Edgar Filing: US ENERGY CORP

form10_k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

þ	Annual report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year Ended December 31, 2010

¨	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 000-6814

U.S. ENERGY CORP.

(Exact Name of Company 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

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $0.01 par value

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.YES ¨ NO þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.YES ¨ NO þ

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 þ NO ¨

Indicate by check mark if disclosure of delinquent filers, pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K þ

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

Large accelerated filer ¨ Accelerated filer þ Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).YES ¨ NO þ

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and ask price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (June 30, 2010): $121,356,000.

Class		Outstanding at March 11, 2011
Common stock, $.01 par value		27,196,495

Documents incorporated by reference: None.

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TABLE OF CONTENTS

Page

Cautionary Statement Regarding Forward-Looking Statements	5

PART I	7

ITEM 1. BUSINESS	7

Overview	7

Industry Segments/Principal Products	7

Office Location and Website	7

Business	7

Oil and Gas	7

Activities other than Oil and Gas	16

ITEM 1 A. RISK FACTORS	18

Risks Involving Our Business	18

Risks Related to Our Stock	29

ITEM 1 B. UNRESOLVED STAFF COMMENTS	30

ITEM 2. PROPERTIES	30

ITEM 3. LEGAL PROCEEDINGS	44

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITITY HOLDERS	46

PART II	46

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASE OF EQUITY SECURITIES	46

ITEM 6. SELECTED FINANCIAL DATA	49

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS	51

Forward Looking Statement	51

General Overview	51

Liquidity and Capital Resources	53

Capital Resources	56

Capital Requirements	60

Results of Operations	62

Critical Accounting Policies	68

Future Operations	71

Effects of Changes in Prices	71

Contractual Obligations	72

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	73

ITEM 8. FINANCIAL STATEMENTS	74

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	125

ITEM 9A. CONTROLS AND PROCEDURES	125

ITEM 9B. OTHER INFORMATION	128

PART III	128

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	128

ITEM 11. EXECUTIVE COMPENSATION	128

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED MATTERS	128

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	128

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES	129

PART IV	132

ITEM 15. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES, REPORTS AND FORMS 8-K	132

SIGNATURES	135

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information discussed in this Annual Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statements of historical facts, are forward-looking statements. Examples of such statements in this Annual Report concern planned capital expenditures for oil and gas exploration; payment or amount of dividends on our common stock in the future; continued earnings swings; cash expected to be available for continued work programs; recovered volumes and values of oil and gas approximating third-party estimates of oil and gas reserves; anticipated increases in oil and gas production; drilling and completion activities in the Williston Basin and other areas; timing for drilling of additional wells; expected spacing for wells to be drilled with our industry partner Brigham Exploration Company in the Bakken/Three Forks formations; and expected well spacing for wells to be drilled with our other industry partners Houston Energy, Southern Resources; PetroQuest Energy, Cirque Resources LP, WR Production Company, Crimson Exploration and Zavanna.

Additional forward-looking statements in this Annual Report related to when payout may be reached for the wells drilled in 2010 with Brigham; the number of locations for wells that may be available for drilling with any of our other industry partners; expected working and net revenue interests, and costs of wells, for the drilling programs with any of our partners; actual decline rates for producing wells in the Bakken/Three Forks formations; submission of a Plan of Operations to the U.S. Forest Service and approval of such Plan in connection with the Mt. Emmons project and the expected length of time to permit and develop the Mt. Emmons project; expected time to receive a return on investment from the geothermal prospects; future cash flows and borrowings; pursuit of potential acquisition opportunities; anticipated business activities in the Gillette, Wyoming area and their impact on our Gillette, Wyoming multi-family housing complex; our expected financial position; and other plans and objectives for future operations.

These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Though we believe that the expectations reflected in these statements are reasonable, they do involve certain assumptions, risks and uncertainties. Results could differ materially from those anticipated in these statements as a result of certain factors, including, among others:

For oil and gas:

·	having sufficient cash flow from operations and/or other sources to fully develop our undeveloped acreage positions;

·	volatility in oil and natural gas prices, including potential depressed natural gas prices and/or declines in oil prices, which would have a negative impact on operating cash flow and could require ceiling test write-downs on our oil and gas assets;

·	the possibility that the oil and gas industry may be subject to new adverse regulatory or legislative actions (including changes to existing tax rules and regulations and changes in environmental regulation);

·	the general risks of exploration and development activities, including the failure to find oil and natural gas in sufficient commercial quantities to provide a reasonable expectation of a return on investment;

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·	future oil and natural gas production rates, and/or the ultimate recoverability of reserves, falling below estimates;

·	the ability to replace oil and natural gas reserves as they deplete from production;

·	environmental risks;

·	availability of pipeline capacity and other means of transporting crude oil and natural gas production; and

·	competition in leasing new acreage and for drilling programs with operating companies, resulting in less favorable terms.

For the molybdenum property:

·	the ability to obtain permits required to initiate mining and processing operations, and Thompson Creek Metals Company USA’s continued participation as operator of the property; and

·	completion of a feasibility study based on a comprehensive mine plan, which indicates that the property warrants construction and operation of mine and processing facilities, taking into account projected capital expenditures and operating costs in the context of molybdenum price trends.

·	we are responsible for the operating costs of the water treatment plant until such time as Thompson Creek makes their election to own a percentage of the property at which time the costs will be split proportionately by percentage of ownership.

For real estate:

·	failure of energy-related business activities in the Gillette, Wyoming area to support sufficient demand for apartments for us to realize a return on the investment.

·	during 2011 we determined that we would finance and sell the multifamily housing project in Gillette, Wyoming. With the proceeds from the property we plan on furthering our oil and gas business. The selling price may not meet our expectations.

For geothermal activities:

the ability to acquire additional Bureau of Land Management and/or other acreage positions in targeted prospect areas, obtain required permits to explore the acreage, drill development wells to establish commercial geothermal resources, and the ability of Standard Steam Trust LLC (“SST”) to access third-party capital to reduce reliance on capital calls to its members (including U.S. Energy Corp.) for continued operations. We have notified SST that we do not intend to fund any cash calls which will result in a dilution of our ownership of SST.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in the section entitled “Risk Factors” in this Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements made above and elsewhere in this Annual Report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations, or otherwise.

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PART I

Item 1 – Business

Overview

U.S. Energy Corp. (“U.S. Energy” or “We”), a Wyoming corporation organized in 1966, acquires and develops oil and gas and other mineral properties. We are continuing to invest aggressively by participating (through passive non-operating investments) in oil and gas plays with industry partners, and, in 2011, by acting as operator for selected properties.

We are maintaining steady progress with our partner, Thompson Creek Metals Company (USA), in the long-term development of the Mt. Emmons molybdenum property in west central Colorado. A multifamily apartment project serving the residential market in Gillette, Wyoming was completed in 2008, and it is generating positive cash flow; we do not intend to make more investments in the real estate housing sector and anticipate financing or selling the multifamily apartment project.

Industry Segments/Principal Products

At December 31, 2010, we have three operating segments: Oil and gas, real estate, and minerals (including geothermal).

Office Location and Website

Principal executive offices are located at 877 North 8th West, Riverton, Wyoming 82501, telephone 307-856-9271.

Our website is www.usnrg.com. We make available on this website, through a direct link to the Securities and Exchange Commission’s website at http://www.sec.gov, free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and Forms 3, 4 and 5 for stock ownership by directors and executive officers. You may also find information related to our corporate governance, board committees and code of ethics on our website. Our website and the information contained on or connected to our website is not incorporated by reference herein and our web address is included only for textual reference to the SEC filings.

Business

Oil and Gas

At December 31, 2010:

·	Estimated proved reserves of 1,954,941 BOE (79% oil, 18% natural gas and 3% plant products), $44.7 million standardized measure and $52.1 million PV10, representing increases of 80%, 123%, and 102% over the 2009 reserves, standardized measure and PV10, respectively.

·	Gross and net leases of 89,496 and 29,370 acres. At March 1, 2011, gross and net leases covered 97,221 and 33,213 acres.

·	Seventeen gross (6.38 net) producing wells (19 and 6.71 at March 1, 2011).

·	1,230 BOE/D average for 2010 (1,051 BOE/D at March 1, 2011).

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·	Exploration and development agreements with eight industry partners and a wholly-owned Bakken/Three Forks acreage play (five partners and no acreage play in 2009). At March 1, 2011, we added another agreement (with Crimson Exploration, Inc.) for a total of nine partners.

PV10 (present value before taxes (discounted at ten percent)) is widely used in the oil and gas industry, and is followed by institutional investors and professional analysts to compare companies. However, PV10 data is not an alternative to the standardized measure of discounted future net cash flows, which is calculated under GAAP and includes the effects of income taxes. The following table reconciles PV10 to the Standardized Measure of Discounted Future Net Cash Flows, which are presented in Note G to the Company’s Consolidated Financial Statements.

	(In thousands)
	At December 31,
	2010		2009		2008
Standardized measure of discounted net cash flows	$	44,653	$	19,984	$	3,318
Future income tax expense (discounted)		7,420		5,776		1,993
PV-10	$	52,073	$	25,760	$	5,311

Activities with Operating Partners in Oil and Gas

The Company holds a geographically diverse portfolio of oil weighted prospects in varying stages of exploration and development, of which a majority of the properties are structured with eight different operating partners (nine at March 1, 2011). Prospect stages range from exploration and completion work, leasing activities (some with current partners to enlarge the land base, some for our own account), and seismic and other early stage science to identify drilling prospects (some with current partners, some for our own account).

A number of the programs were identified and structured in house. Each of the operators for the principal prospects has a substantial technical staff. We believe that these arrangements allow us to deliver value to shareholders without having to build the full staff of geologists, engineers and land personnel needed to work in diverse environments, such as deep Gulf Coast gas formations (PetroQuest), horizontal drilling in North Dakota (Brigham and Zavanna) and South Texas (Crimson Exploration) as well as conventional drilling in California’s San Joaquin Basin.

We do intend to increase our technical staff (a landman and petroleum engineer) to be in position to operate selected properties we acquire on our own such as in Colorado and Montana (see “Operated Oil and Gas Activities”). However, consistent with industry practice with smaller independent companies, we still would utilize specialized consultants with local expertise as needed.

Existing oil and gas projects with operating partners are in these areas:

Williston Basin

With Brigham Exploration Company. On August 24, 2009, we entered into a Drilling Participation Agreement (the “DPA”) with a wholly-owned subsidiary of Brigham Exploration Company. The DPA provides for U.S. Energy and Brigham to jointly explore for oil and gas in up to 19,200 gross acres in a portion of Brigham’s Rough Rider prospect in Williams and McKenzie Counties, North Dakota.

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Under our agreement with Brigham, we earned working interests, out of Brigham’s interests, in fifteen 1,280-acre spacing units in Brigham’s Rough Rider project area, which is located in Williams and McKenzie Counties, North Dakota, by participating in the drilling of one initial well on each unit of acreage. Accordingly, we have earned the rights to drill up to 30 gross wells in the Bakken formation and an additional 30 gross wells in the Three Forks formation, for a total of 60 gross wells, based on current spacing rules in North Dakota. If the spacing is ultimately increased to four wells per 1,280 acre spacing unit, the potential number of drilling locations could increase to 120 gross wells.

The leases in the units are a combination of fee and state leases. In some areas, the rights may be depth limited to the Bakken and the upper part of the Three Fork formations, due to leases obtained by Brigham from third parties, while other leases may have rights to all depths. Working interests earned vary according to Brigham’s initial working interest, after-payout provisions and the provisions governing each stage of the program. At our current projected drilling rate, we expect that it will take four to six years to drill all of the wells on these units.

Our earn-in rights were staged in three groups of units, and were earned upon paying our share of all drilling and completion, or plugging and abandonment costs (if applicable), for all the initial wells (one for each unit) in each group. The numbers of initial wells (and units in the groups) consist of: Six in the First Group; four in the Second Group; and five in the Third Group. For information on the wells drilled through the date this Annual Report was filed, see “Item 2 – Properties – Oil and Natural Gas” below. At the date this Annual Report was filed, we have drilled all 15 wells in the initial phase of the DPA and have completed 12 wells, and are planning on drilling four to six additional (infill) gross wells in 2011.

Brigham is the operator for all the units covered by the DPA, and is compensated for services pursuant to an industry standard operating agreement, except that the customary non-consent provisions have been revised as to the drilling of subsequent wells (see below).

First Group: We earned 65% of Brigham’s initial working interest in six 1,280 acre units; our working interest ranges from 61.46% to 29.58% (48.55% to 23.80% net revenue interest (“NRI”)), for an average 49.54% working interest.

When we have received production revenues (less property and production taxes) from all six of the initial wells in this First Group, equal to our costs on a pooled basis (“Pooled Payout”), our working interest will be reduced to 42.25% of Brigham’s initial working interest in the initial wells, and the NRI will decrease to a range of 31.56% to 15.47%, for an average 25.45% NRI. At December 31, 2010, we projected Pooled Payout for this First Group would occur in the second or third quarter of 2011. Subsequent to December 31, 2010, we have experienced significant workover expense related to one of the six wells, which will delay the Pooled Payout.

U.S. Energy earned 36% of Brigham’s initial working interest to all the acreage in the applicable unit. Brigham will have no back in rights on any subsequent drilling locations in these units (or in any of the units we earned in the Second and Third Groups). All working interest ownership in each initial well, and all the subsequent wells, will be subject to proportionate reduction for third party lease hold rights. At December 31, 2010, three subsequent wells (two producing, one in completion) had been drilled in the First Group.

Second Group: In 2010, we participated in the drilling and completion of the four wells in the Second Group. Brigham gave us notice that it would be taking 50% of the working interest available to it, and we elected to take the remaining 50% of the working interest available to Brigham. The four wells were producing in 2010; our working interest ranges from 48.03% to 21.02% (NRIs of 37.80% to 16.29%).

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We have earned working interest rights in all the acreage in these four units. For future wells drilled in these units, we will hold 36% of Brigham’s initial working interest (without back in rights), subject to proportionate reduction for third party lease hold rights. After Pooled Payout on the Second Group’s four wells, we will assign to Brigham 35% of our working interest in the initial wells in each spacing unit, and the NRI will decrease to a range of 24.26% to 10.61%. We anticipate Pooled Payout for the Second Group will be reached in third or fourth quarter 2012.

Third Group: On January 11, 2010, Brigham gave us notice that it would be taking 50% of the working interest available to it. In accordance with the DPA, we elected to take the remaining 50% of the working interest available to Brigham. All five wells in this group were drilled or being drilled at December 31, 2010; at December 31, 2010, one was producing, one was drilling, one was completing, and two were awaiting completion work. Working (and net revenue) interests range from 41.76% (32.96% NRI) to 20.01% (15.81% NRI).

We have earned 36% of Brigham’s initial working interest in all the acreage in the units in this Third Group (which will not be subject to back in rights), proportionately reduced for third party lease hold rights. After payout on a per initial well basis (“Unpooled Payout”), we will assign 27.7% of our working interest in each initial well to Brigham, resulting in NRIs of 23.83% to 11.49%). We expect Unpooled Payout to be reached on these initial wells in 2013 through 2014.

Non-Participation in Subsequent Wells. Under the form of operating agreement which governs operations for each of the 15 units, after the applicable initial well, we will have the right to elect not to participate in the drilling or completion in subsequent wells proposed to be drilled in a unit. If U.S. Energy or Brigham should make an election not to participate, the non-participating party will assign all its rights in the proposed well to the participating entity for no consideration. However, our working interest rights in all acreage remaining in the unit would not be affected by the assignment.

With Zavanna, LLC. In December 2010, we signed two agreements with Zavanna, LLC (a private oil and gas company based in Denver, Colorado), and other parties, and paid $10,987,000 cash, to acquire, initially (see below), a 35% working interest out of Zavanna’s working interests in oil and gas leases covering approximately 6,050 net acres in McKenzie County, North Dakota. Net revenue interests are expected to be in the range of 28% to 26.95%, proportionately reduced depending on Zavanna’s actual WI%.

The acreage is in two parcels – the Yellowstone Prospect and the SE HR Prospect. We expect this program will result in 31 gross 1,280 acre spacing units (with various working interests of up to 35%), with the potential of 124 gross Bakken and 124 gross Three Forks wells.

In December 2010, we committed to the drilling of one initial horizontal test wells into the Bakken Formation and paid an advance of $1,433,000 for drilling costs on an initial well in the Yellowstone Prospect which began drilling in January 2011 and reached total depth in February 2011. A second well spud in February 2011. A third well (which will be the initial well on the SE HR Prospect), is expected to begin drilling in second quarter 2011.

Our interests in all the acreage is subject to reduction by operation of a 30% reversionary working interest in the separate acreage packages under each agreement. On the earlier of 36 months after spudding each initial test well (the “Project Payout Period”), or reaching “Project Payout,” our 35% working interest will be reduced to 24.5% (with the NRI % also being proportionately reduced). Project Payout is that point in time when we have received proceeds from the sale of production (or from sale of all or part of the acreage to third parties) equal to 130% of: the $10,987,000 (paid on execution of the

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agreements), plus all drilling and completion costs (including dry hole costs) and surface gathering facilities, for all wells drilled on the acreage (and on any additional acreage acquired in the two Areas of Mutual Interest contemplated by the agreements), referred to as the “Project Payout Properties.”

However, if Project Payout does not occur within the 36 month Project Payout Period, the reduction due to operation of the reversionary working interest will take effect on all acreage other than the Project Payout Properties, i.e., that acreage in which wells not have commenced drilling (including all infill locations in drilling units where the Project Payout Properties are located, and the interest in all subsequent operations thereon). After expiration of the Project Payout Period, all costs and expenses related to the Project Payout Properties will continue to be included in the Project Payout calculation until Project Payout occurs.

With Crimson Exploration Inc. On February 22, 2011 USE entered into a participation agreement with Crimson Exploration Inc. (“Crimson”) to acquire a 30% working interest in an oil prospect and associated leases located in Zavala County, Texas.

Under the terms of the agreement, USE will earn a 30% working interest (22.5% net revenue interest) in approximately 4,675 gross contiguous acres (1,402.5 net mineral acres) through a combination of a cash payment and commitment well carry. All future drilling and leasing will be on a heads up basis. For competitive reasons, the financial terms of the transaction will not be disclosed at this time.

The prospect is an Eagle Ford shale oil window target in Zavala County, Texas. Crimson will operate and tentatively plans to spud the first well in the area during the second quarter of this year. The well is planned to be drilled to a total drilling depth of approximately 12,500 feet (~6,000 ft. vertical, ~6,500 ft. horizontal), and to be completed with 14 fracture stimulation stages.

Texas and Louisiana

With PetroQuest Energy, Inc. Five wells have been drilled in coastal Louisiana with PetroQuest (NYSE: PQ). Three dry holes were plugged and abandoned and two wells are producing (both wells produce natural gas and oil); our working interests in the producers is (a) 14% (10.46% NRI before payout (9.76% NRI after payout), and (b) 53.33% (36% NRI). We expect to drill more wells with PetroQuest in 2011 but none have been signed up as of the date this Annual Report is filed. At payout on one of the producing wells (plus 6% annual interest), we will assign 15% of our working interest to a third-party consultant, and an additional 5% of our working interest at 200% of payout. Payout was reached for this well in January 2011.

With Yuma Exploration and Production Company, Inc. We have a working interest in a seismic, lease acquisition and drilling program with Yuma (a private company) that covers approximately 88,320 acres in South Louisiana. Seismic data collection has been completed and is being evaluated. This lease/option program continues through April 27, 2012; in 2010, one well was drilled and watered out and one was in completion at December 31, 2010 (working interests (NRI) in these wells is (a) 4.79% (3.62% NRI, decreasing to 3.17% NRI after payout), and (b) 4.79% (3.78% NRI, decreasing to 3.31% after payout – see below). We expect that Yuma will recommend drilling at least six more prospects in 2011. Participants will have the opportunity to opt in or out of any prospect leasing program, and the initial well in each prospect. Each prospect will have a separate operating agreement designating Yuma as operator. It is expected that the program will yield multiple oil and natural gas prospects, with exploration activities continuing for a number of years.

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The Company holds a 4.79% working interest, Yuma owns an approximate 48% working interest, and the balance (approximately 47.21%) is held by third parties. At payout we will assign to a third party consultant 12.5% of our working interest in each producing well. For their working interests, the participants (other than Yuma) have paid 80% of the initial seismic, overhead and some land costs ($1.2 million by USE), and Yuma is paying 20%. All land and exploration costs going forward are to be paid according to the working interest percentages.

With Houston Energy L.P. In 2009 and 2010, we participated with Houston Energy in drilling two producing wells and three dry holes; in the producers (drilled in 2009), we own a working interest of (a) 8.50% (6.23% NRI after payout, reducing to 4.91% NRI after payout for a consultant’s back in interest); and (b) 25% (17.63% NRI after payout, reducing to 15.42% NRI after payout for a consultant’s back in interest).

We entered into two new agreements with Houston Energy in 2010:

NE Delta Farms Prospect Participation Agreement (Lafourche and Jefferson Parishes, Louisiana)

By paying $60,000 (our share of Houston Energy’s lease acquisition costs), we acquired a working interest before the casing point decision (“CPD”) is made (to complete or abandon a well), in all the prospects (approximately 496 gross acres (123 net mineral acres), we acquired a 33% working interest before the CPD on each prospect (24.75% after CPD (18.19% NRI). An affiliate of Houston Energy, and the 3D seismic company involved in the prospect, will receive a total 4.5% ORRI on the leases in this program.

Subsequent to year end, this well was determined to be non-productive and will be plugged and abandoned.

Gaines County, Texas Participation Agreement (Five Prospects – GTY Permian Basin)

We paid our share ($310,000) of Houston Energy’s lease acquisition and related costs, to acquire a 13.33% working interest (10.00% after CPD), representing an estimated 7.9% NRI. These prospects are burdened by a 3.0% ORRI in favor of an affiliate of Houston Energy. Two non productive wells were drilled on these prospects in 2010 ($529,000 net to USE). Up to 3 additional wells could be drilled under this agreement in 2011.

With Southern Resources Company This agreement covers a 13.5% working interest (9.86% NRI) in 1,282 gross (173 net) acres in Hardin County, Texas (approximately midway between Houston and Beaumont). If we elect to proceed by participating in the initial test well (and paying our $135,000 of seismic, land acquisition and legal costs), we will earn our working interest in all the acreage, and the seller will have an 18.75% carried working interest (to the CPD) in the initial test well, and a 12.5% carried working interest in the second test well (to the CPD). Subsequent wells will be paid proportionate to the all parties’ working interests. Mueller Exploration, Inc. will operate all wells. If the initial test well is not spudded by June 1, 2011, the agreement will terminate.

With WR Production Company. In March 2010, we signed an agreement with WR Production, LLC to purchase a 10% working interest (7.4% average NRI) in 898 gross (90 net) acres. We have paid $188,000 for prospect and leasehold costs to the date of the agreement. Initial well drilling costs will include 3.33% of WP’s working interest share.

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California

With Cirque Resources LP (Kern County, California) Under an October 2010 agreement with Cirque Resources LP (“Cirque”) (a private exploration and development company based in Denver, Colorado), we paid $2,498,000 to Cirque to purchase a 40% working interest (32% NRI) in Cirque’s leases on 6,120 net mineral acres (2,448 acres net to our interest), in the San Joaquin Basin. Of the amount paid, $1,620,000 is an advance against our 40% working interest for the initial well, including 33% of Cirque’s 60% working interest share for the well. Cirque’s lease assignments are held in escrow, until the end of the well’s drilling phase; if we have paid all the drilling costs (ours and Cirque’s carry), the assignments will be recorded and released to us.

Completion and all other costs and expenses on the initial well and for all subsequent wells and any midstream projects (gathering, compressors, and processing/treatment facilities) will be paid by participants in proportion to their working interests. We are estimating our share of total completion costs for the initial well to be in the range of $640,000. Cirque is the operator for all operations on the prospect.

The primary target in the Moose Prospect is the Miocene; the initial well will be drilled to approximately 13,000 feet to test the Stevens Sands in a stratigraphic trap on the flank of the Elk Hills anticline. Current spacing rules and current interpretation of geological data indicate that up to 40 additional locations could be drilled. Additional seismic work including re-analysis of existing 2D and modeling into 3D may be undertaken to further scientific evaluations.

Operated Oil and Gas Activities

Montana Acreage Play

During 2010, U.S. Energy acquired 100% working interest in approximately 16,560 gross mineral acres (11,627 net mineral acres) of undeveloped leasehold interests, fee mineral interest and operating rights in oil and gas leases in Northeast Montana for approximately $809,000. In addition to landowner royalties which range from 12.5% to 15%, some of the leases are burdened with Overriding Royalty Interests (“ORRI”) in favor of the seller as follows:

2% ORRI on leases that have a total royalty interest (“RI”) of 12.5 or less; 1.0% ORRI on leases that have a total RI greater than 12.5% but less than or equal to 15%; 1% ORRI on leases that have a RI greater than 15% but less than or equal to 16.67 %; 0.5% ORRI on leases that have a RI greater than 16.67% but less than or equal to 19%.

We can buy back the ORRIs at any time on a sliding scale of from $60 per net mineral acre where the total royalty interest (exclusive of the ORRIs) is 12.5% or less, down to $15 where the total royalty interest is more than 16.67% but less than or equal to 19%.

Leasing and drilling activities by other companies looking to find Bakken Shale and Three Forks production in the Northeast part of Montana increased significantly in 2010. We are holding our acreage for future exploration and development, and may enlist the participation of industry partners at some point in the future. USE is the operator. No arrangements with other companies have been negotiated to date, and no wells have been drilled on our acreage.

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Apache and Buffalo Creek Prospects (Southeast Colorado)

On January 26, 2011 we paid $87,000 to buy an 80% working interest in leases covering 2,994 net mineral acres in southeast Colorado, for their joint development (U.S. Energy as operator) with the sellers, who retained 20% of the working interest (and, only as to the acreage in the Buffalo Creek acreage, the positive difference between an 80% NRI and landowners’ royalties). We can buy back these ORRIs for $50,000 if the initial production on the initial well is 100 or less barrels of oil per day, and $100,000 if initial production is more than 100 barrels per day.

In addition, we will pay all the drilling costs of the initial well, to the casing point; if the sellers do not elect to participate in completion, the sellers will forfeit to USE their 20% working interest in the 160 acres associated with the well. There will be only one “initial well” to which this provision applies.

Additional leases may be acquired in the area; if acquired from the sellers, the price will be at their cost, without ORRIs or carried working interest. USE is the operator.

Going Forward

In 2011 and beyond, U.S. Energy intends to seek additional opportunities in the oil and natural gas sector, including further acquisition of assets, participation with current and new industry partners in their exploration and development projects, acquisition of operating companies, and the purchase and exploration of new acreage positions.

Credit Facility

On July 30, 2010, we established a credit facility to increase access to capital. This arrangement is available only for our oil and gas segment, and provides us with the flexibility of investing and funding drilling/completion work without having to sell assets. We expect significant borrowings to be serviced with cash flow, and/or equity financing.

The Senior Secured Revolving Credit Facility (the “Facility”) allows us to borrow up to $75 million from a syndicate of banks, financial institutions and other entities, including BNP Paribas (“BNPP,” and, together with other members of the syndicate, the “Lenders”). BNPP also is the administrative agent for the Facility, which is governed by the following documents: Credit Agreement; Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement (the “Mortgage”); and Guaranty and Pledge Agreement (the “Guaranty”), which are referred to below together as the “Facility Documents.” The following summarizes the principal provisions of the Facility as set forth in the Facility Documents, which are filed as exhibits to this Annual Report.

We formed a wholly-owned subsidiary Energy One LLC (“Energy One”), which will be the borrower under the Facility. We assigned to Energy One all of our right, title and interest in and to current and acquired-in-the-future oil and gas properties and equipment related thereto, rights under various operating agreements, proceeds from sale of production and from sale or other disposition (including without limitation farm-ins and farm-outs). We also have unconditionally and irrevocably guaranteed Energy One’s performance of its obligations under the Credit Agreement, including without limitation Energy One’s payment of all borrowings and related fees thereunder.

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From time to time until expiration of the Facility (July 30, 2014), if Energy One is in compliance with the Facility Documents, Energy One may borrow, pay, and re-borrow from the Lenders, up to an amount equal to the Borrowing Base (initially established at $12 million, currently $18.5 million). Energy One borrowed $3.0 million under this Credit Facility on February 18, 2011. Proceeds from the borrowing were used to purchase an interest in Crimson Exploration’s Eagle Ford shale oil prospect in Zavala County, Texas.

The Borrowing Base will be determined semi-annually (more often at the request of BNPP or Energy One), with updated reserve reports prepared by the Company’s independent consulting engineers. Any proposed increase in the Borrowing Base will require approval by all Lenders, and any proposed Borrowing Base decrease will require approval by Lenders holding not less than two-thirds of outstanding loans and loan commitments.

Interest will be payable quarterly at the greater of the Prime Rate, the Federal Funds Effective Rate (plus 0.5%), and the adjusted LIBO for the three prior months (plus 1%), plus, in any event, an additional 1.25% to 3.25%, depending on the amount of the loan relative to the Borrowing Base. Interest rates on outstanding loans are adjustable each day by BNPP as administrative agent. Energy One may prepay principal at any time without premium or penalty, but all outstanding principal will be due on July 30, 2014. If there is a decrease in the Borrowing Base, outstanding principal will be due over the five months following the determination.

Energy One is required to comply with customary affirmative covenants, and with negative covenants. The principal negative covenants (measured at various times as provided in the Credit Agreement) are not permitting (i) Interest Coverage Ratio (Interest Expense to EBITDAX) to be less than 3.0 to 1; (ii) Total Debt to EBITDAX to be greater than 3.5 to 1; and (iii) Current Ratio (current assets plus unused lender commitments under the Borrowing Base) to be a minimum of 1.0 to 1.0. EBITDAX is defined in the Credit Agreement as Consolidated Net Income, plus non-cash charges.

Madison Williams and Company

Since March 2009, Madison Williams and Company (“MWC”), has helped us identify and structure three of the principal drilling programs (Brigham, Zavanna and Crimson), through its relationships with these operators. MWC also assisted in setting up the BNP Paribas credit facility. MWC is acting as our exclusive financial advisor in connection with the purchase or acquisition of oil and gas assets, including oil and gas companies, oil and gas working interests, and joint ventures or similar types of oil and gas ventures from entities that we have mutually agreed to approach regarding possible transactions. The firm also provides financial advisory and investment banking services.

In 2010 and 2009, we paid a total of $1,316,400 to MWC (and its predecessor, the principal capital markets business of SMH Capital, see below): $75,000 general advisory fees; $92,500 retainer fees; expense reimbursements of $70,600; and transaction fees of $1,078,300 related to negotiating and setting up the Credit Facility with BNP Paribas, and the Brigham and Zavanna deals. We will also be paying MWC a fee for the Crimson transaction which was closed in 2011.

The foregoing payments do not include MWC’s services as lead underwriter and bookrunner for USE’s $26.25 million public equity financing in fourth quarter 2009, which was governed by a separate agreement as well as an underwriting agreement for the financing. We anticipate that MWC will have the same role in future public financings.

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MWC is a private management-owned investment banking firm; until late 2009, it was the principal capital markets business of SMH Capital, when it was spun out of Sanders Morris Harris Group. MWC has extensive experience in providing a broad range of services to the energy industry.

Activities other than Oil and Gas

Molybdenum

On August 19, 2008, U.S. Energy and Thompson Creek Metals Company USA (“TCM”), a Colorado corporation headquartered in Englewood, Colorado, entered into an Exploration, Development and Mine Operating Agreement for our Mount Emmons molybdenum property. TCM assigned the agreement to Mt. Emmons Moly Company, a Colorado corporation and wholly owned subsidiary of TCM effective September 11, 2008. Under the terms of the agreement TCM may acquire up to a 75% interest for $400 million (option payments of $6.5 million and project expenditures of $393.5 million).

The Agreement covers two distinct periods of time: The Option Period, during which TCM may exercise an option to acquire up to a 50% interest in Mount Emmons; and the Joint Venture Period, during which TCM will form a joint venture with us, and also have an option to acquire up to an additional 25% interest.

The Option Period:

Through December 31, 2010, TCM has paid us $500,000 (at the September 2008 closing), (not refundable), and $3 million for the $1.0 million option payments for 2009, 2010 and 2011. TCM has the continuing option to make three more $1 million annual payments.

The option is exercisable in two stages:

First Stage - For 15%. At TCM’s election within 36 months of incurring a minimum of $15,000,000 in expenditures on or related to Mount Emmons, TCM may acquire an undivided working interest of 15% in Mount Emmons. TCM also must make the option payments, but each such payment will be credited against the required annual expenditure amount. Following is a table of the options and expenditures due from TCM through June 2011:


Option Payments and Expenditure Amounts, and Deadlines
$	500,000	Option Payment	At Closing*
$	2,000,000	Expenditures	December 31, 2008*
$	1,000,000	Option Payment	January 1, 2009**
$	4,000,000	Expenditures	December 31, 2009**
$	1,000,000	Option Payment	January 1, 2010**
$	4,000,000	Expenditures	December 31, 2010***
$	1,000,000	Option Payment	January 1, 2011***
$	1,500,000	Expenditures	June 30, 2011
$	15,000,000

*	Paid in 2008
**	Paid in 2009
***	Paid in 2010

Costs to operate the water treatment plant at the property are being paid solely by us until TCM elects to exercise its option to own an interest in the property.

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Second Stage - For an Additional 35%. If by July 31, 2018, TCM has incurred a total of at least $43,500,000 of expenditures (including amounts during the first stage) and paid us the total $6,500,000 of option payments (for a total of $50,000,000), TCM may elect to acquire an additional 35% (for a total of 50% after it exercised the first stage option for 15%). None of the interests acquired by TCM will be subject to any overriding royalties to us.

Upon failure by TCM to incur the required amount of expenditures by a deadline, or make an Option Payment to U.S. Energy, subject to the terms of the Agreement, the Agreement may be terminated without further obligation to us from TCM. TCM may terminate the Agreement at any time, but if earned and elected to accept, TCM will retain the interest earned and be responsible for that share of all costs and expenses related to Mount Emmons.

The Joint Venture Period; Joint Venture Terms:

Within six months of TCM’s election to acquire the 50% interest, TCM, in its sole discretion, shall elect to form a Joint Venture and either: (i) participate on a 50%-50% basis with us, with each party to bear their own share of expenditures from formation date; or (ii) acquire up to an additional 25% interest in the project by paying 100% of all expenditures equal to $350 million (for a total of $400 million, including the $50 million to earn the 50% interest in the Second Stage of the Option Period), at which point the participation would be 75% TCM and 25% U.S. Energy. Provided however, if TCM makes expenditures of at least $70 million of the $350 million in expenditures and TCM decides not to fund the additional $280 million in expenditures, TCM will have earned an additional 2.5% (for a total of 52.5%). Thereafter, TCM will earn an incremental added percentage interest for each dollar it spends toward the total $350 million amount.

At any time before incurring the entire $350 million, TCM in its sole discretion, may determine to cease funding 100% of expenditures, in which event U.S. Energy and TCM then would share expenditures in accordance with their participation interests at that date. With certain exceptions, either party’s interest is subject to dilution in the event of non-participation in funding the Joint Venture’s budgets.

Management of the Property

TCM is Project Manager of the Mount Emmons Project. A four person Management Committee governs the projects’ operations, with two representatives each from U.S. Energy and TCM. TCM will have the deciding vote in the event of a committee deadlock.

If and when Mount Emmons goes into production, TCM will purchase our share of the molybdic oxide produced at an average price as published in Platt’s Metals Weekly price less a discount with a cap and a floor. The discount band will be adjusted every five years based upon the United States’ gross domestic product.

Renewable Energy — Geothermal

At December 31, 2010 we owned a minority ownership interest, 22.8%, in a geothermal partnership, Standard Steam Trust, LLC (“SST”).

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In April 2010, SST sold two prospects to a global geothermal industry company, for $8.72 million cash. If the buyer constructs a power plant with more than 30 megawatts of generating capacity, additional cash will be paid to SST equal to $350,000 for each additional megawatt. Our investment in SST does not obligate us to fund any future cash calls. If we elect not to fund cash calls, we will suffer dilution. We have notified that we do not intend to fund any cash calls to the partners which will result in a dilution of our ownership of SST.

Real Estate

In 2008, we completed construction of a nine building, 216-unit multifamily apartment complex in Gillette, Wyoming at a total all-in cost of $24.5 million. The occupancy rate was 89% at December 31, 2010. The Company had an appraisal completed as of December 31, 2010 which valued the property at $21.0 million. An impairment of $1.5 million was therefore recorded at December 31, 2010 on the property. Although the property produces positive cash flow from its operations, the return from oil and gas investments is expected to yield a higher return. The Company therefore plans on selling this property in the future to continue growing its oil and gas business.

Item 1A - Risk Factors

The following risk factors should be carefully considered in evaluating the information in this Annual Report.

Risks Involving Our Business

Global Financial Stress and Credit Crisis.

The continuing Great Recession and concomitant credit crisis and related turmoil in the global financial system may have a material impact on our ability to finance the purchase and/or exploitation of oil and gas properties. The availability of credit to our industry partners may also affect their ability to generate new exploration and development prospects, to meet their obligations to us, and/or on their liquidity, which could result in operational delays or even their failure to make required payments. Additionally, volatility in oil prices, particularly a significant and sustained drop in current oil prices could have a negative impact on our financial position, results of operations, and cash flows.

Risks Related to Climate Change.

While the scope and timing of climate change is not determinate, the adoption of laws and regulations, and international accords to which the United States is a party, could affect our oil and natural gas business segment. The emergence of trends such as a worldwide increase in hybrid power motor vehicle sales, and/or decreased personal motor vehicle use by individuals, in response to perceived negative impacts on the climate from “greenhouse emissions,” could result in lower world-wide consumption of, and prices for, crude oil. Additionally, as part of state-level efforts to reduce these emissions, operating restrictions on emissions by drilling rigs and completion equipment could be enacted, leading to an increase in drilling and completion costs.

In January 2011, President Obama stated that his administration would request legislation reducing if not eliminating various “tax breaks” now available to the oil and gas exploration and production industry. The 2012 budget published in February 2011 proposes many of the same items for legislation that were in the 2011 budget, including proposals to terminate oil and gas company tax preferences, including repeals of expensing intangible drilling costs, passive loss limitations for working interests in oil and natural gas properties, percentage depletion for oil and natural gas wells, and increasing the amortization period for

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geological and geophysical expenses to seven years. If such proposals were enacted substantially as proposed, our income from oil and natural gas investments would be decreased and additional capital likely would become more expensive and more difficult to obtain. Additional adverse impacts could flow from enactment of Federal legislation aimed directly at controlling and reducing emissions of greenhouse emissions. See also the next risk factor.

The adoption of climate change legislation could result in increased operating costs and reduced demand for oil and natural gas.

In June 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. The purpose of ACESA was to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate began work on its own legislation for controlling and reducing emissions of GHGs in the United States, but the legislation stalled in 2010.

The U.S. Environmental Protection Agency is also separately undertaking a rulemaking process to determine whether GHGs will be designated as “pollutants” under the existing Federal Clean Air Act.

Though it is not predicted whether such legislation will be reintroduced and made law, or EPA rule making will be implemented, legislation and/or rule making along the lines previously contemplated would likely require us to incur increased operating costs, and could have an adverse effect on the oil and gas industry.

We will require funding in addition to working capital at December 31, 2010.

We were able to maintain adequate working capital in 2010 primarily through a December 2009 public offering of 5 million shares for $24.3 million of net proceeds. Working capital at December 31, 2010 was $11.1 million, an amount sufficient to continue substantial exploration and development work in oil and gas, but not enough to take full advantage of the opportunities we now have or be in position for new opportunities. We could spend up to $46 million in 2011 for work on existing programs.

Additionally, all of our partner agreements have customary industry non-consent provisions: If a well is proposed to be drilled or completed but a working interest owner doesn’t participate, resulting revenues (which otherwise would go to the non-participant) flow to the participants until they receive from 200% to 300% of the capital they put up to cover the non-participant’s share.

As a result, in order to be in position to avoid non-consent penalties, and make opportunistic investments in new assets, we will be evaluating various options to obtain additional capital, including loans through the Credit Facility, sale of equity and sale of the apartment complex in Gillette, Wyoming.

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Beyond 2011, we may have capital needs from time to time in excess of funds on hand. The minerals business presents the opportunity for significant returns on investment, but achievement of such returns is subject to high risk. As examples:

Initial results from one or more of the oil and gas programs could be marginal but warrant investing in more wells. Dry holes, over budget exploration costs, low commodity prices, or any combination of these factors, could result in production revenues below projections, thus adversely impacting cash expected to be available for continued work in a program, its ultimate returns falling below projections, and a reduction in cash for investment in other programs.

We are paying the annual costs (approximately $1.8 million) to operate and maintain the water treatment plant at the Mount Emmons Project until such time as Thompson Creek Metals elects to acquire an interest. Thereafter, we would be responsible for paying our proportionate share of plant costs. Of greater potential significance, should Thompson Creek Metals elect to participate in the Mount Emmons Project up to the 75% level and expends $400 million on the property, thereafter we would be responsible for our 25% share of all costs, which could be very substantial.

These types of events could require a reassessment of priorities and therefore potential re-allocations of existing capital and mandate obtaining new capital.

Competition may limit our opportunities in the oil and gas business.

The oil and natural gas business is very competitive. We compete with many public and private exploration and development companies in finding investment opportunities. We also compete with oil and gas operators in acquiring acreage positions. Our principal competitors are small to mid-size companies with in-house petroleum exploration and drilling expertise. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. They may be willing and able to pay more for oil and natural gas properties than our financial resources permit, and may be able to define, evaluate, bid for and purchase a greater number of properties. In addition, there is substantial competition in the oil and natural gas industry for investment capital, and we may not be able to compete successfully in raising additional capital if needed.

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

Operations in the Williston Basin and the Eagle Ford Shale 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.

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The results of the drilling programs in the Williston Basin and the Eagle Ford Shale are subject to more uncertainties than drilling in more established formations in other areas.

Williston Basin

Although numerous wells have been drilled and completed 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, industry’s drilling and production history in the formation generally remains somewhat limited. The ultimate success of these drilling and completion strategies and techniques 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. However, actual decline rates may be significantly different than expected. Due to the limited horizontal 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 have participated in may not be replicated in additional wells, even in the same drilling unit.

Through the date this Annual Report was filed, one of the wells we have drilled with Brigham was completed in the Three Forks Formation, and the rest have been completed in the Bakken Formation. Brigham (and other operators) have reported successful completion of Three Forks wells in other parts of the Williston Basin, The Three Forks, underlying the Bakken, is an unconventional carbonate formation (sand and porous rock) which is prospective for oil and gas. It is believed to be separate from the Bakken. However, the Three Forks has been explored to a lesser extent than the Bakken in many areas of the Basin, and its characteristics are not as well defined. Accordingly, we may encounter more uncertainty in drilling Three Forks wells with Brigham, compared with drilling Bakken wells.

The foregoing considerations also apply to our opportunities to drill the same formations with Zavanna.

Eagle Ford Shale

The Eagle Ford Shale, covering 14 counties in South Texas, is now a very active area for exploration and development, involving large companies (such as Shell, ConocoPhillips, and Chesapeake Energy) as well as a host of mid-size to small independents. However, like the Bakken, since the data base is still evolving, the Eagle Ford characteristics are not well defined and thus can present more uncertainty than more mature drilling areas.

Operating in less developed regions of 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, and some of the initial gas production is lost to flaring.

Access to adequate gathering systems or pipeline takeaway capacity is limited in the Williston Basin. 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. Additionally, access to equipment and service providers may not be available on a timely or cost effective basis, which could delay a drilling program.

As of the date this Annual Report was filed, all of the wells we have drilled with Brigham have produced oil and natural gas (generally an initial ratio of about 85% oil and 15% gas). Oil sales commence immediately after completion work is finished, but natural gas is flared (burned off) until the well can be hooked up to a transmission line. Installation of a gathering system can take from 90 to 120

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days, or longer, depending on well location, weather conditions, and availability of service providers. As of the date this Annual Report was filed, all but 2 of our wells with Brigham are selling gas.

We may encounter the same operating issues in the drilling program with Zavanna.

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

We may not be able to participate in all or even a substantial portion of the many locations we have earned through the Drilling Participation Agreement with Brigham, and available to us through the Zavanna program, or the drilling locations available in the Crimson Participation Agreement. The extent of 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 costs, adjusted for contract provisions, any financial derivatives that hedge our oil and gas revenue and asset retirement obligations, and unescalated oil and gas prices during the period, (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 tax assets directly attributable to 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.

Effective for years ending on and after December 31, 2009, the SEC amended the disclosure rules to require such revenue estimates to be based on the average price received during the 12-month period before the ending date of the period covered by the report, determined as an unweighted average of the

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first-day-of-the-month price for each month within such period. Accordingly, our estimated future net revenues as of December 31, 2010 and 2009 are based on the monthly average price received during the full year period. For 2008, in accordance with SEC disclosure requirements previously in effect, estimated future net revenues (discounted at 10% per annum) from proved reserves were calculated based upon prices for oil and natural gas at December 31, 2008.

Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at December 31, 2010 and 2009, which were not included in the amortized cost pool, were $21.6 million and $5.4 million, respectively. These costs consist of wells in progress, costs for seismic analysis of potential drilling locations, as well as land costs, all related to unproved properties.

We perform a quarterly and annual ceiling test for each of our oil and gas cost centers (at December 31, 2010 and 2009, there was one such cost center (the United States)). The ceiling test incorporates assumptions regarding pricing and discount rates over which we have no influence in the determination of present value. In arriving at the ceiling test for the year ended December 31, 2010, we used $79.43 per barrel for oil and $4.376 per MMbtu for natural gas to compute the future cash flows of each of the producing properties at that date. The discount factor used was 10%.

Capitalized costs for oil and gas properties did not exceed the ceiling test limit in 2010. During 2009, we recorded a non-cash write down of $1.5 million. We may be required to recognize additional pre-tax non-cash impairment charges (write-downs) in future reporting periods depending on the results of oil and gas operations and/or market prices for oil, and to a lesser extent natural gas.

The Williston Basin oil price differential could have adverse impacts on our revenues.

Generally, crude oil produced from the Bakken formation in North Dakota is high quality (36 to 44 degrees API, which is comparable to West Texas Intermediate Crude). However, 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.

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 of this reverse leverage effect, 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. Such a price downturn also could reduce cash flow from the Williston Basin properties, and adversely impact our ability to participate fully in drilling with Brigham and Zavanna.

Our business may be impacted by adverse commodity prices.

Since June, 2009, oil prices have ranged from a ten year high with a spot price of $133.88 per barrel, to $41.12 per barrel at December 31, 2008, to $74.47 at the end of 2009, to $91.38 at December 31, 2010. Global markets, in reaction to the Great Recession, and perceived upticks or downticks in future global supply, have caused these large fluctuations. The first quarter 2011 political changes in the Mideast may continue to propel oil prices to or beyond the highs experienced in late 2008, but drop if the “fear premium” fades. This could add to the risks associated with our hedging program (see the risk factor “The use of hedging arrangements in oil and gas production could result in financial losses or reduce income” below).

Natural gas prices are historically volatile, and reached a ten year high during July 2008 on the City Gate at $12.48 per thousand cubic feet of natural gas, then down to $6.24 per Mcf at December 31, 2009, and further down to $4.40 at December 30, 2010. Molybdenum prices have declined from a ten year high

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of $38.00 per pound in June 2005 to a ten year low average price of $8.03 per pound in April 2009. The average price at December 31, 2010 was $16.60 per pound, compared to $11.50 per pound at year end 2009. Price stabilization or improvement in 2011 will be dependent on continued strong demand, but demand could weaken if industrial consumption sags due to economic constraints in key markets (particularly China and Southeast Asia). Significant oil price declines from December 31, 2010 would decrease anticipated revenues and could impair the carrying value of our producing properties.

We do not have independent reports on the value of some of the mineral properties.

We have not yet completed a feasibility study on the Mount Emmons Project. A feasibility study would establish the potential economic viability of the molybdenum property based on a reassessment of historical and additional drilling and sampling data, the design and costs to build and operate a mine and mill, the cost of capital, and other factors. A feasibility study conducted by professional consulting and engineering firms will determine if the deposits contain proved reserves (i.e., amounts of minerals in sufficient grades that can be extracted profitably under current commodity pricing assumptions and estimated development and operating costs).

Geothermal renewable reserve reports estimate the energy potential of geothermal properties in terms of capacity to generate electricity with plants to be built on the properties in the future. Currently we have no reserve reports for our geothermal properties.

The timing and cost to obtain reports for the Mt. Emmons molybdenum property or the geothermal properties cannot be predicted. However, when such reports are obtained, they may not support our internal valuations of the properties, and additionally may not be sufficient to maintain business relationships with current industry partners, or attract new partners or investment capital.

The development of oil and gas properties involves substantial risks that may result in a total loss of investment.

The business of exploring for and developing natural gas and oil properties involves a high degree of business and financial risks, and thus a significant risk of loss of initial investment even a combination of experience, knowledge and careful evaluation may not be able to overcome. The cost of drilling, completing and operating wells is often uncertain. Factors which can delay or prevent drilling or production, or otherwise impact expected results include but are not limited to:

·	unexpected drilling conditions;

·	permitting with State and Federal agencies;

·	easements from land owners;

·	adverse weather;

·	high pressure or irregularities in geologic formations;

·	equipment failures;

·	title problems;

·	fires, explosions, blowouts, cratering, pollution and other environmental risks or accidents;

·	changes in government regulations;

·	reductions in commodity prices;

·	pipeline ruptures; and

·	unavailability or high cost of equipment and field services and labor.

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A productive well may become uneconomic in the event that unusual quantities of water or other non-commercial substances are encountered in the well bore, which impair or prevent production. We may participate in wells that are unproductive or, though productive, won’t produce in economic quantities.

In addition, initial 24-hour or other limited-duration production rates announced regarding our oil and gas properties are not indicative of future production rates. Such stated rates on our wells should not be used as an indication of future production rates.

We do not currently operate most of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of these non-operated assets.

Other than the Montana acreage in Daniels County, and the acreage in southeastern Colorado (for which we are the operator), we do not operate or expect to be the operator for any of the prospects we hold with industry partners.

Allowing others to operate limits our ability to exercise influence over the operations of the drilling programs. In the usual case in the oil and gas industry, new work is proposed by the operator and often is approved by most of the non-operating parties. If the work is approved by the holders of a majority of the working interest, but we disagreed with the proposal and did not participate, we would forfeit our share of revenues from the well until the participants receive 200% to 300% of their investment and in some cases, we would lose all interest in the well. This kind of situation would be avoided only if a majority of the working interest owners agreed with us and the proposal did not proceed.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves.

Oil and gas reserve reports are prepared by independent consultants to estimate the quantities of hydrocarbons that can be economically recovered from proved producing and proved undeveloped properties, utilizing current commodity prices and taking into account capital and other expenditures. These reports also estimate the future net present value of the reserves, and are used for internal planning purposes and for testing the carrying value of the properties on our balance sheet.

The reserve data included in this Annual Report represent estimates only. Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as future commodity prices, production costs, severance and excise taxes, availability of capital, estimates of required capital expenditures and workover and remedial costs, and the assumed effect of governmental regulation. The assumptions underlying our estimates of our proved reserves could prove to be inaccurate, and any significant inaccuracy could materially affect, among other things, future estimates of the reserves, the economically recoverable quantities of oil and natural gas attributable to the properties, the classifications of reserves based on risk of recovery, and estimates of our future net cash flows.

At December 31, 2010, 70% of our estimated proved reserves were producing, 19% were proved developed non-producing and 11% were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is almost always based on analogy to existing wells, in contrast to the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations.

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Revenues from estimated proved developed non-producing reserves will not be realized until sometime in the future, if at all.

You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing and success of the production and the expenses related to the development of oil and natural gas properties, each of which is subject to numerous risks and uncertainties, will affect the timing and amount of actual future net cash flows from our proved reserves and their present value. In addition, our PV10 estimates are based on costs as of the date of the estimates, and average prices in 2010. Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate.

Further, the effect of derivative instruments is not reflected in these assumed prices; we have three such instruments in place at December 31, 2010 but did not have any such instruments in place at December 31, 2009. Also, the use of a 10% discount factor to calculate PV10 may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

The use of hedging arrangements in oil and gas production could result in financial losses or reduce income.

We use derivative instruments, typically fixed-rate swaps and costless collars to manage price risk underlying our oil and gas production. The fair value of our derivative instrument will be marked to market at the end of each quarter and the resulting unrealized gains or losses due to changes in the fair value of our derivative instrument will be recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

·	production is less than the volume covered by the derivative instruments;

·	the counter-party to the derivative instrument defaults on its contract obligations;

·	there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

·	the steps we take to monitor our derivative financial instruments do not detect and prevent transactions that are inconsistent with the Company's risk management strategies.

In addition, depending on the type of derivative arrangements we enter, the agreements could limit the benefit we would receive from increases in oil prices. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil prices.

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We may incur losses as a result of title deficiencies in oil and gas leases.

Typically, operators obtain a preliminary title opinion prior to drilling. To date, our operators have provided preliminary title opinions prior to drilling. In addition, we rely on the operators to provide us with ownership of the interest we pay for. However, from time to time, our operators may not retain attorneys to examine title, even on a preliminary basis, before starting drilling operations. If curative title work is recommended to provide marketability of title (and assurance of payment from production), but is not successfully completed, a loss may be incurred from drilling even a productive well because the operator (and therefore USE) would not own the interest.

Insurance may be insufficient to cover future liabilities.

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

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

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

Oil and gas, mineral and geothermal operations are subject to environmental regulations that can materially adversely affect the timing and cost of operations.

Oil and gas exploration and production are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase costs and may prevent or delay the commencement or continuance of operations. Specifically, the industry generally is subject to regulations regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, state laws require wells and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. Such laws and regulations have been frequently changed in the past, and we are unable to predict the ultimate cost of compliance as a result of future changes. The adoption or enforcement of stricter regulations, if enacted, could have a significant impact on our operating costs.

Our business activities in geothermal and mining are regulated by government agencies. Permits are required to explore for minerals, operate mines and build and operate processing plants. The regulations under which permits are issued change from time to time to reflect changes in public policy or scientific understanding of issues. If the economics of a project cannot withstand the cost of complying with changed regulations, we might decide not to move forward with the project.

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We must comply with numerous environmental regulations on a continuous basis, to comply with United States environmental laws, including the National Environmental Policy Act (“NEPA”), Clean Air Act, the Clean Water Act, and the Resource Conservation and Recovery Act (“RCRA”). Other laws impose reclamation obligations on abandoned mining properties, in addition to or in conjunction with federal statutes. Environmental regulatory programs create potential liability for operators, and may result in requirements to perform environmental investigations or corrective actions under federal and state laws and federal and state Superfund requirements.

Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Williston Basin and the Gulf Coast are adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months which could materially increase our operating and capital costs. Gulf Coast operations are subject to the risk of hurricanes.

Our geothermal assets may not be developed.

To complete our geothermal project business plan through acquisition of land positions in numerous prospects and establishing the power potential through drilling will require substantial capital. SST will require additional capital to develop its geothermal prospects. If sufficient funding cannot be obtained through cash calls to the partners in SST, sale of properties and or debt or equity financing, the properties may never be developed with could impact the value of our investment. We have advised SST that we do not intend to fund any future cash calls. At December 31, 2010 we had a 22.8% ownership in SST.

Risks associated with development of the Mount Emmons Project.

The Mount Emmons molybdenum property is located on fee property within the boundary of U.S. Forest Service (“USFS”) land. Although mining of the mineral resource will occur on the fee property, associated ancillary activities will occur on USFS land. USE and Thompson Creek Metals submitted a baseline Plan of Operations to the USFS in 2010. The 2010 Plan of Operations is for baseline data collection to prepare the full mine Plan of Operation. Under the procedures mandated by the National Environmental Protection Act (“NEPA”), the USFS will prepare an environmental analysis in the form of an Environmental Assessment to evaluate the predicted environmental and socio-economic impacts of the proposed baseline data collection activity. The NEPA process provides for public review and comment of the proposed plan.

The USFS is the lead regulatory agency in the NEPA process, and coordinates with the various Federal and State agencies in the review and approval of the Mine Plan of Operations. Various Colorado state agencies will have primary jurisdiction over certain areas. For example, enforcement of the Clean Water Act in Colorado is delegated to the Colorado Department of Public Health and Environment and a water discharge permit under the National Pollution Discharge Elimination System (“NPDES”) is required before the USFS can approve the Plan of Operations. We currently have a NPDES Permit from the State of Colorado for the operation of the water treatment plant.

In addition, the Colorado Division of Reclamation, Mining and Safety issues mining and reclamation permits for mining activities, pursuant to the Colorado Mined Land Reclamation Act, and otherwise exercises supervisory authority over mining in the state. As part of obtaining a permit to mine, USE and Thompson Creek Metals will be required to submit a detailed reclamation plan for the eventual mine closure, which must be reviewed and approved by the agency. In addition, USE and Thompson Creek

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Metals will be required to provide financial assurance that the reclamation plan will be achieved (by bonding and/or insurance) before the mining permit will be issued.

Obtaining and maintaining the various permits for the mining operations at the Mount Emmons Project will be complex, time-consuming, and expensive. Changes in a mine’s design, production rates, quality of material mined, and many other matters, often require submission of the proposed changes for agency approval prior to implementation. In addition, changes in operating conditions beyond our and Thompson Creek Metals’ control, or changes in agency policy and Federal and State laws, could further affect the successful permitting of the mine operations. The timing and cost, and ultimate success of the mining operation cannot be predicted.

Reliance on Thompson Creek Metals. Thompson Creek Metals is the operator of the Mount Emmons Project and has an option to acquire up to a 75% interest by performing and paying for the work to get the project permitted and operational and making option payments. Thompson Creek could exit our agreement at any time without penalty. Should we be unable to find a replacement partner in due course, U.S. Energy Corp. would have to fund the considerable permitting and development costs thereafter to advance development of the project. We may be unable to obtain such funding on acceptable terms, or at all.

We depend on key personnel.

Our employees have experience in dealing with the exploration and financing of mineral properties, but we have a limited technical staff and executive group. From time to time we rely on third party consultants for professional geophysical and geological advice in oil and gas matters, and on Thompson Creek Metals for mining expertise. The loss of key employees could adversely impact our business, as finding replacements could be difficult as a result of competition for experienced personnel in the minerals industry. We hired an experienced geologist in 2010, and are searching for additional employees to provide full time talent as we expand staffing to operate some properties.

Risks Related to Our Stock

We have authorization to issue shares of preferred stock with greater rights than our common stock.

Although we have no current plans, arrangements, understandings or agreements to do so, our articles of incorporation authorize the board of directors to issue one or more series of preferred stock and set the terms of the stock without seeking approval from holders of the common stock. Preferred stock that is issued may have preferential rights over the common stock, in terms of dividends, liquidation rights and voting rights.

Future equity transactions and exercises of outstanding options or warrants could result in dilution.

From time to time, we have sold restricted stock and warrants and convertible debt to investors in private placements conducted by broker-dealers, or in negotiated transactions. Because the stock was issued as restricted, the stock was sold at a discount to market prices, and/or the debt-to-stock conversion price was at or lower than market. These transactions caused dilution to existing shareholders. Also, from time to time, options and warrants are issued to employees, directors and third parties as incentives, with exercise prices equal to market prices at dates of issuance. Exercise of in-the-money options and warrants could result in dilution to existing shareholders.

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We do not intend to declare dividends on our common stock.

We paid a one-time special cash dividend of $0.10 per share on our common stock in July 2007. However, we do not intend to declare dividends in the foreseeable future.

We have in place take-over defense mechanisms that could discourage some advantageous transactions.

We have adopted a shareholder rights plan, also known as a poison pill. The plan is designed to discourage a takeover of the Company at an unfair price. However, it is possible that the board of directors and a potential takeover acquirer would not agree on a higher price, in which case the takeover might be abandoned, even though the takeover price might be at a significant premium to market prices. Therefore, as a result of the mere existence of the plan, shareholders may not receive the premium price.

Our stock price likely will continue to be volatile due to several factors.

Our stock is traded on the Nasdaq Capital Market. In the two years ended December 31, 2010, the stock has traded as high as $7.06 per share and as low as $1.54 per share. The principal factors which have contributed, or in the future could contribute, to this volatility include:

·	price swings in the oil and gas commodities markets;

·	price and volume fluctuations in the stock market generally;

·	relatively small amounts of USE stock trading on any given day;

·	fluctuations in USE’s financial operating results;

·	industry trends;

·	legislative and regulatory changes; and

·	global economic uncertainty

Item 1 B - Unresolved Staff Comments.

None.

Item 2 – Properties

Oil and Natural Gas

The following table sets forth our net proved reserves as of the dates indicated. Our reserve estimates as of December 31, 2009 and 2010 are based on reserve reports prepared by Ryder Scott Company, L.P. (“Ryder Scott”), and Cawley, Gillespie & Associates, Inc. (“CGA”). Our reserve estimates as of December 31, 2008 are based on a reserve report prepared by Ryder Scott Company, L.P. Ryder Scott and CGA are nationally recognized independent petroleum engineering firms. Ryder Scott is a Texas Registered Engineering Firm (F-1580). Our primary contact at Ryder Scott is Mr. James F. Latham, Senior Vice President. Mr. Latham is a State of Texas Licensed Professional Engineer (License #49586). CGA is a Texas Registered Engineering Firm (F-693). Our primary contact at CGA is Mr. W. Todd Brooker, Vice President. Mr. Brooker is a State of Texas Licensed Professional Engineer (License # 83462). Ryder Scott prepared the estimates related to our Gulf Coast Basin, including Louisiana and Texas properties and CGA prepared the estimates for our North Dakota properties. The reserve estimates were based upon the review by the relevant engineering firm(s) of production histories and other geological, economic, ownership and engineering data, as provided by us and by the operators. Copies of these reports are filed as exhibits to this Annual Report.

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We do not have in-house geophysical or reserve engineering expertise. We therefore primarily rely on the operators of our producing wells who provide production data to our contract reserve engineers.

Summary of Oil and Gas Reserves as of Fiscal Year End (1)

	December 31,
	2010		2009		2008
Net proved reserves
Oil (Bbls)
Developed		1,362,733		811,789		29,798
Undeveloped		183,713		--		--
Total		1,546,446		811,789		29,798

Natural gas (Mcf)
Developed		1,996,490		1,502,296		1,000,000
Undeveloped		139,286		--		--
Total		2,135,776		1,502,296		1,000,000

Plant Products (Bbls)
Developed		52,532		24,031		--
Undeveloped		--		--		--
Total		52,532		24,031		--

Total proved reserves (BOE)		1,954,941		1,086,203		196,465

(1) 2009 and 2010 reserves are based on average prices per barrel of oil and per MMbtu of natural gas at the first day of each month in the 12-month period prior to the end of the reporting period. 2008 reserves are based on the price per barrel of oil and per MMbtu of natural gas on the last day of 2008.

As of December 31, 2010, our proved reserves totaled 1,954,941 BOE (89% developed and 11% undeveloped), comprised of 1,546,446 Bbls of oil (79% of the total), 2,135,776 Mcf of natural gas and 52,532 Bbls of natural gas liquid. See the "Glossary of Oil and Gas Terms" for an explanation of these and other terms. You should not place undue reliance on estimates of proved reserves. See "Risk Factors - Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves”.

Proved Undeveloped Reserves

Proved undeveloped reserves of 183,713 barrels of oil and 139,286 Mcf of natural gas were added in 2010 in connection with drilling completed by our partners. We had no proved undeveloped reserves at December 31, 2009 and accordingly, there were no conversions of proved undeveloped reserves to proved developed producing wells in 2010.

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Oil and Gas Production, Production Prices, and Production Costs

The following table sets forth certain information regarding our net production volumes, average sales prices realized and certain expenses associated with sales of oil and natural gas for the periods indicated. We urge you to read this information in conjunction with the information contained in our financial statements and related notes included in this Annual Report. The information set forth below is not necessarily indicative of future results.


	December 31,
	2010		2009		2008
Production Volume
Oil (Bbls)		303,433		80,461		2,330
Natural gas (Mcf)		757,905		467,691		73,635
Natural gas liquids (Bbls)		19,104		5,987		--
BOE		448,855		164,397		14,603

Daily Average Production Volume
Oil (Bbls/d)		831		220		6
Natural gas (Mcf/d)		2,076		1,281		202
Natural gas Liquids (Bbls/d)		52		16		--
BOE/d		1,230		450		40

Oil Price per Bbl Produced
Realized Price	$	72.11	$	66.22	$	35.50

Natural Gas Price per Mcf Produced
Realized Price	$	4.96	$	4.30	$	6.88

Natural Gas Liquids Price per Bbl Produced
Realized Price	$	47.53	$	40.25	$	--

Average Sale Price per BOE (1)	$	59.15	$	46.11	$	40.35

Expense per BOE
Production costs (2)	$	6.81	$	2.40	$	4.26
Depletion, depreciation and amortization	$	23.64	$	21.72	$	26.16

(1) Amounts shown are based on oil and natural gas sales, divided by sales volumes. Natural gas produced but flared is not included.
(2) Production costs are comprised of oil and natural gas production expenses (excluding ad valorem and severance taxes), and are computed using production costs as determined under ASC 932-235-55.

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Drilling and Other Exploratory and Development Activities

The following table sets forth information with respect to development and exploration wells we completed from January 1, 2008 through December 31, 2010. The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells.

	Development Wells Drilled
	2010	2009	2008
Producing
Gross	--	--	--
Net	--	--	--
Dry
Gross	--	--	--
Net	--	--	--

	Exploration Wells Drilled
	2010	2009	2008
Producing
Gross	8.0000	8.0000	1.0000
Net	2.9409	3.3286	0.1500
Dry
Gross	5.0000	2.0000	1.0000
Net	0.3902	0.5833	0.2000

The information above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered. See "Management's Discussion and Analysis of Financial Condition and Results of Operation – General Overview.”

Oil and Natural Gas Properties, Wells, Operations and Acreage

The following table details our working interests in producing wells as of December 31, 2010. A well with multiple completions in the same bore hole is considered one well. Wells are classified as oil or natural gas wells according to the predominant production stream, except that a well with multiple completions is considered an oil well if one or more is an oil completion.

	Gross Producing Wells		Net Producing Wells		Average Working Interest (1)
Oil		14.00		5.63		40.21214	%
Natural Gas		3.00		0.75		24.99333	%
Total (1)		17.00		6.38		37.52647	%

(1) The average working interest for the thirteen Williston Basin wells producing at December 31, 2010 is 41.38%; the remaining four wells (Southeast Texas and Louisiana), have 7.65%, 14%, 25% and 53.3% working interests, respectively.

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The following map reflects where our oil and gas wells are generally located in the Williston Basin of North Dakota:

Acreage

The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2010.


	Developed		Undeveloped		Total
Area	Gross	Net	Gross	Net	Gross	Net
Williston Basin	14,080	5,955	51,090	19,144	65,170	25,099
Texas and Louisiana	4,414	978	12,734	845	17,148	1,823
California	--		7,178	2,448	7,178	2,448
Total	18,494	6,933	71,002	22,437	89,496	29,370

Present Activities

As of March 1, 2011, we were drilling 1 gross (0.30 net) wells in the Williston Basin, and 5 gross (1.51 net) wells in the Williston Basin were drilled and waiting on completion.

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Molybdenum – Mount Emmons Project

We re-acquired the Mount Emmons (formerly known as the Lucky Jack molybdenum property) located near Crested Butte, Colorado on February 28, 2006. The property was returned to us by Phelps Dodge Corporation (“PD”) in accordance with a 1987 Amended Royalty Deed and Agreement between us and Amax Inc. (“Amax”). The Mount Emmons Project includes a total of 25 patented and approximately 1,219 unpatented mining and mill site claims, which together approximate 9,311 acres, or over 13 square miles of claims.

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We own both surface and mineral rights at the Mount Emmons Project in fee pursuant to mineral patents issued by the United States of America. All fee property requires the payment of property taxes to Gunnison County. Unpatented mining and mill site claims require the payment of an annual maintenance fee of $140 per claim to the Bureau of Land Management; the total amount paid for claim maintenance fees in 2010 was $171,000, which was paid by TCM.

The breakdown of the property is as follows:

	Acres	Number of Claims
Patented / Fee	365	25
Unpatented Claims	6,171	664
Mill Site Claims	2,775	555
Fee Property (1)	160	n/a
Total	9,471	1,244

(1) This property (fee ownership) is in the vicinity of the mining claims but presently is not considered by TCM and U.S. Energy to be part of the Mount Emmons Project.

The Mount Emmons Project is located in Gunnison County, Colorado. The property is accessed by vehicle traffic on Gunnison County Road 12.

Thompson Creek Metals Company (USA) has an option to acquire up to a 75% interest in the Project. See Part I above.

We had leased various patented and unpatented mining claims on the Mount Emmons molybdenum property to Amax in 1974. In the late 1970s, Amax delineated a large deposit of molybdenum on the properties, reportedly containing approximately 155 million tons of mineralized material averaging 0.44% molybdenum disulfide (MoS2). In 1981, Amax constructed a water treatment plant at the Mount Emmons molybdenum property to treat water flowing from the old Keystone mine workings and for potential use in milling operations. By 1983, Amax had reportedly spent an estimated $150 million in the acquisition of the property, securing water rights, extensive exploration, ore body delineation, mine planning, metallurgical testing and other activities involving the mineral deposit. Amax was merged into Cyprus Minerals in 1992 to form Cyprus Amax. PD then acquired Mount Emmons in 1999 through its acquisition of Cyprus Amax. Thereafter, PD acquired additional conditional water rights and patents to certain mineral claims.

The exploration work conducted in the late 1970’s by Amax, Inc. as discussed in Cyprus Amax’s Patent Claim Application to the Bureau of Land Management dated December 23, 1992, defined the initial mineralized material at the Mount Emmons Project as follows: “Molybdenite is present in randomly distributed veinlets (i.e. stockwork veining) and in some larger veins that are up to two feet wide. This mineralized zone is found in metamorphosed sedimentary rocks and in Tertiary igneous complex which acted as the source of the mineralization.”

There also are a number of existing mine adits located on the property. Historic work completed by Amax, Inc. in the 1970s and early 1980s included: 2,400 feet of new drift with 18 underground diamond drill stations to facilitate underground drilling (consisting of 168 diamond drill holes for a total of 157,037 feet of core drilling). The majority of the drilling was concentrated within 3,000 feet north and south; 3,000 feet east and west and 2,000 vertical feet defining the area of mineralized material. A bulk sample

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was collected from this area and sent off site for metallurgical testing. Amax, Inc. also facilitated the completion of an Environmental Impact Statement (“EIS”) as required by NEPA for the Plan of Operations submitted to the United States Forest Service (“USFS”). The Amax, Inc. EIS is now outdated.

In its 1992 patent application, Cyprus Amax stated that the size and grade of the Mount Emmons deposit was determined to approximate 220 million tons of mineralized material grading 0.366% molybdenite. In a letter dated April 2, 2004, the BLM estimated that there were about 23 million tons of mineralized material containing 0.689% molybdenite, and that about 267 million pounds of molybdenum trioxide was recoverable. This letter covered only the high-grade mineralization which is only a portion of the total mineral deposit delineated to date. The BLM relied on a mineral report prepared by Western Mine Engineering (“WME”) for the U.S. Forest Service, which directed and administered the WME contract. WME’s analysis was based upon a price of $4.61 per pound for molybdic oxide and was used by the BLM in determining that nine claims satisfied the patenting requirement that the mining claims contain a valuable mineral that could be mined profitably. WME consulted a variety of sources in preparation of its report, including a study prepared in 1990 by American Mine Services, Inc. and a pre-feasibility report later prepared by Behre Dolbear & Company, Inc. in 1998.

Even with the historical data available, the size, configuration and operations of the mine plan that may be proposed by TCM have not been finalized. These factors, as well as the prevailing prices for molybdic oxide when the mine is active, will determine the economic viability of the project. We note that the statements made by the predecessor owners of the Mount Emmons Project regarding “recoverable” minerals and “mineable “reserves” were based on costs, permitting requirements, and commodity prices then prevailing. The $4.61 price used by WME should not be considered to be a current breakeven price for Mount Emmons. It is anticipated that a full feasibility study will be prepared in the future, using current and expected capital costs, and operating expenses, to estimate the viability of the project. It will be possible to classify some, or none, of the mineralized resources as “reserves” or “recoverable” only after a full feasibility study, based on a specific mine plan, has been completed.

In December 2008, an additional 160 acres of fee land in the vicinity of the claims was purchased for $4 million ($2 million in January 2009, $400,000 annually for five years). We share with TCM the purchase cost of this land on a 50-50 basis.

Geology

The sedimentary sequence in the Mount Emmons area spans from late Cretaceous to early Tertiary time. The oldest formation is the Mancos, a 4,000 foot sequence of shales with some interbedding limestone and siltstones. The Mancos Formation is not exposed on Mount Emmons, but may be seen in valley bottoms a few miles to the north, south, and east. All of the Mancos Formation encountered in the vicinity of the Mount Emmons mineralization has been strongly metamorphosed and attempts to correlate internal divisions of the unit have not been made. The overlying Mesaverde Formation, also of the late Cretaceous age, consists of a massive repetitive sequence of alternating sandstones, siltstones, shales and minor coals. Coal seams were not observed in any of the diamond drill holes, or in any of the underground drifts. On Mount Emmons the Mesaverde Formation varies from 1,100 to 1,700 feet thick. The variability in thickness of the Mesaverde Formation is mainly due to post-depositional erosion. The Ohio Creek Formation, dominantly a coarse sandstone with local chert pebble conglomerate and well-defined shale to siltstone beds, overlies the Mesaverde Formation. The Ohio Creek Formation is of early Tertiary (Paleocene) age and remains fairly consistent at 400 feet thick on Mount Emmons. Capping Mount Emmons is the Wasatch Formation, also of early Tertiary (Paleocene to Eocene) age.

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On a more regional scale, within the Ruby Range the Wasatch Formation may reach 1,700 feet in thickness. However, on Mount Emmons specifically, all but the basal 600 to 700 feet has been eroded. The Wasatch Formation is composed of alternating sequences of immature shales, siltstones, arkosic sandstones, and volcanic pebble conglomerates. The Mount Emmons stock has intruded the Mancos and Mesaverde sediments, strongly metamorphosing both formations to hornfels up to 1500 feet outward from the igneous body.

Sedimentary rocks on Mount Emmons generally dip 15 – 20 degrees to the southeast, south, and southwest as is consistent with the locations of the Oh-Be-Joyful anticline and Coal Creek syncline.

During crystallization of the Red Lady Complex, hydrothermal fluids collected near the top of the magma column. These fluids were released after a period of intense fracturing in the solid upper portions of the Red Lady Complex and the surrounding country rock. This release of fluids was responsible for the formation of the major part of the Mount Emmons molybdenum mineralized zone and the associated alteration zones. Hydrothermal alteration associated with the Mount Emmons stock occurs in several distinct overlapping zones. Altered rocks include sedimentary rocks of the Mancos, Mesaverde, Ohio Creek and Wasatch Formations, the rhyodacite porphyry sills, and rocks of the Mount Emmons stock.

Water Treatment Plant; Site Facilities

PD’s 2006 re-conveyance of the property to U.S. Energy also included the transfer of ownership and operational responsibility of the mine water treatment plant located on the property. The water treatment permit issued under the Colorado Discharge Permit System was assigned to us by the Colorado Department of Health and Environment. We are responsible for all operating and maintenance costs until such time as Thompson Creek Metals elects to acquire a 15% interest in the property. Thereafter, costs will be shared according to our and Thompson Creek’s participation interests. We also are evaluating using the plant in milling operations.

The water treatment plant was constructed by Amax, Inc. in 1981 (at a cost of approximately $15 million) to treat mine discharge water from the historic lead and zinc Keystone Mine. A certified water treatment plant operations contractor with four licensed and/or trained employees operate the water treatment plant on a continuous basis, treating water discharged from the historic lead and zinc Keystone Mine. The plant utilizes a standard lime pH adjustment to precipitate heavy metals from the water. Mine water is then filtered and discharged in compliance with the approved NPDES Permit for the plant, and solids are dewatered and mixed with cement for proper disposal in accordance with state and federal law.

Additional equipment used in the operation of the water treatment plant includes a large front-end loaders, forklifts, specialized snow removal equipment and pickup trucks. The Mount Emmons Project currently has a 24-hour, seven days a week security contract service to protect the property.

Several capital upgrades to onsite facilities have been made since 2006. Current facilities include a core and office building, five ancillary pump houses and underground pipelines and utilities, which move water from five water storage ponds to the water treatment plant. Surface access is maintained to the four underground adits and the ancillary pump houses.

Historical Capital Expenditures by Prior Owners, and Related Information

Amax, Inc. reportedly spent approximately $150 million in exploration and related activities on the Mount Emmons Project, which included construction of the water treatment plant. During 2007, Kobex Resources, the predecessor of TCM, spent approximately $10.5 million on the property. From August 2008 to December 31, 2010, TCM has spent approximately $12.2 million on the property. Our annual

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operating cost for the water treatment plant is approximately $1.8 million. The total costs associated with future drilling and the development of the Project has not yet been determined by TCM.

We are using grid electric power to operate the water treatment plant and other facilities from the local electric utility serving Gunnison County. We have been granted conditional water rights from the State of Colorado for operation and development of the Project. TCM is reviewing and evaluating potential future power and water needs, however no definitive development project plans have been finalized or approved at this time.

Additional drilling will need to be conducted to further delineate the depth, grades and volume of mineralized materials before we can determine if there are reserves present in the project (presently in the advanced exploration stage). The time table for completing drilling, and the permitting and construction of the mine and milling facilities, is dependent upon several factors, including local, State and Federal regulations and availability of capital, which is driven by the market price for molybdenum.

Activities in 2010 and Plans for 2011

TCM, the Project Manager, submitted a baseline Plan of Operations on March 30, 2010, to the US Forest Service and has been responding to questions from the USFS as they review the baseline Plan of Operations (“PoO”). The NEPA process that the USFS will follow for review of the baseline PoO is an EA. We expect that the baseline Plan of Operations will facilitate the base line data collection needed for additional permitting efforts.

At the date of this filing, TCM is reviewing and developing a detailed plan to conduct prospecting activities underground in the existing 2000 drift drill stations. This plan is expected to be completed and approved later in 2011.

Information About Molybdenum Markets

The metallurgical market for molybdenum is characterized by cyclical and volatile prices, little product differentiation and strong competition. In the market, prices are influenced by production costs of domestic and foreign competitors, worldwide economic conditions, world supply/demand balances, inventory levels, the U.S. Dollar exchange rate and other factors. Molybdenum prices also are affected by the demand for end-use products in, for example, the construction, transportation and durable goods markets. A substantial portion the of world’s molybdenum supply is produced as a by-product of copper mining. Today, by-product production is estimated to account for approximately 60% of global molybdenum production.

Annual Metal Week Dealer Oxide mean prices averaged $16.00 in 2010, compared to $11.29 in 2009. The increase in the average annual price for molybdenum is a result of the global economic recovery from the Great Recession which led to dramatic reductions in steel output and pricing, and correspondingly in market demand for molybdenum and it’s pricing.

Real Estate

Remington Village - Gillette, Wyoming.

We have built and own a nine building multifamily apartment complex, with 216 units on 10.15 acres located in Gillette, Wyoming. The apartments are a mix of one, two, and three bedroom units, with a clubhouse and family amenities for the complex. This project is held by our wholly-owned subsidiary Remington Village, LLC.

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Occupancy averaged 89.6% in 2010. For the year, we realized average monthly revenues of approximately $198,000. The occupancy rate at December 31, 2008 was 88%, 80% at December 31, 2009 and 89% at December 31, 2010. The decrease in occupancy rate from 2008 to 2009 was due to the national economic downturn and reduced activities in the oil and gas sector in Wyoming. The apartment complex, along with our corporate aircraft, is pledged as collateral for a $10 million commercial line of credit with a financial institution.

The Company had an appraisal completed as of December 31, 2010 which valued the property at $21.0 million. An impairment of $1.5 million was therefore recorded at December 31, 2010 on the property. Although the property produces positive cash flow from its operations, the return from oil and gas investments is expected to yield a higher return. In 2011 the Company plans on financing and then selling this property to continue growing its oil and gas business.

Fremont County, Wyoming

U.S. Energy owns a 14-acre tract in Riverton, Wyoming, with a two-story 30,400 square foot office building. The first floor is rented to non-affiliates and government agencies; the second floor is occupied by the Company. In addition, own three city lots covering 13.84 acres adjacent to USE’s corporate office building. When the real estate market recovers we intend to sell this property without development. The timing of sale is not known. We also own a 10,000 square foot aircraft hangar on land leased from the City of Riverton with 7,000 square feet of associated offices and facilities and two vacant lots covering 13.2 acres in Fremont County, Wyoming.

Sold Uranium Properties – Possible Future Revenues

In 2007, we sold all of our uranium assets for cash and stock of the purchaser. Included in the sold assets were the Shootaring Canyon uranium mill in Utah and unpatented uranium claims in Wyoming, Colorado, Arizona and Utah. Pursuant to the asset purchase agreement, we may also receive from the purchaser:

·	$20,000,000 cash when the Shootaring Canyon Mill has been operating at 60% or more of its design capacity of 750 short tons per day for 60 consecutive days.

·	$7,500,000 cash on the first delivery (after commercial production has occurred) of mineralized material from any of the claims we sold to a commercial mill (excluding existing ore stockpiles on the properties).

From and after commercial production occurs at the Shootaring Canyon Mill, a production payment royalty (up to but not more than $12,500,000) equal to five percent of (i) the gross value of uranium and vanadium products produced at and sold from the mill; or (ii) mill fees received by the purchaser from third parties for custom milling or tolling arrangements, as applicable. If production is sold to an affiliate of the purchaser, partner, or joint venturer, gross value shall be determined by reference to mining industry publications or data.

The timing of future receipt of funds from any of these contingencies is not known.

Royalty on Uranium Claims

We hold a 4% net profits interest on unpatented mining claims on Rio Tinto’s Jackpot uranium property located on Green Mountain in Wyoming.

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Research and Development

No research and development expenditures have been incurred, either on the Company’s account or sponsored by a customer of the Company, during the past three fiscal years.

Environmental

Operations are subject to various federal, state and local laws and regulations regarding the discharge of materials into the environment or otherwise relating to the protection of the environment, including the National Environmental Policy Act (“NEPA”), Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act ("RCRA"), and the Comprehensive Environmental Response Compensation Liability Act ("CERCLA"). With respect to proposed mining operations at the Mount Emmons property, Colorado’s mine permitting statute, the Abandoned Mine Reclamation Act, and industrial development and siting laws and regulations, also may affect the project. We believe we are in compliance in all material respects with existing environmental regulations. For information on the approximate reclamation costs (decommissioning, decontamination and other reclamation efforts for which we are primarily responsible or potentially responsible) related to the Mount Emmons project, see the consolidated financial statements included in Part II of this Annual Report.

Gas and oil operations also are subject to various federal, state and local governmental and environmental regulations, including regulations governing natural gas and oil production, federal and state regulations for environmental quality and pollution control, and state limits on allowable rates of production by well. These regulations may affect the amount of natural gas and oil available for sale, the availability of adequate pipeline and other regulated transportation and processing facilities, and other matters. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. From time to time, various proposals are made by regulatory agencies and legislative bodies. Regulatory changes can adversely impact the permitting and exploration and development of mineral and oil and gas properties including the availability of capital.

Although all of our oil and gas properties are operated by third parties, the activities on the properties are still subject to environmental protection regulations. Operators are required to obtain drilling permits, restrict substances that can be released into the environment, and require remedial work to mitigate pollution from operations (such as pollution from operations), close and cover disposal pits, and plug abandoned wells. Violations by the operator could result in substantial liabilities, and we would have to pay our share. Based on the current regulatory environment in those states where we have oil and natural gas investments, we don’t expect to make any material capital expenditures for environmental control facilities.

Failure to comply with these regulations could result in substantial fines, environmental remediation orders and/or potential shut down of a project until compliance is achieved. Failure to timely obtain required permits to start operations at a project could cause delay and/or the failure of the project resulting in a potential write-off of the investments made.

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Insurance

The Company has the following insurance coverage:

General

A general liability policy provides $1 million of liability coverage per occurrence, $2 million general aggregate limit and a $10 million commercial excess liability policy. These policies cover bodily injury and property damage, but do not cover all potential liabilities for Company activities. Accordingly, we have additional policies related to other areas of our business.

Oil and Gas Exploration and Development

Pursuant to the Joint Operating Agreements (“JOAs”) between the Company and each operator of the properties where we hold working interests, each working interest owner is responsible for paying its share of costs and expenses related to operations. The liability of the parties is several, not joint or collective, and the relationship between the parties is not a partnership. None of the JOAs provide for indemnification between the parties.

The JOAs also require the operator to obtain and maintain liability insurance for the benefit of all the working interest owners (premiums are paid pro rata by the working interest owners). Policies currently in place provide $1 million per event, $2 million general aggregate liability coverage, $1 million auto insurance, excess coverage (overlaying the preceding) of $5 million to $20 million and $5 million to $15 million for “operator’s extra expense” (control of well). Premiums are paid by the working interest owners pro rata to ownership.

The Company has also purchased non-operator liability insurance providing $1 million of liability coverage per occurrence, $2 million general aggregate limit and $20 million in excess liability.

Mt. Emmons Project

The Company is responsible for all costs to operate the water treatment plant at the Mt. Emmons project until Thompson Creek Metals Company USA (“TCM”) elects to exercise its option to own an interest in the property. We maintain an insurance policy for our benefit in the amounts of $1 million per event, $2 million aggregate general liability, $1 million automobile liability, $10 million environmental impairment liability, and $10 million excess liability (an upper limit on the coverage other than environmental).

U.S. Energy is an additional insured under TCM’s policies with respect to operations at Mt. Emmons not related to the water treatment plant, with policy limits of $1 million per event, $2 million general aggregate liability, and excess liability of $10 million.

We believe the above insurance is sufficient in the current permitting-exploration stage of the Mt. Emmons project. Additional insurance will be obtained as the level of activity in exploration and development expands.

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Corporate Aircraft

The Company maintains a $20 million per event liability policy on its corporate aircraft. We also maintain physical damage insurance, $200,000 and $4 million, on the aircraft which approximates their replacement value.

Remington Village

We have a policy covering $1 million each event, $2 million general aggregate liability and a $9 million of excess liability policy. The deductibles are $1,000 ($5,000 retained limited) per event. We maintain $20.4 million of coverage for the real property written on a Special Form/Replacement Cost basis.

Employees

As of March, 2011, we had 19 full-time employees.

Mining Claim Holdings

Title

Approximately 25 of the Mount Emmons mining claims are patented claims; however the majority of claims are unpatented.

Unpatented claims are located upon federal and public land pursuant to procedures established by the General Mining Law, which governs mining claims and related activities on Federal public lands. Requirements for the location of a valid mining claim on public land depend on the type of claim being staked, but generally include discovery of valuable minerals, erecting a discovery monument and posting thereon a location notice, marking the boundaries of the claim with monuments, and filing a certificate of location with the county in which the claim is located and with the U.S. Bureau of Land Management (“BLM”). If the statutes and regulations for the location of a mining claim are complied with, the locator obtains a valid possessory right to the contained minerals. To preserve an otherwise valid claim, a claimant must also pay certain rental fees annually to the federal government and make certain additional filings with the county and the BLM. Failure to pay such fees or make the required filing may render the mining claim void or voidable.

Because mining claims are self-initiated and self-maintained, they possess some unique vulnerability not associated with other types of property interests. It is impossible to ascertain the validity of unpatented mining claims solely from public records and it can be difficult or impossible to confirm that all of the requisite steps have been followed for location and maintenance of a claim. If the validity of an unpatented mining claim is challenged by the government, the claimant has the burden of proving the economic feasibility of mining minerals located thereon. However, we believe that all of our Mount Emmons mining claims are valid and in good standing.

Proposed Federal Legislation

The U.S. Congress from time to time has considered proposed revisions to the General Mining Law, including as recently as 2009. If these proposed revisions are enacted, payment of royalties on production of minerals from federal lands could be required as well as additional procedural measures, new requirements for reclamation of mined land, and other environmental control measures. The effect of any revision of the General Mining Law on operations cannot be determined until enactment, however, it is

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possible that revisions would materially increase the carrying and operating costs of mineral properties located on federal unpatented mining claims.

Item 3 – Legal Proceedings

Material legal proceedings pending at December 31, 2010, and developments in those proceedings from that date to the date this Annual Report was filed, are summarized below.

Water Rights Litigation –Mount Emmons Molybdenum Property

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

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

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

On August 11, 2010, High Country Citizen’s Alliance, Crested Butte Land Trust and Star Mountain Ranch Association, Inc (“Opposers”) filed a Motion for Summary Judgment alleging that the Plan of Operations did not comply with the Forest Service regulations and did not satisfy certain Reality Check Limitations contained in the Water Rights Decree. On September 24, 2010, U.S. Energy filed a Response to the Motion for Summary Judgment responding that the Plan of Operations complied with the Forest Service and BLM’s regulations and satisfied the Reality Check provision contained in the Water Rights Decree and alternately that the Company had until April 30, 2013 to comply with the Reality Check provision, which is six years after the Supreme Court denied certiorari in the judicial proceeding. The U.S. Department of Justice also filed a response on behalf of the Forest Service and BLM that the Court cannot second guess the Forest Service’s determination that the Company’s Plan of Operations satisfied the Forest Service and BLM’s regulations.

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On November 24, 2010 the District Court Judge denied the Opposers’s Motion for Summary Judgment and held that Company had until April 30, 2013 to comply with the Reality Check provision of the Decree, which is six years after the Supreme Court denied certiorari in the judicial proceeding. The question of the adequacy of the Water Diligence Application is pending.

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

On January 3, 2008, the Division of Reclamation, Mining and Safety of the Colorado Department of Natural Resources (“DRMS”) approved the Company’s Notice of Intent to Conduct Prospecting Notice for the Mount Emmons molybdenum property (“NOI”). The approved NOI provides 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 8, 2008, High Country Citizens’ Alliance (‘HCCA”) filed a request for hearing before the Colorado Mine Land Reclamation Board (“MLRB”) appealing the NOI, claiming it was not prospecting, but rather development and mining. On May 14, 2008, the MLRB denied HCCA’s Request for Hearing and also denied their Request for a Declaratory Order. Citing Colorado law, the MLRB 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 MLRB’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 MLRB 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.

On February 24, 2011, the Denver, Colorado District Court issued an Order dismissing all of HCCA’s claims concerning the appeal of U.S. Energy’s NOI holding that: (i) HCCA does not have standing to request judicial review on the merits of the DRMS’s approval of U.S. Energy’s NOI and (ii) HCCA does not have standing to request a Declaratory Order. This decision upholds MLRB’s May 14, 2008 decision denying HCCA’s Request for Hearing and their Request for a Declaratory Order because HCCA did not have standing or the right to appeal DRMS’s approval of the NOI under Colorado law.

On January 20, 2010 the Company submitted Modification MD-03 (“MD-03”) to the NOI. On November 15, 2010 DRMS issued its determination that MD-03 was complete, the activities proposed were prospecting and that MD-03 was approved. On November 19, 2010 HCCA filed an appeal with the MLRB claiming that: (i) the proposed activities were not prospecting, but rather development and mining, (ii) the current financial warranty amount was insufficient to cover the proposed activities and (iii) the permit should be conditioned upon its compliance with other federal and local governmental agency requirements.

On January 12, 2011, the MLRB on a vote 4-1 vote upheld DRMS’s approval of MD-03 and their determination that: (i) the activities proposed by the NOI and MD-03 are prospecting, not development or mining, (ii) the current financial warranty amount is sufficient to cover the proposed activities and (iii) DRMS’s decision not to make its approval of MD-03 contingent on permits or licenses that may be required by federal , other state, or local agencies was proper and affirmed that decision. On March 2, 2011, HCCA appealed MLRB’s decision on MD-03 to the Denver, Colorado District Court.

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Item 4 – Submission of Matters to a Vote of Security Holders

On June 25, 2010, the annual meeting of shareholders was held for the election of two directors to serve until the terms stated in the Proxy Statement (until the 2013 Annual Meeting of Shareholders and until their successors are elected or appointed and qualified). With respect to the election of the directors, the votes cast were as follows:

Name of Director	Votes For	Withheld
Mark J. Larsen	7,268,168	635,362
Stephen V. Conrad	7,322,244	581,286

The directors now are Keith G. Larsen, Mark J. Larsen, Robert Scott Lorimer, H. Russell Fraser, Allen S. Winters, Stephen V. Conrad and Michael Feinstein.

The shareholders also voted on the ratification of appointment of Hein & Associates LLP, the votes cast were as follows:

		Votes For		Votes Against		Abstain
Ratification of appointment of Hein & Associates LLP as independent auditors for the current fiscal year.		19,291,602		551,196		79,737

PART II

Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchase of Equity Securities

Market Information

Shares of USE common stock are traded on the over-the-counter market, and prices are reported on a "last sale" basis on the Nasdaq Capital Market of the National Association of Securities Dealers Automated Quotation System ("Nasdaq"). Quarterly high and low sale prices follow:

	High		Low
Calendar year ended December 31, 2010
First quarter ended 03/31/10	$	6.76	$	5.14
Second quarter ended 06/30/10		7.06		4.67
Third quarter ended 09/30/10		5.43		4.01
Fourth quarter ended 12/31/10		6.17		4.37

Calendar year ended December 31, 2009
First quarter ended 03/31/09	$	2.09	$	1.54
Second quarter ended 06/30/09		2.57		1.79
Third quarter ended 09/30/09		4.21		1.87
Fourth Quarter through 12-31-09		6.79		3.65

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Holders

At March 9, 2011 the closing market price was $6.19per share. There were approximately 1,627 shareholders of record, with 26,418,713 shares of common stock issued and outstanding at December 31, 2010.

We paid a onetime special $0.10 per share cash dividend to common shareholders of record on July 6, 2007. There are no contractual restrictions on our present or future ability to pay cash dividends.

Issuance of Securities in 2010

During the twelve months ended December 31, 2010, USE issued a total of 649,897 shares. A brief discussion of the issuance of the shares follows:

Registered Securities

During the twelve months ended December 31, 2010, we issued 275,728 shares of common stock as a result of the exercise of options which had been issued to employees, 15,000 shares as a result of the exercise of warrants issued to a director and 236,367 shares as a result of the exercise of warrants which had been issued to two consultants. We also issued 42,802 shares pursuant to the terms of our ESOP. The ESOP funding represents the minimum required amount during the twelve months ended December 31, 2010.

The Company has an active registration statement for $100 million. During December 2009 we raised $26.2 million under this registration statement by issuing 5 million shares. A balance of $73.8 million is available under the registration statement which may be used in the future.

Unregistered Securities

During the twelve months ended December 31, 2010, we issued 80,000 shares pursuant to the 2001 Stock Award Plan, 20,000 shares to each of the executive officers of the Company.

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Equity Plan Compensation Information - Information about Compensation Plans as of December 31, 2010

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)		Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensaiton plans (excluding securities reflected in column (a)) (c)
Equity Companeation plans approved by security holders
1998 Stock Option Plan		10,000	$	2.40		--
2001 Incentive Stock Option Plan		3,001,647	$	3.87		3,765,506
2001 Stock Compensation Plan		(1)		(1)		(1)
2008 Stock Option plan for U.S. Energy Corp. Independent Directors and Advisory board members		120,000	$	2.73		150,686

Equity compensation plans not approved by security holders		--	$	--		--
Total		3,131,647	$	3.83		3,916,192

(1) Four Officers (CEO, COO, CFO and General Counsel) of the Company receive 5,000 shares of common stock at the beginning of each calendar quarter, 20,000 shares per year under this plan. The Company pays the taxes on these shares as the Officers have agreed to not pledge, sell or in any other way leverage these shares. The shareholders of the Company approved this plan.

Stock Performance Graph

The following graph compares the cumulative return on a $100 investment in our common stock for the five years ended December 31, 2010, to that of the cumulative return on a $100 investment in the S&P 500, the NASDAQ Market Index, and the S&P Small Cap 600 Energy Index. In calculating the cumulative return, we assumed reinvestment of the $0.10 per share cash dividend paid in July 2007. The indices are included for comparative purpose only. This graph is not "soliciting material," is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act of 1933 or the Exchange Act, whether made before or after the date the Annual Report was filed and irrespective of any general incorporation language in any such filing.

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COMPARISON OF CUMULATIVE TOTAL RETURN AMONG U.S. ENERGY CORP., THE S&P 500, THE NASDAQ MARKET INDEX, AND THE S&P SMALL CAP 600 ENERGY INDEX

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data is derived from and should be read with the financial statements included in this Report.

	(In thousands)

	December 31,
	2010		2009		2008		2007		2006
Current assets	$	29,824	$	62,100	$	72,767	$	82,729	$	43,325
Current liabilities		18,763		8,672		19,983		8,093		11,595
Working capital		11,061		53,428		52,784		74,636		31,730
Total assets		156,016		146,723		142,631		131,404		51,901
Long-term obligations(1)		1,150		973		1,870		1,283		882
Shareholders' equity		130,688		129,133		111,833		115,100		37,468

(1) Includes $303,000 of accrued reclamation costs on properties at December 31, 2010, $211,000, at December 31, 2009, $144,000, at December 31, 2008, $133,000, at December 31, 2007, and $124,000 at December 31, 2006.

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	(In thousands except per share amounts)

	For the year ended December 31,

	2010			2009			2008			2007			2006
Operating revenues	$	27,176		$	10,349		$	2,222		$	1,174		$	880
Loss from continuning operations		(4,232	)		(9,271	)		(9,604	)		(14,539	)		(14,668	)
Other income & (expense)		1,722			(1,186	)		(17	)		108,824			2,118
(Loss) income before minority interest, income taxes and discontinued operations		(2,510	)		(10,457	)		(9,621	)		94,285			(12,550	)
Minority interest in loss (income) of consolidated subsidiaries		--			--			--			(3,551	)		88
Benefits from (provision for) income taxes		1,738			2,279			3,326			(32,367	)		15,332
Discontinued operations, net of tax		--			--			4,907			(2,004	)		(1,819	)
Net (loss) income	$	(772	)	$	(8,178	)	$	(1,388	)	$	56,363		$	1,051

Per share financial data
Operating revenues	$	1.02		$	0.48		$	0.10		$	0.06		$	0.05
Loss from continuning operations		(0.16	)		(0.43	)		(0.41	)		(0.71	)		(0.79	)
Other income & expenses		0.06			(0.05	)		--			5.32			0.11
(Loss) income before minority interest, income taxes and discontinued operations		(0.09	)		(0.48	)		(0.41	)		4.61			(0.68	)
Minority interest in loss (income) of consolidated subsidiaries		--			--			--			(0.17	)		--
Benefits from (provision for) income taxes		0.06			0.11			0.14			(1.58	)		0.83
Discontinued operations, net of tax		--			--			0.21			(0.10	)		(0.10	)
Net (loss) income per share basic	$	(0.03	)	$	(0.38	)	$	(0.06	)	$	2.75		$	0.06

Net (loss) income per share diluted	$	(0.03	)	$	(0.38	)	$	(0.06	)	$	2.54		$	0.05

Basic shares outstanding		26,763,995			21,604,959			23,274,978			20,469,846			18,461,885
Diluted shares outstanding		26,763,995			21,604,959			23,274,978			22,189,828			21,131,786

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS

Forward Looking Statements

Statements in this discussion about expectations, plans and future events or conditions are forward looking statements. Actual future results, including oil and natural gas production growth, financing sources, and environmental and capital expenditures, could be materially different depending on a number of factors, such as: commodity prices, political or regulatory events, and other matters. Please see “Cautionary Statement Regarding Forward-Looking Statements” and Item 1A in this Report, which should be carefully considered in reading this section.

General Overview

U.S. Energy Corp. (“U.S. Energy” or “Company”) historically invested in mineral properties and sold them prior to placing them into production. Beginning in 2008, the Company began investing primarily in oil and gas properties and expending the amount of capital necessary to place them into production with the intent of generating recurring cash flows, revenues and net income.

The Company is now, predominantly, an oil and gas exploration and production company. Our primary objective is to acquire and develop oil and gas producing properties in the continental United States. Our business is currently focused in the Rocky Mountain region (specifically the Williston Basin of North Dakota and Montana and Anadarko Basin of Colorado), Texas, Louisiana and California, however, we do not intend to limit our focus to these geographic areas. We continue to focus on increasing production, reserves, revenue and cash flow from operations while managing our level of debt. Our liquidity and access to financing under our Senior Secured Revolving Credit Facility (see Liquidity and Capital Resources below) allows us to seek additional oil and gas opportunities in the U.S.

We currently explore for and produce oil and gas primarily through a non-operator business model; however, we expect to operate our Colorado property for our own account in 2011. As a non-operator, we rely on our operating partners to propose, permit and manage wells. Before a well is spud, the operator is required to provide all oil and gas interest owners in the designated well unit the opportunity to participate in the drilling costs and revenues of the well on a pro-rata basis. After the well is completed, our operating partners also transport, market and account for all production.

Additionally, we are involved in the exploration for and development of minerals (molybdenum) through our ownership of the Mt. Emmons project in Colorado, geothermal energy through our investment in Standard Steam Trust and commercial real estate operations. Capitalized dollar amounts invested in each of these areas at December 31, 2010 and December 31, 2009 were as follows:


	(In thousands)
	December 31,		December 31,
	2010		2009
Unproved oil and gas properties	$	21,620	$	5,361
Proved oil and gas properties	$	63,317	$	24,595
Undeveloped mining properties	$	21,077	$	21,969
Investment in geothermal properties	$	2,834	$	2,958
Commercial real estate	$	23,084	$	24,600
	$	131,932	$	79,483

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Oil & Gas

In 2010, we recognized record revenues from oil and natural gas production of $26.5 million, production of 448,855 BOE and oil and gas proved reserves, at December 31, 2010, of 1,954,941 BOE. The key drivers to our success for 2010 included the following:

Drilling programs. Our success is largely dependent on the results of our drilling programs. During the year ended December 31, 2010, we drilled 13 gross wells (3.33 net wells) with a success rate of 62% that was comprised of: (a) seven of seven gross wells (2.41 net wells) in the Williston Basin, and (b) one gross (0.53 net wells) of six gross wells (0.92 net wells) in the Gulf Coast and Texas drilling programs. At December 31, 2010, 6 additional gross wells (1.51 net wells) were awaiting completion (5 gross wells (1.46 net wells) in the Williston Basin and 1 gross well (0.05 net wells) in the onshore Gulf Coast area.

Reserve growth. As a result of our drilling programs discussed above, our reserves increased 80% to 1,954,941 BOE at December 31, 2010, replacing 193% of 2010 production.

Production. Our 2010 annual production of 448,855 BOE, or 1,230 BOE/d, was a record high for the Company. The 2010 production increased 173% from 2009 production of 164,396 BOE or 450 BOE/d, primarily due to production from the Williston Basin.

Financial flexibility. In July 2010, we improved our financial flexibility through establishment of a senior credit facility to borrow up to $75 million from a syndicate of banks, financial institutions and other entities, including BNP Paribas (“BNP”). In October 2010, the Borrowing Base increased from the initial $12.0 million to $18.5 million as a result of a redetermination using our June 30, 2010 financial statements, production reports and a reserve report for our Williston Basin wells. See Capital Resources - BNP Paribas Reserve Lending Facility below.

Commodity prices. Our average realized oil price in 2010 was $72.11 per Bbl (excluding the impact of our economic hedges), or $5.89 higher than in 2009. Our average natural gas price realized during 2010 was $4.96 per Mcf, $0.66 per Mcf higher than the 2009 price of $4.30. Commodity prices are affected by changes in market demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Our financial results are significantly dependent on commodity prices, particularly oil prices, which are beyond our control and have been and are expected to remain volatile.

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

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Other

Minerals (molybdenum). Our investment in the Mt. Emmons project in Colorado is a long term investment. In 2008, we entered into an Option Agreement with Thompson Creek Metals Company USA (“TCM”) under which TCM may acquire up to 75% ownership of the Mt. Emmons project after expending $400 million.

Real estate. We continue to receive cash flows, revenues and net profits from our energy related multifamily housing development in northeastern Wyoming. We do not plan to build or acquire any additional multifamily housing projects.

Geothermal. We own a 22.8% interest in a geothermal limited partnership, Standard Steam Trust, LLC (“SST”). Due to the sale of two of SST’s geothermal properties in 2010, we recorded an equity gain from SST in 2010 of $1.0 million, however, equity losses from the investment in SST are expected until such time as additional SST properties are sold, equity losses reduce the investment to zero or we sell the investment. Our net investment in this partnership at December 31, 2010 is $2.8 million.

The principal factors affecting the Company are the success of its oil and gas exploration activities, commodity prices, drilling and completion costs, lease operating expenses, decline rates of our wells, mechanical and geological issues with our wells, the grade of mineral deposits, permitting and costs associated with exploration and development of the prospects.

Liquidity and Capital Resources

We maintained a strong liquidity position throughout the year ended December 31, 2010, notwithstanding significant investment into our oil and gas properties. The Company experienced $12.4 million in cash flow from operations and reduced its debt while maintaining strong liquidity ratios and cash balances. The following table sets forth key liquidity measures for the year ended December 31, 2010 as compared to the year ended December 31, 2009:

	(in thousands)
	December 31,		December 31,
	2010		2009
Current ratio(1)	1.59 to 1		7.16 to 1
Working capital(2)	$	11,061	$	53,428
Total debt	$	600	$	800
Total cash and marketable securities less debt	$	24,617	$	55,840
Total stockholders' equity	$	130,688	$	129,133
Total liabilities to equity	0.19 to 1		0.14 to 1

(1)Current assets divided by current liabilities
(2)Current assets less current liabilities

Our strong working capital position and current ratio are the result of conservative investment strategies which are expected to yield revenues, cash flow and net income in the future. As of December 31, 2010, our only debt is related to the acquisition of a property near the Mt. Emmons project. Additional sources of capital that may be used to expand operations include borrowings pursuant to our credit facility with BNP, long-term financing and sale of the multifamily housing complex and a $10 million line of credit with a commercial bank.

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Components of the $42.4 million decrease in working capital for the years ended December 31, 2010 from working capital at December 31, 2009 are as follows:

	(In thousands)

	December 31,		December 31,		Increase
	2010		2009		(Decrease)
CURRENT ASSETS:
Cash and cash equivalents	$	6,010	$	33,403	$	(27,393	)
Marketable securities
Held to maturity - treasuries		17,843		22,059		(4,216	)
Available for sale securities		1,364		1,178		186
Accounts receivable
Trade		3,932		3,882		50
Reimbursable project costs		114		2		112
Income taxes		104		353		(249	)
Other current assets		457		1,223		(766	)
Current assets		29,824		62,100		(32,276	)

CURRENT LIABILITIES:
Accounts payable	$	14,915	$	6,500	$	8,415
Accrued compensation		1,669		1,748		(79	)
Commodity risk management liability		1,725		--		1,725
Current portion of long-term debt		200		200		--
Other current liabilities		254		224		30
Total current liabilities		18,763		8,672		10,091
Working Capital	$	11,061	$	53,428	$	(42,367	)

Major changes in working capital during the year ended December 31, 2010 were:

Current Assets. Current assets as of December 31, 2010 decreased by $32.3 million from current assets at December 31, 2009, primarily as a result of the use of cash and monetization of U.S. Treasuries to fund oil and gas exploration and well completion costs, operations and mineral property holding expenses. Please see the discussion below regarding cash flows for the twelve months ended December 31, 2010.

Current Liabilities. Current liabilities increased $10.1 million from at December 31, 2009, primarily as a result of:

·	Accounts payable increased significantly as a result of drilling and completion costs associated with wells in progress at December 31, 2010.

·	At December 31, 2010, we recorded a $1.7 million unrealized loss resulting from derivatives. This represents the fair value of our derivative contracts at December 31, 2010.

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Analysis of Cash Flows:

The following tables summarize the provision and use of cash in Operations, Investing Activities and Financing Activities for the years ended December 31, 2010, 2009 and 2008:


	(In thousands)
	For the years ended December 31,
	2010			2009			2008
Cash provided by (used in) operations	$	12,372		$	2,552		$	(6,536	)
Cash provided by (used in) investing activities	$	(39,859	)	$	17,150		$	(70,557	)
Cash provided by (used in) financing activities	$	94		$	5,267		$	8,909



	For the years ended December 31,
		2010			2009			2008
Net increase (decrease) in cash and cash equivalents	$	(27,393	)	$	24,969		$	(63,858	)
Net (redemption) investment in U.S. Treasury investments		(78	)		(183	)		(1,255	)
Net change in cash and U.S. Treasuries	$	(27,471	)	$	24,786		$	(65,113	)

Investments of surplus cash in U.S. Treasuries have maturity dates in excess of 90 days and are therefore classified as Held to Maturity Marketable Securities for financial presentation purposes under Generally Accepted Accounting Practices (“GAAP”) in the United States of America. Although they are classified in this manner, they are used as needed to fund operations and capital projects, and accordingly are presented in the above table with cash and cash equivalents for clarity of the net change in ready liquid assets. A description of the provision of and use of cash in Operations, Investing Activities and Financing Activities for the year ended December 31, 2010 follows:

Operations:

Operations for the year ended December 31, 2010 resulted in a net after tax loss of $772,000. This loss included $17.2 million in non-cash expenses related to depreciation, depletion, loss related to derivative instruments, impairment of the multifamily housing project, and non-cash compensation.

For a complete discussion of the cash flows from Operations please refer to Results of Operations below.

Investing Activities:

Cash provided by Investing Activities includes:

·	Redemption of U.S. Treasuries in the amount of $4.3 million.

·	$1.1 million that was received as a capital distribution from SST related to the sale of one of SST’s geothermal properties.

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·	In December 2010, TCM prepaid the third annual option payment of $1.0 million that was due in January 2011.

·	Proceeds from the sale of marketable securities of $602,000

Cash consumed in Investing Activities includes:

·	Investment in oil and gas properties of $45.9 million.

·	Investment of $624,000 in property and equipment: $431,000 for equipment at the Mt. Emmons water treatment plant, $22,000 in improvements at the Company’s multifamily housing project and $171,000 in the acquisition of office equipment and software.

Financing Activities:

Cash provided by Financing Activities includes:

·	$294,000 for the exercise of employee options and warrants to third party consultants.

Cash consumed in Financing Activities:

·	We retired $200,000 in long term debt due under a note for the purchase of a 160 acre parcel of property purchased in the vicinity of the Mt. Emmons project.

Capital Resources

Potential primary sources of future liquidity include the following:

Oil and Gas Production

The Company’s current sources of cash are expected to be provided by successful oil and gas wells. The ultimate amount of cash resources derived from the production of oil and gas will be determined by production volumes, the price of oil and gas, exploration and production costs. We plan to continue to explore for and develop oil and gas properties and may also acquire existing production.

To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to economically hedge future sales prices on a portion of our oil production. Our current strategy is to economically hedge up to 50% of our proved developed producing (PDP) volumes. The use of certain types of derivative instruments may prevent us from realizing the benefit of upward price movements. See “Item 1A. Risk Factors - The use of hedging arrangements in oil and gas production could result in financial losses or reduce income.”

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The following table is a summary of our estimated reserves as of December 31, 2010:

Estimated net proved reserves:	Bakken / Three Forks		Gulf Coast / Texas		Total
Producing:
Oil (bbls)		1,120,018		22,616		1,142,634
Gas (Mcf)		505,565		717,000		1,222,565
NGL (bbls)		--		26,000		26,000
Developed Non-producing:
Oil (bbls)		182,328		37,771		220,099
Gas (Mcf)		153,924		620,000		773,924
NGL (bbls)		--		26,532		26,532
Undeveloped
Oil (bbls)		183,713		--		183,713
Gas (Mcf)		139,286		--		139,286
NGL (bbls)		--		--		--

Total (BOE)		1,619,188		335,753		1,954,941

Future net income before income taxes	$	71,362,000	$	10,193,000	$	81,555,000
PV-10	$	43,265,000	$	8,808,000	$	52,073,000

Estimated proved reserves (on a BOE basis) at December 31, 2010 increased by 868,738 BOE or approximately 80% over estimated proved reserves at December 31, 2009. Most of the increase is related to our successful Williston Basin drilling program.

The reserve estimates are calculated by independent engineering firms in accordance with SEC rules. Estimated future net cash flows before income taxes are discounted at 10%. This value is not intended to represent the current market value of the reserves. Reserve estimates are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, oil and gas prices, and other factors.

Estimates of reserve volumes and future net cash flows are based on the average of first day of month prices during the year ended December 31, 2010 ($79.43 per barrel of oil and $4.38 per MMbtu of gas). Future estimated production taxes and ad valorem taxes, capital costs and operating costs are deducted from estimated future cash flows, and the result is discounted at an annual rate of 10% to determine “present value” (“PV10”).

PV10 is widely used in the oil and gas industry, and is followed by institutional investors and professional analysts, to compare companies. However, the PV10 data is not an alternative to the standardized measure of discounted future net cash flows calculated under GAAP and in accordance with ASC 932-235-55, which includes the effects of income taxes. The following table provides a reconciliation of Estimated Future Net Revenues Discounted at 10% to the Standardized Measure of Discounted Future Net Cash Flows as shown in Note G to the Company’s Consolidated Financial Statements.

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	(in thousands) Year Ended December 31, 2010
Estimated future net revenues discounted at 10%	$	52,073
Future income tax expense (discounted)		(7,420	)
Standardized measure of discounted future net cash flows	$	44,653

Cash on Hand

At December 31, 2010, we had $6.0 million in cash and cash equivalents and $17.8 million in U.S. Treasuries. Cash is invested in interest bearing accounts, with the majority invested in U.S. Government Treasuries. During the past three years, this investment policy has insured the preservation of principal and yielded a return.

BNP Paribas Reserve Credit Facility

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

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

The Borrowing Base will be redetermined semi-annually, taking into account updated reserve reports. Any proposed increase in the Borrowing Base will require approval by all Lenders in the syndicate, and any proposed Borrowing Base decrease will require approval by Lenders holding not less than two-thirds of outstanding loans and loan commitments. As of December 31, 2010 we had not borrowed from the Facility. On February 18, 2011 we borrowed $3.0 million under the Credit Facility to fund a portion of our initial participation in the Eagle Ford Shale oil prospect in Zavala County, Texas.

Commercial Bank

Line of Credit - We have a $10.0 million line of credit with a commercial bank. No borrowings have been made under this line of credit as of the date of this report. The line of credit has a variable interest rate which is tied to a national market rate with a minimum interest rate of 5.5%. The expiration date of the line of credit, January 31, 2011, was extended to April 15, 2011. The line of credit may be renewed depending on the financial strength and needs of the Company. The credit line is secured by the Remington Village multifamily housing project and a corporate aircraft.

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Equity Market

We filed a registration statement with the Securities and Exchange Commission on October 20, 2009 which became effective on November 6, 2009. The registration statement provides for the sale of $100 million of the Company’s common stock. During the fourth quarter of 2009, we sold 5 million shares of our common stock for $5.25 per share or $26.3 million, $24.3 million net of offering costs. Additional capital may be raised under the registration statement to fund future oil and gas acquisitions and development drilling.

Real Estate

We own a 216 unit multifamily housing property in Gillette, Wyoming, known as Remington Village. The property averaged an occupancy rate of 90% during 2010 and was 89% occupied as of December 31, 2010. Occupancy is dependent on the regional economy including coal mining operations, oil and gas exploration and construction of a power generating plant in the area. The property generated positive cash flow from operations of $1.2 million during 2010 and is projected to remain in that range of cash flow during 2011. To reach these levels, occupancy rates will have to average 90% and costs and expenses remain similar to those experienced in 2010.

Although the property is pledged as collateral for the $10 million line of credit, there is no debt against the property. In 2011 we made the decision to finance and ultimately sell the property and use the proceeds to further our oil and gas exploration and development projects. The appraised value of the property at December 31, 2010 of $21.0 million resulted in a $1.5 million impairment.

Mt. Emmons Molybdenum Project and Thompson Creek Metals Company, USA

In 2008, we entered into an agreement with TCM for the permitting and development of the Mt. Emmons project, near Crested Butte, Colorado. Under the terms of the agreement, TCM pays all costs related to activities on the project with the exception of the water treatment plant costs which are currently paid 100% by the Company. TCM may earn up to a 75% interest in the property after it spends $400 million. At such time as TCM has acquired its desired level of ownership, the Company and TCM will fund all costs in proportion to their ownership.

TCM is obligated to pay the Company six annual option payments in the amount of $1.0 million each due in January each year through 2014. TCM has paid three of these payments as of December 31, 2010, one of which was prepaid in December 2010 for the January 2011 option payment.

Once permitted and placed into production, the Mt. Emmons project is expected to provide the Company with long term capital resources. Historical records filed by predecessor owners of the Mt. Emmons project with the Bureau of Land Management (BLM) in the 1990’s for the application of patented mineral claims, referenced identification of mineral resources of approximately 220 million tons of 0.366% molybdic disulfide (MoS2) mineralization. A high grade section of the mineralization containing roughly 23 million tons at a grade of 0.689% MoS2 was also reported. No assurance can be given that these quantities of MoS2 exist or that the Company and TCM will be successful in permitting the property.

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Future Receipts of Royalties and Contractual Commitments from Uranium Properties

We retained a 4% Net Profits Royalty on a portion of the Green Mountain uranium property in Wyoming which is owned by Rio Tinto, Inc. No assurance can be given as to when or if the property will be placed into production. Any royalty due will be based on the market price of uranium concentrates and the cost of producing those concentrates.

Pursuant to the terms of the 2007 sale of our uranium properties to sxr Uranium One Inc., we are entitled to receive $20 million when commercial production begins at the Utah uranium mill which the Company sold; $7.5 million when the first delivery of ore to any commercial mill, after commercial production commences, from any of the uranium properties we sold; and a production royalty of up to $12.5 million. No assurance can be given as to if or when these events and payments will occur.

Capital Requirements

Our direct capital requirements during 2011 are the funding of our drilling programs, additional oil and gas exploration and development projects, acquisition of prospective oil and gas properties and or existing production, operating and capital improvement costs of the water treatment plant at the Mt. Emmons project, operations at Remington Village and general and administrative costs. We intend to finance our 2011 capital expenditure plan primarily from the sources described above under “Capital Resources”. We may be required to reduce or defer part of our 2011 capital expenditures plan if we are unable to obtain sufficient financing from these sources.

Oil and Gas Exploration and Development

We expect to spud approximately 40 gross and 13 net wells with capital expenditures of approximately $45.7 million in our 2011 oil and gas drilling program. We have allocated an estimated $33.2 million to be spent in the Williston Basin of North Dakota in the Rough Rider and Yellowstone/SEHR programs with Brigham Exploration and Zavanna LLC, respectively. The remaining $12.5 million in capital expenditure is budgeted to be spent on exploration initiatives in the San Joaquin Basin of California, in Texas and Louisiana (primarily onshore Gulf Coast), and our Colorado drilling program which we will operate. Amounts budgeted for each regional drilling program is contingent upon timing, well costs and success. If our non-Bakken drilling initiatives in California and Colorado are not initially successful, funds allocated for those drilling programs will be allocated to other drilling initiatives in due course. The actual number of gross and net wells could vary in each of these cases. We have also budgeted $1,000,000 for the acquisition of oil and gas leases during 2011.

Mt. Emmons Molybdenum Project

Under the terms of our agreement with TCM, we are responsible for all costs associated with operating the water treatment plant at the Mt. Emmons project. Annual operating costs during 2011 are projected to be approximately $1.8 million. Additionally, we have budgeted $750,000 for capital improvements in the plant which are expected to improve its efficiency.

In 2009, U.S. Energy and TCM purchased a 160 acre parcel of property near the Mt. Emmons project. Under the terms of the purchase agreement the Company is obligated to make annual payments to the prior owner in the amount of $200,000 beginning in January 2010 through January 2014 with 6% interest per annum on the unpaid balance. In addition to the retirement of the debt, we will be responsible for one half of the holding and operating costs of the acreage which are expected to be minimal.

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Through December 31, 2010, TCM has expended $12.2 million on the property which includes $3.5 million in option payments to U.S. Energy. TCM is contractually obligated to spend $2.5 million during 2011, including the $1.0 million option payment to the Company which was pre-paid by TCM in December 2010. As per the terms of the agreement with TCM, we will not be required to fund any of the proposed work to be performed on the property during 2011 unless TCM terminates the agreement. TCM, as project manager, is preparing and evaluating engineering and environmental trade off studies. A Plan of Operations was submitted in 2010 for baseline data collection to the U.S. Forest Service (“USFS”). All the costs related to these studies and activities under the Plan of Operations will be paid for by TCM as per the agreement.

Real Estate

Cash operating expenses at Remington Village are projected to be $1.0 million for 2011. We do not anticipate any major capital expenditures on the property. Remington Village is pledged as collateral for a $10.0 million line of credit with a commercial bank. At the date of this report there was no debt against Remington Village. We plan to obtain long term financing of the property during 2011 and ultimately sell the property to provide capital for the exploration and development or acquisition of oil and gas properties and or production.

Geothermal and Alternative Energy Projects

At December 31, 2010, our net investment was $2.8 million which reflected a 22.8% minority ownership position in a geothermal partnership. We are not obligated to fund cash calls and will suffer further dilution if we do not fund.

Insurance

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

Reclamation Costs

We have reclamation obligations of $159,000 related to our oil and gas wells and $144,000 related to the Mt. Emmons molybdenum property. No reclamation is expected to be performed on the existing wells at December 31, 2010 during the year ended December 31, 2011. Reclamation will only begin after the wells no longer produce oil or gas in economic quantities. The earliest projected reclamation will begin in 2013 in the Gulf Coast unless wells in other areas are abandoned due to operational challenges. As the Mt. Emmons project is developed, the reclamation liability is expected to increase. It is not anticipated that this reclamation work will occur in the near term. Our objective, upon closure of the proposed mine at the Mt. Emmons project, is to eliminate long-term liabilities associated with the property.

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Results of Operations

Year Ended December 31, 2010 Compared with the Year ended December 31, 2009

We recorded a net loss after taxes of $772,000 or $0.03 per share basic and diluted, for the year ended December 31, 2010 as compared to a net loss after taxes of $8.2 million, or $0.38 per share, during the year ended December 31, 2009.

We recognized $27.2 million in revenues during the year ended December 31, 2010 as compared to revenues of $10.3 million during same period in the prior year. Tabular representation of the increases in revenues as well as the income (loss) from operations for the years ended December 31, 2010 and 2009 is as follows:

	(In thousands)
	For the years ending
	December 31, 2010			December 31, 2009
Revenues	$	29,057		$	10,349
Realized loss from risk management activities		(156	)		--
Unrealized (loss) from risk management activities		(1,725	)		--
		27,176			10,349
Operating expenses		17,738			13,086
Depreciation, depletion and amortization		12,130			5,066
Impairment		1,540			1,468
		31,408			19,620
Operating (loss)	$	(4,232	)	$	(9,271	)

The significant increase in revenues of $16.8 million for the year ended December 31, 2010 as compared to those revenues recorded during the prior year is primarily a result of production of oil and gas in the Williston Basin. The increased expenses are a result of the increases in lease operating, work over, and depletion costs recognized during the year ended December 31, 2010. During the year ended December 31, 2009, we recorded an impairment of $1.5 million on the oil and gas operations due to depressed gas prices and dry hole costs which had been capitalized. As a result of increased oil and gas prices during 2010 and additional reserves to amortize the full cost pool, no impairment of our oil and gas assets was required during the year ended December 31, 2010.

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

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Oil and gas operations produced net operating income of $8.0 million during the year ended December 31, 2010 as compared to net operating income of $1.5 million from oil and gas operations during the year ended December 31, 2009. The following table details the results of operations from the oil and gas sector for the years ended December 31, 2010 and 2009:

	(In thousands)
	For the years ending
	December 31, 2010			December 31, 2009
Oil and gas revenues	$	26,548		$	7,581
Realized loss from risk management activities		(156	)		--
Unrealized (loss) from risk management activities		(1,725	)		--
		24,667			7,581
Operating expenses		6,073			1,085
Depreciation, depletion and amortization		10,610			3,571
Impairment		--			1,468
		16,683			6,124
Operating income	$	7,984		$	1,457

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The following table summarizes production volumes, average sales prices and operating revenues for the years ended December 31, 2010 and 2009:

	Year Ended
	December 31,						Increase
	2010			2009			(Decrease)
Production volumes
Oil (Bbls)		303,433			80,461			222,972
Natural gas (Mcf)		757,905			467,691			290,214
Natural gas liquids (Bbls)		19,104			5,987			13,117
Average sales prices
Oil (per Bbl)	$	72.11		$	66.22		$	5.89
Natural gas (per Mcf)		4.96			4.30			0.66
Natural gas liquids (per Bbl)		47.53			40.25			7.28
Operating revenues (in thousands)
Oil	$	21,881		$	5,328		$	16,553
Natural gas		3,759			2,012			1,747
Natural gas liquids		908			241			667
Total operating revenue		26,548			7,581			18,967
Lease operating expense		(3,056	)		(394	)		(2,662	)
Production taxes		(3,017	)		(691	)		(2,326	)
Risk management activities		(1,881	)		-			(1,881	)
Impairment		-			(1,468	)		1,468
Income before depreciation, depletion and amortization		18,594			5,028			13,566
Depreciation, depletion and amortization		(10,610	)		(3,571	)		(7,039	)
Income	$	7,984		$	1,457		$	6,527

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

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

	(In thousands)
	For the years ending
	December 31, 2010			December 31, 2009
Real estate revenues	$	2,509		$	2,768
Operating expenses		1,271			1,059
Interest expense		--			19
Depreciation, depletion and amortization		1,063			1,045
Impairment		1,540			--
		3,874			2,123
Operating (loss) income	$	(1,365	)	$	645

The decline in revenues for the year ended December 31, 2010 as compared to the same period of the prior year is as a result of lower average rental rates, discounts provided and occupancy rates during the year ended December 31, 2010. Occupancy rates were approximately 80% at December 31, 2009 and 89% at December 31, 2010. Operating expenses increased as a result of the multifamily housing project reaching maturity which added additional expenses to the grounds maintenance and ongoing maintenance of apartment units when property damage occurs or tenants move out. The property was appraised at December 31, 2010 and reflected a value of $21.0 million resulting in a $1.5 million impairment.

Mt. Emmons Molybdenum Project - Pursuant to the 2008 Exploration, Development and Mine Operating Agreement TCM, we are required to pay all costs associated with the water treatment plant at the Mt. Emmons project and thereby recorded $1.8 million in costs and expenses for that facility and $85,000 in holding costs of the Mt. Emmons project during the year ended December 31, 2010. During the year ended December 31, 2009, we expended $1.6 million in operating costs related to the water treatment plant and $323,000 in holding costs for the Mt. Emmons project.

General Administrative - General and administrative expenses decreased by $460,000 during the year ended December 31, 2010 as compared to general and administrative expenses for the year ended December 31, 2009.

Other income and expenses - As a result of the sale of two of Standard Steam Trust’s geothermal properties, we recorded an equity gain of $1.0 million from our investment in SST during the year ended December 31, 2010. We recorded an equity loss of $1.4 million for the year ended December 31, 2009. Equity losses from the investment in SST are expected to continue until such time as additional SST properties are sold, equity losses reduce the investment to zero or we sell the investment.

We recorded a gain on sale of marketable securities of $438,000 during the year ended December 31, 2010. The gain was related to the sale of shares of Sutter Gold Mining, Inc. and Kobex Resources, Inc. No similar gains were recorded in the prior year.

We recorded a gain on sale of assets of $115,000 during the year ended December 31, 2010. The gain was primarily related to the sale of an office building that we previously held as rental property. We recorded a loss on sale of assets of $43,000 during the year ended December 31, 2009.

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Interest income decreased from $314,000 during the year ended December 31, 2009 to $112,000 during the year ended December 31, 2010. The decrease is a result of lower amounts of cash invested in interest bearing instruments and lower interest received on those investments.

Interest expense of $70,000 during the year ended December 31, 2010 was related primarily to the financing of a property purchased with TCM near the Mt. Emmons project. During the year ended December 31, 2009 we recorded interest expense of $98,000. The increase over what we recorded in the year ended December 31, 2010 was primarily due to the construction loan for Remington Village which was fully repaid in January 2009.

We therefore recorded a net loss after taxes of $772,000, or $0.03 per share basic and diluted, during the year ended December 31, 2010 as compared to a net loss after taxes of $8.2 million, or $0.38 per share basic and diluted, during the year ended December 31, 2009.

Year Ended December 31, 2009 Compared with the Year ended December 31, 2008

The Company recorded a net loss after taxes of $8.2 million, or $0.38 per share, for the year ended December 31, 2009 as compared to a net loss after taxes of $1.4 million, or $0.06 per share, during the year ended December 31, 2008. The net loss for the year ended December 31, 2008 included a gain of $4.9 million, or $0.21 per share, from discontinued operations related to the sale of a portion of the Company’s investment in Sutter Mining Company, Inc.

Depreciation, amortization and depletion expense increased $3.6 million during the year ended December 31, 2009 over the prior year due primarily to the increased depletion on wells drilled in the Williston Basin and the a full years depreciation of the Company’s multifamily housing complex. Non-cash compensation decreased $601,000 during the year ended December 31, 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 $9.6 million in revenues during the year ended December 31, 2009 as compared to revenues of $2.3 million during the prior year. Fourth quarter revenues were on average four times greater than the first three quarters of 2009. The increase was as a result of the Company’s drilling activity in the Williston Basin wells with Brigham. The fourth quarter revenues were reflective of only six wells drilled and completed during the fourth quarter of 2009 with production occurring primarily during the months of November and December. Revenues during the fourth quarter increased by a factor of four times while expenses roughly doubled of the previous quarters. The increased expenses were a result of the increased depletion recognized on the increased oil production during the quarter. Also included in the increased operating expenses was a $1.4 million bonus accrual pursuant to the Company’s adopted performance compensation plan. The bonus was not paid until the first quarter of 2010. During the year ended December 31, 2009, the Company recorded an impairment of $1.5 million on its oil and gas operations due to depressed oil and gas prices during the first and third quarters of 2009 and only one producing well to spread the entire exploration cost over. As a result of increased oil and gas prices during the fourth quarter of 2009 and additional production to amortize the full cost pool over, no additional impairment was required during 2009.

The oil production from the Williston Basin not only increased revenue trends but also cut the operating loss by half on a quarterly basis. The Company has experienced a very high rate of completion in the Williston Basin with good initial production flows. Future wells may not perform as well. The multi stage frac completion techniques used by the Company and Brigham are relatively new which makes long term production projections uncertain. The Company relies on professional third party reserve engineers to calculate decline curves.

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Oil and gas operations produced a net operating gain during the year ended December 31, 2009 as compared to a loss from oil and gas operations during the year ended December 31, 2008. Production from the Williston Basin during the fourth quarter of 2009 increased revenues from oil and gas operations by 7.7 times over the prior three quarters of 2009 and 12 times over the revenues from oil and gas production during the twelve months ended December 31, 2008. The operating gain from oil and gas operations during the fourth quarter of 2009 was $2.9 million in comparison to an annual gain from oil and gas operations of $1.5 million. During the first three quarters of 2009, the Company recorded an impairment of $1.5 million.

The Company’s other revenue producing sector is commercial real estate. Although revenues increased $1.1 million during the year ended December 31, 2009 over the prior year, the Company experienced a decline in quarterly revenues throughout the year. The decline was as a result of lower occupancy rates at Remington Village. Expenses increased during the fourth quarter as a result of a bad debt write off of $64,000. As a result of a full year of operations, revenues increased as well as the operating gain from $51,000 in 2008 to $645,000 during the year ended December 31, 2009. Commercial real estate generated positive cash flow of $1.7 million during the year ended December 31, 2009 and $1.1 million during the year ended December 31, 2008. Interest expense was reduced from $417,000 during 2008 to $19,000 during 2009 as a result of the repayment of the construction loan utilized to build the property. The loan was retired in January of 2009 and no debt existed against the property as of December 31, 2009.

Mt. Emmons Molybdenum Property

When the Company entered into its agreement with TCM, it agreed to pay all costs associated with the water treatment plant at the Mt. Emmons project and thereby recorded $1.6 million in costs and expenses for that facility and $323,000 in holding costs of the Mt. Emmons project during the year ended December 31, 2009. During the year ended December 31, 2008, the Company expended $1.5 million in operating costs related to the water treatment plant and $834,000 in holding costs related to the Mt. Emmons project.

General Administrative

General and administrative expenses increased by $1.5 million during the year ended December 31, 2009 over those experienced at during the year ended December 31, 2008. The increase was as a result of the accrual of a yearend bonus to all employees of the Company as a result of meeting corporate and personal goals, meeting annual budget goals, increased share price and cash flow from operations. Under a Performance Compensation Plan (“PCP”) adopted by the board of directors, employees can earn from 33% to 100% of their base compensation as bonuses if the terms of the PCP are met. No employees earned 100% of their base compensation or the allowable amount under the PCP during 2009 as certain financial measurements were not met. The PCP was proposed by the Company’s Compensation Committee and adopted by the full Board in April 2009. Details of the PCP are disclosed in their entirety in the Company’s annual proxy statement for the annual meeting held in June of 2009. The bonus for 2009 performance was paid during the first quarter of 2010.

Other income and expenses – The Company recorded an equity loss of $1.4 million from its investment in SST during the year ended December 31, 2009 with no similar losses reported during the prior year. Equity losses from the Company’s investment in SST are expected to continue until such time as SST properties are sold, equity losses reduce the Company’s investment to zero or the Company sells its investment. Interest income decreased from $1.4 million during the year ended December 31, 2008 to $314,000 during the year ended December 31, 2009. The decrease was a result of lower amounts of cash

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invested in interest bearing instruments and lower interest paid on those investments. Interest expense during the year ended December 31, 2009 was related primarily to the construction loan for Remington Village, $19,000, and the financing of a property purchased with TCM near the Mt. Emmons project, $60,000. Interest expense during 2008 related primarily to the construction loan for Remington Village which was fully repaid in January 2009.

During the year ended December 31, 2008, the Company recorded a net gain on the sale of its controlling interest in Sutter Gold Mining, Inc of $4.9 million. No similar activities occurred during the year ended December 31, 2009.

The Company therefore recorded a net loss after taxes of $8.2 million, or $0.38 per share, during the year ended December 31, 2009 as compared to a net loss after taxes of $1.4 million, or $.06 per share, during year ended December 31, 2008.

Critical Accounting Policies

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

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated average prices per barrel of oil and per MMbtu of natural gas at the first of each month in the 12-month period prior to the end of the reporting period and costs, adjusted for contract provisions, financial derivatives that hedge the 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 tax assets directly attributable to 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 December 31, 2010 and December 31, 2009 which were not included in the amortized cost pool were $21.6 million and $5.4 million, respectively. These costs consist of wells in progress, seismic costs that are being analyzed for potential drilling locations as well as land costs and are related to unproved properties. No capitalized costs related to unproved properties are included in the amortization base at December 31, 2010 and December 31, 2009. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are proved, drilled or abandoned.

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

Ceiling Test - We perform a quarterly ceiling test for each of our oil and gas cost centers, which in 2010 and 2009, there was only one. The ceiling test incorporates assumptions regarding pricing and discount rates over which management has no influence in the determination of present value. In arriving at the ceiling test for the year ended December 31, 2010, the Company used $79.43 per barrel for oil and $4.38 per MMbtu for natural gas to compute the future cash flows of the Company’s producing property. The discount factor used was 10%.

At December 31, 2010, the ceiling was in excess of the net capitalized costs as adjusted for related deferred income taxes and no impairment was required. Furthermore, as of year-end there were no unproved properties that were considered to be impaired and reclassified to properties being amortized. Management will continue to review its unproved properties based on market conditions and other changes and if appropriate unproved property amounts may be reclassified to the amortized base of properties within the full cost pool.

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

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

Proved Reserves - Our estimates of proved reserves are based on quantities of oil and gas reserves which current engineering data indicates are recoverable from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are key elements in determining our depletion expense and our full cost ceiling limitation. Estimates of proved reserves are inherently imprecise because of uncertainties in projecting rates of production and timing of developmental expenditures, interpretations of geological, geophysical, engineering and production data and the quality and quantity of available data. Changing economic conditions also may affect our estimates of proved reserves due to changes in developmental costs and changes in commodity prices that may impact reservoir economics. We utilize independent reserve engineers to estimate our proved reserves annually.

On December 29, 2008, the SEC issued a revision to Staff Accounting Bulletin 113 (“SAB 113”) which established guidelines related to modernizing accounting and disclosure requirements for oil and natural gas companies. The revised disclosure requirements include provisions that permit the use of new

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technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The revised rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The revised disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. A significant change to the rules involves the pricing at which reserves are measured. The revised rules utilize a 12-month average price using first of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves rather than year-end prices. In addition, the 12-month average is used to measure ceiling test impairments and to compute depreciation, depletion and amortization. The revised rules became effective for reserve estimation at December 31, 2009 with first reporting for calendar year companies in their 2009 annual reports.

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

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

We review our investment in the Mt. Emmons project annually to determine if an impairment has occurred to the carrying value of the property. As a result of the market price for Molybdenum Oxide increasing from $11.50 per pound at December 31, 2009 to $16.60 per pound at December 31, 2010 and the reduction of the book value of Mt. Emmons by $3.0 million as a result of TCM’s option payments, we have determined that no impairment is needed to the book value of the property.

Long Lived Assets - Real Estate - We evaluate our long-lived assets, which consist of commercial real estate, for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. Impairment calculations are based on market appraisals. If rental rates decrease or costs increase to levels that result in estimated future cash flows, on an undiscounted basis, that are less than the carrying amount of the related asset, an asset impairment is considered to exist. Changes in significant assumptions underlying future cash flow estimates may have a material effect on our financial position and results of operations. The property was appraised at December 31, 2010. The appraisal reflected a value of $21.0 million which resulted in a $1.5 million impairment at December 31, 2010. At December 31, 2010, management determined that an impairment in the amount of $1.5 million existed on the long-lived asset as the December 31, 2010 appraised value was less than the net book value of the asset.

Use of Estimates - The preparation of financial statements in conformity with generally accepted accounting principles in the USA 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 financial statements, and the reported amounts of

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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 gas, these estimates could change in the near term and such changes could be material.

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

Revenue Recognition - We record oil and natural gas revenue under the sales method of accounting. Under the sales method, we recognize revenues based on the amount of oil or natural gas sold to purchasers, which may differ from the amounts to which we are entitled based on its interest in the properties. Gas balancing obligations as of December 31, 2010 were not significant. Revenues from real estate operations are reported on a gross revenue basis and are recorded at the time the service is provided.

Stock Based Compensation - We measure the cost of employee services received in exchange for all equity awards granted including stock options based on the fair market value of the award as of the grant date.

We recognize the cost of the equity awards over the period during which an employee is required to provide service in exchange for the award, usually the vesting period. As share-based compensation expense is recognized based on awards ultimately expected to vest, the expense has been reduced for estimated forfeitures based on historical forfeiture rates.

Income Taxes - We recognize deferred income tax assets and liabilities for the expected future income tax consequences, based on enacted tax laws, of temporary differences between the financial reporting and tax bases of assets, liabilities and carry forwards.

We recognize deferred tax assets for the expected future effects of all deductible temporary differences, loss carry forwards and tax credit carry forwards. Deferred tax assets are reduced, if deemed necessary, by a valuation allowance for any tax benefits which, based on current circumstances, are not expected to be realized. Management believes it is more likely than not that such tax benefits will be realized and a valuation allowance has not been provided.

Future Operations

We intend to acquire new oil and gas properties and pursue new business opportunities. Long term, we intend to be prepared to pay our share of the holding and development costs associated with the Mt. Emmons project.

Effects of Changes in Prices

Natural resource operations are significantly affected by changes in commodity prices. As prices for a particular mineral increase, values 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 those natural resources, but could make sales of such properties more difficult. Operational impacts of changes in mineral commodity prices are common in the natural

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resource business. Historical and current prices for the Company’s two main natural resource participation interests follow:

Oil and Gas - The ten year Cushing, OK WTI spot price for oil reached a high of $133.88 per barrel during June 2008 and a ten year low of $19.39 per barrel during December of 2001. As of December 31, 2010 the Cushing, OK WTI spot price for oil had increased to $89.15 per barrel.

The ten year U.S. Natural Gas City Gate Price reached a high of $12.48 per mcf in July of 2008 and the ten year low was $3.37 per mcf in October 2001. The price per mcf at December 31, 2010 was $5.74.

Higher oil and gas prices should positively impact our revenues going forward while lower oil and gas prices will have a negative impact not only on revenues, cash flows and profitability but also may impact ultimate reserve calculations for our wells. There is no assurance that our projected 2011 investments in oil and gas properties will be profitable.

Molybdenum - The ten year high for dealer molybdenum oxide was $38 per pound in June of 2005 declined to a ten year low of $8.03 per pound in April of 2009. The mean price of molybdenum oxide at December 31, 2010 and December 31, 2009 was $16.60 per pound and $11.50 per pound, respectively. The price of molybdenum will have a direct impact on the development of Mt. Emmons project.

Contractual Obligations

We had three divisions of contractual obligations at December 31, 2010: Debt to third parties of $600,000 with interest at 6% per annum, executive retirement of $1.0 million and asset retirement obligations of $303,000. The debt will be paid over a period of four years in equal installments of $200,000 with interest with the next payment due on January 2, 2012. The executive retirement liability will be paid out over varying periods starting after the actual projected retirement dates of the covered executives. The asset retirement obligations will be retired during the next 34 years. The following table shows the scheduled debt payment, projected executive retirement benefits and asset retirement obligations:

	(In thousands)
	Payments due by period
			Less		One to		Three to		More than
			than one		Three		Five		Five
	Total		Year		Years		Years		Years
Long-term debt obligations	$	600	$	200	$	400	$	--	$	--

Executive retirement		1,039		191		327		163		358

Asset retirement obligation		303		--		69		14		220

Totals	$	1,942	$	391	$	796	$	177	$	578

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Item 7A – Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas. The effects of such pricing volatility have been discussed above, and such volatility is expected to continue. A 10% fluctuation in the price received for oil and natural gas production would have an approximate $2.7 million impact on our 2010 annual revenues.

To mitigate some of our commodity risk, we use derivative instruments, typically fixed-rate swaps and costless collars to manage price risk underlying its oil and gas production. USE may also use puts, calls and basis swaps in the future. We do not hold or issue derivative instruments for trading purposes. The objective of utilizing the economic hedges is to reduce the effect of price changes on a portion of USE’s future oil production, achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. The use of these derivative instruments limits the downside risk of adverse price movements. However, there is a risk that such use may limit our ability to benefit from favorable price movements. Energy One may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the its existing positions.

Energy One's commodity derivative contracts as of December 31, 2010 are summarized below:

Quantity

Settlement Period

Counterparty

Basis

(Bbl/d)

Strike Price

Crude Oil Costless Collars

10/01/10 - 09/30/11

BNP Parabis

WTI

200

Floor:

75.00

Ceiling:

83.25

Crude Oil Swaps

10/01/10 - 09/30/11

BNP Parabis

WTI

200

Fixed:

79.05

01/01/11 - 12/31/11

BNP Parabis

WTI

200

Fixed:

89.60

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

		Fair Value at
Underlying	Location on	December 31,
Commodity	Balance Sheet	2010

Crude oil derivate contract	Current Liability	$	632,000
Crude oil derivate contract	Current Liability		789,000
Crude oil derivate contract	Current Liability		304,000
		$	1,725,000

These contracts are accounted for using the mark-to-market accounting method and accordingly, USE recognizes all unrealized and realized gains and losses related to these contracts currently in earnings and are classified as gain (loss) on derivative instruments, net in our consolidated statements of operations. The net loss realized by us related to these instruments was $156,000, $0 and $0 for the years ended December 31, 2010, 2009 and 2008, respectively.

Item 8 – Financial Statements

Financial statements meeting the requirements of Regulation S-X are included below.

	Page
Report of Independent Registered Public Accounting Firm	75
Financial Statements
Consolidated Balance Sheets as of December 31, 2010 and 2009	76
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008	78
Statement of Stockholders’ Equity	80
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008	83
Notes to Consolidated Financial Statements	85

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

U.S. Energy Corp.

We have audited the accompanying consolidated balance sheets of U.S. Energy Corp. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of U.S. Energy Corp. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), U.S. Energy Corp.’s and subsidiaries’ internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 14, 2011 expressed an unqualified opinion on the effectiveness of U.S. Energy Corp.’s internal control over financial reporting.

HEIN & ASSOCIATES LLP

Denver, Colorado

March 14, 2011

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

	December 31,		December 31,
	2010		2009
CURRENT ASSETS:
Cash and cash equivalents	$	6,010	$	33,403
Marketable securities
Held to maturity - treasuries		17,843		22,059
Available for sale securities		1,364		1,178
Accounts receivable
Trade		3,932		3,882
Reimbursable project costs		114		2
Income taxes		104		353
Other current assets		457		1,223
Total current assets		29,824		62,100

INVESTMENT		2,834		2,958

PROPERTIES AND EQUIPMENT:
Oil & gas properties under full cost method,
net of $14,563 and $3,953 accumulated
depletion, depreciation and amortization		70,374		26,002
Undeveloped mining claims		21,077		21,969
Commercial real estate, net		20,738		23,200
Property, plant and equipment, net		9,336		9,301
Net properties and equipment		121,525		80,472

OTHER ASSETS		1,833		1,193
Total assets	$	156,016	$	146,723

The accompanying notes are an integral part of these statements.

-76-

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

	December 31,		December 31,
	2010		2009
CURRENT LIABILITIES:
Accounts payable	$	14,915	$	6,500
Accrued compensation		1,669		1,748
Commodity risk management liability		1,725		--
Current portion of long-term debt		200		200
Other current liabilities		254		224
Total current liabilities		18,763		8,672

LONG-TERM DEBT, net of current portion		400		600

DEFERRED TAX LIABILITY		5,015		7,345

ASSET RETIREMENT OBLIGATIONS		303		211

OTHER ACCRUED LIABILITIES		847		762

SHAREHOLDERS' EQUITY:
Common stock, $.01 par value; unlimited shares
authorized; 27,068,610 and 26,418,713
shares issued, respectively		271		264
Additional paid-in capital		121,062		118,998
Accumulated surplus		8,713		9,485
Unrealized gain on marketable securities		642		386
Total shareholders' equity		130,688		129,133
Total liabilities and shareholders' equity	$	156,016	$	146,723

The accompanying notes are an integral part of these statements.

-77-

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

	Years ended December 31,
	2010			2009			2008
REVENUES:
Oil and gas	$	26,548		$	7,581		$	589
Realized (loss) on risk management activities		(156	)		--			--
Unrealized (loss) on risk management activities		(1,725	)		--			--
Real estate		2,509			2,768			1,633
		27,176			10,349			2,222

OPERATING EXPENSES:
Oil and gas		6,073			3,611			80
Oil and gas depreciation depletion and amortization		10,610			1,045			382
Impairment of oil and gas properties		--			1,468			--
Real estate		2,334			2,104			1,165
Impairment of real estate properties		1,540			--			--
Water treatment plant		1,793			1,636			1,462
Mineral holding costs		85			323			834
General and administrative		8,973			9,433			7,903
		31,408			19,620			11,826

OPERATING (LOSS):		(4,232	)		(9,271	)		(9,604	)
Other income and (expenses)
Gain/(loss) on sale of assets		115			(43	)		(17	)
Equity gain/(loss) in
unconsolidated investment		1,014			(1,374	)		--
Gain on sale of marketable securities		438			--			--
Impairment of marketable securities		--			--			(1,023	)
Miscellaneous income and (expenses)		113			15			83
Interest income		112			314			1,426
Interest expense		(70	)		(98	)		(486	)
		1,722			(1,186	)		(17	)

LOSS BEFORE INCOME TAX:		(2,510	)		(10,457	)		(9,621	)

The accompanying notes are an integral part of these statements.

-78-

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

	Years ended December 31,
	2010			2009			2008
Income taxes:
Current benefit from (provision for)		104			210			4,645
Deferred benefit from (provision for)		1,634			2,069			(1,319	)
		1,738			2,279			3,326

(LOSS) FROM CONTINUING OPERATIONS		(772	)		(8,178	)		(6,295	)

DISCONTINUED OPERATIONS
Loss from discontinued operations		--			--			(501	)
Gain on sale of discontinued
operations (net of taxes)		--			--			5,408
		--			--			4,907

NET (LOSS)	$	(772	)	$	(8,178	)	$	(1,388	)

NET (LOSS) INCOME PER SHARE
Basic and diluted (loss)
from continuing operations	$	(0.03	)	$	(0.38	)	$	(0.27	)
Basic and diluted income
from discontinued operations		--			--			0.21
	$	(0.03	)	$	(0.38	)	$	(0.06	)

Weighted average shares outstanding
Basic and diluted		26,763,995			21,604,959			23,274,978

The accompanying notes are an integral part of these statements.

-79-

U.S. ENERGY CORP.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(In thousands except share data)
													Unrealized
							Additional						Gain (Loss) on			Unallocated			Total
	Common Stock						Paid-In			Retained			Marketable			ESOP			Shareholders'
	Shares			Amount			Capital			Earnings			Securities			Contribution			Equity

Balance December 31, 2007		23,592,493		$	236		$	96,560		$	19,051		$	(256	)	$	(491	)	$	115,100

Net loss available
to common shareholders		--			--			--			(1,388	)		--			--			(1,388	)
Recognized impairment on
marketable securities		--			--			--			--			256			--			256
Unrealized tax effect on
on the unrealized loss		--			--			--			--			--			--			--
Comprehensive (loss)																				(1,132	)
Funding of ESOP		126,878			1			207			--			--			--			208
Vesting of stock warrants
to outside contractor		--			--			30			--			--			--			30
Issuance of common stock
2001 stock compensation plan		85,000			1			283			--			--			--			284
Vesting of stock options
issued to employees		--			--			1,151			--			--			--			1,151
Vesting of stock options
issued to outside directors		--			--			17			--			--			--			17
Cancellation of common stock
from the ESOP		(155,811	)		(2	)		(489	)		--			--			491			--
Issuance of common stock
from stock warrants		446,698			5			1,523			--			--			--			1,528
Deferred tax on FAS 123R
compensation		--			--			202			--			--			--			202

Common stock buy back program		(2,160,129	)		(22	)		(5,533	)		--			--			--			(5,555	)
Balance December 31, 2008		21,935,129		$	219		$	93,951		$	17,663		$	--		$	--		$	111,833

The accompanying notes are an integral part of these statements.

-80-

U.S. ENERGY CORP
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(continued)
(In thousands except share data)
													Unrealized
							Additional						Gain (Loss) on			Total
	Common Stock						Paid-In			Retained			Marketable			Shareholders'
	Shares			Amount			Capital			Earnings			Securities			Equity

Balance December 31, 2008		21,935,129		$	219		$	93,951		$	17,663		$	--		$	111,833

Net loss available
to common shareholders		--			--			--			(8,178	)		--			(8,178	)
Unrealized gain on
marketable securities		--			--			--			--			602			602
Unrealized tax effect on
on the unrealized gain		--			--			--			--			(216	)		(216	)
Comprehensive (loss)																	(7,792	)
Issuance of common stock		5,000,000			50			24,267			--			--			24,317

Funding of ESOP		36,583			--			217			--			--			217
Issuance of common stock
2001 stock compensation plan		80,000			1			185			--			--			186
Issuance of common stock
from stock warrants		71,088			1			232			--			--			233
Issuance of common stock
from stock options		1,984			--			5			--			--			5
Vesting of stock options
issued to employees		--			--			1,430			--			--			1,430
Vesting of stock warrants
to outside contractor		--			--			9			--			--			9
Vesting of stock options
issued to outside directors		--			--			56			--			--			56
Excess tax benefit on the exercise
stock options and warrants		--			--			38			--			--			38
Common stock buy back program		(706,071	)		(7	)		(1,392	)		--			--			(1,399	)
Balance December 31, 2009		26,418,713		$	264		$	118,998		$	9,485		$	386		$	129,133

The accompanying notes are an integral part of these statements.

-81-

U.S. ENERGY CORP
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(continued)
(In thousands except share data)
											Unrealized
					Additional						Gain (Loss) on			Total
	Common Stock				Paid-In			Retained			Marketable			Shareholders'
	Shares		Amount		Capital			Earnings			Securities			Equity

Balance December 31, 2009		26,418,713	$	264	$	118,998		$	9,485		$	386		$	129,133

Net loss		--		--		--			(772	)		--			(772	)
Unrealized gain on
marketable securities		--		--		--			--			400			400
Unrealized tax effect on
on the unrealized gain		--		--		--			--			(144	)		(144	)
Comprehensive (loss)															(516	)
Issuance of common stock		--		--		--			--			--			--

Funding of ESOP		42,802		--		260			--			--			260
Issuance of common stock
2001 stock compensation plan		80,000		1		429			--			--			430
Issuance of common stock
from stock options - employees		275,728		3		(455	)		--			--			(452	)
Issuance of common stock
from stock options and
warrants - others		251,367		3		743			--			--			746
Vesting of stock options		--		--		1,021			--			--			1,021
Vesting of stock warrants		--		--		66			--			--			66
Balance December 31, 2010		27,068,610	$	271	$	121,062		$	8,713		$	642		$	130,688

The accompanying notes are an integral part of these statements.

-82-

U.S. ENERGY CORP.
STATEMENTS OF CASH FLOWS

	(In thousands)
	For the years ended December 31,
	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(772	)	$	(8,178	)	$	(1,388	)
Income from the sale of SGMI stock		--			--			(5,408	)
Income from discontinued operations		--			--			501
Loss from continuing operations		(772	)		(8,178	)		(6,295	)
Reconcile net loss to net cash used in operations
Depreciation, depletion & amortization		12,130			5,066			1,426
Change in fair value of commodity price
risk management activities, net		1,725			--			--
Accretion of discount on treasury investment		(78	)		(183	)		(1,255	)
Impairment of marketable securities		--			--			1,023
Impairment of oil and gas properties		--			1,468			--
Impairment of real estate properties		1,540			--			--
Gain on sale of marketable securities		(438	)		--			--
Equity (gain)/loss from Standard Steam		(1,014	)		1,374			--
Net change in deferred income taxes		(1,584	)		(2,069	)		1,319
(Gain) loss on sale of assets		(115	)		43			17
Noncash compensation		1,710			1,935			2,536
Noncash services		66			65			46
Net changes in assets and liabilities
Accounts receivable		(162	)		(2,843	)		(342	)
Income tax receivable		249			5,543			(3,809	)
Other current assets		(386	)		(192	)		(18	)
Accounts payable		(567	)		80			(692	)
Accrued compensation expense		6			1,000			(283	)
Other liabilities		62			(557	)		(209	)
NET CASH PROVIDED BY
(USED IN) OPERATING ACTIVITIES		12,372			2,552			(6,536	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Net redemption (investment in) treasury investments		4,293			29,277			(49,897	)
Cash distributions from (to) Standard Steam		1,138			(877	)		(3,455	)
Acquisition & development of real estate		--			(3	)		(11,597	)
Acquisition & development of oil & gas properties		(45,933	)		(17,498	)		(5,354	)
Acquisition & development of mining properties		(123	)		(1	)		(2,905	)
Mining property option payment		1,000			2,000			--
Acquisition of property and equipment		(624	)		(410	)		(294	)
Proceeds from sale of marketable securities		602			--			--
Proceeds from sale of property and equipment		118			11			1,103
Net change in restricted investments		(330	)		4,651			1,842
NET CASH (USED IN)
PROVIDED BY INVESTING ACTIVITIES		(39,859	)		17,150			(70,557	)

The accompanying notes are an integral part of these statements.

-83-

U.S. ENERGY CORP.
STATEMENTS OF CASH FLOWS

	(In thousands)
	For the years ended December 31,
	2010			2009			2008
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock		294			24,516			1,528
Tax benefit from the exercise of stock options		--			38			--
Proceeds from short-term construction debt		--			--			11,423
Proceeds from long term debt		--			--			1,875
Repayments of debt		(200	)		(17,888	)		(363	)
Stock buyback program		--			(1,399	)		(5,554	)
NET CASH PROVIDED BY
FINANCING ACTIVITIES		94			5,267			8,909

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

NET (DECREASE) INCREASE IN
CASH AND CASH EQUIVALENTS		(27,393	)		24,969			(63,858	)

CASH AND CASH EQUIVALENTS
AT BEGINNING OF PERIOD		33,403			8,434			72,292

CASH AND CASH EQUIVALENTS
AT END OF PERIOD	$	6,010		$	33,403		$	8,434

SUPPLEMENTAL DISCLOSURES:
Income tax received	$	(353	)	$	(5,753	)	$	(945	)

Interest paid	$	22		$	39		$	69

NON-CASH INVESTING AND FINANCING ACTIVITIES:

Unrealized gain	$	642		$	386		$	--

Acquisition and development of oil and gas
properties through accounts payable	$	8,983		$	5,522		$	--

Acquisition and development of oil and gas
through asset retirement obligations	$	75		$	58		$	--

Development of mining properties
through asset retirement obligation	$	--		$	9		$	--

The accompanying notes are an integral part of these statements.

-84-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

A. BUSINESS ORGANIZATION AND OPERATIONS

U.S. Energy Corp. was incorporated in the State of Wyoming on January 26, 1966. U.S. Energy Corp. ("USE") engages in the acquisition, exploration, holding, sale and/or development of mineral properties. Principal asset interests at December 31, 2010 are in oil and gas, molybdenum, real estate and minority ownership in a geothermal partnership. Historically, USE also participated in other base and precious metals. Our gold related mining properties were sold during 2008.

B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Principles of Consolidation

The financial statements of USE as of December 31, 2010 include the accounts of USE and wholly owned subsidiaries Energy One, LLC (“Energy One”) and Remington Village, LLC (“Remington Village”). The consolidated financial statements as of December 31, 2009 and December 31, 2008, include USE and Remington Village. All inter-company balances and transactions have been eliminated in consolidation. The financial statements as of December 31, 2010, 2009 and 2008 reflect USE’s ownership in a geothermal partnership, Standard Steam Trust LLC (“SST”) which is accounted for using the equity method. At December 31, 2010 USE’s ownership interest in SST was 22.8%.

Cash and Cash Equivalents

USE considers all highly liquid investments with original maturities of three months or less to be cash equivalents. USE maintains its cash and cash equivalents in bank deposit accounts which exceed federally insured limits. At December 31, 2010 and 2009, USE had its cash and cash equivalents with several financial institutions, primarily invested in U.S. Treasury Bills. USE has not experienced any losses in such accounts and believe is the accounts are not exposed to any significant credit risk on cash and cash equivalents.

Marketable Securities

USE categorizes its marketable securities as available-for-sale or held-to-maturity. Increases or decreases in the fair value which are considered temporary are recorded within equity as comprehensive income or losses. Gains or losses as a result of sale are recorded in operations when realized.

-85-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Accounts Receivable

USE determines any required allowance by considering a number of factors including the length of time trade and other accounts receivable are past due and our previous loss history. USE provides reserves for account receivable balances when they become uncollectable. Payments subsequently received on such reserved receivables are credited to the allowance for doubtful accounts. During the year ended December 31, 2010, USE recorded $76,000 in bad debt expense related to its multifamily housing project. The balance of accounts receivable at December 31, 2010 are for the sale of oil and gas and have been collected subsequent to the balance sheet date. No reserve for uncollectable receivables was booked during the year ended December 31, 2010 or 2009.

Restricted Investments

USE accounts for cash deposits held as collateral for reclamation obligations as restricted investments. Maturities or release dates less than twelve months from the end of the reported accounting period are reported as current assets while maturities or release dates in excess of twelve months from report dates are reported as long term assets.

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. Following is a breakdown of the lives over which assets are depreciated:

Machinery and Equipment:
	Office Equipment	3 to 5 years
	Planes	15 years
	Field Tools and Hand Equipment	5 to 7 years
	Vehicles and Trucks	3 to 7 years
	Heavy Equipment	7 to 10 years
Buildings and Improvements:
	Service Buildings	20 years
	Corporate Headquarter Building	45 years

-86-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

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

	(In thousands)
	December 31,			December 31,
	2010			2009
Oil & Gas properties
Unproved	$	17,926		$	3,993
Wells in progress		3,694			1,367
Proved		63,317			24,595
		84,937			29,955
Less accumulated depreciation
depletion and amortization		(14,563	)		(3,953	)
Net book value		70,374			26,002

Mining properties		21,077			21,969

Commercial real estate		23,084			24,600
Less Accumulated depreciation		(2,346	)		(1,400	)
Net book value		20,738			23,200

Building, land and equipment		14,564			14,196
Less accumulated depreciation		(5,228	)		(4,895	)
Net book value		9,336			9,301
Totals	$	121,525		$	80,472

Oil and Gas Properties

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

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

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. At December 31, 2010, the book value of our oil and gas properties did not exceed the cost center ceiling. During the year ended December 31, 2009, USE recorded a non-cash impairment of $1.5 million.

Mineral Properties

USE 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 USE 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 December 31, 2010 and 2009 reflect capitalized costs associated with USE’s Mount Emmons molybdenum property near Crested Butte, Colorado. USE 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. USE’s carrying balance in the Mount Emmons property at December 31, 2010 and 2009 is as follows:


	(In thousands)
	December 31,			December 31,
	2010			2009
Costs associated with Mount Emmons
beginning of year	$	21,969		$	23,950
Development costs during the year		108			19
Option payment from Thompson Creek		(1,000	)		(2,000	)
Costs at end of year	$	21,077		$	21,969

Long-Lived Assets – Real Estate

USE evaluates its long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. Impairment calculations are generally based on market appraisals. If estimated future cash flows, on an undiscounted basis, are less than the carrying amount of the related asset, an asset impairment is considered to exist. Changes in significant assumptions underlying future cash flow estimates may have a material effect on USE's financial position and results of operations. During the year ended December 31, 2010, USE recorded an impairment of $1.5 million on its multifamily housing property as it is probable that the property will be sold in the near term. (See Subsequent Event Note R) No impairments of long lived assets existed were recorded at December 31, 2009 as the market value of the asset exceeded construction costs.

-88-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Derivative Instruments

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

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

Fair Value of Financial Instruments

The carrying amount of cash equivalents, receivables, other current assets, accounts payable and accrued expenses approximate fair value because of the short-term nature of those instruments. The recorded amounts for short-term and long-term debt approximate the fair market value due to the variable nature of the interest rates on the short-term debt, and the fact that interest rates remain generally unchanged from issuance of the long-term debt.

Asset Retirement Obligations

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

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

	(In thousands)
	December 31,		December 31,
	2010		2009
Beginning asset retirement obligation	$	211	$	144
Accretion of discount		17		12
Liabilities incurred		75		55
Ending asset retirement obligation	$	303	$	211

Mining properties	$	139	$	128
Oil & Gas Wells		164		83
Ending asset retirement obligation	$	303	$	211

Revenue Recognition

USE records natural gas and oil revenue under the sales method of accounting. Under the sales method, USE recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which USE is entitled based on its interest in the properties. Natural gas balancing obligations as of December 31, 2010 and 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.

Stock Based Compensation

USE measures the cost of employee services received in exchange for all equity awards granted including stock options based on the fair market value of the award as of the grant date.

USE has computed the fair values of its options granted to employees using the Black Scholes pricing model and the following weighted average assumptions (no options were granted in 2010 or 2009):

	Year Ended
	December 31,
	2010		2009		2008
Risk-free interest rate		--		--		3.23	%
Expected lives (years)		--		--		6.0
Expected volatility		--		--		56.51	%
Expected dividend yield		--		--		--

USE recognizes the cost of the equity awards over the period during which an employee is required to provide service in exchange for the award, usually the vesting period. As share-based compensation expense is recognized based on awards ultimately expected to vest, the expense has been reduced for estimated forfeitures based on historical forfeiture rates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Income Taxes

USE recognizes deferred income tax assets and liabilities for the expected future income tax consequences, based on enacted tax laws, of temporary differences between the financial reporting and tax bases of assets, liabilities and carry forwards.

Additionally, USE recognizes deferred tax assets for the expected future effects of all deductible temporary differences, loss carry forwards and tax credit carry forwards. Deferred tax assets are reduced, if deemed necessary, by a valuation allowance for any tax benefits which, based on current circumstances, are not expected to be realized. Management believes it is more likely than not that such tax benefits will be realized and a valuation allowance has not been provided.

Net Income (Loss) Per Share

Basic earnings per share are computed based on the weighted average number of common shares outstanding. Common shares held by the ESOP are included in the computation of earnings per share. Total shares held by the ESOP at December 31, 2010, 2009, and 2008 were 685,382, 642,913, and 606,330, respectively. Diluted earnings per share is computed based on the weighted average number of common shares outstanding adjusted for the incremental shares attributed to outstanding options and warrants to purchase common stock, if dilutive. Using the treasury stock method, potential common shares relating to options and warrants are excluded from the computation of diluted loss per share for the years ending December 31, 2010, 2009 and 2008 because they were anti dilutive. Dilutive options and warrants totaled 1,034,446, 282,504 and 226,246 at December 31, 2010, 2009 and 2008, respectively

Recent Accounting Pronouncements

Accounting Standards Update No. 2010-03 - In December 2008, the Securities and Exchange Commission published a Final Rule, Modernization of the Oil and Gas Reporting Requirements. The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices will affect impairment and depletion calculations. In January 2010, the FASB issued Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosure, to align the oil and gas reserve estimation and disclosure requirement of the SEC Final Rule with the ASC 932. The new disclosure requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. USE’s adoption of this Final rule for this annual reported dated December 31, 2009 affected our oil and gas disclosures but had no material effect on our financial position and results of operations.

Accounting Standards Update 2010-09 - In May 2009, the FASB issued FASB ASC 855, “Subsequent Events,” and in February 2010, the FASB issued ASC Update 2010-09, “Subsequent Events (Topic 855) – Amendments to Certain Recognition and Disclosure Requirements,” which establishes standards of accounting for and disclosure of events that occur after the balance sheet date but before

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

financial statements are issued. Under this standard, entities that file or furnish financial statements with the SEC, such as USE, are required to use an issued date in evaluating subsequent events. This standard, as updated, is effective February 24, 2010, and USE adopted it at that date. The adoption did not have a material impact on USE’s results of operations or financial position.

USE has reviewed other current outstanding statements from the FASB and does not believe that any of those statements will have a material adverse affect on the financial statements of USE when adopted.

C. SUTTER GOLD MINING COMPANY, INC. (“SGMI”)

On August 22, 2008, USE sold 39,062,720 common shares of SGMI that it owned, to RMB Resources Ltd. (“RMB”), as trustee for the Telluride Investment Trust. The sale of these shares represented approximately 49.9% of the outstanding common shares of SGMI for purchase price of $5.1 million. USE recorded a gain of $5.4 million from the sale and a loss from discontinued operations of $501,000 for the year ended December 31, 2008.

Under the terms of the agreement, USE retained an equity position of approximately 3,550,361 shares and the 5% net profits interest royalty. USE also participated in a non-brokered private placement by SGMI with the purchase of 4,545,455 units for total cash consideration of $496,000. USE also received 24-month warrants, which were extended an additional 12 months to August 2011, to purchase an additional 2,272,728 common shares of SGMI at a price of Cdn. $0.15 per share. During the year ended December 31, 2010 USE sold 3,000,000 shares of SGMI to a private third party for $525,000 cash consideration and recorded a gain of $378,000.

D. FAIR VALUE

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

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

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

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

Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. As of December 31, 2010, we held $19.2 million of investments in government securities and marketable securities. The fair value of the investments is reflected on the balance sheet as detailed below. The fair value of USE’s commodity risk management liabilities and other accrued liabilities are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. The fair value of USE’s other accrued liabilities that are reflected

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

on the balance sheet are detailed below. The other accrued liabilities are the long term portion of the executive retirement program.

	(In thousands)
			Fair Value Measurements at December 31, 2010 Using
	December 31		Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	2010		(Level 1)		(Level 2)		(Level 3)

Available for sale securities	$	1,364	$	1,364	$	--	$	--

Total assets	$	1,364	$	1,364	$	--	$	--

Commodity risk management liability	$	1,725	$	--	$	1,725	$	--
Other accrued liabilities		847		--		--		847

Total	$	2,572	$	--	$	1,725	$	847

	(In thousands)
			Fair Value Measurements at December 31, 2009 Using
	December 31		Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description		2009	(Level 1)		(Level 2)		(Level 3)

Available for sale securities	$	1,178	$	1,178	$	--	$	--

Total assets	$	1,178	$	1,178	$	--	$	--

Other accrued liabilities	$	762	$	--	$	--	$	762

Total	$	762	$	--	$	--	$	762

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

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


	(In thousands)
December 31, 2010
	Less Than 12 Months				12 Months or Greater				Total
			Unrealized				Unrealized				Unrealized
Description of Securities	Fair Value		Gain		Fair Value		Gain		Fair Value		Gain

Available for sale securities	$	1,364	$	1,003	$	--	$	--	$	1,364	$	1,003

Total	$	1,364	$	1,003	$	--	$	--	$	1,364	$	1,003

December 31, 2009
	Less Than 12 Months				12 Months or Greater				Total
			Unrealized				Unrealized				Unrealized
Description of Securities	Fair Value		Gain		Fair Value		Gain		Fair Value		Gain

Available for sale securities	$	1,178	$	602	$	--	$	--	$	1,178	$	602

Total	$	1,178	$	602	$	--	$	--	$	1,178	$	602

USE’s other financial instruments include cash and cash equivalents, accounts receivable, accounts payable, other current liabilities and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable and other current liabilities approximate fair value because of their immediate or short-term maturities. The carrying value of USE’s long-term debt approximates its fair market value since it interest rates have remained generally unchanged from the issuance of the long-term debt. The fair value and carrying value of our long-term debt was $600,000 and $800,000 as of December 31, 2010 and December 31, 2009, respectively.

E. COMMODITY PRICE RISK MANAGEMENT

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Energy One's commodity derivative contracts as of December 31, 2010 are summarized below:

Quantity

Settlement Period

Counterparty

Basis

(Bbl/d)

Strike Price

Crude Oil Costless Collars

10/01/10 - 09/30/11

BNP Parabis

WTI

200

Floor:

75.00

Ceiling:

83.25

Crude Oil Swaps

10/01/10 - 09/30/11

BNP Parabis

WTI

200

Fixed:

79.05

01/01/11 - 12/31/11

BNP Parabis

WTI

200

Fixed:

89.60

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


		Fair Value at
Underlying	Location on	December 31,
Commodity	Balance Sheet	2010

Crude oil derivate contract	Current Liability	$	632,000
Crude oil derivate contract	Current Liability		789,000
Crude oil derivate contract	Current Liability		304,000
		$	1,725,000

Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are recognized in the unrealized gain (loss) on risk management activities line on the consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recognized in the commodity price risk management activities line on the consolidated statement of operations. During the year ended December 31, 2010 we recognized a loss of $156,000 from the contract settlements of derivatives.

F. MINERAL PROPERTY TRANSACTIONS

Mount Emmons Molybdenum Properties

On August 19, 2008, USE and Thompson Creek Metals Company USA (“TCM”), a Colorado corporation headquartered in Englewood, Colorado, entered into an Exploration, Development and Mine Operating Agreement for USE’s Mount Emmons molybdenum property. TCM assigned the agreement to Mt. Emmons Moly Company, a Colorado corporation and wholly owned subsidiary of TCM effective September 11, 2008. Under the terms of the agreement TCM may acquire up to a 75% interest for $400 million (option payments of $6.5 million and project expenditures of $393.5 million).

The Agreement covers two distinct periods of time: The Option Period, during which TCM may exercise an option (the “Option”) to acquire up to a 50% interest in Mount Emmons; and the Joint

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Venture Period, during which TCM will form a joint venture with USE and also have an option to acquire up to an additional 25% interest in Mount Emmons. The following table sets forth the required option and property expenditures that Thompson Creek must make to own its interest in the Mount Emmons molybdenum property:

	(In thousands)
	Option Payments to U.S. Energy		Expenditures by Thompson Creek on the Project		Total
Closing	$	500			$	500	(1)
December 31, 2008				2,000		2,000	(2)
January 1, 2009		1,000				1,000	(3)
December 31, 2009				4,000		4,000	(4)
January 1, 2010		1,000				1,000	(5)
December 31, 2010				4,000		4,000	(6)
January 31, 2011		1,000				1,000	(7)
June 30, 2011				1,500		1,500

Total - First Stage		3,500		11,500		15,000	(8)

January 2012		1,000				1,000
January 2013		1,000				1,000
January 2014		1,000				1,000
Stage Two Expenditures				32,000		32,000	(9)

Total - Second Stage		3,000		32,000		35,000	(10)

Stage Three Expenditures		-		350,000		350,000	(11)

	$	6,500	$	393,500	$	400,000

(1) Paid at Closing on September 11, 2008
(2) Paid during the twelve months ended December 31, 2008
(3) Paid on January 2, 2009
(4) Paid $3,847,600 and deposited $142,400 into escrow for the project
(5) Paid on December 31, 2009
(6) Paid $4,798,400 and deposited $201,600 into escrow for the project
(7) Paid on December 31, 2010
(8) If TCM has paid a total of $15 million it has option to own 15%
(9) To be paid for the development of the project by July 31, 2018
(10) If TCM has paid a total of $50 million it has option to own 50%
(11) If TCM pays 100% of the next $350 million it has option to own 75% of the project.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Costs to operate the water treatment plant at the property are being paid solely by USE until TCM elects to exercise its option to own an interest in the property.

Failure by TCM to incur the required amount of expenditures by a deadline, or make an Option Payment to USE, subject to the terms of the Agreement, the Agreement may be terminated without further obligation to USE from TCM. TCM may terminate the Agreement at any time, but if earned and elected to accept, TCM will retain the interest earned and be responsible for that share of all costs and expenses related to Mount Emmons.

The Joint Venture Period; Joint Venture Terms:

Within six months of TCM’s election to acquire the 50% interest, TCM, in its sole discretion, shall elect to form a Joint Venture and either: (i) participate on a 50%-50% basis with USE, with each party to bear their own share of expenditures from formation date; or (ii) acquire up to an additional 25% interest in the project by paying 100% of all expenditures equal to $350 million (for a total of $400 million, including the $50 million to earn the 50% interest in the second stage of the Option Period), at which point the participation would be 75% TCM and 25% USE. Provided however, if TCM makes expenditures of at least $70 million of the $350 million in expenditures and TCM decides not to fund the additional $280 million in expenditures, TCM will have earned an additional 2.5% (for a total of 52.5%). Thereafter, TCM will earn an incremental added percentage interest for each dollar it spends toward the total $350 million amount.

At any time before incurring the entire $350 million, TCM in its sole discretion, may determine to cease funding 100% of expenditures, in which event USE and TCM then would share expenditures in accordance with their participation interests at that date, in accordance with the Joint Venture. With certain exceptions, either party’s interest is subject to dilution in the event of non-participation in funding the Joint Venture’s budgets.

Management of the Property

TCM is the Project Manager of Mount Emmons. A four person Management Committee governs the projects’ operations, with two representatives each from USE and TCM. TCM will have the deciding vote in the event of a committee deadlock.

If and when Mount Emmons goes into production, TCM will purchase USE’s share of the molybdic oxide produced at an average price as published in Platt’s Metals Weekly price less a discount with a cap and a floor. The discount band will be adjusted every five years based upon the United States’ gross domestic product.

Oil and Gas Exploration

USE 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Williston Basin, North Dakota

From August 24, 2009 to December 31, 2010, we have drilled and completed 11 gross initial Bakken Formation wells (4.89 net), 1 gross Three Forks formation well (0.17 net) and 1 gross (0.32 net) infill Bakken formation well under the Drilling Participation Agreement with Brigham Oil & Gas, L.P. (“Brigham”) a Delaware limited partnership, wholly-owned by Brigham Exploration Company (a Delaware corporation). Four gross initial Bakken formation wells (1.15 net) and 1 infill Bakken formation wells (0.32 net) were in progress at December 31, 2010. Brigham operates all of the wells.

During the year ended December 31, 2010, we completed 7 gross wells (2.41 net) with our percentage of the net costs of $18.5 million. Four gross wells (1.22 net) were drilled and awaiting completion at December 31, 2010 with net costs to us of $9.5 million. One additional gross well (0.25 net) was being drilled at December 31, 2010 with net costs to the Company of $2.0 million.

Brigham recently announced that the interpretation of the micro-seismic data from the 18 square mile data set accumulated during the Brad Olson 9-16 #2H fracture stimulation indicates that frac wings appear to extend laterally approximately 500' on either side of the wellbore, or 1,000' in total, per well. Based on a one mile wide spacing unit, results from the micro-seismic monitoring appear to support development of at least four wells per producing horizon per 1,280 acre spacing unit, or approximately eight total Bakken and Three Forks wells per spacing unit. If the state of North Dakota allows four wells per formation in each spacing unit, the Company could ultimately drill 60 Bakken formation and 60 Three Forks formation wells for a total of 120 wells. The drilling of each well typically takes 30 days while the completion typically takes 21-28 days.

Additionally, in December 2010, we signed two agreements with Zavanna, LLC (a private oil and gas company based in Denver, Colorado), and other parties, and paid $10,987,000 cash, to acquire a 35% working interest out of Zavanna’s working interests in oil and gas leases covering approximately 6,200 net acres in McKenzie County, North Dakota (see below). Net revenue interests are expected to be in the range of 26.95% to 28%, proportionately reduced depending on Zavanna’s actual WI%.

In December 2010, we committed to the drilling of two initial horizontal test wells into the Bakken Formation and paid an advance of $1,433,000 for drilling costs on an initial well in the Yellowstone Prospect; this well began drilling in January 2011. A second well was spud in February 2011. A third well (which will be the initial well on the SE HR Prospect), is expected to begin drilling in second quarter 2011.

Our interests in all the acreage is subject to reduction by operation of a 30% reversionary working interest in the separate acreage packages under each agreement. On the sooner to occur of 36 months after spudding each initial test well (the “Project Payout Period”), or our reaching “Project Payout,” our 35% working interest will be reduced to 24.5% with the NRI % also being proportionately reduced on all the acreage. Project Payout is that point in time when we have received proceeds from the sale of production (or from sale of all or part of the acreage to third parties) equal to 130% of: the $10,987,000 (paid on execution of the agreements), plus all drilling and completion costs (including dry hole costs) and surface gathering facilities, for all wells drilled on the acreage (and on any additional acreage

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

acquired in the two Areas of Mutual Interest contemplated by the agreements), referred to as the “Project Payout Properties.”

However, if Project Payout does not occur within the Project Payout Period, the reduction due to operation of the reversionary working interest will take effect on all acreage outside the Project Payout Properties, i.e., that acreage in which wells not have been drilled (including all infill locations in drilling units where the Project Payout Properties are located, and the interest in all subsequent operations thereon). After expiration of the Project Payout Period, all costs and expenses related to the Project Payout Properties will continue to be included in the Project Payout calculation until Project Payout occurs.

U.S. Gulf Coast

During the year ended December 31, 2010, we drilled 7 gross wells (0.94 net) in the U.S. Gulf Coast. One gross well (0.50 net) was successfully completed and is currently producing, 1 gross well (0.05 net) was in progress at December 31, 2010, 1 gross well (0.05 net) was completed, but not producing and 4 gross wells (0.34 net) have been plugged and abandoned. Our net investment in these wells through December 31, 2010 was $8.7 million.

California

Under an October 2010 agreement with Cirque Resources LP (“Cirque”) (a private exploration and development company based in Denver, Colorado), we paid $2,498,000 to Cirque to purchase a 40% working interest (32% NRI) in Cirque’s leases on 6,120 net mineral acres (2,448 acres net to our interest), in the San Joaquin Basin. Of the amount paid, $1,620,000 is an advance against our 40% working interest for the initial well, including 33% of Cirque’s 60% working interest share for the well. Cirque’s lease assignments to us, is held in escrow, until the end of the well’s drilling phase; if we have paid all the drilling costs (ours and Cirque’s carry), and the assignments will be recorded and released to us.

General

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

Full Cost Pool – Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at December 31, 2010 and 2009 which were not included in the amortized cost pool were $21.6 and $5.4 million, respectively. These costs consist of unproved 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

base at December 31, 2010 and 2009. 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.

Ceiling Test Analysis – USE performs a quarterly ceiling test for each of its oil and gas cost centers, which in 2010, there was only one. The ceiling test incorporates assumptions regarding pricing and discount rates and over which management has no influence in the determination of present value. In arriving at the ceiling test for the quarter ended December 31, 2010, USE used $79.43 per barrel for oil and $4.38 per MMbtu for natural gas (and adjusted for property specific gravity, quality, local markets and distance from markets) to compute the future cash flows of USE’s producing property. The discount factor used was 10%.

At December 31, 2010, the ceiling was in excess of the net capitalized costs as adjusted for related deferred income taxes and no impairment was required. We will continue to review our unproved properties based on market conditions and other changes and if appropriate, unproved property amounts may be reclassified to the amortized base of properties within the full cost pool.

During the year ended December 31, 2009, USE recorded impairments totaling $1.5 million, ($1.1 million in the first quarter of 2009 and $405,000 in the third quarter of 2009). These impairments were as a result of two factors, (1) low prices for natural gas during the quarter ended March 31, 2009, $3.58 per MMbtu and (b) a dry hole drilled during the quarter ended September 30, 2009, which resulted in costs exceeding the ceiling test.

Wells in Progress - Wells in progress represent the costs associated with unproved 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.

G. SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

Capitalized Costs

The following table presents information regarding USE’s net costs incurred in the purchase of proved and unproved properties, and in exploration and development activities:

	(In thousands)
	December 31,		December 31,
	2010		2009
Oil & Gas properties
Unproved	$	17,926	$	3,993
Wells in progress		3,694		1,367
Proved		63,317		24,595
		84,937		29,955

USE’s DD&A per equivalent BOE was $23.64 in 2010 and $21.72 in 2009.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Undeveloped properties as of December 31, 2010 include costs incurred in the following years:

	(In thousands)
	Acquisitions		Exploration		Development		Total
2007	$	371	$	--	$	--	$	371
2008		95		--		--		95
2009		910		--		--		910
2010		13,562		6,682		--		20,244
Total	$	14,938	$	6,682	$	--	$	21,620

Costs Incurred

Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below:

	(In thousands)
	Year Ended December 31,
	2010		2009		2008
Property acquisition costs:
Proved	$	--	$	--	$	--
Unproved		14,237		560		1,184
Exploration costs		35,899		21,107		4,194
Development costs		4,846		--		--
Total costs incurred	$	54,982	$	21,667	$	5,378

Results of Operations

Results of operations from oil and natural gas producing activities are presented below:

	(In thousands)
	For the years ending
	December 31, 2010			December 31, 2009
Oil and gas revenues	$	26,548		$	7,581
Unrealized (loss) from risk management activities		(1,725	)		--
Loss from risk management activities		(156	)		--
		24,667			7,581
Operating expenses		6,073			1,085
Depreciation, depletion and amortization		10,610			3,571
Impairment		--			1,468
		16,683			6,124
Operating income (loss)	$	7,984		$	1,457

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Oil and Natural Gas Reserves (Unaudited)

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.

Proved oil and natural gas reserve quantities at December 31, 2010 and 2009 and the related discounted future net cash flows before income taxes are based on the estimates prepared by Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. The reserve report for the period ended December 31, 2008 was prepared by Ryder Scott Company, L.P. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.

USE’s net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below:

December 31, 2010	Oil (BBLS)			Natural Gas or NGL (MCFE)
Beginning of year		811,789			1,646,482
Revisions of previous quantity estimates		(55,450	)		(234,852	)
Extensions, discoveries and improved recoveries		1,093,540			1,911,867
Sales of reserves in place		--			--
Production		(303,433	)		(872,529	)
End of Year		1,546,446			2,450,968

Proved developed reserves at end of year		1,362,733			2,311,682


December 31, 2009	Oil (BBLS)			Natural Gas or NGL (MCFE)
Beginning of year		29,798			1,000,000
Revisions of previous quantity estimates		(3,747	)		423,839
Extensions, discoveries and improved recoveries		866,199			710,621
Sales of reserves in place		--			--
Production		(80,461	)		(487,978	)
End of Year		811,789			1,646,482

Proved developed reserves at end of year		811,789			1,646,482

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Standardized Measure (Unaudited)

The standardized measure of discounted future net cash flows relating to USE’s ownership interests in proved oil and natural gas reserves as of year-end is shown below:

	(In thousands)
	Year Ended December 31,
	2010			2009			2008
Future cash inflows	$	124,629		$	51,024		$	7,112
Future costs:
Production		(36,299	)		(14,025	)		(1,154	)
Development		(6,774	)		(104	)		(64	)
Future income tax expense		(11,622	)		(8,273	)		(1,993	)
Future net cash flows		69,934			28,622			3,901
10% discount factor		(25,281	)		(8,638	)		(583	)
Standardized measure of discounted future net cash flows	$	44,653		$	19,984		$	3,318

Future cash flows for the years ended December 31, 2009 and 2010 are computed by applying average prices per barrel of oil and per MMbtu of natural gas at the first day of each month in the 12-month period prior to the end of the reporting period to year-end quantities of proved oil and natural gas reserves. Future cash flows for the year ended December 31, 2008 is based upon the price per barell of oil and per MMbtu of natural gas on the last day of 2008. Prices used in computing year end 2010, 2009 and 2008 future cash flows were $79.43/barrel, $61.18/barrel and $41.41/barrel, respectively, for oil and $4.38/MMbtu, $3.87/MMbtu and $5.88/MMbtu for natural gas, respectively. Future operating expenses and development costs are computed primarily by USE’s petroleum engineers by estimating the expenditures to be incurred in developing and producing USE’s proved oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions.

Future income taxes are based on year-end statutory rates, adjusted for the tax basis of oil and gas properties and available applicable tax assets. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of USE’s oil and natural gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Change in Standardized Measure (Unaudited)

Changes in standardized measure of future net cash flows relating to proved oil and natural gas reserves are summarized below:

	(In thousands)
	Year Ended December 31,
	2010			2009			2008
Balance at beginning of period	$	19,984		$	3,318		$	--
Sales of oil and gas, net of production costs		(20,476	)		(6,496	)		(509	)
Net change in prices and production costs		3,895			297			--
Net change in future development costs		--			--			--
Extensions and discoveries		40,011			26,721			5,820
Revisions of previous quantity estimates		(2,519	)		1,586			--
Previously estimated development costs incurred		--			--			--
Net change in income taxes		(2,138	)		(4,385	)		(1,993	)
Accretion of discount		2,576			531			--
Changes in production rates, timing and other		3,320			(1,588	)		--
Balance at end of period	$	44,653		$	19,984		$	3,318

Sales of oil and natural gas, net of oil and natural gas operating expenses, are based on historical pretax results. Extensions and discoveries and the changes due to revisions in standardized variables are reported on a pretax discounted basis.

H. GEOTHERMAL

During the year ended December 31, 2010, USE’s minority interest investment in Standard Steam Trust, LLC (“SST”), a Denver, Colorado based private geothermal resource acquisition and development company decreased. USE’s investment increased by recognizing a $1.0 million equity gain during the year ended December 31, 2010 and then decreased when USE received a $1.1 capital distribution from SST. USE’s net investment at December 31, 2010 was $2.8 million. Due to not funding cash calls during 2010 from SST USE’s ownership interest decreased from 23.8% to 22.8%. USE has notified SST that it does not intend to fund any future cash calls, which will result in dilution to USE’s ownership interest.

I. ENERGY SECTOR HOUSING

Remington Village – Gillette, Wyoming.

USE owns a nine building multifamily apartment complex, with 216 units on 10.15 acres located in Gillette, Wyoming. At December 31, 2010 the net book value of the multifamily housing complex was $22.2 million and the appraised value was $21.0 million. USE recorded an impairment on the asset of $1.5 million at December 31, 2010. (See Subsequent Events, Note R)

J. BNP RESERVE CREDIT FACILITY

On July 30, 2010, USE established a Senior Secured Revolving Credit Facility (the “Facility”) to borrow up to $75 million from BNP Paribas (“BNP”). At present, BNP is the only lender under the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Facility. In the future, the facility may include other members of a lending syndicate (the “Lenders”) as provided for in the Facility. BNPP also is the administrative agent for the Facility, which is governed by the following documents: Credit Agreement; Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement (the “Mortgage”); and Guaranty and Pledge Agreement (the “Guaranty”), which are referred to below together as the “Facility Documents.” The following summarizes the principal provisions of the Facility as set forth in the Facility Documents, which are filed as exhibits to this Report. The summary is qualified by reference to the complete text of the documents.

USE organized a wholly-owned subsidiary, Energy One LLC (“Energy One”), which will be the borrower under the Facility. USE has assigned to Energy One all of its rights, title and interest in certain oil and gas properties and equipment related thereto, rights under various operating agreements, proceeds from sale of production and from sale or other disposition of the properties. USE also has unconditionally and irrevocably guaranteed Energy One’s performance of its obligations under the Credit Agreement, including without limitation Energy One’s payment of all borrowings and related fees thereunder.

From time to time until expiration of the Facility (July 30, 2014), if Energy One is in compliance with the Facility Documents, Energy One may borrow, pay, and re-borrow funds from the Lenders, up to an amount equal to the Borrowing Base, which was initially established at $12 million. The Borrowing Base will be redetermined semi-annually, taking into account updated reserve reports prepared by USE’s independent consulting engineers. Any proposed increase in the Borrowing Base will require approval by all Lenders in the syndicate (presently only BNP), and any proposed Borrowing Base decrease will require approval by Lenders holding not less than two-thirds of outstanding loans and loan commitments. Using information from the June 30, 2010 financial statements and reserve reports of Energy One, BNP increased the borrowing base to $18.5 million.

Interest will be payable quarterly at the greater of the Prime Rate, the Federal Funds Effective Rate (plus 0.5%), and the adjusted LIBO for the three prior months, plus, an additional 2.25% to 3.25%, depending on the amount of the loan relative to the Borrowing Base. Interest rates on outstanding loans are adjustable each day by BNPP as administrative agent. Energy One may prepay principal at any time without premium or penalty, but all outstanding principal will be due on July 30, 2014. If there is a decrease in the Borrowing Base, the excess of outstanding loans over the Borrowing Base will be due over the six months following the redetermination.

In addition, on a quarterly basis, Energy One will pay BNP, for the account of each Lender (as applicable), a commitment fee of 0.50% of the unused amount of each Lender’s unused amount of its Facility lending commitment, computed daily until July 30, 2014.

Energy One is required to comply with customary affirmative covenants, and with negative covenants. The principal negative financial covenants (measured at various times as provided in the Credit Agreement) do not permit (i) Interest Coverage Ratio (Interest Expense to EBITDAX) to be less than 3.0 to 1; (ii) Total Debt to EBITDAX to be greater than 3.5 to 1; and (iii) Current Ratio (current assets plus unused lender commitments under the Borrowing Base) to be less than 1.0 to 1.0. EBITDAX is defined in the Credit Agreement as Consolidated Net Income, plus non-cash charges.

If Energy One fails to pay interest or principal when due, or fails to comply with the covenants in the Credit Agreement (after a reasonable cure period, if applicable), BNP as Administrative Agent may (and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

shall, if requested by the Majority Lenders (Lenders holding not less than 2/3 of the outstanding loan principal), declare the loans immediately due, and foreclose on Energy One’s assets and enforce USE’s guaranty.

At closing, pursuant to a separate fee letter with BNP, USE paid BNP $145,000 for initial arrangement and upfront fees, $59,000 to BNPP’s legal counsel for legal fees, and will be paying BNPP a commercially reasonable Facility fees in the future if the Borrowing Base is increased. Additionally, USE has paid Madison Williams and Company, investment banker to USE, $240,000 under the terms of a 2009 financial services agreement, in proportion to the initial $12 million Borrowing Base.

As of December 31, 2010 we had not borrowed from the Facility. On February 18, 2011 we borrowed $3.0 million under the Credit Facility to fund our initial participation in an Eagle Ford shale oil prospect in Zavala County, Texas.

K. OTHER LIABILITIES AND DEBT

As of December 31, 2010 and 2009, USE had current and long term liabilities associated with the following funding commitments:


	(In thousands)
	December 31,			December 31,
	2010			2009
Other liabilities and debt:
Other liabilities
Security deposits		191			150
Deferred rent		58			35
Employee health insurance self funding		5			--
Accrued expenses		--			29
Retainage on construction in progress		--			10
	$	254		$	224

Other long term liabilities:
Accrued retirement costs	$	847		$	762

Debt:
Long term Debt
Real estate note - collateralized by
property, interest at 6%	$	600		$	800

Less current portion		(200	)		(200	)
Totals	$	400		$	600

In December 2008, USE and TCM purchased land for $4 million ($2 million in January 2009, $400,000 annually for five years). USE is responsible for one-half the purchase price. As of December 31, 2010 USE has paid $1.4 million leaving $600,000 to be paid at the rate of $200,000 per year through 2013.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

At the date of filing of this annual report USE has a $10,000,000 line of credit from a commercial bank. The line of credit has a variable interest rate (5.5% minimum). The line of credit expired January 31, 2011 but was extended by the bank to April 15, 2011. As of the date of this report none of the line of credit had been drawn down. The line of credit is collateralized by USE’s multifamily housing project, Remington Village, and a corporate aircraft.

L. INCOME TAXES

The provision for income taxes is composed of the following:

	(In thousands)
	Years ended December 31,
	2010			2009			2008
Current income tax (benefit)
Federal	$	(104	)	$	(210	)	$	(4,551	)
State		--			--			(94	)
	$	(104	)	$	(210	)	$	(4,645	)

Deferred income tax (benefit)
Federal	$	(1,543	)	$	(1,794	)	$	1,319
State		(91	)		(275	)		--
	$	(1,634	)	$	(2,069	)	$	1,319

The effective income tax rate differs from the U.S. Federal Statutory income tax rate due to the following:

	(In thousands)
	Years ended December 31,
	2010			2009			2008
Federal statutory income tax rate	$	(853	)	$	(3,555	)	$	(3,271	)
State income income taxes, net of federal benefit		(50	)		(209	)		(96	)
Incentive stock options		258			404			338
Percentage depletion carryover		(1,067	)		(128	)		--
Other		(26	)		1,209			(297	)
	$	(1,738	)	$	(2,279	)	$	(3,326	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

The Components of deferred tax assets and liabilities as of December 31, 2010 and 2009 are as follows:

	(In thousands)
	December 31,			December 31,
	2010			2009
Deferred tax assets:
Net operating loss	$	1,857		$	2,078
Derivative instruments		621			--
Asset retirement obligation		109			40
Stock based compensation		287			629
Deferred compensation		372			534
Alternative minimum tax credit		706			810
Contribution carryover		27			19
Equity investments		362			--
Percentage depletion carryover		1,198			128
		5,539			4,238

Deferred tax liabilities:
Property and equipment		(10,149	)		(10,700	)
Marketable securities		(361	)		--
		(10,510	)		(10,700	)

Net deferred tax (liabilities)		(4,971	)		(6,462	)
Less: Valuation Allowance		--			--
Net deferred tax (liability)	$	(4,971	)	$	(6,462	)

During the year ended December 31, 2010, deferred tax assets increased by $1.3 million and deferred tax liabilities decreased by $0.2 million. The net change in deferred tax liabilities decreased by $1.5 million compared to the previous year. This decrease is comprised of a deferred income tax benefit $1.6 million, and a reduction to other comprehensive income of $0.1 million resulting from the future tax impact of unrealized gain on marketable securities.

USE has net operating loss carryovers as of December 31, 2010 of $6.4 million for federal income tax purposes and $4.4 million for financial reporting purposes. The difference of $2.0 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. The net operating losses may be used to offset taxable income through 2030. In addition, USE has alternative minimum tax credit carry-forwards of $0.7 million which are available to offset future federal income taxes over an indefinite period.

During 2010, the Internal Revenue Service (“IRS”) issued information document requests (“IDR’s”) requesting information for the tax years ended December 31, 2009, 2008 and 2007. USE responded to the IDR’s and is currently waiting on a response from the IRS as to whether or not the IRS will commence an examination of USE for those years. USE agreed to extend the statute of limitations for the 2007 tax year

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

until July 2012. USE does not anticipate any adjustments to the tax years ended December 31, 2007, 2008 and 2009.

USE adopted the applicable provisions of ASC 740 to recognize, measure, and disclose uncertain tax positions in the financial statements. Under ASC 740, tax positions must meet a “more-likely-than-not” recognition threshold to be recognized. During the year ended December 31, 2010, no adjustments were recognized for uncertain tax positions.

USE recognizes interest and penalties related to uncertain tax positions in income tax expense (benefit). No interest and penalties related to uncertain tax positions were accrued at December 31, 2010.

The tax years 2007 through 2009 for federal returns and 2006 through 2009 for state returns remain open to examination by the major taxing jurisdictions in which we operate, no material changes to unrecognized tax positions are anticipated during the next year.

M. SEGMENTS AND MAJOR CUSTOMERS

During the years ended December 31, 2010 and December 31, 2009, and December 31, 2008, USE, for financial reporting purposes, operated in three business segments, the exploration for and sale of oil and gas, rental of multifamily housing units and mining. As of December 31, 2010, no one customer had a majority of the units under contract in USE’s multifamily housing project in Gillette, Wyoming. USE’s operating segments are reflected in the tables below:

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

	(In thousands)
	For the years ended December 31,
	2010			2009			2008
Revenues:
Oil and gas	$	24,667		$	7,581		$	589
Real estate		2,509			2,768			1,633
Total revenues:		27,176			10,349			2,222

Operating expenses:
Oil and gas		16,683			6,124			462
Real estate		3,874			2,104			1,165
Mineral properties		1,878			1,959			2,296
Total operating expenses:		22,435			10,187			3,923

Interest expense
Oil and gas		--			--			--
Real estate		--			19			417
Mineral properties		48			60			--
Total interest expense:		48			79			417

Operating income/(loss)
Oil and gas	$	7,984		$	1,457		$	127
Real estate		(1,365	)		645			51
Mineral properties		(1,926	)		(2,019	)		(2,296	)
Operating income/(loss)
from identified segments		4,693			83			(2,118	)

General and administrative expenses		(8,973	)		(9,433	)		(7,903	)
Add back interest expense		48			79			417
Other revenues and expenses:		1,722			(1,186	)		(17	)
(Loss) before
income taxes	$	(2,510	)	$	(10,457	)	$	(9,621	)

Depreciation expense:
Oil and gas	$	10,610		$	1,045		$	382
Real estate		1,063			3,571			517
Mineral properties		77			54			49
Corporate		380			396			478
Total depreciation expense	$	12,130		$	5,066		$	1,426

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

	(In thousands)
	December 31,
	2010		2009		2008
Assets by segment
Oil and Gas properties	$	75,639	$	30,016	$	8,523
Real estate		20,800		23,450		30,980
Mineral properties		21,258		21,998		24,927
Corporate assets		38,319		71,259		78,201
Total assets	$	156,016	$	146,723	$	142,631

N. SHAREHOLDERS’ EQUITY

During 2010, USE issued 649,897 shares of common stock. Issued shares consist of (a) 275,728 shares as a result of the exercise of options by employees of USE; (b) 236,367 shares issued as a result of warrants being exercised (c) 80,000 shares issued to officers of USE pursuant to the 2001 Stock Compensation Plan; (d) 42,802 shares issued for the 2010 ESOP contribution and (e) 15,000 shares as a result of exercise of options by an outside director.

Stock Option Plans

The Board of Directors adopted the U.S. Energy Corp. 1989 Stock Option Plan for the benefit of USE’s employees. The Option Plan, as amended and renamed the 1998 Incentive Stock Option Plan (“1998 ISOP”), reserved 3,250,000 shares of USE’s $.01 par value common stock for issuance under the 1998 ISOP. Options which expired without exercise were available for reissue until the 1998 ISOP was replaced by the 2001 ISOP. The last options issued under the 1998 ISOP will expire if not exercised by January 9, 2011 and the 1998 ISOP will be terminated at that date.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

During the years ended December 31, 2010, 2008 and 2007 the following activity occurred under the 1998 ISOP:

	Year ended December 31,
	2010			2009		2008
Grants
Qualified		--			--		--
Non-Qualified		--			--		--
		--			--		--

Price of Grants
High		--			--		--
Low		--			--		--

Exercised
Qualified		35,000			--		--
Non-Qualified		389,215			--		--
		424,215			--		--
Total Cash Received	$	--	(1)	$	--	$	--

Forfeitures/Cancellations
Qualified		--			--		77,782
Non-Qualified		--			--		27,617
		--			--		105,399

(1) 263,971 shares valued at $1,396,000 were withheld from the option exercises to cover the cost of the exercises, federal income tax and statutory payroll taxes.

In December 2001, 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 (amended by approval of the shareholders in 2004 and 2007) reserves for issuance 25% of USE’s shares of common stock issued and outstanding at any time. The 2001 ISOP has a term of 10 years. Options issued under the 2001 ISOP remain exercisable until their expiration date under the terms of the 2001 ISOP.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

During the years ended December 31, 2010, 2009 and 2008 the following activity occurred under the 2001 ISOP:

	Year ended December 31,
	2010			2009		2008
Grants
Qualified		--			--		248,817
Non-Qualified		--			--		313,683
		--			--		562,500

Price of Grants
High		--			--	$	2.52
Low		--			--	$	2.52

Exercised
Qualified		111,359			1,984		--
Non-Qualified		163,893			--		--
		275,252			1,984		--
Total Cash Received	$	63,000	(1)	$	5,000	$	--

Forfeitures/Cancellations
Qualified		--			4,000		77,221
Non-Qualified		--			--		482,709
		--			4,000		559,930


(1) In addition to the cash exercise of 25,015 options: 43,676 shares valued at $301,000 were exchanged for exercises of 60,901 options; and 116,062 shares valued at $596,000 were withheld from the exercise of 189,336 options to cover the cost of the exercises, federal income tax and statutory payroll taxes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

A summary of the Employee Stock Option Plans activity in all plans for the year ended December 31, 2010, 2009 and 2008 is as follows:

	Year ended December 31,
	2010					2009					2008
	Options			Weighted Average Exercise Price		Options			Weighted Average Exercise Price		Options			Weighted Average Exercise Price
Outstanding at beginning
of the period		3,711,114		$	3.64		3,717,098		$	3.63		3,819,927		$	3.75
Granted		--		$	--		--		$	--		562,500		$	2.52
Forfeited		--		$	--		--		$	--		(5,333	)	$	4.97
Expired		--		$	--		(4,000	)	$	2.46		(659,996	)	$	3.37
Exercised		(699,467	)	$	2.63		(1,984	)	$	2.52		-		$	--
Outstanding at period end		3,011,647		$	3.87		3,711,114		$	3.64		3,717,098		$	3.63
Exercisable at period end		2,404,148		$	3.78		2,614,453		$	3.43		2,131,269		$	3.29

Weighted average fair
value of options
granted during
the period				$	--				$	--				$	1.41

During the year ended December 31, 2010 a total of 699,467 options were exercised by employees by the payment of $63,000 in cash and the surrender of 325,195 shares valued at $1.8 million. In the year ended December 31, 2009, 1,984 options were exercised by the payment of $5,000. No options were exercised during the year ended December 31, 2008.

Option related compensation expense is recognized over the vesting period of the options and is calculated using the Black Scholes option pricing model. USE initially assumed no forfeitures, but has subsequently reduced the cumulative expense based on historical forfeiture.

No option related compensation expense was recognized for options which vested prior to the adoption of FAS 123R. Prior to the adoption of FAS 123R, USE accounted for option compensation pursuant to APB Opinion No. 25. The following table sets forth the option compensation related expense for the years ended December 31, 2007 through the vesting period of the employee options outstanding at December 31, 2010:

					Option Related Compensation Expense for the Year Ended December 31,
Year Ended December 31,	Options Granted		Total Expense		2007		2008			2009		2010		2011		Thereafter
2005		700,000	$	--	$	--	$	--		$	--	$	--	$	--	$	--
2006		25,000		12,000		15,000		(3,000	)		--		--		--		--
2007		1,558,000		4,355,000		592,000		1,081,000			1,167,000		757,000		756,000		2,000
2008		562,500		791,000		--		73,000			263,000		264,000		191,000		--
2009		--		--		--		--			--		--		--		--
2010		--		--		--		--			--		--		--		--
		2,845,500	$	5,158,000	$	607,000	$	1,151,000		$	1,430,000	$	1,021,000	$	947,000	$	2,000

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

The following table summarizes information about employee stock options outstanding and exercisable at December 31, 2010:

Grant Price Range		Options Outstanding at December 31, 2010		Weighted average remaining contractual life in years		Weighted average exercise price		Options exercisable at December 31, 2010		Weighted average exercise price

$	2.25		125,112		0.94	$	2.25		125,112	$	2.25
$	2.26 - $2.40		10,000		0.03	$	2.40		10,000	$	2.40
$	2.41 - $2.46		397,319		3.50	$	2.46		397,319	$	2.46
$	2.47 - $2.52		462,880		7.73	$	2.52		275,381	$	2.52
$	2.53 - $3.86		373,768		4.79	$	3.86		373,768	$	3.86
$	3.87 - $3.90		377,928		0.93	$	3.90		377,928	$	3.90
$	3.91 - $4.97		1,264,640		6.57	$	4.97		844,640	$	4.97

			3,011,647		5.16	$	3.87		2,404,148	$	3.78

The following table sets forth the number of options available for grant as well as the intrinsic value of the options outstanding and exercisable:

	2010		2009		2008
Available for future grant		3,765,506		3,327,780		1,924,524
Intrinsic value of option exercised	$	1,956,000	$	14,000	$	--
Aggregate intrinsic value of options outstanding	$	6,660,000	$	8,514,000	$	--
Aggregate intrinsic value of options exercisable	$	5,526,000	$	6,543,000	$	--

Employee Stock Ownership Plan

The Board of Directors of USE adopted the U.S. Energy Corp. 1989 Employee Stock Ownership Plan ("ESOP") in 1989, for the benefit of all USE’s employees. Employees become eligible to participate in the ESOP after one year of service which must consist of at least 1,000 hours worked. After the employee becomes a participant in the plan, he or she must have a minimum of 1,000 hours of service in each plan year to be considered for allocations of funding from USE. Employees become 20% vested after three years of service and increase their vesting by 20% each year thereafter until such time as they are fully vested after eight years of service.

An employee’s total compensation paid, which is subject to federal income tax, up to an annual limit of $245,000, $245,000 and $230,000 for the years ended December 31, 2010, 2009 and 2008, respectively, is the basis for computing how much of the total annual funding is contributed into his or her personal account. An employee’s compensation divided by the total eligible compensation paid to all plan participants is the percentage that each participant receives on an annual basis. USE funds 10% of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

all eligible compensation annually in the form of common stock and may fund up to an additional 15% to the plan in common stock. As of December 31, 2010, all shares of USE’s stock that have been contributed to the ESOP have been allocated. The estimated fair value of shares that are not vested is approximately $156,900.

During the year ended December 31, 2010, the Board of Directors of USE approved a contribution of 42,802 shares to the ESOP at the price of $6.08 for a total expense of $260,000. This compares to contributions to the ESOP during the year ended December 31, 2009 and 2008 of 36,583 and 126,876 shares to the ESOP at prices of $5.93 and $1.64 per share, respectively. The expense for the contributions during the years ended December 31, 2009 and 2008 were $217,000 and $208,000, respectively.

Warrants to Others

As of December 31, 2010, there were 320,000 warrants outstanding to purchase shares of USE's common stock. Of the total outstanding warrants, 276,667 were exercisable. USE values these warrants using the Black-Scholes option pricing model and expenses that value over various terms based on the nature of the award. Activity for the periods ended December 31, 2010, 2009 and 2008 for warrants is presented in the following table:

	Year ended December 31,
	2010					2009					2008
	Warrants			Weighted Average Exercise Price		Warrants			Weighted Average Exercise Price		Warrants			Weighted Average Exercise Price
Outstanding at beginning
of the period		581,367		$	2.91		1,036,387		$	3.43		1,445,585		$	3.58
Granted		10,000		$	5.04		--		$	--		170,000		$	2.59
Forfeited		(20,000	)	$	2.52		--		$	--		--		$	--
Expired		--		$	--		(383,932	)	$	4.26		(132,500	)	$	3.98
Exercised		(251,367	)	$	2.97		(71,088	)	$	3.27		(446,698	)	$	3.42
Outstanding at period end		320,000		$	2.95		581,367		$	2.91		1,036,387		$	3.43
Exercisable at period end		276,667		$	2.93		494,701		$	2.98		886,387		$	3.58

Weighted average fair
value of options
granted during
the period				$	2.99				$	--				$	1.28

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

The following table summarizes information about non employee warrants outstanding and exercisable at December 31, 2010:

Grant Price Range		Warrants Outstanding at December 31, 2010		Weighted average remaining contractual life in years		Weighted average exercise price		Warrants exercisable at December 31, 2010		Weighted average exercise price

	2.25		10,000		0.93	$	2.25		10,000	$	2.25
$	2.25 - $2.46		100,000		1.99	$	2.46		100,000	$	2.46
$	2.47 - $2.52		110,000		7.07	$	2.52		76,667	$	2.52
$	2.53 - $3.86		75,000		3.35	$	3.86		75,000	$	2.77
$	2.87 - $3.90		15,000		0.93	$	3.90		15,000	$	3.86
$	3.91 - $5.04		10,000		9.48	$	5.04		-	$	3.90

			320,000		4.21	$	2.95		276,667	$	2.93

These warrants are held by persons or entities other than employees and officers of USE.

USE has computed the fair values of its warrants granted to outside consultants and outside directors using the Black Scholes pricing model and the following weighted average assumptions:

	Year Ended
	December 31,
	2010	2009	2008
Risk-free interest rate	2.24%	--	2.41% - 3.23%
Expected lives (years)	6.0	--	1.78 - 6.0
Expected volatility	63.79%	--	46.05% - 56.51%
Expected dividend yield	--	--	--

O. COMMITMENTS, CONTINGENCIES AND OTHER

Legal Proceedings

From time to time, we are party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position or results of operations. Following are currently pending legal matters:

Water Rights Litigation –Mount Emmons Molybdenum Property

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

operations and associated permits with the Forest Service and BLM within six years of entry of the 2002 Decree, or within six years of the final determination in the Applicant’s pending patent application, whichever occurs later. The BLM issued the mineral patents on April 2, 2004. Although, the issuance of the patents was appealed, on April 30, 2007, the United States Supreme Court made a final determination upholding BLM’s issuance of the mineral patents.

On August 11, 2010, High Country Citizen’s Alliance, Crested Butte Land Trust and Star Mountain Ranch Association, Inc. (“Opposers”) filed a Motion for Summary Judgment alleging that the Plan of Operations did not comply with the Forest Service regulations and did not satisfy certain Reality Check Limitations contained in the Water Rights Decree. On September 24, 2010, U.S. Energy filed a Response to the Motion for Summary Judgment responding that the Plan of Operations complied with the Forest Service and BLM’s regulations and satisfied the Reality Check provision contained in the Water Rights Decree and alternately that the Company had until April 30, 2013 to comply with the Reality Check provision, which is six years after the Supreme Court denied certiorari in the judicial proceeding. The U.S. Department of Justice also filed a response on behalf of the Forest Service and BLM that the Court cannot second guess the Forest Service’s determination that the Company’s Plan of Operations satisfied the Forest Service and BLM’s regulations.

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

On January 3, 2008, the Division of Reclamation, Mining and Safety of the Colorado Department of Natural Resources (“DRMS”) approved the Company’s Notice of Intent to Conduct Prospecting for the Mount Emmons molybdenum property (“NOI”). The approved NOI provides 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.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

On March 8, 2008, High Country Citizens’ Alliance (‘HCCA”) filed a request for hearing before the Colorado Mine Land Reclamation Board (“MLRB”) appealed the NOI, claiming it was not prospecting, but rather development and mining. On May 14, 2008, the MLRB denied HCCA’s Request for Hearing and also denied their Request for a Declaratory Order. Citing Colorado law, the MLRB determined that HCCA did not have standing or the right to appeal DRMS’s approval of the NOI under Colorado law.

Asset Retirement Obligations

Reclamation liabilities at December 31, 2010 were those related to the Mount Emmons molybdenum property and oil and gas wells drilled in the Gulf Coast area and Williston Basin of North Dakota.

Mount Emmons

The Mount Emmons molybdenum property is located on fee property within the boundary of U.S. Forest Service (“USFS”) land. Although mining of the mineral resource will occur on the fee property, associated ancillary activities will occur on USFS land. USE and TCM submitted an initial Plan of Operations in accordance with 36 C.F.R. Sec. 228.4(d) on March 31, 2010. An additional Plan of Operations will be submitted to the USFS for the USFS approval, which approval is required before initial construction and mining and processing may occur. Under the procedures mandated by National Environmental Protection Act (“NEPA”), the USFS will prepare an environmental analysis in the form of

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

an Environmental Assessment and/or and Environmental Impact Statement to evaluate the predicted environmental and social economic impacts of the proposed development and mining of the Mount Emmons molybdenum property. The NEPA process provides for public review and comment of the proposed plan.

Obtaining and maintaining the various permits for the mining operations at Mount Emmons will be complex, time-consuming, and expensive. Changes in a mine’s design, production rates, quality of material mined, and many other matters, often require submission of the proposed changes for agency approval prior to implementation. In addition, changes in operating conditions beyond USE and TCM’s control, or changes in agency policy and Federal and State law, could further affect the successful permitting of the mine operations.

Although USE is confident that the Plan of Operations for Mount Emmons will ultimately be approved by the USFS, the timing and cost, and ultimate success of the mining operation cannot be predicted. The reclamation liability at December 31, 2010 for Mount Emmons was $139,000.

Oil and Gas Wells

USE is responsible for its portion of reclamation costs on the oil and gas wells it participates in once the well is no longer economic and needs to be plugged and abandoned. At December 31, 2010, USE’s liability for its wells was $159,000. The wells are projected to be reclaimed at various times beginning in 2013 and ending in 2043. In the event that the reclamation cost changes the reclamation cost will be adjusted.

401(K) Plan

The Board of Directors of USE adopted the U.S. Energy Corp. 401(K) Plan ("401(K)") in 2004. USE matches 50% of an employee’s salary deferrals up to a maximum contribution per employee of $4,000 annually. USE expensed $49,000, $48,000, and $51,000 for the years ended December 31, 2010, 2009 and 2008, respectively related to these contributions.

Executive Officer Compensation

In December 2001, the Board of Directors adopted (and the shareholders approved) the 2001 Stock Award Plan to compensate its executive officers. The Stock Award Plan was amended on June 22, 2007 by a vote of the shareholders. Under the Plan, 20,000 shares may be issued annually to each officer during his employment. During the years ended December 31, 2010, 2009 and 2008, USE collectively issued 80,000, 80,000, and 85,000 shares of stock to these officers, respectively. While in USE’s employ, the officers have agreed not to sell, pledge or otherwise dispose of or encumber the shares granted under the 2001 Stock Award Plan. In consideration of this agreement USE has agreed to pay all taxes due on the shares granted to the officers.

USE is committed to pay the surviving spouse or dependent children of the former Chairman and Founder, who passed away on September 4, 2006, one years’ full salary and 50% of that amount annually for an additional four years thereafter. During the three years ended December 31, 2010, 2009 and 2008, respectively USE paid $85,000 per annum under this plan. USE will pay $57,000, the remaining amount under the plan, during 2011. The Board of Directors also approved payment of 50% of the then existing wages to USE’s former General Counsel for a period of five years. USE will pay $85,000 annually under

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

this agreement beginning at date of retirement, January 12, 2007, to January 12, 2012. Neither of these two retirement benefits to former officers is funded, however, an estimated liability has been accrued as of December 31, 2010 in the amount of $137,000

On October 20, 2005, the Board of Directors of USE adopted an Executive Retirement Policy for the then Chairman/CEO President/COO and CFO/Treasurer/V.P. Finance. Under the terms of the Retirement Plan, the retired executive will receive payments equaling 50% of the greater of (i) the amount of compensation the Executive Officer received as base cash pay on his/her final regular pay check or (ii) the average annual pay rate, less all bonuses, he/she received over the last five years of his/her employment with Company. To be eligible for this benefit, the executive officer must serve in one of the designated executive offices for 15 years, reach the age of 60 and be an employee of USE on December 31, 2010. Through each executive’s employment contract USE has also agreed to pay for health insurance for the executive and his spouse from date of retirement, after age 60, until the executive is eligible for Medicare. During 2007, the Board of Directors voted unanimously to fund the retirement benefit for the then active officers who qualified under the plan. The funding is held in a separate trust account that is managed by an independent trustee and is subject only to the claims of creditors in the event of insolvency of USE. At December 31, 2010, USE had funded the executive retirement account with the amount calculated by a third party actuary, of $949,000 recorded as Other Long Term Assets. Additional amounts will be deposited annually until each executive’s 60th birthday. At December 31, 2010, there were three officers who were included in the Retirement Plan and four that may qualify for the health insurance benefit.

Compensation expense for executives under all plans for the year ended December 31, 2010, 2009 and 2008 was $314,000, $192,000, and $108,000, respectively. The total accrued liability for executive retirement under all plans at December 31, 2010, 2009 and 2008 was $1.0 million, $915,000, and $879,000, respectively.

USE has also established a mandatory retirement age of 70 unless the board specifically requests the services of an employee or officer beyond that age. Certain officers and one employee have agreements for payment of severance in the event of a change of control of USE.

Operating Leases

USE is the lessor of portions of the office buildings and building improvements that it owns. USE occupies the majority of its main office building. The leases are accounted for as operating leases and expire at various periods through September, 2011, and provided for minimum monthly receipts of $8,000 through December 31, 2010. Rental income under the agreements was $98,000, $138,000, and $102,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Future minimum receipts for non-cancelable operating leases are $96,000 for the year ended December 31, 2011.

P. DISCONTINUED OPERATIONS

On August 22, 2008, USE sold its controlling interest in SGMI. As a result of the sale the revenues and expenditures of SGMI for the year ended December 31, 2008 are presented in the December 31, 2008 Statement of Operations as Discontinued Operations. USE recognized a gain of $5.4 million, net of taxes on the sale of its interest in SGMI and a loss of $501,000 for the discontinued operations of SGMI. (See Subsequent Event Note R)

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Q. SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

	(In thousands except per share data)
	Three Months Ended
	December 31,			September 30,			June 30,			March 31,
	2010			2010			2010			2010
Operating revenues	$	6,524		$	6,363		$	6,826		$	7,463

Operating income (loss)	$	(4,403	)	$	(874	)	$	(291	)	$	1,336

Income (loss) before income tax and discontinued operations	$	(4,021	)	$	(826	)	$	(120	)	$	2,457

Benefit from (provision for) income taxes	$	2,087		$	591		$	(10	)	$	(930	)

Net income (loss)	$	(1,934	)	$	(235	)	$	(130	)	$	1,527

Income (loss) per share, basic	$	(0.07	)	$	(0.01	)	$	--		$	0.06

Basic weighted average shares outstanding		26,973,834			26,855,513			26,734,636			26,487,162

Income (loss) per share, diluted	$	(0.07	)	$	(0.01	)	$	--		$	0.05

Diluted weighted average shares outstanding		26,973,836			26,855,513			26,734,636			27,785,572

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

	(In thousands except per share data)
	Three Months Ended
	December 31,			September 30,			June 30,			March 31,
	2009			2009			2009			2009
Operating revenues	$	6,013		$	1,377		$	1,499		$	1,460

Operating income (loss)	$	(1,354	)	$	(2,296	)	$	(2,194	)	$	(3,427	)

Income (loss) before income tax and discontinued operations	$	(2,194	)	$	(2,608	)	$	(2,196	)	$	(3,459	)

Benefit from (provision for) income taxes	$	992		$	864		$	(689	)	$	1,112

Net (loss)	$	(1,202	)	$	(1,744	)	$	(2,885	)	$	(2,347	)

Loss per share, basic	$	(0.05	)	$	(0.09	)	$	(0.13	)	$	(0.11	)

Basic weighted average shares outstanding		22,195,694			21,288,841			21,311,266			21,654,519

Loss per share, diluted	$	(0.05	)	$	(0.09	)	$	(0.13	)	$	(0.11	)

Diluted weighted average shares outstanding		22,195,694			21,288,841			21,311,266			21,654,519

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

	(In thousands except per share data)
	Three Months Ended
	December 31,			September 30,			June 30,			March 31,
	2008			2008			2008			2008
Operating revenues	$	1,175		$	569		$	329		$	149

Operating loss	$	(1,688	)	$	(2,648	)	$	(2,499	)	$	(2,769	)

Loss before income tax and discontinued operations	$	(2,609	)	$	(2,458	)	$	(2,320	)	$	(2,234	)

Benefit from income taxes	$	886		$	1,062		$	704		$	674

Discontinued operations, net of tax	$	--		$	5,198		$	(134	)	$	(157	)

Net income (loss)	$	(1,722	)	$	3,801		$	(1,750	)	$	(1,717	)

Income (loss) per share, basic
Continuing operations	$	(0.08	)	$	(0.06	)	$	(0.07	)	$	(0.06	)
Discontinued operations		--			0.22			--			(0.01	)
	$	(0.08	)	$	0.16		$	(0.07	)	$	(0.07	)

Basic weighted average shares outstanding		22,195,694			23,505,340			23,615,657			23,749,056

Income (loss) per share, diluted
Continuing operations	$	(0.08	)	$	(0.06	)	$	(0.07	)	$	(0.06	)
Discontinued operations		--			0.22			--			(0.01	)
	$	(0.08	)	$	0.16		$	(0.07	)	$	(0.07	)

Diluted weighted average shares outstanding		22,195,694			23,505,340			23,615,657			23,749,056

R. SUBSEQUENT EVENTS

Southeast Colorado Oil Prospect

On January 31, 2011 USE entered into an acquisition, exploration and development agreement with a private party in an oil and gas prospect located in Southeast Colorado.

Under the terms of the agreement, we acquired an 80% working interest in approximately 3,000 net acres. We have also agreed to carry the seller for their 20% working interest to casing point in the initial well. The dry hole cost of the well is estimated to be $250,000. We will be the operator of the project and the initial well is planned to be spud in the second quarter of 2011. All subsequent wells will be drilled on a heads up basis. The prospect is a Mississippian target with an expected total drilling depth of approximately 6,500 feet.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010, 2009 AND 2008

(Continued)

Crimson Exploration Inc. Agreement

On February 22, 2011 USE entered into a participation agreement with Crimson Exploration Inc. (“Crimson”) to acquire a 30% working interest in an oil prospect and associated leases located in Zavala County, Texas.

Under the terms of the agreement, USE will earn a 30% working interest (22.5% net revenue interest) in approximately 4,675 gross contiguous acres (1,402.5 net mineral acres) through a combination of a cash payment and commitment well carry. All future drilling and leasing will be proportionate to each parties working interest. For competitive reasons, the financial terms of the transaction will not be disclosed at this time.

The prospect is an Eagle Ford shale oil window target in Zavala County, Texas. Crimson will operate and tentatively plans to spud the first well in the area during the second quarter of this year. The well is planned to be drilled to a total drilling depth of approximately 12,500 feet 6,000 ft. vertical, 6,500 ft. horizontal), and to be completed with 14 fracture stimulation stages.

BNP Credit Facility

On February 18, 2011, USE borrowed an initial $3.0 million under our credit agreement with BNP Paribas to fund a portion of our initial participation in the Eagle Ford Shale oil prospect in Zavala County, Texas.

Real Estate

In 2011 USE determined that it will use the equity in its multifamily housing project in Gillette, Wyoming to further the development of its oil and gas business. It plans on doing this by first obtaining a long term loan against the property and then selling it to a third party. USE will therefore report its real estate operations under discontinued operations during 2011.

Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A. Controls and Procedures

Effectiveness of Disclosure Controls and Procedures

We are required to maintain disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) that are assigned to ensure that required information is recorded, processed, summarized and reported within the required timeframe, as specified in the rules set forth by the SEC. Our disclosure controls and procedures are also designed to ensure that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2010 and, based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of December 31, 2010.

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Management’s Annual Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, and effected by our Board, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of USE; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Forward looking statements regarding the effectiveness of internal controls during future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on our assessment, we believe that, as of December 31, 2010, our internal control over financial reporting was effective based on those criteria.

Our internal control over financial reporting as of December 31, 2010, has been audited by Hein & Associates LLP, the independent registered public accounting firm who also audited our consolidated financial statements. Hein & Associates LLP’s report on our internal control over financial reporting appears on page 128 of this Annual Report.

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 December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

U.S. Energy Corp.

We have audited U.S. Energy Corp.’s (the “Company”) internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. U.S. Energy Corp.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, U.S. Energy Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of U.S. Energy Corp. and subsidiaries and the related consolidated statement of operations, shareholders’ equity and cash flows for the year ended December 31, 2010 of U.S. Energy Corp. and our report dated March 14, 2011 expressed an unqualified opinion.

HEIN & ASSOCIATES LLP

Denver, Colorado

March 14, 2011

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Item 9B – Other Information

None

PART III

In the event a definitive proxy statement containing the information being incorporated by reference into this Part III is not filed within 120 days of December 31, 2010, we will file such information under cover of a Form 10-K/A.

Item 10 - Directors and Executive Officers of the Registrant

The information required by Item 10 with respect to directors and certain executive officers is incorporated herein by reference to our Proxy Statement for the Meeting of Shareholders to be held in June 2010, under the captions Proposal 1: Election of Directors, Filing of Reports Under Section 16(a), and Business Experience and Other Directorships of Directors and Nominees.

USE has adopted a Code of Ethics. A copy of the Code of Ethics will be provided to any person without charge upon written request addressed to Steven R. Youngbauer, Secretary, 877 North 8th West, Riverton, Wyoming 82501.

Information Concerning Executive Officers Who Are Not Directors

Steven R. Youngbauer is not a director of USE. Mr. Youngbauer (age 61) has been General Counsel and Corporate Secretary for USE since January 23, 2007. He serves at the will of the board of directors. There are no understandings between Mr. Youngbauer and any other person pursuant to which he was named an officer or General Counsel. He has no family relationships with any of the other executive officer or directors of USE. During the past five years, Mr. Youngbauer has not been involved in any Reg. S-K Item 401(f) proceeding.

Item 11 - Executive Compensation

The information required by Item 11 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders to be held in June 2011, under the captions “Executive Compensation and Director's Fees” and “Other Compensation”.

Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Matters

The information required by Item 12 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders to be held in June 2011, under the caption "Principal Holders of Voting Securities."

Item 13 - Certain Relationships and Related Transactions

The information required by Item 13 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders to be held in June 2011, under the caption “Certain Relationships and Related Transactions.”

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Item 14 - Principal Accountant Fees and Services

The information required by Item 14 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders to be held in June 2010, under the caption “Principal Accountant Fees and Services”.

Glossary of Oil and Gas Terms

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and in this report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcfe. One billion cubic feet of natural gas equivalent. In reference to natural gas, natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of oil, condensate or natural gas liquids.

Boe. A barrel of oil equivalent is determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquid.

Completion. The installation of permanent equipment for the production of oil or natural gas. Completion of the well does not necessarily mean the well will be profitable.

Completion Rate. The number of wells on which production casing has been run for a completion attempt as a percentage of the number of wells drilled.

Developed Acreage. The number of acres, which are allocated or assignable to producing wells or wells capable of production.

Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of an oil or gas well.

Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

Fault. A break in the rocks along which there has been movement of one side relative to the other side.

Fault Block. A body of rocks bounded by one or more faults.

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Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.

Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.

Mcf. One thousand cubic feet of natural gas.

MMBtu. One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the percentage working interest we own.

Net Production. Production that we own less royalties and production due others.

Oil. Crude oil, condensate or other liquid hydrocarbons.

Operator. The individual or company responsible for the exploration, development, and production of an oil or gas well or lease.

Pay. The vertical thickness of an oil and gas producing zone. Pay can be measured as either gross pay, including non-productive zones or net pay, including only zones that appear to be productive based upon logs and test data.

PV10. The pre-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized Measure. The after-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

Trend. A geographical area that has been known to contain certain types of combinations of reservoir rock, sealing rock and trap types containing commercial amounts of hydrocarbons.

Working Interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

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PART IV

Item 15 - Exhibits, Financial Statements, Schedules, Reports, and Forms 8-K

(a) Exhibit No.	Title of Exhibit

3.1**	Restated Articles of Incorporation (incorporated by reference from Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed September 14, 1990)

3.1(a)**	Articles of Amendment to Restated Articles of Incorporation (incorporated by reference from Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed September 14, 1992)

3.1(b)**	Articles of Amendment (Second) to Restated Articles of Incorporation (establishing Series A Convertible Preferred Stock) (incorporated by reference from Exhibit 3.1(B) to the Company’s Annual Report on Form 10-K filed September 13, 2000)

3.1(c)**	Articles of Amendment (Third) to Restated Articles of Incorporation (increasing number of authorized shares) (incorporated by reference from Exhibit 3.1(C) to the Company’s Registration Statement on Form S-3 (333-75864), filed December 21, 2001)

3.1(d)**	Articles of Amendment to Restated Articles of Incorporation (providing that directors may be removed by the shareholders only for cause) (incorporated by reference from Exhibit 10.1 to the Company’s Report on Form 8-K filed June 26, 2006)

3.1(e)**	Articles of Amendment to Restated Articles of Incorporation (creating Series P Preferred Stock) (see exhibit 4.11 below)

3.2**	Restated Bylaws, as amended through April 17, 2009 (incorporated by reference from Exhibit 3.2 to the Company’s Report on Form 8-K filed April 21, 2009)

4.1**	Amendment to 1998 Incentive Stock Option Plan (incorporated by reference from Exhibit 4.1 to the Company’s Annual Report on Form 10-K filed August 29, 2001, and amended on June 18, 2002 and September 25, 2002)

4.2**	2001 Incentive Stock Option Plan (amended in 2003) (incorporated by reference from Exhibit 4.2 to the Company’s Annual Report on Form 10-K filed April 15, 2005)

4.3**	2008 Stock Option Plan for Independent Directors and Advisory Board Members (incorporated by reference from Exhibit 4.3 to the Company’s Annual Report on Form 10-K filed March 13, 2009)

4.4**	Warrant to Purchase Common Shares, effective October 15, 2005, between R. Jerry Falkner and U.S. Energy Corp. (incorporate by reference from exhibit 4.9 to the Company’s Annual Report on Form 10-KA filed November 4, 2009)

4.5**	Class B Warrant to Purchase Common Shares dated March 2, 2004 as amended through July 16, 2007, between Bourne Capital, LLC and U.S. Energy Corp.

4.6**	Rights Agreement dated as of September 19, 2001, amended as of September 30, 2005, between U.S. Energy Corp. and Computershare Trust Company, Inc. as Rights Agent. The Articles of Amendment to the Restated Articles of Incorporation creating the Series P Preferred Stock are included as Exhibit C to the Rights Agreement, as well as the form of Right Certificate and Summary of Rights (incorporated by reference from Exhibit 4.1 to the Company’s Registration Statement on Form 8-A12G/A filed November 17, 2005)

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4.7**	USE 2001 Officers’ Stock Compensation Plan (incorporated by reference from Exhibit 4.21 to the Company’s Annual Report on Form 10-K filed September 13, 2002)

10.1**	Exploration, Development and Mine Operating Agreement dated August 19, 2008, by and between U.S. Energy Corp. and Thompson Creek Metals Company USA – Redacted(1) (incorporated by reference from Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed November 10, 2008)

10.2**	Form of Production Payment Royalty Agreement (Exhibit A to the Asset Purchase Agreement with sxr Uranium One, Inc.) (incorporated by reference from Exhibit 10.2 to the Company’s Report on Form 8-K filed February 23, 2007)

10.3**	Amendment to Agreements, effective January 31, 2007, between Uranium Power Corp. and U.S. Energy Corp., Crested Corp., and USECC (incorporated by reference from Exhibit 10.5 to the Company’s Annual Report on Form 10-K filed April 2, 2007)

10.4(a)**	BNP Paribas Lending Facility – Credit Agreement (incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed August 2, 2010)

10.4(b)**	BNP Paribas Lending Facility – Mortgage Agreement (incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K filed August 2, 2010)

10.4(c)**	BNP Paribas Lending Facility – Guaranty (incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K filed August 2, 2010)

14.0**	Code of Ethics (incorporated by reference from Exhibit 14 to the Company’s Annual Report on Form 10-K filed March 30, 2004)

16.0**	Concurrence letter of former accountants (incorporated by reference from Exhibit 16(B) to the Company’s Report on Form 8-K/A filed February 1, 2007)

21.1*	Subsidiaries of Registrant

23.0*	Consent of Ryder Scott Company L.P.

23.1*	Consent of Cawley, Gillespie & Associates, Inc.

23.2*	Consent of Independent Registered Accounting Firm (Hein & Associates LLP)

31.1 *	Certification under Rule 13a-14(a) Keith G. Larsen

31.2 *	Certification under Rule 13a-14(a) Robert Scott Lorimer

32.1 *	Certification under Rule 13a-14(b) Keith G. Larsen

32.2 *	Certification under Rule 13a-14(b) Robert Scott Lorimer

99.1*	Reserve Report (Ryder Scott Company L.P.)

99.2*	Reserve Report (Cawley, Gillespie & Associates, Inc.)

* Filed herewith. ** Previously filed. (1) This agreement was filed in redacted format and a request for confidential treatment was submitted to the Securities and Exchange Commission in 2008. On February 13, 2009, the Commission granted the request.

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(b)	Reports on Form 8-K. In the last quarter of 2010, the Registrant filed six (6) reports on Form 8-K: October 6, 2010 - Production from State 36-1 #2H well. November 2, 2010 - Acquisition, Exploration and Development Agreement November 3, 2010 - Production from Brad Olsen 9-16 #2H well. November 9, 2010 - 3rd Quarter highlights and Financial results. December 14, 2010 – Participation Agreements. December 16, 2009 – Retirement of Officer/Board of Director.
(c)	See paragraph a(3) above for exhibits.
(d)	Financial statement schedules see above. No other financial statements are required to be filed.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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: March 11, 2010	By:	/s/ Keith G. Larsen
		KEITH G. LARSEN, Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Date: March 11, 2010	By:	/s/ Keith G. Larsen
		KEITH G. LARSEN, Director, Chairman and CEO


Date: March 11, 2010	By:	/s/ Robert Scott Lorimer
		ROBERT SCOTT LORIMER
		Principal Financial Officer/
		Chief Accounting Officer, and Director


Date: March 11, 2010	By:	/s/ Mark J. Larsen
		MARK J. LARSEN, President and Director


Date: March 11, 2010	By:	/s/ Allen S. Winters
		ALLEN S. WINTERS, Director


Date: March 11, 2010	By:	/s/ H. Russell Fraser
		H. RUSSELL FRASER, Director


Date: March 11, 2010	By:	/s/ Stephen V. Conrad
		STEPHEN V. CONRAD, Director


Date: March 11, 2010	By:	/s/ Michael H. Feinstein
		MICHAEL H. FEINSTEIN, Director

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