interest owners’ participation in the initial wells and/or subsequent wells in each 1,280 acre spacing unit.

During January and February of 2009, the Company drilled a well in northeastern Wyoming with a nonaffiliated company. The drilling resulted in a dry hole at an approximate cost of $401,000 to the Company.

In January 2009, the Company paid TLPC Holdings, Ltd, an affiliate of Texas Land & Petroleum Company, LLC (“TL&P”), a private Texas company, a $45,000 prospect fee and signed an agreement for an oil well drilling program in Texas. Because drilling had not commenced timely, the Company withdrew from the project in August 2009 and received a full refund of the prospect fee.

In May and June of 2009, the Company drilled two wells in eastern Texas with a nonaffiliated company. One well has been determined to be productive and the other a dry hole with net costs to the Company of $403,000 and $98,000, respectively. The productive well, the Stoddard #1, commenced production and sales in September 2009.

In July 2009, the Company drilled a productive well, the SL 19863 #1, in southeast Louisiana with a nonaffiliated company incurring net costs to the Company of $827,000. Production from this well commenced in late August 2009.

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

Approximately $17.3 million has been expended under all oil and gas agreements the Company has entered into through September 30, 2009. Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at September 30, 2009 and December 31, 2008 which were not included in the amortized cost pool were $11.3 million and $3.0 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, 2009 and December 31, 2008. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are evaluated, drilled or abandoned.

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U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

(Continued)

Ceiling Test Analysis – The Company performs a quarterly ceiling test for each of its oil and gas cost centers, which in 2009, there was only one. The ceiling test incorporates assumptions regarding pricing and discount rates at quarter end and over which management has no influence in the determination of present value. In arriving at the ceiling test for the quarter ended September 30, 2009, the Company used $70.46 per barrel for oil and $3.24 per Mcf for natural gas to compute the future cash flows of the Company’s producing property. The discount factor used was 10%.

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

Long-Lived Assets

The Company evaluates its 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 the Company's financial position and results of operations. At September 30, 2009 and December 31, 2008, no impairment existed on the Company’s long-lived assets as the appraised value at September 30, 2009 and December 31, 2008 exceeded construction and carrying value and rental rates remained strong and costs within projected limits.

4) Asset Retirement Obligations

The Company accounts for its asset retirement obligations under FASB ASC 410-20, “Asset Retirement Obligations.” The Company records the fair value of the reclamation liability on its inactive mining and oil and gas properties as of the date that the liability is incurred. The Company reviews the liability each quarter and determines if a change in estimate is required and also accretes the discounted liability on a quarterly basis for the future liability. Final determinations are made during the fourth quarter of each year. The Company deducts any actual funds expended for reclamation during the quarter in which it occurs.

-16-

U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

(Continued)

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

Asset Retirement Obligations
(Amounts in thousands)

	September 30,		December 31,
	2009		2008
Beginning asset retirement obligation	$	144	$	133

Accretion of estimated ARO		9		9

Liabilities incurred		--		25
Liabilities settled		--		(23	)

Ending asset retirement obligation	$	153	$	144

5) Other Comprehensive Income (Loss)

Unrealized gains and losses on investments are excluded from net income but are reported as comprehensive income on the Condensed Balance Sheets under Shareholders’ Equity. The following table reconciles net loss to comprehensive loss:

(Amounts in thousands)

	For the three months						For the nine months
	ending September 30,						ending September 30,
	2009			2008			2009			2008
Net loss	$	(1,744	)	$	3,801		$	(6,976	)	$	334

Comprehensive gain/(loss) from the
unrealized gain/(loss) on marketable securities		371			(110	)		594			(285	)

Deferred income taxes
on marketable securities		(134	)		39			(214	)		84

Comprehensive (loss)/gain	$	(1,507	)	$	3,730		$	(6,596	)	$	133

6) Long-term debt

On January 16, 2009, the Company paid $16.8 million to Zions National Bank to retire the construction loan for its multifamily housing project in Gillette, Wyoming. The housing project is a 216 unit apartment complex on 10.15 acres and cost a total of $24.5 million to construct.

-17-

U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

(Continued)

At September 30, 2009, 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 five equal payments of $200,000, plus accrued interest, beginning on January 2, 2010 through January 2, 2014:

(Amounts in thousands)

	September 30,			December 31,
	2009			2008
Short-term Debt
Construction note - collateralized by
property, interest at 2.71%	$	--		$	16,813

Long-term Debt
Real estate note - collateralized by
property, interest at 6%	$	1,000		$	1,875

Less current portion		(200	)		(875	)
Totals	$	800		$	1,000

7) Shareholders’ Equity

Common Stock

During the three and nine months ended September 30, 2009, the Company issued 20,000 and 60,000 shares, respectively, of common stock to officers of the Company pursuant to the 2001 Stock Compensation Plan. The Company recorded $40,200 and $112,000 in compensation expense as a result of the issuance of these shares during the three and nine months ended September 30, 2009, respectively. The Company also purchased 706,071 shares of its common stock during the nine months ended September 30, 2009 to finish its $8.0 million stock buyback plan. From inception, the Company purchased a total of 3,094,200 shares for $8.0 million or an average of $2.59 per share under the stock buyback plan.

The following table details the changes in common stock during the nine months ended September 30, 2009:

(Amounts in thousands, except for share amounts)

							Additional
	Common Stock						Paid-In
	Shares			Amount			Capital

Balance December 31, 2008		21,935,129		$	219		$	93,951

2001 stock compensation plan		60,000			1			111

Expense of employee options vesting		--			--			1,069

Expense of director options vesting		--			--			42

Expense of company warrants issued		--			--			8

Common stock buyback program		(706,071	)		(7	)		(1,392	)

Balance September 30, 2009		21,289,058		$	213		$	93,789

-18-

U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

(Continued)

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 USE'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, 2009, the Company recognized $360,000 and $1,069,000, respectively, in compensation expense related to employee options. The Company computes the fair values of its options granted using the Black-Scholes pricing model.

Warrants to Others

From time to time the Company issues stock purchase warrants to non-employees for services. During the three and nine months ended September 30, 2009, the Company recorded $15,000 and $50,000, respectively, in expense for warrants issued to third parties. The Company will recognize an additional $121,000 in expense over the life of the outstanding warrants.

The following table represents the activity in employee stock options and non-employee stock purchase warrants for the nine months ended September 30, 2009:

	September 30, 2009
	Employee Stock Options					Stock Purchase Warrants
				Weighted					Weighted
				Average					Average
				Exercise					Exercise
	Options			Price		Warrants			Price

Outstanding balance at December 31, 2008		3,717,098		$	3.63		1,036,387		$	3.43
Granted		-		$	-		-		$	-
Forfeited		-		$	-		-		$	-
Expired		(4,000	)	$	2.46		(383,932	)	$	4.26
Exercised		-		$	-		-		$	-
Outstanding at September 30, 2009		3,713,098		$	3.64		652,455		$	2.95
Exercisable at September 30, 2009		2,616,437		$	3.43		565,789		$	3.01

Weighted Average Remaining Contractual Life - Years					5.83					3.76

Aggregate intrinsic value of options / warrants outstanding				$	2,401,000				$	622,000

-19-

U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

(Continued)

8) Income Taxes

The Company completed book and tax basis studies during the nine months ended September 30, 2009 and discovered a previously unrecorded difference between its tax basis and its book basis in fixed assets. A non-cash adjustment of the associated deferred tax liability and deferred income tax expense in the amount of $1.1 million was made during the nine months ended September 30, 2009 to reflect this difference. In addition, due to an increased presence in certain states such as Louisiana, the Company determined that an increase to its effective tax rate from 35% to 36% was necessary. This increase resulted in a noncash charge to deferred income tax expense and deferred tax liability of $300,000.

9) Segment Information

As of September 30, 2009, the Company had three reportable segments: Oil and Gas, Real Estate Operations, and Maintenance of Mineral Properties.

Costs paid by the Company during the three and nine months ended September 30, 2009 for holding mineral properties were primarily related to the water treatment plant at the Mount Emmons molybdenum property. The costs for the water treatment plant during the three months ended March 31, 2008 were paid by the Company’s then partner on the property. The costs of the water treatment plant during the three months ended September 30, 2008 and the nine months ended September 30, 2009 were paid for by the Company.

-20-

U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

(Continued)

A summary of results of operations and total assets by segment follows:

(Unaudited)
(Amounts in thousands)

	For the three months						For the nine months
	ended September 30,						ended September 30,
	2009			2008			2009			2008
Revenues:
Real estate	$	686		$	564		$	2,165		$	995
Oil & gas		593			--			1,912			--
Other		5			5			14			52
Total revenues:		1,284			569			4,091			1,047

Operating expenses:
Real estate		507			311			1,517			712
Oil and gas		446			--			1,936			--
Impairment of oil & gas properties		405			--			1,468			--
Mineral properties		379			1,208			1,398			2,282
Total operating expenses:		1,737			1,519			6,319			2,994

Interest expense
Real estate		--			132			19			206
Oil & gas		--			--			--			--
Mineral properties		15			--			45			--
Total interest expense:		15			132			64			206

Operating gain/(loss)
Real estate	$	179		$	121		$	629			77
Oil & gas		(258	)		--			(1,492	)		--
Mineral properties		(389	)		(1,203	)		(1,429	)		(2,230	)
Operating (loss)		(468	)		(1,082	)		(2,292	)		(2,153	)

Other revenues and expenses:		(2,140	)		(1,376	)		(5,971	)		(4,859	)

(Loss) before discontinued
operations and income taxes	$	(2,608	)	$	(2,458	)	$	(8,263	)	$	(7,012	)

Depreciation expense:
Real estate	$	262		$	184		$	783		$	332
Oil & gas		475			--			1,795			--
Mineral properties		13			9			41			27
Corporate		98			88			299			329
Total depreciation expense	$	848		$	281		$	2,918		$	688


							As of
							September 30,			December 31,
								2009			2008
Assets by segment
Real estate							$	23,661		$	30,980
Oil & Gas properties								14,077			8,523
Mineral properties								22,993			24,927
Corporate assets								55,152			78,201
Total assets							$	115,883		$	142,631

-21-

U.S. ENERGY CORP.

Notes to Condensed Financial Statements (Unaudited)

(Continued)

10) Subsequent Event

On October 20, 2009, the Company filed a Form S-3 universal shelf registration statement with the Securities and Exchange Commission (“SEC”), for the offer and sale of up to $100 million of its common stock. Under the registration statement, from time to time the Company may offer to sell shares of its common stock.

On October 16, 2009, the Company announced that the Brad Olson 9-16 #1H flowed at an initial 24-hour production test rate of approximately 1,805 barrels of oil and 1.84 MMCF of natural gas per day or 2,112 BOE/D. USE’s initial working interest in this well is approximately 61% (~48% net revenue interest).

On November 2, 2009, the Company announced that the BCD Farms 16-21 #1H well, flowed at an initial 24-hour production test rate of approximately 1,553 barrels of oil and 1.34 MMCF of natural gas per day or 1,776 BOE/D. The well is located in the northwest portion of the Rough Rider acreage, and is located approximately 13 miles northwest of the Brad Olsen well. USE's initial working interest in this well is approximately 45% (~35.55 net revenue interest).

On October 30, 2009, the administrative law judge issued an order rejecting the Petitioners request and finding that the Company did not need to provide financial assurances as a condition of the NPDES permit for the water treatment plant at the Mount Emmons Property.

-22-

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 the Company's liquidity, capital resources and results of operations during the quarter and nine months ended September 30, 2009 and 2008. The following also updates information as to our financial condition provided in our 2008 Annual Report on Form 10-K. Statements in the following discussion maybe 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

The Company is involved in the exploration for and development of oil and gas, minerals and geothermal energy as well as real estate development. The Company’s primary objective in the short to mid-term is to develop and acquire oil and gas producing properties as well as develop its geothermal properties. The long-term goal of the Company is to participate in the development of the Mount Emmons molybdenum property in Colorado. In addition to the Company’s oil and gas properties, the Company owns one multifamily housing complex as well as various other real estate properties which provide cash flows to fund operations. Through these businesses, it is the Company’s primary goal to improve shareholder value by developing long-term recurring revenues, cash flows and net income.

FASB Codification Discussion

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. Over the years, the FASB and other designated GAAP-setting bodies, have issued standards in the form of FASB Statements, Interpretations, FASB Staff Positions, EITF consensuses, AICPA Statements of Position, etc. One standard that applies to our business is FASB Statement No. 128, “Earnings per Share.” That standard, originally issued in 1997, has been interpreted and amended many times over the years.

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. To the Company, this means instead of following the earnings per share rules in FASB Statement No. 128, we will follow the guidance in Topic 260, “Earnings per Share”. 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 rather than FASB Statement No. 128, etc. The above change was made effective by the FASB for periods ending on or after September 15, 2009. We have updated references to GAAP in this Quarterly Report on Form 10-Q to reflect the guidance in the Codification.

-23-

Liquidity and Capital Resources

At September 30, 2009, the Company had $11.7 million in cash and cash equivalents and $27.2 million in Treasury Bills with longer than 90-day maturities from date of purchase for a total of $38.9 million or $1.83 per outstanding common share. Its working capital (current assets minus current liabilities) was $40.1 million. As discussed below in Capital Resources and Capital Requirements, the Company projects that its capital resources at September 30, 2009 will be sufficient to fund its operations and capital projects through the balance of 2009. To fund projected oil and gas exploration beyond the end of calendar 2009, the Company will need to obtain additional capital. The Company is currently considering its alternatives, including sales of additional shares of its capital stock. Additionally, the Company is pursuing financing of its real estate property in Gillette, Wyoming and renewing its line of credit with a commercial bank. The line of credit in the amount of $5.0 million expired on October 1, 2009 and was fully available at that time. The Company is negotiating with the bank for its renewal.

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 raise to levels which either allow the properties to be sold or placed into production through joint venture partners, or by the Company for its 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 less exploration activity and the cost of drilling is typically reduced.

Cash flows during the nine months ended September 30, 2009:

·	Operations provided $2.9 million, Investing Activities provided $19.4 million and Financing Activities consumed $19.1 million for a net increase in cash of $3.2 million.

·	For a discussion on cash consumed in Operations please refer to Results of Operations below.

Investing Activities:

·	Cash provided by investing activities was generated primarily through the redemption of U.S. Government Treasury Bills, $24.1 million and restricted cash investments held as collateral for a construction loan, $4.7 million, for a total of $28.8 million.

·	Additional cash was provided by investing activities as a result of the Company’s receipt of the first of six anticipated annual payments of $1.0 million from Thompson Creek Metals USA (“TCM”) as an option payment on the Mount Emmons property.

Investing activities consumed cash through the completion of the development of its multifamily housing complex in Gillette, Wyoming, $91,000, the acquisition and development of oil and gas properties, $9.1 million, investment in Standard Steam Trust, $877,000 and the purchase of property and equipment, $249,000.

Financing Activities:

·	The Company retired $17.7 million in debt during the nine months ended September 30, 2009. This debt consisted of $16.8 million for the construction of the Company’s multifamily housing complex in Gillette, Wyoming and $875,000 for the joint purchase with TCM of a parcel of property in Colorado.

·	The Company purchased 706,071 shares of its common stock pursuant to its stock buyback plan which consumed $1.4 million during the nine months ended September 30, 2009.

-24-

Following is a discussion regarding the Company’s Capital Resources and Capital Requirements during the balance of 2009. For longer-range projections of the Company’s capital resources and requirements, please refer to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.

Capital Resources

Sources of capital during the balance of 2009 are expected to consist of (1) the sale of oil and gas production from the Company’s existing and anticipated oil and gas operations, (2) receipts of cash for the rental of real estate properties, (3) cash on hand, (4) long-term financing of the Company’s multifamily housing complex, and (5) a line of credit in the amount of $5.0 million that expired on October 1, 2009 and is being negotiated for renewal, which may be extended. In addition, we are also considering financing alternatives that may include the issuance of capital stock of the Company.

Oil and Gas Production

At September 30, 2009 the Company had two producing wells and one additional successful well that did not begin production until the fourth quarter of 2009. The Company receives on average $212,000 per month from these producing wells with average operating cost of $19,000 per month, before non cash depletion expense, for average cash flows of $193,000 per month from oil and gas production. The Company anticipates that cash flows from oil and gas operations will increase through the balance of 2009 as the wells being drilled with Brigham begin to produce. Decreases in the price of oil and natural gas however could decrease these monthly cash flow amounts.

Primarily due the drilling of one dry hole in the third quarter with net costs to the Company of $98,000 and low market price for gas at September 30, 2009, capitalized costs for oil and gas properties at September 30, 2009 exceeded the ceiling test limit. The Company therefore recorded a $405,000 non-cash write down of its oil and gas properties during the quarter ended September 30, 2009. In the quarter ended March 31, 2009, the Company recorded a $1.1 million non-cash ceiling test write down of its oil and gas properties primarily due to low market price for natural gas at March 31, 2009. The total impairment recorded in 2009 through September 30, 2009 is $1.5 million.

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. The Company plans on continuing in the oil and gas exploration business and may also acquire existing oil and gas properties.

Real Estate

The Company’s multi-family complex in Gillette, Wyoming is complete and had an occupancy rate of 82% at September 30, 2009. Revenues are approximately $220,000 per month and net cash flow from this property is approximately $160,000 per month. As of September 30, 2009 there is continuing evidence that the overall housing rental market in Gillette has softened. Lower overall commodity prices for coal and natural gas (the primary industries in Gillette, Wyoming) and the resulting reductions in workforces are placing pressure on the rental housing market. The Company will continue to focus on tenant retention and control of overhead costs in an effort to minimize the impact of any downturn. The Company has initiated the process to secure long-term financing for the property. The property cost $24.5 million and has been appraised in excess of that amount.

-25-

Cash on Hand

The Company invests its working capital in interest bearing accounts and the majority of its cash surplus in short-term U.S. Government Treasuries. Although the Company could benefit from higher interest bearing investments, it has its cash invested in U.S. Treasuries to preserve the principal in the current turbulent financial markets and to avoid becoming an inadvertent investment company.

Capital Requirements

The direct capital requirements of the Company during the balance of 2009 are the funding of the development of the Company’s interest in its oil and gas properties, the potential acquisition of additional oil and gas properties or companies, funding of our geothermal investment and Remington Village operations, costs associated with the water treatment plant at the Mount Emmons molybdenum project and general and administrative costs.

Mount Emmons Molybdenum Property

Under the terms of its agreement with TCM, the Company is responsible for all costs associated with operating the water treatment plant at the Mount Emmons molybdenum property. Operating costs during the balance of 2009 are projected to be approximately $423,000. Additionally, the Company projects fourth quarter capital improvement expenditures of $35,000 at the water treatment plant which are expected to improve its efficiency. The Company also participates 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. The Company’s portion of those costs during the balance of 2009 is projected to be $15,000. Actual future costs could be different from those estimates made above.

Oil and Gas Development

Brigham Exploration Company (“BEXP”)

At September 30, 2009, the Company had funded the drilling of two wells with BEXP with net costs to USE of $6,858,000. Pursuant to the Drilling Participation Agreement, the Company has committed to fund 65% of BEXP’s initial working interest in four additional wells during the fourth quarter of 2009 with expected net costs to the Company of $11.7 million. If the Company elects to participate in wells with BEXP beyond the initial six well program, an additional two wells could be drilled in the fourth quarter bringing the total estimated capital requirement for the fourth quarter to approximately $16.6 million.

The Company’s portion of operating costs and expenses for these wells is projected to be approximately $150,000 for the fourth quarter of 2009.

PetroQuest Energy, Inc. (“PQ”)

The Company’s portion of operating costs and expenses for its producing well are projected to be $57,000 during the remaining three months of 2009.

-26-

The Company has elected to participate in the drilling of one Gulf Coast well with Petroquest in the fourth quarter of 2009, The Company will participate as an approximate 4.24% working interest owner with projected net costs to the Company of $220,000. While successful Gulf Coast wells can provide favorable returns on investment, we will continue to assess the viability of participating in additional wells with PQ. If we should elect not to participate in any undrilled prospects proposed by PQ where we have paid for lease and seismic costs, we will attempt to farm out or sell our interest.

YUMA Exploration and Production Company Inc. (“YUMA”)

The Company has budgeted $1.0 million in drilling costs in the fourth quarter of 2009 for wells with YUMA. The actual expenditure of these funds is contingent upon the generation of viable drilling prospects by seismic evaluation and the availability and cost of drill rigs. No firm commitment has been made to drill any wells as of September 30, 2009; however leasing activity is expected to commence with projected net costs to the Company of $42,000 in the fourth quarter.

Houston Energy, L.P. (“Houston Energy”)

As of September 30, 2009, the Company has no commitment to drill any additional wells on other prospects with Houston Energy. While successful Gulf Coast wells can provide favorable returns on investment, we will continue to assess the viability of participating in additional wells with Houston Energy on a project by project basis.

Wildes Exploration Agreement (“Wildes”)

The Company has contracted to pay Wildes an annual $100,000 consulting and management fee for the prospects with PQ and an additional $50,000 annually for properties with Yuma. Additionally, Wildes has a back-in interest in wells drilled with PQ, Yuma and Houston Energy. Each back-in interest is governed by different contracts but is not effectuated until such time as the Company has recovered its cost plus varying amounts. No back-in interests will become effective during the remainder of 2009 for Wildes.

Other Oil and Gas Exploration or Acquisition Opportunities

The Company will continue to seek additional opportunities to either explore for or acquire existing oil and gas production.

Real Estate

The cash operating costs of the multifamily housing complex in Gillette, Wyoming are estimated to be $195,000 for the balance of 2009. There are no additional budgeted capital expenditures for real estate operations during 2009.

Geothermal Energy Projects

The Company has a 25% ownership interest in a geothermal company. Budgeted cash expenditures to maintain the Company’s 25% ownership will require the expenditure of an estimated $3.1 million during the balance of 2009 if all the contemplated drilling and property acquisition projects are achieved. In the event that the Company elects to either partially fund or not participate in cash calls its only penalty is dilution of ownership.

-27-

Reclamation Costs

At September 30, 2009, there were no reclamation projects on the Company’s mineral or oil and gas properties that would require the expenditure of cash reserves during the balance of 2009.

Results of Operations

Three Months Ended September 30, 2009 compared to 2008

Operations for the quarter ended September 30, 2009 resulted in a loss of $2.6 million. The net loss, after taxes was $1.7 million, or $0.09 per share, as compared to net income of $3.8 million, or $0.16 per share, during the quarter ended September 30, 2008. Net income at September 30, 2008 included a gain of $5.2 million, or $0.22 per share, from discontinued operations related to the sale of a portion of the Company’s investment in Sutter Gold Mining Inc. (“Sutter”). The losses from continuing operations at September 30, 2009 and 2008 included $1.7 million and $865,000 in non cash items, respectively, consisting of depreciation, amortization, depletion, impairment on oil and gas properties, non cash compensation and non cash payment for services rendered. Depreciation, amortization and depletion expense increased $567,000 during the quarter ended September 30, 2009 over the prior year due primarily to the completion of the Company’s multifamily housing complex, in the amount of $78,000, the amortization of full cost oil and gas capitalized costs in the amount of $475,000 and $14,000 from equipment.

The Company recognized $1.3 million in revenues during the quarter ended September 30, 2009 as compared to revenues of $569,000 during the same quarter of the prior year. Real estate revenues increased by $189,000 as a result of the completion of the multifamily housing complex in Gillette, Wyoming and oil and gas revenues increased $526,000 as a result of production from an oil and gas well completed in the fourth quarter of 2008. Real estate operations resulted in a net gain before taxes of $179,000. Oil and gas operations resulted in a loss of $258,000 during the quarter ended September 30, 2009. This loss is primarily as a result of an impairment of $405,000 taken during the quarter.

-28-

The following table summarizes production volumes, average sales prices and operating revenues for the three months ended September 30, 2009 and 2008:


						2009 Period Compared to 2008 Period
	Three Months Ended								%
	September 30,					Increase			Increase
	2009			2008		(Decrease)			(Decrease)
Production volumes
Oil and condensate (Bbls)		3,351			--		3,351			100	%
Natural gas (Mcf)		120,314			--		120,314			100	%
Natural gas liquids (Bbls)		3,504			--		3,504			100	%
Average sales prices
Oil and condensate (per Bbl)	$	42.67		$	--	$	42.67			100	%
Natural gas (per Mcf)		2.91			--		2.91			100	%
Natural gas liquids (per Bbl)		28.54			--		28.54			100	%
Operating revenues (in thousands)
Oil and condensate	$	143		$	--	$	143			100	%
Natural gas		350			-		350			100	%
Natural gas liquids		100			-		100			100	%
Total operating revenue		593			-		593			100	%
Lease operating expense		29			-		29			100	%
Impairment		(405	)		-		(405	)		100	%
Gain before DD&A		217			-		217			100	%
DD&A		(475	)		-		(475	)		100	%
Gain (Loss)	$	(258	)	$	-	$	(258	)		100	%

General and administrative expenses increased by $141,000 during the quarter ended September 30, 2009 as compared to the prior year. This increase relates primarily to the entry into the oil and gas business which has required additional professional consulting services. Future growth into this business segment will likely require additional professional employees and consultants.

Other income and expenses – The Company recorded an equity loss from its investment in a geothermal partnership in the amount of $339,000 during the quarter ended September 30, 2009 with no similar losses reported during the prior year. The geothermal industry is a capital intensive business which will result in ongoing equity losses until such time as properties are sold or the Company sells its investment. Interest income decreased from $324,000 during the quarter ended September 30, 2008 by $236,000 to interest income of $88,000 at September 30, 2009. The decrease is a result of lower amounts of cash invested in interest bearing instruments and lower interest paid on those investments.

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The Company therefore recorded a net loss before taxes of $2.6 million during the quarter ended September 30, 2009 as compared to a net loss before taxes of $2.5 million during the quarter ended September 30, 2008. The reduction in net earnings after taxes of $3.8 million recorded at September 30, 2008 to a net after tax loss of $1.7 million during the quarter ended September 30, 2009 is as a result of the gain recorded during 2008 from the sale of the Company’s interest in a gold mining company, Sutter.

Nine Months Ended September 30, 2009 compared to 2008

Operations for the nine months ended September 30, 2009 resulted in a loss of $7.0 million, or $0.33 per share, as compared to net income of $334,000, or $0.01 per share, during the nine months ended September 30, 2008. Net income for the nine months ended September 30, 2008 included a gain of $5.4 million, or $0.20 per share from discontinued operations related to the sale of a portion of the Company’s investment in Sutter. The losses from continuing operations for the nine months ended September 30, 2009 and 2008 included $5.7 million and $2.8 million in non-cash items, respectively, consisting of depreciation, amortization, depletion, impairments taken on oil and gas properties, non-cash compensation and non-cash payment for services rendered. Depreciation, amortization and depletion expense increased $2.2 million during the nine months ended September 30, 2009 over the prior year due primarily to the completion of the Company’s multifamily housing complex, in the amount of $451,000, and the amortization of full cost oil and gas capitalized costs in the amount of $1.8 million. Non-cash compensation decreased $852,000 during the nine months ended September 30, 2009 from those recorded during the same period of 2008 as a result of lower expenses related to the amortization of stock options and lower market prices for the Company’s common stock related to equity compensation.

The Company recognized $4.1 million in revenues during the nine months ended September 30, 2009 as compared to revenues of $1.0 million during the same period of the prior year. Real estate revenues increased by $1.2 million as a result of the completion of the multifamily housing complex in Gillette, Wyoming. Oil and gas revenues increased $1.9 million as a result of production from an oil and gas well completed in the fourth quarter of 2008. Real estate operations resulted in a net gain before taxes of $629,000. Oil and gas operations resulted in a loss of $1.5 million which includes $1.8 million in non-cash depletion and amortization expense and an impairment of $1.5 million. The impairment was recorded as a result of depressed prices for natural gas and dry hole expenses which had been capitalized.

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The following table summarizes production volumes, average sales prices and operating revenues for the nine months ended September 30, 2009 and 2008:

						2009 Period Compared to 2008 Period
	Nine Months Ended								%
	September 30,					Increase			Increase
	2009			2008		(Decrease)			(Decrease)
Production volumes
Oil and condensate (Bbls)		10,451			--		10,451			100	%
Natural gas (Mcf)		351,191			--		351,191			100	%
Natural gas liquids (Bbls)		4,507			--		4,507			100	%
Average sales prices
Oil and condensate (per Bbl)	$	45.16		$	--	$	45.16			100	%
Natural gas (per Mcf)		3.69			--		3.69			100	%
Natural gas liquids (per Bbl)		31.95			--		31.95			100	%
Operating revenues (in thousands)
Oil and condensate	$	472		$	--	$	472			100	%
Natural gas		1,296			-		1,296			100	%
Natural Gas Liquids		144			-		144			100	%
Total operating revenue		1,912			-		1,912			100	%
Lease operating expense		(141	)		-		(141	)		100	%
Impairment		(1,468	)		-		(1,468	)		100	%
Gain before DD&A		303			-		303			100	%
DD&A		(1,795	)		-		(1,795	)		100	%
Gain (Loss)	$	(1,492	)	$	-	$	(1,492	)		100	%

When the Company entered into its agreement with TCM, it agreed to pay all costs associated with the water treatment plant at the Mount Emmons molybdenum property and thereby recorded $1.4 million in costs and expenses for that facility during the nine months ended September 30, 2009. Costs associated with the water treatment plant during the three months ended March 31, 2008 were paid by the Company’s then partner prior to its exit from the project on September 30, 2008.

General and administrative expenses decreased by $294,000 during the nine months ended September 30, 2009 as compared to the same period in the prior year. This reduction is due to cost saving efforts.

Other income and expenses – The Company recorded an equity loss from its investment in a geothermal partnership in the amount of $505,000 during the nine months ended September 30, 2009 with no similar losses reported during the prior year. Equity losses from the Company’s investment in geothermal will continue until such time as properties are sold or the Company sells its investment. Interest income decreased from $1.2 million during the nine months ended September 30, 2008 to $264,000 at September 30, 2009. The decrease is a result of lower amounts of cash invested in interest bearing instruments and lower interest paid on those investments.

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The Company therefore recorded a net loss before taxes of $8.3 million during the nine months ended September 30, 2009 as compared to a net loss before taxes of $7.0 million during the nine months ended September 30, 2008. The increase in the net loss between the two periods is primarily due to the impairment taken on the oil and gas assets and the reduction of interest income earned during the periods. Offsets to these increases are the gain from real estate operations and reductions of general and administrative costs and expenses.

Critical Accounting Policies

For detailed descriptions of Company’s significant accounting policies, please see pages 53 to 56 of the Company’s Annual Report on Form 10K for the year ended December 31, 2008.

Mineral Properties - The Company capitalizes 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 the Company subsequently determines 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, 2009 and December 31, 2008 reflect capitalized costs associated with the Company’s Mount Emmons molybdenum property near Crested Butte, Colorado. The Company has 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. The Company received the first of six anticipated annual payments in the amount of $1.0 million in January 2009. This payment was applied as a reduction of the Company’s 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 $10.00 per pound in December 2008 and continued to decline during the first quarter of 2009. During the third quarter of 2009 spot prices for molybdenum increased to a high of $17.50 per pound in August, 2009 and were $14.00 per pound at September 30, 2009. The historic models prepared by third parties indicate that prices for molybdenum could decrease even lower than $10.00 and the property would still be economical given the carried investment amount of $23.0 million at September 30, 2009 and $23.9 million at December 31, 2008, respectively. No impairment was therefore taken during either period on the Mount Emmons molybdenum property.

Oil and Gas Properties - The Company 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 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 unevaluated properties.

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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 year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge the Company’s 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 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.

Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at September 30, 2009 and December 31, 2008 which were not included in the amortized cost pool were $11.3 million and $3.0 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, 2009 and December 31, 2008. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are evaluated, drilled or abandoned.

Primarily due to the drilling of one dry hole in the third quarter with net costs to the Company of $98,000 and low market price for natural gas at September 30, 2009, capitalized costs for oil and gas properties at September 30, 2009 exceeded the ceiling test limit. The Company therefore recorded a $405,000 non-cash write down of its oil and gas properties during the quarter ended September 30, 2009. In the quarter ended March 31, 2009, the Company recorded a $1.1 million non-cash ceiling test write down of its oil and gas properties primarily due to low market price for natural gas at March 31, 2009. The total impairment recorded during the nine months ended September 30, 2009 is $1.5 million. 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 in the near term. 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 additional write-downs of oil and gas properties could occur in the future.

Long-Lived Assets

Asset Retirement Obligations - The Company accounts for its asset retirement obligations under ASC 410-20 (formerly SFAS No. 143, "Accounting for Asset Retirement Obligations"). The Company records the fair value of the reclamation liability on its inactive mining properties as of the date that the liability is incurred. The Company reviews the liability each quarter and determines if a change in estimate is required as well as accretes the liability on a quarterly basis for the future liability. Final determinations are made during the fourth quarter of each year. The Company deducts any actual funds expended for reclamation during the quarter in which it occurs.

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Future Operations

Management intends to continue seeking opportunities presented by the recent and future projected market prices for oil and natural gas, minerals and geothermal assets. We intend to acquire new oil and gas properties and pursue new business opportunities in the mineral and geothermal business. 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 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, 2009, the Company is receiving revenues from its oil and gas business. The Company’s 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.

The Company’s multifamily housing revenues could be affected negatively if there was a sustained down turn in the price of coal, natural gas and oil 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 its Annual Report of 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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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 two divisions of contractual obligations at September 30, 2009: Debt to third parties of $1.0 million with interest at 6% per annum and asset retirement obligations of $153,000. The debt will be paid over a period of five years and the asset retirement obligations will be retired during the next 34 years. The following table shows the scheduled debt payment and expenditures for budgeted asset retirement obligations:

Contractual Obligations
September 30, 2009
(Amounts 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	$	1,000	$	200	$	600	$	200	$	--

Other long-term liabilities		153		--		--		26		127

Totals	$	1,153	$	200	$	600	$	226	$	127

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

The Company experiences market risks primarily in three areas: commodity prices, drilling costs and interest rates. Our mineral related revenues are derived from the sale of our natural gas and crude oil production. In the future, the Company may seek to reduce its exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. At September 30, 2009, the Company had not put any hedges in place for its existing production.

Availability of drilling rigs and experienced crews has a direct correlation to the market price for oil and natural gas. At September 30, 2009 drilling costs have decreased due to lower market prices for natural gas. As the price for oil and natural gas increase, drilling costs will also likely increase due to increased exploration activity.

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Lower overall commodity prices for coal and natural gas (the primary industries in Gillette, Wyoming) and the resulting reductions in workforces are placing pressure on the rental housing market and our real estate revenues. Although the current occupancy rate is still high, as of September 30, 2009 there is evidence that the overall housing rental market in Gillette, Wyoming has softened. No assurance can be given that the current occupancy rates will not fall due to lower commodity prices or a surplus of houses that may become available due to defaults on existing mortgages.

Revenues earned and cash received from invested surplus cash are dependent on the interest rates paid on U.S. Treasury Bills, which rates in turn may be affected by the general economy and demand for credit.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of September 30, 2009, the Company’s management, including its Chief Executive Office 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, 2009 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 Treatment Facility – Permit Renewal Protest

The Company received a NPDES Permit renewal for Mount Emmons from the Colorado Department of Public Health and Environment – Water Quality Division (“Water Quality Division”) effective September 1, 2008. The NPDES Permit is for a five (5) year period (2008 - 2013). On August 28, 2008, the Town of Crested Butte, Board of County Commissioners for the County of Gunnison and High Country Citizens’ Alliance (“Petitioners”) filed a Request for Adjudicatory Hearing before the Water Quality Division to challenge the NPDES Permit. The Petitioners seek revisions to the Permit that would require the Company to maintain a prepaid operating contract and provide additional financial security for long term operation of the plant. During the permit approval process, the Division rejected similar permit revisions proposed by the Petitioners as not being required or authorized by Colorado law. The hearing will be held in early 2009 before an Administrative Law Judge in the Office of Administrative Courts (“OAC”). The Company will participate in the hearing as an interested party. The Company expects to work cooperatively with the Water Quality Division in defending the NPDES Permit.

A hearing was held on October 2, 2009 in Denver, Colorado concerning a protest of the Colorado Water Quality Division decision not to require financial assurances in the issuance to the Company of a renewal NPDES permit for the water treatment plant at the Mount Emmons property. On October 30, 2009, the administrative law judge issued an order rejecting the Petitioners request and finding that the Company did not need to provide financial assurances as a condition of the NPDES permit for the water treatment plant at the Mount Emmons Property.

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 March 28, 2008, the Company and the Colorado Attorney General’s Office filed independent Motions to Dismiss alleging among other matters that: (i) HCCA had no standing to appeal the NOI; (ii) the NOI is not an appealable decision under Colorado law; (iii) HCCA’s appeal is not timely; and (iv) the appeal is based on information obtained in violation of Colorado law.

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.

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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, 2009, see Item 1, Part II of the Company’s Annual Report on Form 10-K filed on March 13, 2009 and the Company’s Quarterly Report on Form 10-Q filed on August 6, 2009. For detailed information on the proceedings disclosed above, see the Company’s Annual Report on Form 10-K filed on March 13, 2009 (Item 1 of Part III, pages 28 to 30) under the caption “Water Treatment Facility – Permit Renewal Protest” and “Appeal of Approval of Notice of Intent to Conduct Prospecting for the Mount Emmons Property.”

ITEM 1A. Risk Factors

Except as set forth below, there have been no material changes to the risk factors discussed in Part I, “Item 1A. Risk Factors” (pages 13 to 20) in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 and the Form 10-Q filed on May 8, 2009, which could materially affect the Company’s business, financial condition or future results. 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.

Successful exploitation of the Williston Basin is subject to risks related to horizontal drilling and completion techniques.

Operations in the Williston Basin involve utilizing the latest drilling and completion techniques to generate the highest possible cumulative recoveries and therefore generate the highest possible returns. Risks that are encountered while drilling include, but are not limited to, landing the well bore in the desired drilling zone, staying in the zone while drilling horizontally through the shale formation, running casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore.

Completion risks include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations, and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Ultimately, the success of these latest drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period.

Operating in less developed basins such as the Williston Basin has risks that include, but are not limited to, securing access to takeaway capacity and securing access to equipment and service providers on a timely and cost effective basis.

Access to adequate gathering systems or pipeline takeaway capacity can be limited in less developed basins. In order to secure takeaway capacity, our operators may be forced to enter into arrangements that are not as favorable to operators in other areas. In addition, the availability of drilling rigs and other services may be more challenging. If we are unable to execute on our drilling program because of takeaway capacity or access to equipment, we potentially could be faced with lease expirations and the value of our undeveloped acreage could decline.

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We may not be able to drill wells on a substantial portion of our Williston Basin acreage.

We may not be able to participate in all or even a substantial portion of the many locations we earn through the Drilling Participation Agreement with Brigham. Our participation will depend on drilling and completion results, commodity prices, the availability and cost of capital relative to ongoing revenues from completed wells, and other factors.

Lower oil and natural gas prices may cause us to record ceiling limitation write-downs, which would reduce stockholders’ equity.

We use the full cost method of accounting to account for our oil and natural gas investments. Accordingly, we capitalize the cost to acquire, explore for and develop these properties. Under full cost accounting rules, the net capitalized cost of oil and gas properties may not exceed a “ceiling limit” that is based upon the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of the cost or fair market value of unproved properties. If net capitalized costs exceed the ceiling limit, we must charge the amount of the excess to earnings (called a “ceiling limitation write-down”). The risk of a ceiling test write-down increases when oil and gas prices are depressed or if we have substantial downward revisions in estimated proved reserves.

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 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 unevaluated 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 year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge the Company’s 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 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.

Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at September 30, 2009 and December 31, 2008, which were not included in the amortized cost pool, were $11.3 million and $3.0 million, respectively. These costs consist of wells in progress, seismic costs being analyzed for potential drilling locations, as well as land costs, all related to unproved properties. No capitalized costs related to unproved properties are included in the amortization base at September 30, 2009 and December 31, 2008. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are evaluated, drilled or abandoned.

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We perform a quarterly ceiling test for each of our oil and gas cost centers (at September 30, 2009, there was one such cost center). The ceiling test incorporates assumptions regarding pricing and discount rates at quarter end and over which we have no influence in the determination of present value. In arriving at the ceiling test for the quarter ended September 30, 2009, we used $70.46 per barrel for oil and $3.24 per Mcf for natural gas to compute the future cash flows of the producing property at that date. The discount factor used was 10%.

Primarily due the drilling of one dry hole in the third quarter with net costs of $98,000 and low market price for gas at September 30, 2009, capitalized costs for oil and gas properties at September 30, 2009 exceeded the ceiling test limit. As a result, we recorded a $450,000 non-cash write down of oil and gas properties during the quarter. This write-down was in addition to the $1.1 million non-cash ceiling test write down a March 31, 2009 (due to low market prices for gas at March 31, 2009). The total write-down in 2009 through the third quarter was $1.4 million. We may be required to recognize additional pre-tax non-cash impairment charges (write-downs) in future reporting periods if market prices for oil or natural gas continue to decline.

The Williston Basin oil price differential could have adverse impacts.

Due to takeaway constraints, oil prices in the Williston Basin generally have been from $8.00 to $10.00 less than prices for other areas in the United States. However, drilling and completion costs for the wells we drill in the Williston Basin are comparable to other areas where there is no price differential. As a result, while a significant prolonged downturn in oil prices on a national basis could result in a ceiling limitation write-down of the oil and gas properties we hold outside the Williston Basin, the write-downs could be more substantial for the properties in the Williston Basin due to the oil price differential. Such a price downturn also could reduce cash flow from the Williston Basin properties, and adversely impact our ability to participate fully in the many wells we will have available if we earn acreage in all 15 units under the Drilling and Participation Agreement.

The results of our drilling program in the Williston Basin are subject to more uncertainties than drilling in more established formations in other areas.

Brigham has only recently begun drilling wells in the Bakken and Three Forks formations in the Williston Basin, with horizontal wells and completion techniques that have proven to be successful in other shale formations. Brigham’s experience as well as the industry’s drilling and production history in the formation generally are limited. The ultimate success of these drilling and completion strategies and techniques in these formations will be better evaluated over time as more wells are drilled and longer term production profiles are established.

In addition, based on reported decline rates in these formations, estimated average monthly rates of production may decline by approximately 70% during the first twelve months of production. Actual decline rates may be significantly different than expected. Due to the limited production data for the Bakken and Three Forks formations, drilling and production results are more uncertain than encountered in other formations and areas with histories. Good results from wells we drill with Brigham may not be replicated in additional wells, even in the same drilling unit.

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

During the nine months ended September 30, 2009, 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.

During the nine months ended September 30, 2009, the Company purchased and cancelled 706,071 shares of its common stock under its Stock Buyback Plan which is now completed. The following table sets forth the activity during the nine months ended September 30, 2009 pursuant to the Stock Buyback Plan:

	Total Number Of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publically Announced Plan		Maximum Dollar Value of Shares that may be purchased under Plan

December 31, 2008		2,388,129	$	2.76		2,388,129	$	1,398,226.64

January 1 to 31, 2009		242,700	$	1.98		2,630,829	$	917,105.19

February 1 to 28, 2009		148,100	$	1.88		2,778,929	$	638,294.86

March 1 to 31, 2009		138,500	$	1.79		2,917,429	$	390,332.70

April 1 to 30, 2009		141,400	$	2.20		3,058,829	$	78,788.67

May 1 to 31, 2009		35,371	$	2.23		3,094,200	$	-

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

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ITEM 6. Exhibits

(a)	Exhibits

	3.1	Restated Articles of Incorporation as Amended (incorporated by reference from exhibit 4.1 to the Company’s Form S-3 filed October 21, 2009)
	3.2	Bylaws, as amended through April 17, 2009 (incorporated by reference from exhibit 3.2 to the Company’s Form 8-K filed April 21, 2009)
	10.1	Drilling Participation Agreement with Brigham Exploration Company dated August 24, 2009 (incorporated by reference from exhibit 10.1 to the Report on Form 8-K filed August 28, 2009)
	10.2	Employment Agreement by and between Keith G. Larsen and the Company dated as of April 20, 2009 (incorporated by reference form exhibit 10.1 to the Company’s Report on Form 8-K filed April 21, 2009)
	10.3	Employment Agreement by and between Mark J. Larsen and the Company dated as of April 20, 2009 (incorporated by reference form exhibit 10.2 to the Company’s Report on Form 8-K filed April 21, 2009)
	10.4	Employment Agreement by and between R. Scott Lorimer and the Company dated as of April 20, 2009 (incorporated by reference form exhibit 10.3 to the Company’s Report on Form 8-K filed April 21, 2009)
	10.5	Employment Agreement by and between Steven R. Youngbauer and the Company dated as of April 20, 2009 (incorporated by reference form exhibit 10.4 to the Company’s Report on Form 8-K filed April 21, 2009)
	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

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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 6, 2009	By:	/s/ Keith G. Larsen
		KEITH G. LARSEN,
		Chairman and CEO




Date: November 6, 2009	By:	/s/ Robert Scott Lorimer
		ROBERT SCOTT LORIMER
		Principal Financial Officer and
		Chief Accounting Officer

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