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, 2012

¨	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:

Common Stock, $0.01 par value

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

None

(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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES 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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

Smaller reporting company ¨

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, 2012): $57,980,000.

Class		Outstanding at March 11, 2013
Common stock, $.01 par value	27,667,602

Documents incorporated by reference: Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2013 annual meeting of stockholders to be filed within 120 days after December 31, 2012.

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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	8

Oil and Gas	8

Activities other than Oil and Gas	15

ITEM 1 A. RISK FACTORS	16

Risks Involving Our Business	16

Risks Related to Our Stock	30

ITEM 1 B. UNRESOLVED STAFF COMMENTS	31

ITEM 2. PROPERTIES	32

ITEM 3. LEGAL PROCEEDINGS	49

ITEM 4. MINE SAFETY DISCLOSURES	51

PART II	51

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASE OF EQUITY SECURITIES	51

ITEM 6. SELECTED FINANCIAL DATA	53

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS	55

Forward Looking Statement	55

General Overview	55

Results of Operations	60

Overview of Liquidity and Capital Resources	70

Capital Resources	71

Capital Requirements	72

Overview of Cash Flow Activities	73

Critical Accounting Policies	74

Future Operations	77

Effects of Changes in Prices	77

Contractual Obligations	77

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	78

ITEM 8. FINANCIAL STATEMENTS	80

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	129

ITEM 9A. CONTROLS AND PROCEDURES	129

ITEM 9B. OTHER INFORMATION	132

PART III	132

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	132

ITEM 11. EXECUTIVE COMPENSATION	132

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	132

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	133

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES	133

PART IV	136

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	136

SIGNATURES	139

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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 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts are forward-looking statements.

Examples of forward-looking statements in this Annual Report include:

·	planned capital expenditures for oil and gas exploration and environmental compliance;

·	potential drilling locations and available spacing units, and possible changes in spacing rules;

·	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 in North Dakota, the Eagle Ford shale in Texas and other areas;

·	timing of drilling additional wells and performing other exploration and development projects;

·	expected spacing and the number of wells to be drilled with our oil and gas industry partners;

·	when “Pooled Payout” or similar thresholds will be reached for the purposes of our agreements with Brigham and Zavanna;

·	expected working and net revenue interests, and costs of wells, relating to the drilling programs with our partners;

·	actual decline rates for producing wells in the Bakken/Three Forks and Eagle Ford formations;

·	submission of a plan of operations to the U.S. Forest Service and approval of such plan in connection with the Mt. Emmons molybdenum project (“Mt. Emmons Project”), the receipt of necessary permits relating to the project, and the expected length of time to permit and develop the project;

·	future cash flows, expenses and borrowings;

·	pursuit of potential acquisition opportunities;

·	anticipated business activities in the Gillette, Wyoming area and their impact on our multi-family housing complex;

·	our expected financial position;

·	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,” “up to,” and similar terms and phrases. Though we believe that the expectations reflected in these statements are reasonable, they involve certain assumptions, risks and uncertainties. Results could differ materially from those anticipated in these statements as a result of numerous factors, including, among others:

For oil and gas:

·	our ability to obtain sufficient cash flow from operations, borrowing and/or other sources to fully develop our undeveloped acreage positions;

volatility in oil and natural gas prices, including potentially 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, and which could adversely impact the borrowing base available under our credit facility with Wells Fargo Bank;

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·	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 return on investment;

·	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 related midstream infrastructure and services;

·	competition in leasing new acreage and for drilling programs with operating companies, resulting in less favorable terms or fewer opportunities being available;

·	higher drilling and completion costs related to competition for drilling and completion services and shortages of labor and materials;

·	unanticipated weather events resulting in possible delays of drilling and completions and the interruption of anticipated production streams of hydrocarbons, which could impact expenses and revenues, respectively; and

·	unanticipated down-hole mechanical problems, which could result in higher than expected drilling and completion expenses and/or the loss of the wellbore or a portion thereof.

For the molybdenum property:

·	the ability to obtain permits required to initiate mining and processing operations; and the risks associated with adverse rulings concerning these permits;

·	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;

·	the ability to fund the capital expenditures required to build the mine and its infrastructure, and the related processing facilities, after all permits and a favorable feasibility study have been received;

·	the ability to find a suitable joint venture partner or raise sufficient capital for the project;

·	continued compliance with current environmental regulations and the possibility of new legislation, environmental regulations or permit requirements adverse to the mining industry;

·	molybdenum prices and operating costs staying within the parameters established by the feasibility study;

·	successfully managing the substantial operating risks attendant to a large scale mining and processing operations; and

·	compliance and operating costs associated with the wastewater treatment plant and stormwater management system.

For real estate:

·	insufficient demand for apartments in our multi-family apartment project in Gillette, Wyoming (“Remington Village”) which could impact our ability to sell the property;

·	inability of the Company to sell Remington Village on acceptable terms; and

·	an economic downturn could affect rental rates, occupancy and bad debt collection.

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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. 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.

PART I

Item 1 – Business

Overview

U.S. Energy Corp. (“U.S. Energy”, “USE”, the “Company”, “we” or “us”), is a Wyoming corporation organized in 1966. We are an independent energy company focused on the acquisition and development of oil and gas producing properties and other mineral properties in the continental United States. Our oil and gas business is currently focused in the Rocky Mountain region (specifically the Williston Basin of North Dakota and Montana), Louisiana, and Texas. However, we do not intend to limit our focus to these geographic areas. We continue to focus on increasing production, reserves, revenues and cash flow from operations while managing our level of debt.

We currently explore for and produce oil and gas through a non-operator business model. However, in the future we may expand our activities to include operations. As a non-operator, we rely on our operating partners to propose, permit, drill, complete and produce oil and gas wells. Before a well is drilled, the operator provides all oil and gas interest owners in the designated well the opportunity to participate in the drilling and completion costs and revenues of the well on a pro-rata basis. Our operating partners also produce, transport, market and account for all oil and gas production.

We are also involved in: (i) the exploration for and development of minerals (molybdenum) through our ownership of the Mt. Emmons Project located in west central Colorado, which is a long-term development mining project, (ii) geothermal resources through a minority interest in Standard Steam Trust LLC (“SST”) and (iii) real estate through our ownership of Remington Village, a multi-family housing project serving the residential market in Gillette, Wyoming, which is generating positive cash flow and is accounted for as a property held for sale at December 31, 2012. We do not intend to make more investments in the real estate housing sector.

Industry Segments/Principal Products

At December 31, 2012, we have two operating segments: Oil and Gas and Maintenance of Mineral Properties (including molybdenum and geothermal). See Note L to the consolidated financial statements included in this Annual Report for certain financial information by segment.

Office Location and Website

Our principal executive office is 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 (the “SEC”) 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 relating to stock ownership of our directors and executive officers. You

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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 are not incorporated by reference herein and should not be considered part of this document. In addition, you may read and copy any materials we file with the SEC at the SEC's Public Reference Room, which is located at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Information regarding the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330.

Business

Oil and Gas

We participate in oil and gas projects primarily as a non-operating working interest owner through exploration and development agreements with various oil and gas exploration and production companies. Our working interest varies by project. These projects may result in numerous wells being drilled over the next three to five years. We are also actively pursuing potential acquisitions of exploration, development and production-stage oil and gas properties or companies.

At December 31, 2012 we had:

·	Estimated proved reserves of 2,913,324 BOE (90% oil and 10% natural gas), with a standardized measure value of $71.0 million and a PV10 of $76.5 million.

·	At March 1, 2013, our leases covered 152,283 gross and 12,550 net acres.

·	Eighty-three gross (15.05 net) producing wells (87 gross and 15.30 net at March 1, 2013).

·	1,215 BOE/d average net production for 2012.

PV10 (defined in “Glossary of Oil and Gas Terms”) is widely used in the oil and gas industry and is considered by institutional investors and professional analysts when comparing 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 as of the dates indicated, which are presented in Note F to the our consolidated financial statements.

	(In thousands)
	At December 31,
	2012		2011		2010
Standardized measure of discounted net cash flows	$	71,017	$	62,191	$	44,653
Future income tax expense (discounted)		5,448		10,346		7,420
PV-10	$	76,465	$	72,537	$	52,073

Activities with Operating Partners in Oil and Gas

The Company holds a geographically and geologically diverse portfolio of oil-weighted prospects in varying stages of exploration and development. Prospect stages range from prospect origination, including geologic and geophysical mapping, leasing, exploration drilling and development. The Company engages in the prospect stages either for its own account or with prospective partners to enlarge the oil and gas lease ownership base.

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Each of the operators of our 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 required to work on diverse projects involving horizontal drilling in North Dakota and South Texas and conventional exploration in Gulf Coast prospects. However, consistent with industry practice with smaller independent oil and gas companies, we also utilize specialized consultants with local expertise as needed.

The Company currently has oil and gas projects with operating partners in the following areas:

Williston Basin, North Dakota

Brigham. On August 24, 2009, we entered into a Drilling Participation Agreement (the “DPA”) with Brigham Oil & Gas, L.P. (“Brigham”), now a subsidiary of Statoil, 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. Under the DPA, we earned working interests, out of Brigham’s interests, in fifteen 1,280-acre spacing units in Brigham’s Rough Rider project area 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. In addition, if four horizons within the Three Forks formation are determined to be economical, the total potential number of Three Fork wells could increase significantly.

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 under the terms of the 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.

Our earn-in rights were staged in three groups of units and were earned upon paying our share of all drilling and completion costs, 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 and completed all 15 wells in the initial phase of the DPA and have completed six additional gross infill wells. These wells produced an average of approximately 597 BOE/d net to the Company (90% oil and 10% natural gas and natural gas liquids) during the fourth quarter of 2012.

Brigham is the operator for all the units covered by the DPA, and is compensated for its 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 initial wells drilled in the 1,280 acre units; our working interest (or “WI”) ranges from 61.46% to 29.58% (48.55% to 23.80% net revenue interest (or “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 the 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, 2012, we

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estimate that the Pooled Payout for the First Group of wells will occur in the second quarter of 2013. This group of wells produced an average of approximately 198 BOE/d net to the Company (93% oil and 7% natural gas and natural gas liquids) during the fourth quarter of 2012.

We earned 36% of Brigham’s initial working interest in all of the acreage in the applicable unit, which working interest was subsequently reduced by the sale to Brigham on December 15, 2011 as noted below. 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 interests in each initial well, and all of the subsequent wells, will be subject to proportionate reduction for third party leasehold rights.

Second Group: In 2010, we participated in the drilling and completion of the four wells in the Second Group. Brigham provided 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 all producing in 2012; our working interests range from 48.03% to 21.02% (NRIs range from 37.80% to 16.29%).

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 leasehold rights, which working interest was subsequently reduced by the sale to Brigham on December 15, 2011 as noted below. 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 that Pooled Payout for the Second Group will be reached in second quarter of 2014. This group of wells produced an average of approximately 109 BO/d net to the Company (82% oil and 18% natural gas and natural gas liquids) during the fourth quarter of 2012.

Third Group: On January 11, 2010, Brigham provided us notice that it would be taking 50% of the working interest available to it in the Third Group. 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 and producing at December 31, 2012. 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 the Third Group (which will not be subject to back in rights), proportionately reduced for third party leasehold rights, which working interest was subsequently reduced by the sale to Brigham on December 15, 2011 as noted below. 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 on each individual well to be reached on these initial wells between early-2013 and late 2017.

Effective December 15, 2011, the Company sold an undivided 75% of its undeveloped acres in the Rough Rider prospect to Brigham for $13.7 million. Under the terms of the agreement, the Company retained the remaining 25% of its interest in the undeveloped acreage and its original working interest in its 20 developed wells in the Rough Rider prospect. After the sale, our working interest in the undeveloped acreage in the Rough Rider Prospect ranges from 3.41% to 9.90%.

From August 24, 2009 to December 31, 2012, we have drilled and completed 20 gross Bakken formation wells (7.31 net) and one gross Three Forks formation well (0.18 net) under the DPA. Two gross wells (0.07 net) are in progress as of the date of this report. At this time, we anticipate that Brigham will drill at least three additional gross wells in the Rough Rider acreage in 2013. Drilling plans beyond 2013 are not known at this time.

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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 was drilled, we have the right to elect not to participate in the drilling or completion in subsequent wells proposed to be drilled in a unit. If the Company 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.

Zavanna, LLC. In December 2010, we signed two agreements with Zavanna (a private oil and gas company based in Denver, Colorado), and other parties. The Company paid $11.0 million in cash to acquire 35% of Zavanna’s working interests in oil and gas leases covering approximately 6,050 acres net to Zavanna’s interest in McKenzie County, North Dakota which interest was subsequently reduced by the sale to GeoResources, Inc. and Yuma Exploration and Production Company, Inc. on January 24, 2012 as noted below. The current total net acres subject to the agreement is approximately 1,650.

The acquired acreage is in two prospects – the Yellowstone Prospect and the SE HR Prospect. We expect this program will result in 27 gross 1,280 acre spacing units with the potential for 108 gross Bakken and 108 gross Three Forks wells, based on an assumed four wells per formation in each spacing unit.

Our interests in all the acreage in both prospects is subject to reduction by a 30% reversionary working interest under each prospect upon expiration of the “Project Payout Period” or “Project Payout,” as those terms are defined in the agreements, whichever occurs first. Project Payout will occur when we have received proceeds from the sale of production (or from the sale of all or part of the acreage to third parties) equal to 130% of: the $11.0 million 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 acquired in the two Areas of Mutual Interest contemplated by the agreements). This acreage is referred to collectively as the “Project Payout Properties.” The Project Payout Period for the Yellowstone Project is from the spud date of the initial well drilled in the prospect to July 15, 2014 and the Project Payout Period for the SE HR Prospect is from the spud date of the initial well drilled in the prospect to March 31, 2014.

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 other than the Project Payout Properties (i.e., that acreage on which wells have not commenced drilling, including all infill locations in drilling units where the Project Payout Properties are located). 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. Based on the current economic assumptions used in the December 31, 2012 reserve report, we do not expect these projects to achieve Project Payout.

On January 24, 2012 (but effective as of December 1, 2011), the Company sold an undivided 75% of its undeveloped acreage in the SE HR Prospect and the Yellowstone Prospect to GeoResources, Inc. (56.25%) and Yuma Exploration and Production Company, Inc. (18.75%) for a total of $16.7 million. Under the terms of the agreement, the Company retained the remaining 25% of its interest in the undeveloped acreage and its original working interest in its 10 developed wells in the SE HR and Yellowstone prospects. Our working interest in the remaining locations is approximately 8.75% and net revenue interests in new wells after the sale are in the range of 6.7375% to 7.0%, proportionately reduced depending on Zavanna’s actual working interest percentages.

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As of December 31, 2012, we have interests in twenty-seven gross 1,280 acre spacing units in the Yellowstone and SEHR prospects with Zavanna. We have drilled and completed 16 gross Bakken formation wells (2.68 net) in these prospects, including two gross wells (0.13 net) operated by Murex Petroleum and one gross well (0.01 net) operated by Slawson Exploration Company, Inc. Zavanna operates the remaining wells. These wells produced an average of approximately 377 BOE/d net to the Company (93% oil and 7% natural gas and natural gas liquids) during the fourth quarter of 2012.

Bakken/Three Forks Asset Package Acquisition. On September 21, 2012, but effective July 1, 2012, we acquired interests in 27 producing Bakken and Three Forks formation wells and related acreage in McKenzie, Williams and Mountrail Counties of North Dakota for $2.3 million after adjusting for related revenue and operating expenses from the effective date through September 21, 2012. Under the terms of the agreement, we acquired working interests in 23 drilling units ranging from less than 1% to approximately 5%, with an average working interest of 1.45%. All acreage is currently held by production and produced approximately 46 BOE/d net to the Company (95% oil and 5% natural gas and natural gas liquids) during the fourth quarter of 2012.

For further information on the wells drilled in North Dakota through the date of this Annual Report, see “Item 2 – Properties – Oil and Natural Gas” below.

California

Cirque Resources LP. Under an October 2010 agreement with Cirque Resources LP, (“Cirque”), the Company paid $2.5 million 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 in Kern County, California. Of the amount paid, $1.6 million was an advance against our 40% working interest for the initial well, including 33% of Cirque’s 60% working interest share for the well.

The primary target in the prospect was the Miocene formation on the flank of the Elk Hills anticline in Kern County, California. The initial well was drilled by Cirque and reached its total depth of 13,403 feet during the last week of December 2011. The Stevens Sands objective target was encountered and had hydrocarbon shows, but did not have sufficient porosity or permeability to be deemed productive. The Company has agreed with the operator’s recommendation to plug and abandon the well. The Company’s net cost in this well through December 31, 2012 was $2.4 million. During 2012, the Company sold its interests in this prospect for $93,000.

Texas and Louisiana

Crimson Exploration Inc. In 2011, we entered into two participation agreements with Crimson Exploration Inc. (“Crimson”) to acquire working interests in oil prospects and associated leases located in Zavala and Dimmit Counties, Texas (the “Leona River prospect” and “Booth Tortuga prospect”) and working interests in 11 gross wells (2.98 net) producing from the Austin Chalk formation. Under the terms of the agreements, the Company has earned a 30% working interest (and approximate 22.5% net revenue interest) in approximately 11,861 gross acres (3,358.5 net acres). All drilling and leasing will be on a heads up basis with no carry by the Company. The prospects include Eagle Ford, Buda and Pearsall shale oil window targets. Crimson is the operator of the prospects. Through the date of this report, we have drilled 3 gross (.90 net) Eagle Ford formation horizontal wells. Wells in these prospects produced an average of approximately 62 BOE/d net to the Company (80% oil and 20% natural gas and natural gas liquids) during the fourth quarter of 2012.

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On November 13, 2012 the Company acquired a 60% interest in 889.39 gross acres (444 net) of deep oil and gas rights (which include the Buda formation) located within the Booth Tortuga prospect acreage for $266,000.

As a result of subsequent acquisitions, our current total acreage in the Leona River and the Booth Tortuga prospects is approximately 13,507 gross acres (3,861 net). Based upon assumed 120 acre spacing units, there is a potential for up to 98 gross and 29.6 net Eagle Ford or other formation drilling locations. Looking forward, the Company continues to seek additional leasing opportunities in the Eagle Ford oil window jointly with Crimson.

Houston Energy L.P. The Company has an interest in one producing well with Houston Energy L.P. (“Houston”) with a 25% WI (17.63% NRI). During the fourth quarter of 2012, average daily production from this well was approximately 5 BOE/d net to the Company (99% oil and 1% natural gas).

PetroQuest Energy, L.L.C. The Company has an interest in one natural gas and oil producing well with PetroQuest Energy, L.L.C. in coastal Louisiana, with a working interest of 17.0% (12.75% NRI). During the fourth quarter of 2012, average daily production from this well was approximately 80 BOE/d net to the Company (100% natural gas).

Southern Resources Company. Our agreement with Southern Resources Company (“Southern”) covers a 13.5% working interest (9.86% NRI) in 1,282 gross (173 net) acres in Hardin County, Texas. The Company earned a working interest in all the acreage by participating in the initial test well and paying $135,000 in seismic, land acquisition and legal costs. The Company agreed to carry the seller in an 18.75% working interest to the casing point decision (“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 for proportionally to all parties’ working interests. Mueller Exploration, Inc. (“Mueller”) operates all of the wells. As of December 31, 2012 we had one gross producing well in this project (0.14 net). No drilling is currently scheduled on these properties in 2013. During the fourth quarter of 2012, average daily net production from this well was approximately 4 BOE/d (18% oil and 82% natural gas and natural gas liquids).

Woodbine Acquisition. In May 2012, we entered into a participation agreement with Mueller to participate in the Woodbine Sub-Clarksville 7 Project located in Anderson and Cherokee Counties, Texas. Under the terms of the agreement, we acquired a 26.5% initial working interest (19.6% net revenue interest) in approximately 6,766 gross acres (1,274 net) for $1.7 million. The promoted amount covered our portion of the costs for land, geological and geophysical work, as well as all dry hole costs for an initial test well in each of the seven prospects. Upon payout of our initial well costs in each unit, our interest will be reduced to a 19.8% working interest (14.7% net revenue interest). Future infill drilling will be on a heads up basis, and our interest will be a 19.8% working interest (14.7% net revenue interest). All seven initial wells were drilled in 2012 and deemed to be non-productive. Two of the wells had non-commercial quantities of oil and gas, indicating potential for up-dip exploration. However, no additional drilling is scheduled at this time.

For further information on the wells drilled in Texas and Louisiana through the date of this Annual Report, see “Item 2 – Properties – Oil and Natural Gas” below.

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Operated Oil and Gas Activities

Daniels County, Montana Acreage

In 2010 through 2012, the Company acquired a working interest in approximately 30,332 gross mineral acres (18,939 net acres) of undeveloped leasehold interests in Daniels County, Montana for approximately $1.2 million. This acreage is believed to have conventional and horizontal Bakken and Three Forks resource potential.

On June 8, 2012, we sold an undivided 87.5% of this acreage to Greehey & Company Ltd. (“Greehey”) for $3.7 million. This amount was recorded as a credit to our full cost pool. In addition, we transferred $1.0 million in costs from unevaluated properties to “proved properties” as a result of this sale. Under the terms of the agreement, we retained a 12.5% working interest in the acreage and reserved overriding royalty interests (“ORRI”) in leases we owned that had in excess of 81% NRI. Greehey also committed to drill a vertical test well to depths sufficient to core the Bakken and Three Forks formations on or before December 31, 2015. We delivered an 80% NRI to the purchaser and a 1% ORRI to Energy Investments, Inc., (EII”), a land broker, in connection with the sale. We also paid EEI a commission equal to 10% of the cash consideration paid by Greehey.

Forward Plan

In 2013 and beyond, the Company intends to seek additional opportunities in the oil and natural gas sector, including but not limited to 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 Senior Secured Revolving Credit Facility (the “Credit Facility”) through our wholly-owned subsidiary, Energy One LLC, which allows us to borrow up to a maximum of $100 million (with a current borrowing base of $30.0 million) from a syndicate of banks, financial institutions and other entities, including Wells Fargo Bank, National Association (“Wells Fargo,” and together with other members of the syndicate, the “Lenders”). Wells Fargo replaced BNP Paribas as a Lender on April 24, 2012. This arrangement is available only for our oil and gas segment, and provides us with the flexibility of investing and funding drilling/completion work. We expect our borrowings to be serviced with cash flow and/or equity financing.

Wells Fargo is the administrative agent for the Facility, which is governed by a Credit Agreement, a Mortgage, a Deed of Trust, an Assignment of As-Extracted Collateral, a Security Agreement, a Fixture Filing and Financing Statement and a Guaranty and Pledge Agreement. We refer to these documents together as the Facility Documents. The following summarizes the principal provisions of the Credit Facility as set forth in the Facility Documents.

The Company 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 from the Lenders, up to an amount equal to the borrowing base. The borrowing base is re-determined semi-annually (or more often at the request of Wells Fargo or Energy One), based on updated reserve reports prepared by the Company’s

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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 the outstanding loans and loan commitments. On April 10, 2012, the borrowing base increased to $30.0 million (from $28.0 million) as a result of a redetermination utilizing our December 31, 2011 financial statements, production reports and reserve reports.

Interest is payable quarterly at the greater of the prime rate, the federal funds effective rate (plus 0.5%), and the adjusted LIBO rate 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 Wells Fargo 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 in excess of the borrowing base will be due over the five months following the determination.

Energy One is required to comply with customary affirmative and negative covenants under the Credit Agreement. Under the agreement, our (i) “Interest Coverage Ratio” (the ratio of EBITDAX to Interest Expense, as those terms are defined in the agreement) may not be less than 3.0 to 1; (ii) the ratio of Total Debt, as defined in the agreement, to EBITDAX may not be greater than 3.5 to 1; and (iii) the Current Ratio (the ratio of current assets plus unused Lender commitments under the borrowing base to current liabilities) must be at least 1.0 to 1.0. EBITDAX is defined in the Credit Agreement as consolidated net income plus non-cash charges. Compliance with these covenants is measured at various times as provided in the Credit Agreement. As of December 31, 2012, Energy One was in compliance with all the covenants under the Credit Facility.

At December 31, 2012, Energy One had $10.0 million in debt outstanding under the Credit Facility.

Activities other than Oil and Gas

Molybdenum

The Company re-acquired the Mt. Emmons Project located near Crested Butte, Colorado on February 28, 2006. The Mt. Emmons Project includes a total of 160 fee acres, 25 patented and approximately 1,345 unpatented mining and mill site claims, which together approximate 9,853 acres, or over 15 square miles. For further information, see “Item 2 – Properties – Molybdenum - Mt. Emmons Project” below.

Renewable Energy — Geothermal

At December 31, 2012 we owned a minority ownership interest, 19.54%, in SST, a geothermal limited liability company. Our investment in SST does not obligate us to fund any future cash calls, but if we elect not to fund cash calls, we will suffer dilution. We did not participate in any cash calls in 2010, 2011 or 2012, which diluted our ownership. We do not currently expect to fund any future cash call, and as a result, we may experience further dilution of our ownership of SST.

Assets Held for Sale

In 2008, we completed construction of Remington Village, a nine-building, 216-unit multifamily apartment complex in Gillette, Wyoming for a total all-in cost of $24.5 million. The occupancy rate was 89% during December 2012. Impairments of $1.5 million, $3.1 million and $3.0 million were recorded to reflect the difference between the cost of the property and its estimated fair market value at December 31, 2010, 2011 and 2012, respectively. 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

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therefore plans to sell this property to continue growing its oil and gas business. The property is collateralized with a $10 million conventional note with First Interstate Bank of Riverton, Wyoming. For further information, see “Item 2 – Properties – Real Estate” below.

In September 2012, we made the decision to sell our corporate aircraft and related facilities and we plan to use the proceeds to further the development of our oil and gas business, reduction of debt or for general corporate purposes. During the year ended December 31, 2012, the Company recorded non-cash impairments totaling $2.3 million to adjust the carrying value of the aircraft to the expected sale value less a $35,000 sales commission. In January 2013, the Company sold its aircraft hangar and related facilities for $767,000. In March 2013, the Company sold the aircraft for $1.9 million.

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 could adversely affect our business.

Continuing turmoil in the global financial system may have a material impact on our ability to finance the purchase, exploration 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.

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 risk, 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;

·	inability to obtain required permits from State and Federal agencies;

·	inability to obtain, or limitations on, easements from land owners;

·	adverse weather;

·	high pressure or irregularities in geologic formations;

·	equipment failures;

·	title problems;

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

·	changes in government regulations and issuance of local drilling restrictions or moratoria;

·	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, do not 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.

Dry holes and other unsuccessful or uneconomic exploration, exploitation and development activities adversely affect our cash flow, profitability and financial condition, and can adversely affect our reserves. As a non-operator, we have limited ability to control the manner in which drilling and other exploration and development activities on our properties are conducted, which may increase these risks.

Our business may be impacted by adverse commodity prices.

In the past three years, oil prices have ranged from a high of $113.39 per barrel to a low of $64.78 per barrel. Global markets, in reaction to the recession, and perceived upticks or downticks in future global supply, have caused these large fluctuations, and significant future changes are likely. Natural gas prices have also been volatile, reaching a ten year high during February 2003 on the Henry Hub of $18.48 per MMbtu, and a ten year low during April 2012 of $1.82 per MMbtu. Declines in the prices we receive for our oil and natural gas production adversely affect many aspects of our business, including our financial condition, revenues, results of operations, liquidity, rate of growth and the carrying value of our oil and natural gas properties, all of which depend primarily or in part upon those prices. Declines in the prices we receive for our oil and natural gas also adversely affect our ability to finance capital expenditures, make acquisitions, raise capital and satisfy our financial obligations. In addition, declines in prices reduce the amount of oil and natural gas that we can produce economically and, as a result, adversely affect our quantities of proved reserves. Among other things, a reduction in our reserves can limit the capital available to us, as the maximum amount of available borrowing under the Credit Facility is, and the availability of other sources of capital likely will be, based to a significant degree on the estimated quantities of those reserves.

Mineral prices also change significantly over time. Molybdenum prices have fluctuated significantly, with a ten-year high 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, 2012 was $11.40 per pound, compared to $13.37 per pound at year end 2011. Price improvement in 2013 will be dependent on continued demand, but demand could weaken if industrial consumption sags due to economic constraints in key global markets. Lower molybdenum prices would adversely affect the feasibility of developing the Mt. Emmons Project.

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 per barrel than prices for other areas in the United States, and recently as much as $25.00 less per barrel. This discount, or differential, may widen in the future, which would reduce the price we would receive for our production.

Drilling and completion costs for the wells we drill in the Williston Basin are comparable to or higher than 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,

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Zavanna and other operators. Our production in other areas could also be affected by adverse changes in differentials. In addition, changes in differentials could make it more difficult for us to effectively hedge our exposure to changes in commodity prices.

We will require funding in addition to working capital at December 31, 2012.

We were able to maintain adequate working capital in 2012 primarily through borrowing under the Credit Facility and cash flow from operations. Working capital at December 31, 2012 was $12.8 million, an amount sufficient to continue substantial exploration and development work on our oil and gas properties, but not enough to take full advantage of the opportunities we now have or to be in position to pursue new opportunities. In 2013, we have budgeted $27.1 million for work on existing oil and gas programs and acquisitions.

Our exploration and development agreements contain customary industry non-consent provisions. Pursuant to these provisions, if a well is proposed to be drilled or completed but a working interest owner doesn’t participate, the resulting revenues (which otherwise would go to the non-participant) flow to the participants until they receive from 150% to 300% of the capital they provided to cover the non-participant’s share. In order to be in position to avoid non-consent penalties and to make opportunistic investments in new assets, we will continually evaluate various options to obtain additional capital, including borrowings under the Credit Facility and sales of one or more of a portion of our non-producing oil and gas assets, equity securities and Remington Village.

Beyond 2013, we may have capital needs from time to time in excess of funds on hand. The oil and gas and minerals businesses present 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 or other adverse 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 available for investment in other programs.

·	We are paying the annual costs (approximately $2.0 million) to operate and maintain the water treatment plant and stormwater management system at the Mt. Emmons Project, and these costs could increase in the future.

These types of events could require a reassessment of priorities and therefore potential re-allocations of existing capital and could also mandate obtaining new capital. There can be no assurance that we will be able to complete any financing transaction on acceptable terms. For example, our ability to borrow under the Credit Facility may be limited if we are unable, or run a significant risk of becoming unable, to comply with the financial covenants that we are required to satisfy under the agreement. In addition, the borrowing base under the agreement is subject to redetermination periodically and from time to time in the Lenders’ discretion. Borrowing base reductions may occur as a result of unfavorable changes in commodity prices, asset sales, performance issues or other events. In addition to reducing the capital available to finance our operations, a reduction in the borrowing base could cause us to be required to repay amounts outstanding under the Credit Facility in excess of the reduced borrowing base, and the funds necessary to do so may not be available at that time. Other sources of external debt or equity financing may not be available when needed on acceptable terms or at all, especially during periods in which financial market conditions are unfavorable. Also, sales of equity securities would be dilutive to existing shareholders.

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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 (Bakken and Three Forks shales) 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 in an effort 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 sufficient period of time.

The drilling and completion of a horizontal well in the Williston Basin or the Eagle Ford formation currently costs approximately $7.5 million (Eagle Ford) and approximately $11.5 million (Bakken/Three Forks) on a gross basis, which is significantly more expensive than a typical onshore shallow conventional well. Accordingly, unsuccessful exploration or development activity affecting even a small number of wells could have a significant impact on our results of operations. Costs other than drilling and completion costs can also be significant for Williston Basin, Eagle Ford and other wells. For example, we incurred approximately $3.1 million in workover costs relating to a single Williston Basin well in 2011, and these costs substantially exceeded our estimates.

The results of the drilling programs in the Williston Basin (Bakken and Three Forks shales) 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, the industry’s drilling and production history in the formations 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.

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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 wells targeting the Bakken and Three Forks formations, drilling and production results are more uncertain than those encountered in other formations and areas with longer histories. Good results from wells we have participated in may not be replicated in additional wells, even in the same drilling unit. In addition, increases in the number of wells drilled per spacing unit could impact per-well performance.

Through the date of this Annual Report, 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 compared with drilling Bakken wells.

The foregoing considerations also apply to our opportunities to drill the same formations with Zavanna and other operators in the Williston Basin.

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 and Three Forks, 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.

If our access to oil and gas markets is restricted, it could negatively impact our production and revenues. Securing access to takeaway capacity may be particularly difficult in less developed areas of the Williston Basin.

Market conditions or limited availability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, rail transportation and processing facilities owned and operated by third parties. In particular, access to adequate gathering systems or pipeline or rail 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 as those in other areas.

As of the date of this Annual Report, all of the wells we have drilled in the Williston Basin have produced oil and natural gas (generally at an initial ratio of about 85% oil and 15% gas). Oil sales generally 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 days, or longer, depending on well location, weather conditions, and availability of service providers. As of the date of this Annual Report, all but one of our Williston Basin wells are selling gas.

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If continued drilling in the Williston Basin, and other areas such as the Eagle Ford, proves to be successful, the amount of oil and natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines or rail tankers currently available in these areas. If this occurs, it will be necessary for new rail takeaway lines, pipelines and gathering systems to be built. Certain pipeline or rail projects that are planned for the Williston Basin and other areas may not occur. In such event, we might have to shut in our wells until a pipeline connection or rail capacity is available. In the case of natural gas, we may have to sell natural gas production at significantly lower prices than we would otherwise receive and/or flare the gas we produce.

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 under 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, applicable spacing rules 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, if we have substantial downward revisions in estimated proved reserves or if we drill unproductive wells.

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

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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, 2012, 2011 and 2010, which were not included in the amortized cost pool, were $9.2 million, $20.0 million and $21.6 million, respectively. These costs consist of wells in progress, costs for seismic analysis of potential drilling locations, and 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, 2012 and 2011, 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, 2012, we used $94.71 per barrel for oil and $2.757 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%.

During 2012 capital costs for oil and gas properties exceeded the ceiling test limit and we recorded a non-cash write down of $5.2 million primarily due to lower prices for oil and natural gas, higher actual and forecast capitalized well costs and higher forecast lease operating expenses. Capitalized costs for oil and gas properties did not exceed the ceiling test limit in 2011. 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.

We do not currently operate our drilling locations. 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.

We do not operate or expect to be the operator of any of the prospects we hold with industry partners. As a non-operator, our ability to exercise influence over the operations of the drilling programs is limited. 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 interests, but we disagree with the proposal and do not (or are unable to) participate, we will forfeit our share of revenues from the well until the participants receive 150% to 300% of their investment. In some cases, we could lose all of our interest in the well. We would avoid a penalty of this kind only if a majority of the working interest owners agree with us and the proposal does not proceed.

The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including:

·	the nature and timing of the operator’s drilling and other activities;

·	the timing and amount of required capital expenditures;

·	the operator’s geological and engineering expertise and financial resources;

·	the approval of other participants in drilling wells; and

·	the operator’s selection of suitable technology.

The fact that we do not operate our prospects with industry partners makes it more difficult for us to predict future production, cash flows and liquidity needs.

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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 provide estimates of the quantities of hydrocarbons that can be economically recovered from proved properties, utilizing current commodity prices and taking into account expected capital and other expenditures. These reports also provide estimates of the future net present value of the reserves, which we use 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, 2012, 66% of our estimated proved reserves were producing, 3% were proved developed non-producing and 31% were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is almost always based on analogy to existing wells, volumetric analysis or probabilistic methods, in contrast to the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Revenues from estimated proved developed non-producing and proved undeveloped 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 and standardized measure estimates are based on costs as of the date of the estimates and assume fixed commodity prices. 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 six such instruments in place at December 31, 2012. Also, the use of a 10% discount factor to calculate PV10 and standardized measure values 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 instruments 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 instruments will be recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

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Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for the relevant 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 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:

·	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 our risk management strategies.

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

Additionally, the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, among other things, imposes restrictions on the use and trading of certain derivatives, including energy derivatives. The nature and scope of those restrictions will be determined in significant part through implementing regulations that are in the process of being implemented by the SEC, the Commodities Futures Trading Commission and other regulators. If, as a result of the Dodd-Frank Act or its implementing regulations, capital or margin requirements or other limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability to implement our hedging strategy. In particular, a requirement to post cash collateral in connection with our derivative positions, which are currently collateralized on a non-cash basis by our oil and natural gas properties and other assets, would likely make it impracticable to implement our current hedging strategy. In addition, requirements and limitations imposed on our derivative counterparties could increase the costs of pursuing our hedging strategy.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, the loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our potential drilling locations are identified, the leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases could become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

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A substantial portion of our producing properties are located in the Williston Basin, making us vulnerable to risks associated with having operations concentrated in this geographic area.

Because our operations are geographically concentrated in the Williston Basin (87% of our production in the fourth quarter of 2012 was from the Williston Basin), the success and profitability of our operations may be disproportionally exposed to the effect of regional events. These include, among others, fluctuations in the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline and other transportation capacity constraints, available rigs, equipment, oil field services, supplies, labor and infrastructure capacity. In addition, our operations in the Williston Basin may be adversely affected by seasonal weather and lease stipulations designed to protect wildlife, which can intensify competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in the Williston Basin also increases exposure to unexpected events that may occur in this region such as natural disasters or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of these risks could have a material adverse effect on our financial condition and results of operations.

Our acquisition activities may not be successful.

As part of our growth strategy, we have made and may continue to make acquisitions. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources to acquire attractive companies and properties. The following are some of the risks associated with acquisitions, including any completed or future acquisitions:

·	some of the acquisitions may not produce revenues, reserves, earnings or cash flow at anticipated levels;

·	we may assume liabilities that were not disclosed to us or that exceed our estimates;

·	we may be unable to integrate acquisitions successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and

·	acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures.

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. We rely on our operating partners to provide us with ownership of the interests we pay for. To date, our operators have generally provided preliminary title opinions prior to drilling. 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 a productive well because the operator (and therefore the Company) 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

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property; and a residential multi-family housing complex in Gillette, Wyoming. We also have potential exposure in connection with our corporate aircraft (until it is sold) and general liability and property damage associated with the ownership of other corporate assets. In the past, we relied 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. In some cases, we may continue to rely on those operators’ insurance coverage policies depending on the coverage. However, since June 2011, we have established our own insurance policies for our oil and gas operations that are broader in scope and coverage and are in our control. We also maintain insurance policies for liabilities associated with and damage to our multifamily housing complex, corporate aircraft and general corporate assets.

We also have separate policies for the Mt. Emmons properties and liability and environmental exposures for the water treatment plant operations at the Mount 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 and for any deductible provided for in the relevant policy. If uncovered liabilities are substantial, payment thereof could adversely impact the Company’s cash on hand, resulting in possible curtailment of operations. Moreover, some liabilities are not insurable at a reasonable cost or at all.

We do not have a feasibility study relating to Mt. Emmons.

We have not yet completed a feasibility study on the Mt. 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 of 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).

The timing and cost of obtaining a feasibility study for the Mt. Emmons property cannot be predicted. However, when such a study is obtained, it may not support our internal valuations of the property, and additionally may not be sufficient to attract new partners or investment capital.

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

Oil and gas exploration, development and production activities are subject to certain federal, state and local laws and regulations relating to a variety of issues, including 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, well construction, the spacing of wells, unitization and pooling of properties, habitat and endangered species protection, reclamation and remediation, restrictions on drilling activities in restricted areas, emissions into the environment, management of drilling wastes, water discharges, chemical disclosures 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 any future changes. The adoption or enforcement of stricter regulations, if enacted, could have a significant impact on our operating costs.

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Our business activities in mining are also regulated by government agencies. Among other things, permits are required to explore for minerals, operate mines and build and operate processing facilities. 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 new or modified regulations, we may decide not to move forward with the project.

In addition, we must comply with numerous environmental laws and regulations with respect to our mining activities, including the National Environmental Policy Act, or NEPA, the Clean Air Act, the Clean Water Act, and the Resource Conservation and Recovery Act, or RCRA. Other laws impose reclamation obligations on abandoned mining properties, in addition to or in conjunction with federal statutes.

Under these laws and regulations, we could be liable for personal injuries, property and natural resource damages, releases or discharges of hazardous materials, well reclamation costs, oil spill clean-up costs, other remediation and clean-up costs, plugging and abandonment costs, governmental sanctions, and other environmental damages. Some environmental laws, such as the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), impose joint and several and strict liability. Strict liability means liability without fault such that in some situations we could be exposed to liability for clean-up costs and other damages as a result of conduct that was lawful at the time it occurred or for the conduct of third parties. These third parties may include prior operators of properties we have acquired, operators of properties in which we have an interest and parties that provide transportation services for us. If exposed to joint and several liabilities, we could be responsible for more than our share of a particular clean-up, reclamation or other obligation, and potentially for the entire obligation, even where other parties were involved in the activity giving rise to the liability.

Changes in applicable laws and regulations could increase our costs, reduce demand for our production and impede our ability to conduct operations or have other adverse effects on our business.

Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us. For example, many of our activities involve the use of hydraulic fracturing, which is a process that creates a fracture extending from the well bore in a rock formation to enable oil or natural gas to move more easily through the rock pores to a production well. Fractures are typically created through the injection of water and chemicals into the rock formation. Legislative and regulatory efforts at the federal level and in some states and localities have been made to impose new or more burdensome permitting, disclosure and safety requirements on hydraulic fracturing operations and in some cases to prohibit hydraulic fracturing altogether in designated areas. These restrictions, to the extent adopted in areas in which we operate, could increase our costs and make it more difficult, or impossible, to pursue some of our development projects. For example, the Environmental Protection Agency (the “EPA”) amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act, or the SDWA, to exclude hydraulic fracturing from the definition of “underground injection.” The 111th United States Congress considered bills entitled the Fracturing Responsibility and Awareness of Chemicals Act, or the FRAC Act, to amend the SDWA to repeal this exemption, but Congress adjourned without taking any significant action on the bills. The FRAC Act was re-introduced in the 112th Congress and, if enacted, would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, including disclosure of chemicals used in the fracturing process, and meet plugging and abandonment requirements. The FRAC Act’s proposal to require the reporting and public disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could

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adversely affect groundwater. It is not possible to predict whether the current or a future session of Congress may act further on hydraulic fracturing legislation. Such legislation, if adopted, could establish an additional level of regulation and permitting at the federal level. In addition, in March 2010, at the request of the U.S. Congress, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources. A final draft report is expected to be released for public comment and peer review in 2014.

Currently, hydraulic fracturing is regulated primarily at the state level through permitting and other compliance requirements. For example, North Dakota requires disclosure of information concerning the chemicals used in hydraulic fracturing fluids and imposes certain well construction and testing requirements. In addition, Montana has enacted regulations requiring operators to disclose information about hydraulic fracturing fluids on a well-by-well basis. Further, operators must generally obtain approval from the state before hydraulic fracturing occurs and submit a report after the work is performed. Montana also requires specific construction and testing requirements for wells that will be hydraulically fractured. Other states in which we conduct operations may implement similar or more onerous requirements.

Additionally, the Colorado Department of Public Health and Environment is preparing to undertake the renewal of the existing discharge permit, which expires August 31, 2013. Beginning in 2013, we will also be commencing a more comprehensive study of natural and human-induced conditions that may be affecting water quality in Coal Creek.

Additionally, President Obama’s 2013 fiscal year budget includes proposals that would, if enacted into law; make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

In addition, climate change has emerged as an important topic in public policy debate. It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in greenhouse gases (“GHGs”). Products produced by the oil and natural gas exploration and production industry are a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations. The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the Clean Air Act. The EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered, and may in the future consider, “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production. For example, 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. Also, 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 regulatory changes and/or perceived negative impacts on the climate from GHGs could result in lower world-wide consumption of, and prices for, crude oil.

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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 sometimes cannot be conducted as effectively during the winter months, and this can materially increase our operating and capital costs. Gulf Coast operations are also subject to the risk of adverse weather events, including hurricanes.

Shortages of equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices and activity levels in new regions, causing periodic shortages. These problems can be particularly severe in certain regions such as the Williston Basin. During periods of high oil and gas prices, the demand for drilling rigs and equipment has increased along with increased activity levels, and this may result in shortages of equipment. In addition, there is currently a shortage of hydraulic fracturing capacity in many of the areas in which we operate. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel in our exploration, production and midstream operations. These types of shortages and subsequent price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

The exploration and future development of our Mt. Emmons Project is highly speculative, involves substantial expenditures, and may be non-productive.

Mineral exploration and development, including the exploration and development of our Mt. Emmons Project, involves a high degree of risk. Exploration projects are frequently unsuccessful and few prospects that are explored are ultimately developed into producing mines. We cannot assure you that our exploration or development efforts at Mt. Emmons will be successful. Substantial expenditures are required to determine if the project has economically mineable mineralization, and our ability to fund these expenditures will be driven substantially by the market price for molybdenum. It could take several years to obtain the necessary governmental approvals and permits to establish proven and probable mineral reserves and to develop and construct mining and processing facilities. Because of these uncertainties, it cannot be assumed that our efforts at Mt. Emmons will result in the discovery of economic mineral reserves or the development of the project into a producing mine. Similarly, other attempts to create value from the Mt. Emmons Project, including a potential land exchange transaction, may not be successful.

Development of the Mt. Emmons Project is subject to numerous environmental and permitting risks

The Mt. Emmons Project is located on fee property within the boundary of U.S. Forest Service (“USFS”) land. Although mining of the mineral resource would occur on the fee property, associated ancillary activities will occur on USFS land. The Company submitted a full mine plan of operations in part to satisfy the requirements of the conditional water rights decree on October 10, 2012. Under the procedures mandated by the National Environmental Protection Act (“NEPA”), the USFS is expected to

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prepare an environmental analysis in the form of an environmental impact statement to evaluate the predicted environmental and socio-economic impacts of the proposed mine plan. 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. A water discharge permit under the Colorado Discharge Permit System (“CDPS”) is required before the USFS can approve the plan of operations. We currently have CDPS permits for the discharge from the water treatment plant and for stormwater discharges associated with the Mt. Emmons Project, but this project is not related to proposed mining activities.

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

Obtaining and maintaining the various permits for the mining operations at the Mt. Emmons Project will be complex, time-consuming, and expensive, and is subject to ongoing litigation. 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 control, or changes in agency policy and federal and state laws, could further affect the successful permitting of the mine operations and the costs of complying with environmental permits and related requirements. The timing, cost, and ultimate success of our future development efforts and mining operations cannot be predicted.

We depend on key personnel.

Our employees have experience in dealing with the acquisition of 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 engineering, geophysical and geological advice in oil and gas matters. 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 oil and gas and minerals industry.

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

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issued without registration under the Securities Act of 1933, it was sold at a discount to market prices. We have also issued stock in public offerings. 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 would result in dilution to existing shareholders. Future issuances of equity securities, or securities convertible into equity securities, would also have a dilutive effect on existing shareholders. In addition, the perception that such issuances may occur could adversely affect the market price of our common stock.

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. Accordingly, stockholders must look solely to increases in the price of our common stock to realize a gain on their investment, and this may not occur.

We could implement take-over defense mechanisms that could discourage some advantageous transactions.

Although our shareholder rights plan expired in 2011, certain provisions of our governing documents and applicable law could have anti-takeover effects. For example, we are subject to a number of provisions of the Wyoming Management Stability Act, an anti-takeover statute, and have a classified or “staggered” board. In addition, we could implement additional anti-takeover defenses in the future. These existing or future defenses could prevent or discourage a potential transaction in which shareholders would receive a takeover price in excess of then-current market values, even if a majority of the shareholders support such a transaction.

Our stock price likely will continue to be volatile.

Our stock is traded on the Nasdaq Capital Market. In the two years ended December 31, 2012, the stock has traded as high as $6.60 per share and as low as $1.50 per share. The principal factors which have contributed and/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 stock trading on any given day;

·	fluctuations in our financial operating results;

·	industry trends;

·	legislative and regulatory changes; and

·	global economic uncertainty.

The stock market has recently experienced significant price and volume fluctuations, as have commodity prices. These fluctuations have particularly affected the market prices of securities of oil and gas companies like ours. These market fluctuations could adversely affect the market price of our stock.

Item 1 B - Unresolved Staff Comments.

None.

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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, 2010, 2011 and 2012 are based on reserve reports prepared by Cawley, Gillespie & Associates, Inc., or CGA, Ryder Scott Company, L.P., or Ryder Scott, and Netherland, Sewell & Associates, Inc., or NSAI. CGA, Ryder Scott and NSAI are nationally recognized independent petroleum engineering firms. CGA is a Texas Registered Engineering Firm (F-693). Our primary contact at CGA is Mr. W. Todd Brooker, Senior Vice President. Mr. Brooker is a State of Texas Licensed Professional Engineer (License # 83462). 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). NSAI is a Texas Registered Engineering Firm (F-2699). Our primary contact at NSAI is Mr. Richard B. Talley, Jr., Vice President. Mr. Talley is a State of Texas Licensed Professional Engineer (License # 102425). CGA prepared the estimates for all properties in 2012 and for our North Dakota properties in 2011 and 2010. NSAI prepared the estimates for our Austin Chalk and Eagle Ford properties in Texas in 2011 and 2010. Ryder Scott prepared the estimates related to our Gulf Coast Basin, including Louisiana and Texas properties in 2011 and 2010. The reserve estimates were based upon the review (by the relevant contracted engineering firm(s)) of the production histories and other geological, economic, ownership and engineering data, as provided by us and the corresponding operators to them. Copies of these reports are filed as exhibits to this Annual Report.

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,
	2012		2011		2010
Net proved reserves
Oil (Bbls)
Developed		1,770,659		1,884,068		1,362,733
Undeveloped		842,984		853,930		183,713
Total		2,613,643		2,737,998		1,546,446

Natural gas (Mcf)
Developed		1,420,295		1,973,453		1,996,490
Undeveloped		377,791		760,595		139,286
Total		1,798,086		2,734,048		2,135,776

Plant Products (Bbls)
Developed		--		1,688		52,532
Undeveloped		--		--		--
Total		--		1,688		52,532

Total proved reserves (BOE)		2,913,324		3,195,361		1,954,941

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(1)

Reserve estimates 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. Reserve estimates as of December 31, 2012 are based on prices of $94.71 per barrel of oil and $2.757 per MMbtu of natural gas, in each case adjusted for regional price differentials and other factors.

As of December 31, 2012, our proved reserves totaled 2,913,324 BOE (69% developed and 31% undeveloped), comprised of 2,613,643 Bbls of oil (90% of the total) and 1,798,086 Mcf of natural gas (10% of the total). 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”. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetrics, material balance, advance production type curve matching, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

Proved Undeveloped Reserves

As of December 31, 2012, we had 905,950 BOE of proved undeveloped reserves, which is a decrease of 74,746 BOE, or 8%, compared with 980,696 BOE of proved undeveloped reserves at December 31, 2011. We invested approximately $4.4 million to convert 111,630 BOE of proved undeveloped reserves to “proved developed reserves” in 2012 in our Bakken/Three Forks properties. The following table details the changes in the quantity of proved undeveloped reserves during the year ended December 31, 2012:


December 31, 2012		BOE
Beginning of year		980,696
Conversion to Proved Developed Producing		(111,630)
Revisions of previous quantity estimates		(91,953)
Extensions, discoveries and improved recoveries		645,953
Purchase of reserves in place		--
Sales of reserves in place		(517,116)
End of Year		905,950

As of December 31, 2012, we have no proved undeveloped reserves that have been on the books in excess of five years and we have recorded no material proved undeveloped locations that were more than one direct offset from an existing producing well. Additionally, no proved undeveloped reserves are scheduled for development beyond five years of booking. As of December 31, 2012, estimated future development costs relating to proved undeveloped reserves are projected to be approximately $21.0 million over the next five years.

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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,
	2012		2011		2010
Production Volume
Oil (Bbls)		373,531		300,325		303,433
Natural gas (Mcf)		347,810		736,261		757,905
Natural gas liquids (Bbls)		13,203		19,325		19,104
BOE		444,702		442,360		448,855

Daily Average Production Volume
Oil (Bbls/d)		1,021		823		831
Natural gas (Mcf/d)		950		2,017		2,076
Natural gas Liquids (Bbls/d)		36		53		52
BOE/d		1,215		1,212		1,230

Oil Price per Bbl Produced
Realized Price	$	82.38	$	87.80	$	72.11

Natural Gas Price per Mcf Produced
Realized Price	$	3.25	$	4.85	$	4.96

Natural Gas Liquids Price per Bbl Produced
Realized Price	$	47.84	$	52.88	$	47.53

Average Sale Price per BOE (1)	$	73.16	$	69.98	$	59.15

Expense per BOE
Production costs (2)	$	16.42	$	19.10	$	6.81
Depletion, depreciation and amortization	$	33.49	$	31.64	$	23.64

(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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The following table provides a regional summary of our production for the years ended December 31, 2012, 2011 and 2010:

	December 31,
	2012	2011	2010
Williston Basin
Oil (Bbls)	352,372	271,939	282,527
Natural gas (Mcf)	124,077	129,635	98,820
Natural gas liquids (Bbls)	12,113	-	-
BOE	385,165	293,545	298,997
Gulf Coast / East Texas
Oil (Bbls)	3,120	16,081	20,906
Natural gas (Mcf)	194,888	590,982	659,085
Natural gas liquids (Bbls)	477	19,325	19,104
BOE	36,078	133,903	149,858
Eagle Ford
Oil (Bbls)	10,283	4,290	-
Natural gas (Mcf)	27,351	8,479	-
Natural gas liquids (Bbls)	437	-	-
BOE	15,279	5,703	-
Austin Chalk
Oil (Bbls)	7,756	8,015	-
Natural gas (Mcf)	1,494	7,165	-
Natural gas liquids (Bbls)	176	-	-
BOE	8,181	9,209	-
Total
Oil (Bbls)	373,531	300,325	303,433
Natural gas (Mcf)	347,810	736,261	757,905
Natural gas liquids (Bbls)	13,203	19,325	19,104
BOE	444,702	442,360	448,855

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, 2010 through December 31, 2012. The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells.

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	Years Ended December 31,
	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Development:
Productive		11.0000		1.7621		1.0000		0.2491		--		--
Non-productive		--		--		--		--		--		--
		11.0000		1.7621		1.0000		0.2491		--		--
Exploratory:
Productive		8.0000		1.1198		12.0000		2.9817		8.0000		2.9409
Non-productive		7.0000		1.3913		4.0000		0.7954		5.0000		0.3902
		15.0000		2.5111		16.0000		3.7771		13.0000		3.3311
Total		26.0000		4.2732		17.0000		4.0262		13.0000		3.3311

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, 2012. 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		82.00		14.88		18.14027	%
Natural Gas		1.00		0.17		17.00000	%
Total (1)		83.00		15.05		18.12653	%

(1)	The average working interest for the sixty-six Williston Basin wells producing at December 31, 2012 is 16.08%; the remaining seventeen wells (Texas and Louisiana) have an average working interest of 26.07%.

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The following map reflects where our oil and gas properties are generally located:

Acreage

The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2012.

	Developed				Undeveloped				Total
AREA	Gross		Net		Gross		Net		Gross		Net

Williston Basin
Rough Rider Prospect (1)		19,200		1,175		--		--		19,200		1,175
Yellowstone and SEHR Prospects (1)		20,480		859		15,360		791		35,840		1,650
ASEN North Dakota Acquisition (1)		29,440		400		--		--		29,440		400
Wolverine Prospect, Daniels County, MT		--		--		30,382		2,367		30,382		2,367

East Texas and Louisiana		4,414		978		19,500		2,119		23,914		3,097

Eagle Ford/Austin Chalk
Leona River Prospect		240		72		4,435		1,330		4,675		1,402
Booth Tortuga Prospect		8,832		2,459		--		--		8,832		2,459
TOTAL		82,606		5,943		69,677		6,607		152,283		12,550

(1) The total gross acres for this area is calculated by multiplying the number of drilling units we participate in by 1,280 acres

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As a non-operator, we are subject to lease expiration if any operator does not commence the development of operations within the agreed terms of our leases. All of our leases for undeveloped acreage summarized in the table below will expire at the end of their respective primary terms, unless we renew the existing leases, establish commercial production from the acreage or some other “savings clause” is exercised. In addition, our leases typically provide that the lease does not expire at the end of the primary term if drilling operations have been commenced. While we generally expect to establish production from most of our acreage prior to expiration of the applicable lease terms, there is no assurance that we can do so. The approximate expiration of our gross and net acres which are subject to expiration between 2013 and 2016 are set forth below:

	Williston Basin, North Dakota and Montana				Eagle Ford/Austin Chalk, Texas				East Texas and Louisiana				TOTAL
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
2013		21,680		1,215		1,154		409		19,500		2,119		42,334		3,743
2014		15,359		1,444		2,392		476		-		-		17,751		1,920
2015		6,783		403		889		445		-		-		7,672		848
2016		1,920		96		-		-		-		-		1,920		96
		45,742		3,158		4,435		1,330		19,500		2,119		69,677		6,607

Present Activities

As of March 11, 2013, we were in the process of drilling 2 gross wells (0.06 net) and 7 gross wells (0.18 net) were drilled and waiting on completion.

Molybdenum – Mt. Emmons Project

The Mt. Emmons Project is located near Crested Butte, Colorado and includes a total of 160 fee acres, 25 patented and approximately 1,345 unpatented mining and mill site claims, which together approximate 9,853 acres, or over 15 square miles of claims and fee lands. The Mt. Emmons Project is located in Gunnison County, Colorado. The property is accessed by vehicle traffic on Gunnison County Road 12.

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We own both surface and mineral rights at the Mt. Emmons Project in fee pursuant to mineral patents issued by the federal government. 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 to the Bureau of Land Management; the total amount paid for mining and millsite claim maintenance fees in 2012 was $193,000.

The breakdown of the property is as follows:

	Acres	Number of Claims
Patented Claims / Fee Land	365	25
Unpatented Claims	5,923	664
Mill Site Claims	3,405	681
Fee Property	160	n/a
Total	9,853	1,370

History of the Mt. Emmons Project

We leased various patented and unpatented mining claims on the Mt. Emmons Project to Amax, Inc. (“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 Mt. Emmons Project to treat water flowing from the historic 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. Phelps Dodge (“PD”) then acquired the Mt. Emmons Project in 1999 through its acquisition of Cyprus Amax. Thereafter, PD acquired additional conditional water rights and patents to certain mineral claims. The Company re-acquired the Mt. Emmons Project on February 28, 2006. The property was returned to us by PD in accordance with a 1987 Amended Royalty Deed and Agreement between us and Amax.

The exploration work conducted in the late 1970s by Amax 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 Mt. 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 are also a number of existing mine adits located on the property. Historic work completed by Amax 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 was collected from this area and sent off site for metallurgical testing.

In its 1992 patent application, Cyprus Amax stated that the size and grade of the Mt. Emmons deposit was determined to approximate 220 million tons of mineralized material grading 0.366% molybdenite. In a letter dated April 2, 2004, the U.S. Bureau of Land Management (the “BLM”) estimated that there was 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

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which is only a portion of the total mineral deposit delineated to date. The analysis set forth in the letter 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.

We note that the statements made by the predecessor owners of the Mt. Emmons Project regarding “recoverable” minerals and “mineralized material” were based on costs, permitting requirements and commodity prices then prevailing. We believe these estimates to be relevant, but they should not be relied upon. Substantial additional exploration and drilling efforts and a full feasibility study will be required, using current estimated 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.

On April 21, 2011, Thompson Creek Metals Company USA (“Thompson Creek” or “TCM”) terminated the August 10, 2008 Exploration, Development and Mine Operating Agreement (“the Agreement”) with the Company. TCM advised the Company that the termination was the result of TCM desiring to concentrate efforts on other mineral resource projects with a shorter projected time line for commencing production. Although TCM had spent approximately $14.4 million in option payments and work expenditures on the property through April 21, 2011, TCM had not earned an interest in the property at termination and currently has no interest in the property.

In December 2008, an additional 160 acres of fee land in the vicinity of the claims was purchased by the Company and TCM for $4 million ($2 million in January 2009, $400,000 annually for five years). On December 6, 2011, TCM notified the Company that it wishes to sell its interest in the property. The Company has 18 months (until June 6, 2013) to decide whether to purchase TCM’s interest and the property and close such purchase.

In October 2012, the Company acquired 17 additional mill site claims, totaling approximately 85 additional acres.

Geology

The sedimentary sequence in the Mt. Emmons area spans from the late Cretaceous to the early Tertiary periods. 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 Mt. 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 Mt. 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 Mt. 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 Mt. Emmons. Capping Mt. Emmons is the Wasatch Formation, also of early Tertiary (Paleocene to Eocene) age.

On a more regional scale, within the Ruby Range the Wasatch Formation may reach 1,700 feet in thickness. However, on Mt. 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

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sandstones, and volcanic pebble conglomerates. The Mt. Emmons stock has intruded the Mancos and Mesaverde sediments, strongly metamorphosing both formations to hornfels up to 1,500 feet outward from the igneous body.

Sedimentary rocks on Mt. 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 Mt. Emmons molybdenum mineralized zone and the associated alteration zones. Hydrothermal alteration associated with the Mt. 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 Mt. Emmons stock.

Water Treatment Plant; Site Facilities

PD’s 2006 re-conveyance of the property to the Company 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 Public Health and Environment (“CDPHE”). We are responsible for all operating and maintenance costs. Also, as described in the Mine Plan of Operations submitted to the USFS, the Company plans on using the current mine water treatment plant in the milling operations for the Mt. Emmons Project.

The water treatment plant was constructed by Amax in 1981 (at a cost of approximately $15 million) to treat mine discharge water from the historic Keystone Mine which produced lead and zinc. A certified water treatment plant operations contractor with five licensed and/or trained employees operates the water treatment plant on a continuous basis, treating water discharged from the historic Keystone Mine. The plant utilizes a standard lime pH adjustment to precipitate heavy metals from the water. Mine water is then filtered and discharged to Coal Creek in accordance with the requirements of the CDPS permit for the plant, and solids are dewatered and mixed with cement for proper disposal in accordance with state and federal law. Modifications and improvements to the treatment system were tested and implemented in 2012 to enhance compliance with existing and anticipated future discharge requirements. We also maintain coverage under the CDPS General Permit for Stormwater Discharges associated with the Metal Mining Industry. This permit provides authorization to discharge stormwater from the Mt. Emmons Project subject to the general requirements of the permit itself, which are applicable to all active and inactive metal mining operations in Colorado, and a site-specific stormwater management plan. Permit modifications in 2012 require monitoring of stormwater discharges and the reporting of monitoring results to the CDPHE in 2013. In 2013, we will also be commencing a more comprehensive study of natural and human-induced conditions in the region that may be affecting water quality in Coal Creek.

Additional equipment used in the operation of the water treatment plant includes large front-end loaders, forklifts, specialized snow removal equipment and pickup trucks.

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.

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Historical Capital Expenditures by Prior Owners, and Related Information

Amax reportedly spent approximately $150 million in exploration and related activities on the Mt. Emmons Project, which included construction of the water treatment plant. Since the Company reacquired the property in 2006, an additional $22.7 million has been spent on the development of the property. In addition, our annual 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.

We are using grid electric power to operate the water treatment plant and other facilities from the local electric utility serving Gunnison County.

Activities in 2010 - 2012 and Plans for 2013

On October 10, 2012, the Company submitted a full mine plan of operations to the U.S. Forest Service to satisfy the requirements of the conditional water rights decree. During 2013, we will be working with the U.S. Forest Service to achieve a completeness determination of the mine plan of operations.

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 $12.81 in 2012, compared to $15.59 in 2011.

Real Estate

Remington Village - Gillette, Wyoming

We own Remington Village, 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.

Occupancy averaged 89% in 2012. For the year, we realized average monthly revenues of approximately $170,000. The occupancy rate was 89% at December 31, 2010, 82% at December 31, 2011 and 88% at December 31, 2012. The decrease in occupancy rate from 2010 to 2011 was due to the national economic downturn, reduced activities in the oil and gas sector in Wyoming and competition with available single family housing. On May 5, 2011, we borrowed $10.0 million from a commercial bank. The note is secured by the Remington Village. The note has a term of five years and has an interest rate of 5.50% per annum. The proceeds of the note are being used to facilitate our general business obligations.

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Impairments of $3.0 million, $3.1 million and $1.5 million were recorded at December 31, 2012, 2011 and 2010, respectively, on the property to reflect the difference between the cost of the property and its estimated fair market value. 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 plans to sell this property in 2013 and redirect the sale proceeds to 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, we own three city lots covering 13.84 acres adjacent to our corporate office building and two unrelated vacant lots covering approximately 10.23 acres in Fremont County, Wyoming. When the real estate market recovers we intend to sell these properties without development.

There can be no assurance that sales of any of these assets, or of Remington Village, will be completed on the terms, or in the time frame, we expect or at all.

In January 2013, we sold our 10,000 square foot aircraft hangar on land leased from the City of Riverton with 7,000 square feet of associated offices and facilities for $767,000.

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 the time 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 any potential 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.

Marketing, Major Customers and Delivery Commitments

Markets for oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. All of our production is marketed by our industry partners for our benefit and is sold to competing buyers, including large oil refining companies and independent marketers. Substantially all of our production is sold pursuant to agreements with pricing based on prevailing commodity prices, subject to adjustment for regional differentials and similar factors. We had no material delivery commitments as of December 31, 2012.

Competition

The oil and natural gas business is highly competitive in the search for and acquisition of additional reserves and in the sale of oil and natural gas. Our competitors principally consist of major and intermediate sized integrated oil and natural gas companies, independent oil and natural gas companies and individual producers and operators. In particular, we compete for property acquisitions and our operating partners compete for the equipment and labor required to operate and develop our properties. Our competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.

Environmental

Like the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve natural resources and the environment. The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands. Federal, state and local laws and regulations regarding the discharge of materials into the environment or otherwise relating to the protection of the environment include NEPA, the Clean Air Act, the Federal Water Pollution Control Act of 1972 (the “Clean Water Act”), the Colorado Water Quality Control Act, the Oil Pollution Act of 1990, RCRA, and CERCLA. Regulations, including permit requirements, applicable to our operations have been changed frequently in the past and, in general, these changes have imposed more stringent requirements that increase operating costs and/or require capital expenditures to remain in compliance. Failure to comply with these requirements can result in civil and/or criminal penalties and liability for non-compliance, clean-up costs and other environmental damages. It is also possible that unanticipated developments or changes in the law could require us to make environmental expenditures significantly greater than those we currently expect.

With respect to proposed mining operations at the Mt. Emmons Project, Colorado’s mine permitting statute, the Abandoned Mine Reclamation Act, and industrial development and siting laws and regulations, may also affect the project. We believe we are in compliance in all material respects with existing environmental regulations. In October 2012, the CDPHE modified the CDPS stormwater permit

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for the site to require additional monitoring to determine whether or not stormwater discharges from the site are in full compliance with permit requirements. The CDPHE is likely to impose more stringent requirements when the permit is up for renewal in 2013. In addition, we will be performing monitoring at and surrounding the Mt. Emmons Project beginning in 2013 in an effort to identify sources of heavy metals loading to Coal Creek. The results of these studies may be used to revise water quality standards and permit limits in a way that better ensures the feasibility of discharge permit compliance long term. 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 Mt. Emmons Project, see the consolidated financial statements included in Part II of this Annual Report.

We may generate wastes, including “solid” wastes and “hazardous” wastes that are subject to regulation under RCRA and comparable state statutes, although certain mining and oil and natural gas exploration and production wastes currently are exempt from regulation as hazardous wastes under RCRA. EPA has limited the disposal options for certain wastes that are designated as hazardous wastes. Moreover, certain wastes generated by our mining and oil and natural gas operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes and, as a result, become subject to more rigorous and costly management, disposal and remediation requirements.

With respect to hydraulic fracturing, the EPA amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act, or the SDWA, to exclude hydraulic fracturing from the definition of “underground injection.” The 111th United States Congress considered bills entitled the Fracturing Responsibility and Awareness of Chemicals Act, or the FRAC Act, to amend the SDWA to repeal this exemption, but Congress adjourned without taking any significant action on the bills. The FRAC Act was re-introduced in the 112th Congress and, if enacted, would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, including disclosure of chemicals used in the fracturing process and meet plugging and abandonment requirements. The FRAC Act’s proposal to require the reporting and public disclosure of chemicals used in the fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. It is not possible to predict whether the current or a future session of Congress may act further on hydraulic fracturing legislation. Such legislation, if adopted, could establish an additional level of regulation and permitting at the federal level. In addition, in March 2010, at the request of the U.S. Congress, EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts hydraulic fracturing may have on drinking water resources. A first progress report is planned for late 2012. A final draft report is expected to be released for public comment and peer review in 2014.

Currently, regulation of hydraulic fracturing primarily is conducted at the state level through permitting and other compliance requirements. For example, Colorado and Wyoming recently have enacted rules to regulate hydraulic fracturing. The Colorado rules require companies to identify the chemicals and the concentrations of those chemicals used in hydraulic fracturing on searchable public database. The Wyoming rules require companies to submit to the Wyoming Oil and Gas Conservation Commission a list of chemicals they plan to use in hydraulic fracturing operations on a well-by-well basis. Companies also have to report the concentration of each chemical used once the work is complete. States in which we conduct operations may implement similar disclosure requirements.

In April 2011, the EPA issued regulations specifically applicable to the oil and gas industry that will require operators to capture 95 percent of the volatile organic compounds (“VOC”) emissions from natural gas wells that are hydraulically fractured. The reduction in VOC emissions will be accomplished

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primarily through the use of “reduced emissions completion” or “green completion” to capture natural gas that otherwise would escape to the air. EPA also issued regulations that set requirements for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves and sweetening units at gas processing plants. The adoption of these regulations, or the adoption of any other laws or regulations restricting or reducing these emissions, will increase our operating costs.

Climate change has emerged as an important topic in public policy debate regarding our environment. It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in greenhouse gases (“GHGs”). Products produced by the oil and natural gas exploration and production industry are a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations. The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the Clean Air Act. The EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered, and may in the future consider, “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.

Although all of our currently producing oil and gas properties are operated by third parties, the activities on the properties are still subject to environmental protection regulations that affect us. 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 for which we could have liability. Based on the current regulatory environment in those states where we have oil and natural gas investments and rules and regulations currently in effect, we do not currently expect to make any material capital expenditures for environmental control facilities.

Gas and oil operations also are subject to various federal, state and local regulations governing natural gas and oil production 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 groundwater resources, 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 to change existing requirements or to add new requirements. Regulatory changes can adversely impact the permitting and exploration and development of mineral and oil and gas properties including the availability of capital.

In addition, oil and gas and mineral projects are subject to extensive permitting requirements. 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.

Insurance

The following summarizes the material aspects of the Company’s insurance coverage:

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General

We have liability insurance coverage in amounts we deem sufficient for our business operations, consisting of property loss insurance on all major assets equal to the approximate replacement value of the assets and additional liability and control of well insurance for our oil and gas drilling programs. Payment of substantial liabilities in excess of coverage could require diversion of internal capital away from regular business, which could result in curtailment of projected future operations.

Mt. Emmons Project

The Company is responsible for all costs to operate the water treatment plant at the Mt. Emmons Project. 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).

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.

Corporate Aircraft

Until the corporate airplane is sold, the Company maintains a $20 million per event liability policy. We also maintain a $4 million physical damage insurance policy on the aircraft which approximates its 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 December 31, 2012, we had 15 full-time employees.

Mining Claim Holdings

Title

Approximately 25 of the Mt. Emmons Project 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 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

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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 Mt. Emmons Project 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 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, 2012 and developments in those proceedings from that date to the date of this Annual Report are summarized below.

Water Rights Litigation –Mt. Emmons Project

On July 25, 2008, we filed an Application for Finding of Reasonable Diligence with the Colorado Water Court (“Water Diligence Application”) concerning the conditional water rights associated with the Mt. Emmons Project (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 Decree, or within six years of the final determination of the 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 (by denial of certiorari) upholding BLM’s issuance of the mineral patents. 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 United States Forest Service (“USFS”) regulations and did not satisfy certain “reality check” limitations contained in the Decree. On September 24, 2010, we filed a response to the motion for summary judgment responding that the plan of operations complied with USFS and BLM regulations and satisfied the reality check limitations. The U.S. Department of Justice also filed a response on behalf of the USFS and BLM asserting that the Court cannot second guess the USFS’s determination that the plan of operations satisfied USFS and BLM regulations.

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. On

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October 10, 2012 the Company filed a Plan of Operations with the USFS in compliance with the reality check provision of the Decree. The question of the adequacy of the Water Diligence Application is pending.

Appeal of Approval of Notice of Intent to Conduct Prospecting for the Mt. Emmons Project

On March 8, 2008, High Country Citizens’ Alliance (“HCCA”) filed a request for hearing before the Colorado Mine Land Reclamation Board (“Board”) of the approval of a “Notice of Intent to Conduct Prospecting” (“NOI”) for the Mt. Emmons Project, which was approved by the Division of Reclamation, Mining and Safety of the Colorado Department of Natural Resources (“DRMS”) on January 3, 2008. 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 1970s. On May 14, 2008, the MLRB denied HCCA’s request for hearing and also denied its request for a declaratory order. Citing Colorado law, the Board determined that HCCA did not have standing or the right to appeal DRMS’s approval of the NOI under Colorado law.

On August 28, 2008, HCCA appealed the 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 Board has filed an answer with the Court. The DRMS and the Company both filed the responsive pleadings in addition to motions to dismiss the HCCA complaint.

On February 24, 2011, the District Court issued an order dismissing all of HCCA’s claims concerning the appeal of the NOI holding that: (i) HCCA does not have standing to request judicial review on the merits of the DRMS’s approval of the NOI and (ii) HCCA does not have standing to request a declaratory order. This decision upholds the Board’s May 14, 2008 decision denying HCCA’s request for hearing and its 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.

Appeal of Modification – Notice of Intent to Conduct Prospecting for the Mt. Emmons Project

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 Board 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 Board on a 4-1 vote upheld DRMS’s approval of MD-03 and its 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 District Court.

On June 30, 2012, the District Court affirmed the Board’s decision on all matters including our position that the current financial warranty amount was sufficient to cover the proposed activities. The District Court dismissed the HCCA’s complaint and authorized our reimbursement of costs reimbursed from HCCA upon the filing the proper paperwork. On July 25, 2012, HCCA filed an appeal of the District Court’s decision with the Colorado Court of Appeals.

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Brigham Oil & Gas, L.P.

On June 8, 2011, Brigham Oil & Gas, L.P. (“Brigham”), as the operator of the Williston 25-36 #1H Well, filed an action in the State of North Dakota, County of Williams, in District Court, Northwest Judicial District, Case No. 53-11-CV-00495 to interplead to the court the undistributed suspended funds from this well to protect itself from potential litigation. Brigham became aware of an apparent dispute with respect to ownership of the mineral interest between the ordinary high water mark and the ordinary low water mark of the Missouri River. Brigham has suspended payment of certain proceeds of production related to the minerals in and under this property pending resolution of the apparent dispute. Energy One is a working interest owner in this well as a result of a participation agreement and a joint operating agreement with Brigham and Energy One’s legal position is aligned with Brigham. All funds due to Energy One on this well have been distributed to Energy One and there are no undistributed suspended funds held in suspense by Brigham for Energy One. Although initially listed as a defendant in this proceeding, Brigham and Energy One anticipate filing with the court documents to change Energy One’s status to an additional plaintiff.

Item 4 – Mine Safety Disclosures.

Not applicable.

PART II

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

Market Information

Our common stock is traded on the over-the-counter market, and prices are reported on a "last sale" basis on the Nasdaq Capital Market. Quarterly high and low sale prices follow:

	High		Low
Calendar year ended December 31, 2012
First Quarter	$	3.77	$	2.85
Second Quarter		3.14		2.15
Third Quarter		2.49		2.12
Fourth Quarter		2.18		1.50
Calendar year ended December 31, 2011
First Quarter	$	6.60	$	5.17
Second Quarter		6.49		3.88
Third Quarter		4.57		2.20
Fourth Quarter		3.40		2.05

Holders

At March 11, 2013 the closing market price was $1.77 per share. There were approximately 1,131 shareholders of record, with 27,652,602, shares of common stock issued and outstanding at December 31, 2012.

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We paid a one-time 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 2012

During the twelve months ended December 31, 2012, we issued a total of 242,694 shares of common stock. These issuances were comprised of 1,070 shares of common stock as a result of the exercise of options which had been issued to employees and 20,000 shares as a result of the exercise of warrants issued to outside directors. We also issued 161,624 shares pursuant to the terms of our ESOP. The ESOP funding represents the minimum required amount during the twelve months ended December 31, 2012. During the twelve months ended December 31, 2012, we issued 60,000 shares pursuant to the 2001 Stock Award Plan, comprised of 20,000 shares each to the CEO, COO and General Counsel.

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, 2012, 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. 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.

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

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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 except per share data)
	Years ended December 31,
	2012		2011		2010		2009		2008

Current assets	$	26,015	$	41,604	$	50,562	$	85,300	$	95,882
Current liabilities		13,253		20,937		18,763		8,672		19,983
Working capital		12,762		20,667		31,799		76,628		75,899
Total assets		140,827		162,439		156,016		146,723		142,631
Long-term obligations(1)		11,457		13,532		1,150		973		1,870
Shareholders' equity		116,117		126,781		130,688		129,133		111,833

(1) Includes $686,000 of accrued reclamation costs at December 31, 2012, $510,000 at December 31, 2011,
$303,000 at December 31, 2010, $211,000 at December 31, 2009, and $144,000 at December 31, 2008

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	(In thousands except per share data)
	For the years ended December 31,
	2012			2011			2010			2009			2008
Operating revenues	$	32,534		$	30,958		$	26,548		$	7,581		$	691
Loss from continuing operations		(10,344	)		(5,216	)		(986	)		(9,935	)		(10,296	)
Other income & expenses		849			(717	)		(332	)		(1,331	)		(17	)
Loss before income taxes and discontinued operations		(9,495	)		(5,933	)		(1,318	)		(11,266	)		(10,313	)
Benefit from income taxes		44			3,755			1,860			2,562			3,326
Discontinued operations, net of tax		(1,794	)		(2,629	)		(1,314	)		526			5,599

Net loss	$	(11,245	)	$	(4,807	)	$	(772	)	$	(8,178	)	$	(1,388	)

Per share financial data
Operating revenues	$	1.18		$	1.14		$	0.99		$	0.35		$	0.03
Loss from continuing operations		(0.38	)		(0.19	)		(0.04	)		(0.46	)		(0.44	)
Other income & expenses		0.03			(0.03	)		(0.01	)		(0.06	)		--
Gain (loss) before income taxes and discontinued operations		(0.34	)		(0.22	)		(0.05	)		(0.52	)		(0.44	)
Benefit from income taxes		--			0.14			0.07			0.12			0.14
Discontinued operations, net of tax		(0.07	)		(0.10	)		(0.05	)		0.02			0.24

Net loss per share basic and diluted	$	(0.41	)	$	(0.18	)	$	(0.03	)	$	(0.38	)	$	(0.06	)

Basic shares outstanding		27,466,549			27,238,869			26,763,995			21,604,959			23,274,978

Diluted shares outstanding		27,466,549			27,238,869			26,763,995			21,604,959			23,274,978

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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”, “USE”, the “Company”, “we” or “us”) is an independent energy company focused on the acquisition and development of 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), Texas and Louisiana. However, we do not intend to limit our focus to these geographic areas. We continue to focus on increasing production, reserves, revenues and cash flow from operations while managing our level of debt. Prior to 2008 the Company invested in mineral properties and sold them prior to placing them into production.

We currently explore for and produce oil and gas through a non-operator business model; however, we may operate oil and gas properties for our own account and may expand our holdings or operations into other areas. As a non-operator, we rely on our operating partners to propose, permit and manage wells. Before a well is drilled, the operator is required to provide all oil and gas interest owners in the designated well 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.

We are also involved in the exploration for and development of minerals (molybdenum) through our ownership of the Mt. Emmons Project in Colorado. Gross capitalized dollar amounts invested in each of these areas at December 31, 2012 and December 31, 2011 were as follows:

	(In thousands)
	December 31,		December 31,
	2012		2011
Unproved oil and gas properties	$	9,169	$	20,007
Proved oil and gas properties		119,919		99,496
Undeveloped mining properties		20,739		20,739
	$	149,827	$	140,242

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Oil & Gas Activities

In 2012, we had the following financial and operational results:

Revenue growth. In 2012, we recognized record revenues from oil and natural gas production of $32.5 million as compared to $31.0 million during the year ended December 31, 2011. This comes as a result of increased production during 2012 that was offset by lower oil and gas prices for a net increase of $1.5 million.

Reserves. Our proved reserves were 2,913,324 BOE at December 31, 2012 as compared to 3,195,361 BOE at December 31, 2011.

Production. Our 2012 annual production was 444,702 BOE, or 1,215 BOE/d, as compared to 442,360 BOE, or 1,212 BOE/d in 2011.

Financial flexibility. In the first quarter of 2012, the borrowing base under the Credit Facility was redetermined and was increased from $28.0 million to $30.0 million and the maximum commitment amount of the bank group increased to $100.0 million. At the end of 2012, we had $10.0 million outstanding under the facility. See “Capital Resources – Wells Fargo Senior Credit Facility” below.

Commodity prices. Our average realized oil price in 2012 was $82.38 per Bbl (excluding the impact of our economic hedges), or $5.42 lower than the 2011 price of $87.80. Our average natural gas price realized during 2012 was $3.25 per Mcf, $1.60 per Mcf lower than the 2011 price of $4.85. 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.

Through Energy One, from time to time, we enter into commodity derivative contracts (“hedges”), typically costless collars and fixed price swaps. U.S. Energy is a guarantor of Energy One’s obligations under the hedges. The objective of our hedging program 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, such use may limit our ability to benefit from favorable price movements. Energy One may 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 its existing positions.

The Dodd-Frank Act included provisions generally requiring over-the-counter derivative transactions to be executed through an exchange or centrally cleared. On July 10, 2012, the CFTC and the SEC adopted final joint rules under Title VII of the Dodd-Frank Act, which define certain terms and determine certain types of transactions that will be regulated under the Dodd-Frank Act swap rules. The issuance of these final rules also triggers compliance dates for a number of other final Dodd-Frank Act rules. The ultimate effect on our business of these new rules and any additional regulations is currently uncertain. Under CFTC rules we believe our derivative activity will qualify for the commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement if certain requirements are satisfied. However, certain other rules and regulations could require us to post margin in connection with commodity price risk management activities. Although we cannot predict the ultimate effect of additional rules and regulations in this area, they may result in

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increased costs and cash collateral requirements for the types of derivative instruments we use to manage our financial risks related to volatility in oil prices and could make it impracticable to implement our hedging strategy.

Drilling programs. We have active agreements with several oil and gas exploration and production companies. Our working interest varies by project and can range from approximately 1% to 62%. These projects may result in numerous wells being drilled over the next three to five years. We are also actively pursuing the potential acquisition of additional exploration, development or production stage oil and gas properties or companies. The following table details our interests in producing wells as of December 31, 2012 and 2011.

	December 31,
	2012		2011
	Gross	Net(1)	Gross	Net(1)
Williston Basin:
Productive wells	66.00	10.61	23.00	8.09
Wells being drilled or awaiting completion	4.00	0.20	7.00	1.62

Gulf Coast/South Texas:
Productive wells	3.00	0.56	5.00	1.12
Wells being drilled or awaiting completion	--	--	1.00	0.13

Eagle Ford:
Productive wells	3.00	0.90	1.00	0.30
Wells being drilled or awaiting completion	--	--	1.00	0.30

Austin Chalk:
Productive wells	11.00	2.98	11.00	2.98
Wells being drilled or awaiting completion	--	--	--	--

Total:
Productive wells	83.00	15.05	40.00	12.49
Wells being drilled or awaiting completion	4.00	0.20	9.00	2.05

(1)

Net working interests may vary over time under the terms of the applicable contracts.

Williston Basin, North Dakota

Rough Rider Prospect. We participate in fifteen 1,280 acre drilling units in the Rough Rider prospect with Brigham Oil & Gas, L.P. (“Brigham”), a subsidiary of Statoil. From August 24, 2009 to December 31, 2012, we have drilled and completed 20 gross Bakken formation wells (7.31 net) and one gross Three Forks formation well (0.18 net) under the Drilling Participation Agreement with Brigham. Brigham operates all of the wells.

During the year ended December 31, 2012, the Company completed three gross wells (0.45 net) in the Rough Rider prospect. Our net investment in the Rough Rider prospect wells was $4.5 million for the year ended December 31, 2012.

Yellowstone and SEHR Prospects. We participate in twenty-seven gross 1,280 acre spacing units in the Yellowstone and SEHR prospects with Zavanna, LLC (“Zavanna”). Through December 31, 2012, we

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have drilled and completed 16 gross Bakken formation wells (2.68 net) in these prospects, including two gross wells (0.13 net) operated by Murex Petroleum and one gross well (0.01 net) operated by Slawson Exploration Company, Inc. Zavanna operates the remaining wells. At December 31, 2012, four additional gross wells (0.20 net) were being drilled or had been drilled and were awaiting completion.

During the year ended December 31, 2012, we completed eleven gross wells (1.65 net) and drilled ten gross wells (0.58 net) in the Yellowstone and SEHR prospects. Our net investment in the Yellowstone and SEHR prospect wells was $20.4 million during the year ended December 31, 2012.

On January 24, 2012 (but effective December 1, 2011), we sold an undivided 75% of our undeveloped acreage in the Yellowstone and SEHR prospects to GeoResources, Inc. (56.25%) and Yuma Exploration and Production Company, Inc. (18.75%) for $16.7 million and $1.4 million in reimbursed well costs. Under the terms of the agreement, we retained the remaining 25% of our interest in the undeveloped acreage and our original working interest in the initial 10 developed wells in the prospects. Our average working interest in the remaining locations is approximately 8.75% and our net revenue interests in new wells post sale are in the range of 6.7375% to 7.0%, proportionately reduced depending on Zavanna’s actual working interest percentages.

Bakken/Three Forks Asset Package Acquisition. On September 21, 2012, but effective July 1, 2012, we acquired interests in 27 producing Bakken and Three Forks formation wells and related acreage in McKenzie, Williams and Mountrail Counties of North Dakota for $2.3 million after adjusting for related revenue and operating expenses from the effective date through September 21, 2012. Under the terms of the agreement, we acquired working interests in 23 drilling units ranging from less than 1% to approximately 5%, with an average working interest of 1.45%. During the year ended December 31, 2012, we completed two additional gross wells (0.05 net) on these acquired properties. Our net investment in these wells was $508,000 during the year ended December 31, 2012. All acreage is currently held by production and produces approximately 47 BOE/d net to the Company.

Daniels County, Montana Undeveloped Acreage. On June 8, 2012, we sold an undivided 87.5% of our acreage in Daniels County, Montana to Greehey & Company Ltd. (“Greehey”) for $3.7 million. Under the terms of the agreement, we retained a 12.5% working interest in the acreage and reserved overriding royalty interests (“ORRI”) in leases we owned that had in excess of 81% NRI. Greehey also committed to drill a vertical test well to depths sufficient to core the Bakken and Three Forks formations on or before December 31, 2015. The Company delivered an 80% NRI to Greehey and a 1% ORRI to Energy Investments, Inc. (“EII”), a land broker in connection with the sale. The Company also paid EEI a commission equal to 10% of the cash consideration paid by Greehey.

U.S. Gulf Coast (Onshore) and East Texas

We participate with several different operators in the U.S. Gulf Coast (onshore) and in East Texas. At December 31, 2012, we had three gross producing wells (0.56 net) in this region.

In May 2012, we acquired a 26.5% initial working interest in approximately 6,766 gross acres in this area through a cash payment of $1.7 million. The promoted amount covers our portion of the costs for land, geological and geophysical work, as well as the dry hole costs for an initial test well in each of seven different prospects. Upon payout, our working interest will be reduced to 19.8%. During the year ended December 31, 2012, all seven prospects were drilled and deemed to be nonproductive.

During the year ended December 31, 2012, we drilled one additional gross well (0.10 net) that was determined to be nonproductive. Our net investment in Gulf Coast / East Texas wells and properties was $2.4 million during the year ended December 31, 2012.

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Eagle Ford Shale, South Texas

We may participate in up to 114 gross (34 net) drilling locations in the Leona River and Booth-Tortuga Eagle Ford prospects with Crimson Exploration Inc. ("Crimson"). During the year ended December 31, 2012, we drilled and completed two gross wells (0.60 net). Our net investment in these wells during the 2012 was $4.6 million.

Impairment of Proved Properties

2012 Production Results

The following table provides a regional summary of our production during the year ended December 31, 2012:

	Williston Basin			Gulf Coast / East Texas			Eagle Ford			Austin Chalk			Total
2012 Production
Oil (Bbl)		352,372			3,120			10,283			7,756			373,531
Gas (Mcf)		124,077			194,888			27,351			1,494			347,810
NGLs (Bbl)		12,113			477			437			176			13,203
Equivalent (BOE)		385,165			36,078			15,279			8,181			444,702
Avg. Daily Equivalent (BOE/d)		1,052			99			42			22			1,215
Relative percentage		87	%		8	%		3	%		2	%		100	%

Other

Minerals (molybdenum). The Mt. Emmons Project is located near Crested Butte, Colorado and includes a total of 160 fee acres, 25 patented and approximately 1,345 unpatented mining and mill site claims, which together approximate 9,853 acres, or over 15 square miles of claims and fee lands. Historical records filed by predecessor owners of the Mt. Emmons Project with the 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 will be successful in permitting the property. Our net investment in this property at December 31, 2012 was $20.7 million.

Geothermal. We own a 19.54% interest in Standard Steam Trust LLC (“SST”), a geothermal limited partnership. We recorded an equity loss from SST in 2012 of $359,000. 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, 2012 was $2.3 million. We have notified SST that we do not intend to fund any cash calls, which decision will result in a dilution of our ownership in SST if future cash calls are made.

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Real estate – asset held for sale. We will continue to receive cash flows, revenues and net profits from Remington Village until its sale. We do not plan to build or acquire any additional multifamily housing projects.

The principal factors affecting us are the success of our 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 our prospects.

Additional Comparative Data

The following table provides information regarding selected production and financial information for the year ended December 31, 2012 and the immediately preceding three quarters.

	For the Three Months Ended
	December 31, 2012			September 30, 2012			June 30, 2012			March 31, 2012
	(in Thousands, except for production data)
Production (BOE)		107,823			106,060			118,783			112,036
Oil, gas and NGL production revenue	$	8,039		$	7,639		$	8,522		$	8,335
Unrealized and realized derivative (loss) gain	$	(5	)	$	(466	)	$	1,764		$	(202	)
Lease operating expense	$	1,969		$	1,692		$	1,630		$	2,010
Production taxes	$	853		$	822		$	928		$	883
DD&A	$	3,812		$	3,410		$	4,030		$	3,641
General and administrative	$	1,497		$	1,659		$	1,760		$	1,894
Mineral holding costs	$	205		$	400		$	206		$	110
Water treatment plant	$	424		$	609		$	436		$	509
Income (loss) from continuing operations	$	(5,932	)	$	(2,709	)	$	(991	)	$	(712	)

Results of Operations

Three Months Ended December 31, 2012 Compared with the Three Months Ended December 31, 2011

During the three months ended December 31, 2012, we recorded a net loss after taxes of $7.9 million as compared to a net loss after taxes of $2.8 million during the same period of 2011. Significant components of the change in operating revenues and results of operations for the three months ended December 31, 2012 as compared to the three months ended December 31, 2011 are as follows:

Oil and Gas Operations. Excluding the $4.7 million non-cash impairment taken on our oil and gas properties during the period, oil and gas operations produced a net operating income of $1.4 million during the quarter ended December 31, 2012 as compared to operating income of $1.7 million during the quarter ended December 31, 2011. The following table summarizes production volumes, average sales prices and operating revenues for the three months ended December 31, 2012 and 2011:

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	Three Months Ended
	December 31,						Increase
	2012			2011			(Decrease)
Production volumes
Oil (Bbls)		90,798			92,842			(2,044	)
Natural gas (Mcf)		84,879			131,757			(46,878	)
Natural gas liquids (Bbls)		2,878			3,861			(984	)
Equivalent (BOE)		107,823			118,663			(10,840	)
Avg. Daily Equivalent (BOE/d)		1,172			1,290			(118	)
Average sales prices
Oil (per Bbl)	$	83.39		$	86.94		$	(3.55	)
Natural gas (per Mcf)		3.83			4.51			(0.68	)
Natural gas liquids (per Bbl)		49.34			46.61			2.73
Operating revenues (in thousands)
Oil	$	7,572		$	8,072		$	(500	)
Natural gas		325			594			(269	)
Natural gas liquids		142			180			(38	)
Total operating revenue		8,039			8,846			(807	)
Lease operating expense		(1,969	)		(1,954	)		(15	)
Production taxes		(853	)		(921	)		68
Impairment		(4,666	)		-			(4,666	)
Income before depreciation, depletion and amortization		551			5,971			(5,420	)
Depreciation, depletion and amortization		(3,812	)		(4,230	)		418
Income	$	(3,261	)	$	1,741		$	(5,002	)

During the three months ended December 31, 2012, we produced approximately 107,823 barrels of oil equivalent (BOE), or an average of 1,172 BOE/d as compared to 118,663 BOE and 1,290 BOE/d during the three months ended December 31, 2011. Portions of our natural gas production are sent to gas processing plants to extract from the gas various natural gas liquids (“NGLs”) that are sold separately from the remaining natural gas. We sell some of our 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 NGLs and the remaining natural gas. In the table above, our share of processing costs is classified in lease operating expenses.

We recognized $8.0 million in revenues during the three months ended December 31, 2012 as compared to $8.8 million during the same period of the prior year. This $807,000 decrease in revenue is primarily due to lower oil sales volumes and lower average oil sales prices in 2012 when compared to 2011. Revenue from gas sales was also lower in the three months ended December 31, 2012 when compared to the same period in 2011, primarily due to production declines from wells in the Gulf Coast.

Our average net realized price (operating revenue per BOE) for the three months ended December 31, 2012 was $74.55 per BOE compared with $74.55 for the same period in 2011. Due to takeaway constraints, the discount, or differential, for oil prices in the Williston Basin has ranged from $7 to $25 per barrel during 2012. Until additional takeaway capacity is available, we expect this differential to continue (with the amount of the differential varying over time) and that our oil sales revenue will be affected by lower realized prices.

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Lease operating expense of $2.0 million for the three months ended December 31, 2012 was comprised of $1.7 million in lease operating expense and $300,000 in workover expense. The $15,000 increase in total lease operating expense in 2012 as compared to 2011 is primarily a result of more producing wells in the three months ended December 31, 2012 as compared to the same period of 2011.

Our depletion, depreciation and amortization (DD&A) rate for the three months ended December 31, 2012 was $35.35 per BOE compared to $35.65 per BOE for the same period in 2011. We have been impacted by higher DD&A rates related to our Williston Basin wells due to increases in drilling and completion costs for wells in this region. Our DD&A rate can also fluctuate as a result of impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.

In 2013, we anticipate completing wells that were drilled during the fourth quarter of 2012 as well as drilling and completing new wells. We also anticipate that our production rates will remain stable or may increase as a result of these activities. In particular, we expect that oil volumes will remain stable or may increase as we drill and complete oil wells in the Williston Basin and other areas. However, natural gas and natural gas liquids volumes are expected to continue to decrease as production declines from our Gulf Coast producing wells. Various factors, including extensive workover costs on existing wells, lower commodity prices, commodity price differentials, cost overruns on projected drilling projects, unsuccessful wells or other development activities and/or faster than expected declines in production from existing wells, would have a negative effect on production, cash flows and earnings from the oil and gas segment and could cause actual results to differ materially from those we expect.

Mt. Emmons and Water Treatment Plant Operations. We recorded $424,000 in costs and expenses for the water treatment plant and $205,000 for holding costs for the Mt. Emmons molybdenum property during the three months ended December 31, 2012. During the three months ended December 31, 2011, we recorded $454,000 in operating costs related to the water treatment plant and $140,000 in holding costs.

General and Administrative. General and administrative expenses decreased by $386,000 during the three months ended December 31, 2012 as compared to general and administrative expenses for the three months ended December 31, 2011. Lower general and administrative costs in 2012 are primarily a result of $235,000 lower stock compensation expenses, $108,000 lower wage and tax expenses, $108,000 lower depreciation expense and $58,000 lower professional services expense. These decreases in costs were partially offset by an increase in franchise taxes of $52,000, contract services of $41,000, insurance costs of $32,000 and other general and administrative costs of $2,000.

Property impairment. In September 2012, we made the decision to sell our corporate aircraft and its related facilities to cut overhead costs and plan to use the proceeds to further the development of our oil and gas business, reduction of debt or for general corporate purposes. As a result of the anticipated sale amount, at December 31, 2012, the Company recorded a non-cash impairment of $543,000 to adjust the carrying value to the expected sale value. There were no similar property impairments recorded during the three months ended December 31, 2011.

Other income and expenses. We recognized an unrealized and realized derivative loss of $5,000 in the fourth quarter of 2012 compared to a loss of $1.7 million for the same period in 2011. The 2012 amount includes a loss on unrealized changes in the fair value of our commodity derivative contracts of $163,000 and realized cash settlement gains on derivatives of $158,000.

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During the quarter ended December 31, 2011, we recognized a $143,000 gain on the sale of marketable securities from the sale of shares of Sutter Gold Mining. There were no similar sales during the fourth quarter of 2012.

We recorded equity losses of $191,000 and $19,000 from the investment in SST during the quarters ended December 31, 2012 and 2011, respectively. Equity losses from the investment in SST are expected to continue until such time as SST properties are sold, equity losses reduce our investment to zero or we sell the investment.

Interest income decreased to $1,000 during the quarter ended December 31, 2012 from $4,000 during the quarter ended December 31, 2011. The decrease is a result of lower amounts of cash invested in interest bearing instruments during the quarter, and lower interest rates received on those investments.

Interest expense decreased to $75,000 during the quarter ended December 31, 2012 from $119,000 during the quarter ended December 31, 2011.

Discontinued operations. We recorded a loss of $548,000, net of taxes from Remington Village during the quarter ended December 31, 2012 as compared to a loss of $3.1 million, net of taxes for the quarter ended December 31, 2011. On March 5, 2013, the Company entered into a Purchase and Sale Agreement to sell Remington Village for $15.0 million. As a result of the anticipated sales amount, the Company recorded a non-cash impairment of $630,000 net of taxes during the fourth quarter of 2012 to adjust the carrying value of the project to the expected sales value. During the fourth quarter of 2011, the Company recorded a non-cash impairment of $3.1 million.

We therefore recorded a net loss after taxes of $7.9 million, or $0.29 per share basic and diluted, during the quarter ended December 31, 2012 as compared to a net loss after taxes of $2.8 million, or $0.10 per share basic and diluted, during the quarter ended December 31, 2011.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011

During the year ended December 31, 2012, we recorded a loss of $11.2 million or $0.41 per share basic and diluted, as compared to a loss of $4.8 million, or $0.18 per share, during the year ended December 31, 2011. Significant components of the change in operating revenues and results of operations for the year ended December 31, 2012 as compared to the year ended December 31, 2011 are as follows:

Oil and Gas Operations. Excluding the $5.2 million non-cash impairment taken on our oil and gas properties during the period, oil and gas operations produced operating income of $6.9 million during the year ended December 31, 2012 as compared to operating income of $5.4 million during the year ended December 31, 2011. The increase in earnings from oil and gas operations is primarily due to (a) a $4.4 million increase in oil revenues during 2012 compared to 2011 and (b) $1.1 million lower lease operating expenses in the year ending December 31, 2012 as compared to the prior year. This increase was partially offset by $896,000 higher depletion expense in 2012 and a $2.8 million decrease in natural gas and natural gas liquids revenues. The following table summarizes production volumes, average sales prices and operating revenues for the years ended December 31, 2012 and 2011:

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	Year Ended
	December 31,						Increase
	2012			2011			(Decrease)
Production volumes
Oil (Bbls)		373,531			300,329			73,202
Natural gas (Mcf)		347,811			736,261			(388,450	)
Natural gas liquids (Bbls)		13,203			19,325			(6,122	)
Equivalent (BOE)		444,702			442,364			2,338
Avg. Daily Equivalent (BOE/d)		1,215			1,212			3
Average sales prices
Oil (per Bbl)	$	82.38		$	87.80		$	(5.42	)
Natural gas (per Mcf)		3.25			4.85			(1.59	)
Natural gas liquids (per Bbl)		47.79			52.88			(5.09	)
Operating revenues (in thousands)
Oil	$	30,772		$	26,368		$	4,404
Natural gas		1,131			3,568			(2,437	)
Natural gas liquids		631			1,022			(391	)
Total operating revenue		32,534			30,958			1,576
Lease operating expense		(7,301	)		(8,450	)		1,149
Production taxes		(3,487	)		(3,102	)		(385	)
Impairment		(5,189	)		-			(5,189	)
Income before depreciation, depletion and amortization		16,557			19,406			(2,849	)
Depreciation, depletion and amortization		(14,893	)		(13,997	)		(896	)
Income	$	1,664		$	5,409		$	(3,745	)

During the year ended December 31, 2012, we produced approximately 444,702 barrels of oil equivalent (BOE), or an average of 1,215 BOE/d as compared to 442,364 BOE and 1,212 BOE/d during the year ended December 31, 2011. Portions of our natural gas production are sent to gas processing plants to extract from the gas various natural gas liquids (“NGLs”) that are sold separately from the remaining natural gas. We sell some of our 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 NGLs and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses.

We recognized $32.5 million in revenues during the year ended December 31, 2012 as compared to $31.0 million during the prior year. This $1.5 million increase in revenue is primarily due to higher oil sales volumes in 2012 when compared to 2011. Revenue from gas sales was lower in the year ended December 31, 2012 when compared to 2011, primarily due to production declines from our wells in the Gulf Coast.

Our average net realized price (operating revenue per BOE) for the year ended December 31, 2012 was $73.16 per BOE compared with $69.98 for 2011. The increase in our equivalent realized price for production corresponds with a higher percentage of our production coming from oil in 2012 when compared with 2011. Due to takeaway constraints, the discount, or differential, for oil prices in the Williston Basin has ranged from $7 to $25 per barrel during 2012. Until additional takeaway capacity is available, we expect this differential to continue (with the amount of the differential varying over time) and that our oil sales revenue will be affected by lower realized prices.

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Lease operating expense of $7.3 million for the year ended December 31, 2012 was comprised of $5.5 million in lease operating expense and $1.8 million in workover expense. The $1.1 million reduction in total lease operating expense in 2012 as compared to 2011 is primarily a result of $2.0 million lower workover expense, partially offset by higher lease operating expenses as a result of an increase in the number of producing wells.

Through December 31, 2012, the Company recorded a proved property impairment of $5.2 million related to its oil and gas assets primarily due to a decline in natural gas prices, higher projected capitalized well costs and higher projected lease operating expenses. There were no proved property impairments recorded during the year ended December 31, 2011.

Our depletion, depreciation and amortization (DD&A) rate for the year ended December 31, 2012 was $33.49 per BOE compared to $31.64 per BOE for 2011. We have been impacted by higher DD&A rates related to our Williston Basin wells due to increases in drilling and completion costs for wells in this region. Our DD&A rate can also fluctuate as a result of impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.

Mt. Emmons and Water Treatment Plant Operations. We recorded $2.0 million in costs and expenses for the water treatment plant and $921,000 for holding costs for the Mt. Emmons molybdenum property during the year ended December 31, 2012. During the year ended December 31, 2011, we recorded $1.9 million in operating costs related to the water treatment plant and $486,000 in holding costs. Holding costs during 2011 were partially funded by another party under an operating agreement. As a result of the termination of this agreement in 2011, our 2012 costs are higher as we now bear all the costs associated with the project.

General and Administrative. General and administrative expenses decreased by $1.5 million to $6.8 million during the year ended December 31, 2012 as compared to general and administrative expenses of $8.3 million for the year ended December 31, 2011. Lower general and administrative costs in 2012 are primarily a result of $1.4 million lower stock compensation expenses, $196,000 lower wage and tax expenses, $133,000 lower depreciation expense and $70,000 lower bank charges expense. These decreases in costs were partially offset by an increase in contract services of $305,000.

Other income and expenses. We recognized an unrealized and realized derivative gain of $1.1 million in the year ended December 31, 2012 compared to a loss of $848,000 in 2011. The 2012 amount includes a gain on unrealized changes in the fair value of our commodity derivative contracts of $1.1 million and a realized cash settlement gain on derivatives of $21,000.

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We recorded equity losses of $359,000 and $211,000 from our investment in SST during the years ended December 31, 2012 and 2011, respectively. Equity losses from the investment in SST are expected to continue until such time as SST properties are sold, equity losses reduce our investment to zero or we sell the investment.

Gain on the sale of marketable securities from the sale of shares of Sutter Gold Mining decreased to $82,000 during the year ended December 31, 2012 from $529,000 during the year ended December 31, 2011.

Interest income decreased to $9,000 during the year ended December 31, 2012 from $40,000 during the year ended December 31, 2011. The decrease is a result of lower amounts of cash invested in interest bearing instruments during the quarter, and lower interest rates received on those investments.

Interest expense decreased to $203,000 during the year ended December 31, 2012 from $326,000 during the year ended December 31, 2011. The decrease in interest expense was related primarily to lower average debt balances during 2012 when compared to 2011.

Discontinued operations. We recorded a loss of $1.8 million, net of taxes from the discontinued operations of Remington Village during the year ended December 31, 2012 and a loss of $2.6 million, net of taxes, for the year ended December 31, 2011. The increase in income is primarily a result of a $1.9 million impairment, net of taxes recorded at December 31, 2012 as compared to an impairment of $3.1 million, recorded at December 31, 2011.

We therefore recorded a net loss after taxes of $11.2 million, or $0.41 per share basic and diluted, during the year ended December 31, 2012 as compared to a net loss after taxes of $4.8 million, or $0.18 per share basic and diluted, during the year ended December 31, 2011.

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010

During the year ended December 31, 2011, we recorded a loss of $4.8 million or $0.18 per share basic and diluted, as compared to a loss of $772,000, or $0.03 per share, during the year ended December 31, 2010. The decrease in net earnings for 2011 as compared to 2010 is primarily due to (a) $5.5 million higher lease operating expenses in 2011 which included approximately $3.1 million in proportionate workover costs on one well, (b) $3.4 million higher oil and gas depletion expense, (c) a $3.1 million impairment in 2011 on the discontinued operations of our Remington Village project as compared to at $1.5 million impairment in 2010, (d) a 2010 equity gain of $1.0 million related to our investment in SST as compared to an equity loss of $211,000 in 2011, (e) $85,000 higher costs related to the operation of the Mt. Emmons water treatment plant and (f) $401,000 higher mineral holding costs for Mt. Emmons. These decreases in net earnings after taxes were offset by (a) $4.4 million higher revenues from oil and gas sales during 2011, (b) a deferred tax benefit of $3.8 million during the year ended December 31, 2011 as compared to a deferred tax benefit of $1.9 million during the year ended December 31, 2010, (c) $848,000 in realized and unrealized loss on risk management activities in 2011 as compared to a realized and unrealized loss of $1.9 million in 2010, (d) $712,000 lower general and administrative expenses and (e) $91,000 higher income from the sale of marketable securities.

We recognized $30.1 million in revenues during the year ended December 31, 2011 as compared to revenues of $24.7 million during the prior year. Components of the change in operating revenues and results of operations for the year ended December 31, 2011 as compared to the year ended December 31, 2010 are as follows:

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Oil and Gas Operations. Oil and gas operations produced net operating income of $4.6 million during the year ended December 31, 2011 as compared to net operating income of $8.0 million from oil and gas operations during the year ended December 31, 2010. The decrease in earnings from oil and gas operations is primarily due to $5.5 million higher lease operating expenses in 2011 which included approximately $3.1 million in proportionate workover costs on one well and $3.4 million higher oil and gas depreciation, depletion and amortization expense. This is partially offset by an increase in oil and gas revenues of $4.4 million and $848,000 in realized and unrealized loss on risk management activities in 2011 as compared to a realized and unrealized loss of $1.9 million in 2010. The following table details the results of operations from the oil and gas sector for the years ended December 31, 2011 and 2010:

	(In thousands)
	For the years ending
	December 31, 2011			December 31, 2010
Oil and gas revenues	$	30,958		$	26,548
Realized (loss) from risk management activities		(1,974	)		(156	)
Unrealized gain (loss) from risk management activities		1,126			(1,725	)
		30,110			24,667
Operating expenses		11,552			6,073
Depreciation, depletion and amortization		13,997			10,610
		25,549			16,683
Operating income	$	4,561		$	7,984

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The following table summarizes production volumes, average sales prices and operating revenues for the years ended December 31, 2011 and 2010:

	Year Ended
	December 31,						Increase
	2011			2010			(Decrease)
Production volumes
Oil (Bbls)		300,329			303,433			(3,104	)
Natural gas (Mcf)		736,261			757,905			(21,644	)
Natural gas liquids (Bbls)		19,325			19,104			221
Average sales prices
Oil (per Bbl)	$	87.80		$	72.11		$	15.69
Natural gas (per Mcf)		4.85			4.96			(0.11	)
Natural gas liquids (per Bbl)		52.88			47.53			5.35
Operating revenues (in thousands)
Oil	$	26,368		$	21,881		$	4,487
Natural gas		3,568			3,759			(191	)
Natural gas liquids		1,022			908			114
Total operating revenue		30,958			26,548			4,410
Lease operating expense		(8,450	)		(3,056	)		(5,394	)
Production taxes		(3,102	)		(3,017	)		(85	)
Risk management activities		(848	)		(1,881	)		1,033
Impairment		-			-			-
Income before depreciation, depletion and amortization		18,558			18,594			(36	)
Depreciation, depletion and amortization		(13,997	)		(10,610	)		(3,387	)
Income	$	4,561		$	7,984		$	(3,423	)

During the year ended December 31, 2011, we produced approximately 442,360 BOE, or an average of 1,212 BOE/d as compared to 448,855 BOE and 1,230 BOE/d during the year ended December 31, 2010. Portions of our natural gas production are sent to gas processing plants to profitably extract from the gas various NGLs that are sold separately from the remaining natural gas. We sell some of our processed gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGL and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses.

Our average net realized price for the year ended December 31, 2011, was $69.98 per BOE compared with $59.15 per BOE for 2010. The increase in our equivalent realized price for production corresponds with stronger oil prices in 2011 when compared with 2010.

Lease operating expense of $8.4 million for the year ended December 31, 2011 was comprised of $4.7 million in lease operating expense and $3.7 million in workover expense. Of the $3.7 million in workover expense, $3.1 million was related to one well. While there can be no assurance that we will not experience these types of workover costs in the future, we do not expect these high workover costs to occur regularly.

Our depletion, depreciation, and amortization (DD&A) rate for the year ended December 31, 2011 increased 34% percent to $31.64 per BOE compared to $23.64 per BOE for 2010. We have been impacted by higher DD&A rates related to our Williston Basin wells due to increases in drilling and

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completion costs for wells in this region. Our DD&A rate can also fluctuate as a result of impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.

Mt. Emmons and Water Treatment Plant Operations. We recorded $1.9 million in costs and expenses for the water treatment plant and $486,000 for holding costs of the Mt. Emmons property during the year ended December 31, 2011. During the year ended December 30, 2010, we recorded $1.8 million in operating costs related to the water treatment plant and $85,000 in holding costs. The increase in holding costs is directly as a result of Thompson Creek electing to terminate its agreement with us. As a result, we paid the majority of the holding costs related to Mt. Emmons in 2011 while Thompson Creek paid the majority of these costs in 2010.

General and Administrative. General and administrative expenses decreased by $712,000 during the year ended December 31, 2011 as compared to general and administrative expenses for the year ended December 31, 2010. Lower general and administrative costs in 2011 are primarily a result of $916,000 lower accrued bonus compensation and were partially offset by $217,000 in higher bank fees related to our note on Remington Village and the Credit Facility.

Other income and expenses. During the year ended December 31, 2011, we had an equity loss of $211,000 related to our investment in SST. During the year ended December 31, 2010, as a result of the sale of two of SST’s geothermal properties, we recorded an equity gain of $1.0 million from our investment in SST. 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 $529,000 during the year ended December 31, 2011 related to the sale of shares of Sutter Gold Mining, Inc. During the year ended December 31, 2010, we recorded a gain on sale of marketable securities of $438,000 related to the sale of shares of Sutter Gold Mining, Inc. and Kobex Resources, Inc.

We recorded a gain on sale of assets of $137,000 during the year ended December 31, 2011 primarily related to the sale of equipment. During the year ended December 31, 2010, we recorded a gain on sale of assets of $115,000. The gain was primarily related to the sale of an office building that we previously held as rental property.

Interest income decreased from $112,000 during the year ended December 31, 2010 to $40,000 during the year ended December 31, 2011. 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 $326,000 during the year ended December 31, 2011 was related primarily to the borrowings under the Credit Facility of $266,000 and $36,000 for the financing of a property purchased near the Mt. Emmons Project.

Discontinued operations. We recorded a loss of $2.6 million, net of taxes from the discontinued operations of Remington Village during the year ended December 31, 2011 and a loss of $1.3 million, net of taxes for the year ended December 31, 2010. The decrease in income is primarily a result of a $3.1 million impairment recorded at December 31, 2011 as compared to an impairment of $1.5 million recorded at December 31, 2010, $323,000 higher interest expense in 2011 as compared to 2010 and $370,000 lower net tax affected operating income in the year ended December 31, 2011 as compared to 2010. This is partially offset by $946,000 in scheduled depreciation costs that were not recorded during 2011 as a result of Remington Village being classified as an asset held for sale.

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We therefore recorded a net loss after taxes of $4.8 million, or $0.18 per share basic and diluted, during the year ended December 31, 2011 as compared to a net loss after taxes of $772,000, or $0.03 per share basic and diluted, during the year ended December 31, 2010.

Overview of Liquidity and Capital Resources

At December 31, 2012, we had $2.8 million in cash and cash equivalents. Our working capital (current assets minus current liabilities) was $12.8 million. The following table sets forth key liquidity measures for the year ended December 31, 2012 as compared to the year ended December 31, 2011:

	(In thousands)
	December 31,			December 31,
	2012			2011
Current ratio(1)	1.96 to 1			1.99 to 1
Working capital(2)	$	12,762		$	20,667
Total debt	$	10,200		$	12,400
Total cash and marketable securities less debt	$	(7,192	)	$	640
Total stockholders' equity	$	116,117		$	126,781
Total debt to equity	0.09 to 1			0.10 to 1

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

As discussed below in Capital Resources and Capital Requirements, we project that our capital resources at December 31, 2012, together with cash flow from operations, will be sufficient to fund operations and capital projects through 2013. Given the size of our potential commitments related to our existing inventory of drilling projects, however, our requirements for additional capital could increase significantly during 2013 if we elect to participate in any currently unanticipated drilling of additional wells. As a result, we may consider drawing down additional debt on the Credit Facility, selling or joint venturing an interest in some of our oil and gas assets, or accessing the capital markets or other alternatives, as we determine how to best fund our capital program.

The principal recurring uncertainty which affects the Company is variable prices for commodities producible from our oil, gas and mineral properties. Significant price swings can have adverse or positive effects on our business of exploring for, developing and producing oil and gas or minerals. Availability of drilling and completion equipment and crews fluctuates with the market prices for oil and natural gas and thereby affects the cost of drilling and completing wells. When prices are low there is typically less exploration activity and the cost of drilling and completing wells is generally reduced. Conversely, when prices are high there is generally more exploration activity and the cost of drilling and completing wells generally increases.

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Capital Resources

Potential primary sources of future liquidity include the following:

Oil and Gas Production. At December 31, 2012, we had 83 gross producing wells (15.05 net). During the year ended December 31, 2012, we received an average of $2.7 million per month from these producing wells with an average operating cost of $462,000 per month (excluding workover costs) and production taxes of $291,000, for average cash flows of $2.0 million per month from oil and gas production before non-cash depletion expense. We anticipate that cash flows from oil and gas operations will remain stable and may increase through the balance of 2013 as additional wells being drilled with Zavanna, Brigham, and others begin to produce. However, decreases in the price of oil and natural gas (or changes in applicable differentials), increased operating costs and workover expenses, declines in production rates, and other factors could decrease these average monthly cash flow amounts.

Normal production declines and the back-in after payout provisions granted to Brigham and Zavanna will eventually decrease the amount of cash flow we receive from these wells. We anticipate drilling more Bakken and Three Forks wells with Brigham and Zavanna in the future and will continue to search for additional drilling opportunities to replace these oil reserves and cash flows.

Cash on Hand. At December 31, 2012, we had $2.8 million in cash and cash equivalents.

Wells Fargo Senior Credit Facility. On July 30, 2010, we established a senior credit facility through Energy One to borrow up to $75 million (since increased to $100 million as described below) from a syndicate of banks, financial institutions and other entities. The syndicate initially included BNP Paribas, which has since sold its North American reserve-based and related diversified energy lending business to Wells Fargo Bank, National Association. The Credit Facility is being used to advance our short and mid-terms goals of increasing our investment in oil and gas.

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. The borrowing base is 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. On April 10, 2012, the maximum commitment amount increased to $100 million and the borrowing base increased to $30.0 million (from $28.0 million) as a result of a redetermination using our December 31, 2011 financial statements, production reports and reserve reports. As of December 31, 2012, Energy One was in compliance with all the covenants under the Credit Facility.

In 2012, we borrowed $10.0 million under the Credit Facility to fund our drilling programs.

Asset Held for Sale – Remington Village. Until Remington Village is sold, we will continue to receive rental receipts from the property. The property had an average occupancy rate of 89% during 2012 and was 88% occupied as of December 31, 2012. Occupancy is dependent on the regional economy, including local coal mining operations, which has been affected by the global recession. The property generated average positive cash flow from operations of $90,000 per month during 2012 and cash flow is projected to remain in that range during 2013.

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On May 5, 2011, we borrowed $10.0 million from a commercial bank against Remington Village. The note is amortized over 20 years with a balloon payment at the end of five years and has an interest rate of 5.50% per annum. The proceeds of the note were used to fund our general business obligations.

Capital Requirements

Our direct capital requirements during 2013 relate to 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, payment of debt obligations, operating and capital improvement costs of the water treatment plant at the Mt. Emmons Project and ongoing permitting activities for the Mt. Emmons Project, operations at Remington Village until it is sold and general and administrative costs. We intend to finance our 2013 capital expenditure plan primarily from the sources described above under “Capital Resources”. We may be required to reduce or defer part of our 2013 capital expenditures plan if we are unable to obtain sufficient financing from these sources. We regularly review our capital expenditure budget to assess changes in current and projected cash flows, acquisition opportunities, debt requirements and other factors.

Oil and Gas Exploration and Development. Expenditures for exploration, development and acquisitions of oil and gas properties are the primary use of our capital resources. Of our $27.1 capital expenditure budget for 2013, $7.1 million has been allocated to drilling programs in the Williston Basin and $20.0 million has been allocated for the acquisition of producing properties with associated proven reserves. Amounts budgeted for drilling programs are contingent upon timing, well costs and success. If any of our drilling initiatives are not initially successful or progress more slowly than anticipated, funds allocated for that program may be allocated to other initiatives and/or acquisitions in due course. The actual number of gross and net wells could vary in each of these cases.

Mt. Emmons Project. We are responsible for all costs associated with the Mt. Emmons Project, which includes operation of a water treatment plant. Operating costs for the water treatment plant during 2013 are expected to be approximately $150,000 per month. Additionally, we have budgeted $1.5 million for permitting costs, holding costs and water treatment plant capital improvements that are expected to improve the plant’s efficiency and reduce costs.

In 2009, 160 acres of fee land in the vicinity of the mining claims was purchased by the Company and TCM for $4.0 million ($2.0 million in January 2009 and $400,000 annually for five years thereafter). On December 6, 2011, TCM notified the Company that it wishes to sell its interest in the property. The Company has 18 months from that date (until June 6, 2013) to decide whether to purchase TCM’s interest in the property, at TCM’s cost, and close such purchase. The Company has budgeted $2.0 million for this purchase.

Real Estate. Cash operating expenses at Remington Village are projected to be approximately $89,000 per month until Remington Village is sold.

Insurance. We have liability insurance coverage in amounts we deem 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 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.

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Reclamation Costs. We have reclamation obligations with an estimated present value of $524,000 related to our oil and gas wells and $162,000 related to the Mt. Emmons Property. No reclamation is expected to be performed during the year ended December 31, 2013 unless a well, or wells, are abandoned due to unexpected operational challenges. As the Mt. Emmons project is developed, the reclamation liability is expected to increase. It is not anticipated that his 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.

Overview of Cash Flow Activities

The following table presents changes in cash flows between the years ended December 31, 2012 and 2011. The analysis following the table should be read in conjunction with our consolidated statements of cash flows in Part II, Item 8 of this report.

	(In thousands)
	For the years ended December 31,
	2012			2011			Change
Net cash provided by operating activities	$	13,139		$	2,567		$	10,572
Net cash (used in) investing activities		(20,877	)		(17,775	)		(3,102	)
Net cash (used in) provided by financing activities		(2,433	)		21,558			(23,991	)

Operating Activities. Cash provided by operations for the year ended December 31, 2012 increased to $13.1 million as compared to cash provided by operations of $2.6 million for the prior year. This $10.5 million year over year increase in cash from operating activities is predominantly a result of a $1.6 million improvement in oil, gas and NGL production revenues and $1.1 million lower lease operating expenses. The remainder of the change in cash provided by operations is part of the complete discussion of cash provided by operations in “Results of Operations” above.

Investing Activities. Investing activities provided cash during 2012 through $21.5 million in proceeds from the sale of oil and gas properties, $101,000 from the sale of shares of Sutter Gold Mining and $76,000 from the sale of property and equipment.

Investing activities consumed cash through the acquisition and development of oil and gas properties in the amount of $42.3 million during 2012. Other uses of cash for investing activities in the period were an $116,000 change in restricted investments and $102,000 for the purchase of equipment.

The $3.1 million increase in cash used in investing activities during the year ended December 31, 2012 as compared to the prior year is primarily a result of: (a) $21.5 million in sales of oil and gas properties during 2012 with $13.6 million in oil and gas property sales during 2011, (b) $17.8 million in redemption of treasury investments in 2011 and no redemption of treasury investments in 2012, (c) $8.0 million less investment in oil and gas properties in 2012 as compared to 2011 and (d) $101,000 in proceeds from the sale of marketable securities in 2012 as compared to $846,000 in proceeds from the sale of marketable securities in 2011.

Financing Activities. Financing activities consumed $2.4 million during the year ended December 31, 2012. Components of the cash flow from financing activities during the year ended December 31, 2012 include $12.5 million in repayments of debt, new borrowings of $10.0 million under the Credit Facility and $51,000 of proceeds through the issuance of common stock. During the year ended

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December 31, 2011 financing activities provided $21.6 million. Components of cash flow from financing activities during the year ended December 31, 2011 include the provision of $33.1 million from new debt, and outflows of $11.4 million for debt payments and $146,000 net from the exercise of employee options and non-employee director options.

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, 2012 and December 31, 2011 which were not included in the amortized cost pool were $9.2 million and $20.0 million, respectively. These costs consist of wells in progress, seismic costs that are being analyzed for potential drilling locations as well as land costs and are related to unproved properties. No capitalized costs related to unproved properties are included in the amortization base at December 31, 2012 and December 31, 2011. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are proved, drilled or abandoned.

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

Ceiling Test. We perform a quarterly ceiling test for each of our oil and gas cost centers, of which in 2012 and 2011 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, 2012, the Company used $94.71 per barrel for oil and $2.757 per MMbtu for natural gas to compute the future cash flows of the Company’s producing property. The discount factor used was 10%.

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At December 31, 2012, our net capitalized costs exceeded the ceiling test limit and as a result, we recorded proved property impairments totaling $5.2 million, related to our oil and gas assets, primarily due to a decline in natural gas prices, higher projected capitalized well costs and higher projected lease operating expenses. 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 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.

Derivative Instruments. We use derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk underlying our 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 our derivative instruments as cash flow hedges, 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 they 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. The master contracts with approved counterparties identify the CEO and President as Company representatives authorized to execute trades. See Note D, 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 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.

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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, 2012 and December 31, 2011 reflect capitalized costs associated with 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. We have determined that no impairment is needed to the book value of the property at December 31, 2012.

Assets Held for Sale. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to determine if there is any excess of carrying value over fair value less costs to sell. Subsequent changes to estimated fair value less the cost to sell will impact the measurement of assets held for sale if the fair value is determined to be less than the carrying value of the assets.

Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include oil and gas reserves used for depletion and impairment considerations and the cost of future asset retirement obligations. Due to inherent uncertainties, including the future prices of oil and 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 our interest in the properties. Gas balancing obligations as of December 31, 2012 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

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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 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 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 $145.31 per barrel during July 2008 and a ten year low of $18.02 per barrel during April 2003. As of December 31, 2012 the Cushing, OK WTI spot price for oil was $91.83 per barrel.

The ten year Henry Hub Gulf Coast Natural Gas Spot Price reached a high of $18.48 per MMbtu in February 2003 and the ten year low was $1.82 per MMbtu in April 2012. The price per MMbtu at December 31, 2012 was $3.43.

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 2013 investments in oil and gas properties will be profitable.

Molybdenum. The ten year high for dealer molybdenum oxide was $38.00 per pound in June 2005 and the ten year low was $8.03 per pound in April 2009. The mean price of molybdenum oxide at December 31, 2012 and December 31, 2011 was $11.79 per pound and $13.61 per pound, respectively. The price of molybdenum will have a direct impact on the development of Mt. Emmons Project.

Contractual Obligations

We had three principal categories of contractual obligations at December 31, 2012: Debt to third parties of $19.8 million, executive retirement obligations of $896,000 and asset retirement obligations of

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$686,000. The debt consists of debt to a commercial bank secured by Remington Village, debt related to our oil and gas reserves and debt for the purchase of land near the Mt. Emmons Project. The debt to the commercial bank bears an interest rate of 5.5% per annum. The oil and gas debt bears a weighted average interest rate of 2.92% per annum and the land debt bears an interest rate of 6.0% per annum. The debt to the commercial bank is amortized over 20 years with a balloon payment due at the end of five years on May 5, 2016. The balloon payment at maturity is $8.8 million. The oil and gas debt at December 31, 2012 of $10.0 million was drawn in three separate tranches, each with a term of six months. Principal and accrued interest is due at the end of each respective tranche’s six month term. However this debt can be continued, at our election, if we remain in compliance with the covenants under the Credit Facility through July 30, 2014). The $200,000 land debt, plus accrued interest is due on January 2, 2014. 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 are expected to be retired during the next 34 years.

The following table shows the scheduled debt payment, projected executive retirement benefits and asset retirement obligations as of December 31, 2012. This table reflects the debt obligation on Remington Village pursuant to the terms of the note. However, because the related property is reflected as a current asset held for sale, the note is also classified in the financial statements as a current liability held for sale.

	(In thousands)
	Payments due by period
			Less		One to		Three to		More than
			than one		Three		Five		Five
	Total		Year		Years		Years		Years
Debt obligations	$	19,821	$	508	$	19,313	$	--	$	--

Executive retirement		896		125		371		28		372

Asset retirement obligation		686		46		23		14		603

Totals	$	21,403	$	679	$	19,707	$	42	$	975

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 market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which could impact our prospective revenues. A 10% fluctuation in the price received for oil and natural gas production would have had an approximate $3.3 million impact on our 2012 annual revenues.

To mitigate some of our commodity risk, we use derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk. We 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 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

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movements. However, such use may limit our ability to benefit from favorable price movements. We 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 existing positions.

Through Energy One, we have entered into commodity derivative contracts (“economic hedges”) with Wells Fargo and BNP Paribas, as described below. The derivative contracts are priced using West Texas Intermediate (“WTI”) quoted prices. The Company is a guarantor of Energy One’s obligations under the economic hedges.

Energy One's commodity derivative contracts as of December 31, 2012 are summarized below:

			Quantity
Settlement Period	Counterparty	Basis	(Bbl/d)		Strike Price

Crude Oil Costless Collar
10/01/12 - 03/31/13	Wells Fargo	WTI		200	Put:	$	85.00
					Call:	$	101.00
Crude Oil Costless Collar
01/01/13 - 06/30/13	Wells Fargo	WTI		200	Put:	$	90.00
					Call:	$	105.75
Crude Oil Costless Collar
10/01/12 - 09/30/13	BNP Paribas	WTI		200	Put:	$	95.00
					Call:	$	116.60
Crude Oil Costless Collar
04/01/13 - 06/30/13	Wells Fargo	WTI		200	Put:	$	90.00
					Call:	$	97.50
Crude Oil Costless Collar
07/01/13 - 09/30/13	Wells Fargo	WTI		400	Put:	$	90.00
					Call:	$	97.50
Crude Oil Costless Collar
10/01/13 - 12/31/13	Wells Fargo	WTI		600	Put:	$	90.00
					Call:	$	97.50

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 they are classified as gain (loss) on derivative instruments, net in our consolidated statements of operations. The net gain realized by us related to these instruments was $21,000 for the year ended December 31, 2012. We recognized realized net losses of $2.0 million and $156,000 for the years ended December 31, 2011 and 2010, respectively.

Interest Rate Risk. At December 31, 2012, we had long-term debt of $10.2 million, of which $200,000 was at a fixed rate of 6.0% and $10.0 million was at a variable rate pursuant to our Credit Facility. The interest rate that we pay on amounts borrowed under the Credit Facility is derived from the Eurodollar rate and a margin that is applied to the Eurodollar rate. The margin that we pay is based upon the percentage of our available borrowing base that we utilize at the beginning of the quarter. At December 31, 2012, the borrowing base for the Credit Facility was $30.0 million. At December 31, 2012 we had utilized $10.0 million, or 33%, of the borrowing base. At this level of utilization, the Credit

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Facility requires us to pay a margin of 2.50%. Our all-in interest rate under the facility at December 31, 2012 was 3.01%. A 10% increase in the Eurodollar rate would equal approximately five basis points. Such an increase in the Eurodollar rate would change our annual interest expense by approximately $15,000, assuming amounts borrowed under our Credit Facility equaled our total potential borrowing base of $30.0 million as of December 31, 2012.

Item 8 – Financial Statements

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

	Page
Report of Independent Registered Public Accounting Firm	81
Financial Statements
Consolidated Balance Sheets as of December 31, 2012 and 2011	82
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010	84
Consolidated Statements of Comprehensive Loss	86
Statement of Stockholders’ Equity	87
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010	90
Notes to Consolidated Financial Statements	92

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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, 2012 and 2011, and the related consolidated statements of operations, comprehensive loss, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, 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 15, 2013 expressed an unqualified opinion on the effectiveness of U.S. Energy Corp.’s internal control over financial reporting.

HEIN & ASSOCIATES LLP

Denver, Colorado

March 15, 2013

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

	December 31,		December 31,
	2012		2011
Current assets:
Cash and cash equivalents	$	2,825	$	12,874
Marketable securities
Available for sale securities		183		166
Accounts receivable
Trade		5,182		5,496
Income taxes		--		113
Commodity risk management asset		472		3
Assets held for sale		17,051		22,600
Other current assets		302		352
Total current assets		26,015		41,604

Investment		2,264		2,623

Properties and equipment
Oil & gas properties under full cost method,
net of $43,454 and $28,561 accumulated
depletion, depreciation and amortization		85,634		90,942
Undeveloped mining claims		20,739		20,739
Property, plant and equipment, net		4,435		4,728
Net properties and equipment		110,808		116,409

Other assets		1,740		1,803
Total assets	$	140,827	$	162,439

The accompanying notes are an integral part of these statements.

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

	December 31,			December 31,
	2012			2011
Current liabilities:
Accounts payable	$	2,692		$	9,370
Accrued compensation		295			501
Commodity risk management liability		--			601
Current portion of debt		200			200
Liabilities held for sale		10,022			10,241
Other current liabilities		44			24
Total current liabilities		13,253			20,937

Long-term debt, net of current portion		10,000			12,200

Deferred tax liability		--			1,189

Asset retirement obligations		686			510

Other accrued liabilities		771			822

Commitment and contingencies (Note N)

Shareholders' equity
Common stock, $.01 par value; unlimited shares
authorized; 27,652,602 and 27,409,908
shares issued, respectively		277			274
Additional paid-in capital		123,078			122,523
Accumulated (deficit) surplus		(7,339	)		3,906
Unrealized gain on marketable securities		101			78
Total shareholders' equity		116,117			126,781
Total liabilities and shareholders' equity	$	140,827		$	162,439

The accompanying notes are an integral part of these statements.

-83-

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

	For the year ended December 31,
	2012			2011			2010
Oil, gas, and NGL production revenues:	$	32,534		$	30,958		$	26,548

Operating expenses:
Oil and gas		10,788			11,552			6,073
Oil and gas depreciation, depletion and amortization		14,893			13,997			10,610
Impairment of oil and gas properties		5,189			--			--
Water treatment plant		1,978			1,878			1,793
Mineral holding costs		921			486			85
General and administrative		6,810			8,261			8,973
Impairment of corporate aircraft		2,299			--			--
		42,878			36,174			27,534
Loss from operations		(10,344	)		(5,216	)		(986	)
Other income and expenses:
Realized gain (loss) on risk management activities		21			(1,974	)		(156	)
Unrealized gain (loss) on risk management activities		1,070			1,126			(1,725	)
(Loss) gain on the sale of assets		(12	)		137			115
Equity loss in unconsolidated investment		(359	)		(211	)		1,014
Gain on sale of marketable securities		82			529			438
Miscellaneous income and (expenses)		241			(38	)		(60	)
Interest income		9			40			112
Interest expense		(203	)		(326	)		(70	)
		849			(717	)		(332	)
Loss before income taxes and discontinued operations		(9,495	)		(5,933	)		(1,318	)

The accompanying notes are an integral part of these statements.

-84-

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

	For the year ended December 31,
	2012			2011			2010
Income taxes:
Current (provision for) benefit from		(104	)		--			104
Deferred (provision for) benefit from		148			3,755			1,756
		44			3,755			1,860

(Loss) income from continuing operations		(9,451	)		(2,178	)		542

Discontinued operations:
Discontinued operations, net of taxes		97			434			226
Impairment on discontinued operations, net of taxes		(1,891	)		(3,063	)		(1,540	)
		(1,794	)		(2,629	)		(1,314	)
Net (loss)	$	(11,245	)	$	(4,807	)	$	(772	)

Net (loss) income per share basic and diluted
Loss from continuing operations	$	(0.34	)	$	(0.08	)	$	0.02
Income (loss) from discontinued operations		(0.07	)		(0.10	)		(0.05	)
Net (loss) income per share	$	(0.41	)	$	(0.18	)	$	(0.03	)

Weighted average shares outstanding
Basic and Diluted		27,466,549			27,238,869			26,763,995

Diluted		27,466,549			27,238,869			26,763,995

The accompanying notes are an integral part of these statements.

-85-

U.S. ENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)

	For the years ended December 31,
	2012			2011			2010
Net (loss)	$	(11,245	)	$	(4,807	)	$	(772	)
Other comprehensive income (loss):
Marketable securities, net of tax		23			(564	)		256

Total comprehensive (loss) income	$	(11,222	)	$	(5,371	)	$	(516	)

The accompanying notes are an integral part of these statements.

-86-

U.S. ENERGY CORP
STATEMENT OF SHAREHOLDERS' EQUITY
(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 January 1, 2010		26,418,713		264		118,998			9,485			386			129,133

Net loss		--		--		--			(772	)		--			(772	)
Unrecognized gain on
marketable securities		--		--		--			--			400			400
Unrealized tax effect on
on the unrealized gain		--		--		--			--			(144	)		(144	)
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		275,728		3		(455	)		--			--			(452	)
Issuance of common stock
from stock warrants		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.

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U.S. ENERGY CORP
STATEMENT OF SHAREHOLDERS' EQUITY
(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, 2010		27,068,610		271		121,062			8,713			642			130,688

Net loss		--		--		--			(4,807	)		--			(4,807	)
Recognized gain on
marketable securities		--		--		--			--			(850	)		(850	)
Unrecognized gain on
marketable securities		--		--		--			--			(30	)		(30	)
Unrealized tax effect on
on the unrealized gain		--		--		--			--			316			316
Funding of ESOP		98,958		1		287			--			--			288
Issuance of common stock
2001 stock compensation plan		75,000		1		369			--			--			370
Issuance of common stock
from stock options		124,444		1		(209	)		--			--			(208	)
Issuance of common stock
from stock warrants		42,896		--		61			--			--			61
Vesting of stock options		--		--		947			--			--			947
Vesting of stock warrants		--		--		6			--			--			6
Balance December 31, 2011		27,409,908	$	274	$	122,523		$	3,906		$	78		$	126,781

The accompanying notes are an integral part of these statements.

-88-

U.S. ENERGY CORP
STATEMENT OF SHAREHOLDERS' EQUITY
(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, 2011		27,409,908		274		122,523		3,906			78			126,781

Net loss		--		--		--		(11,245	)		--			(11,245	)
Recognized gain on
marketable securities		--		--		--		--			(54	)		(54	)
Unrecognized gain on
marketable securities		--		--		--		--			90			90
Unrealized tax effect on
on the unrealized gain		--		--		--		--			(13	)		(13	)
Funding of ESOP		161,624		2		241		--			--			243
Issuance of common stock
2001 stock compensation plan		60,000		1		162		--			--			163
Issuance of common stock
from stock options		1,070		--		--		--			--			--
Issuance of common stock
from stock warrants		20,000		--		50		--			--			50
Vesting of stock options		--		--		33		--			--			33
Vesting of stock warrants		--		--		69		--			--			69
Balance December 31, 2012		27,652,602	$	277	$	123,078	$	(7,339	)	$	101		$	116,117

The accompanying notes are an integral part of these statements.

-89-

U.S. ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
	(In thousands)
	For the years ended December 31,
	2012			2011			2010
Cash flows from operating activities:
Net (loss)	$	(11,245	)	$	(4,807	)	$	(772	)
Loss from discontinued operations includes
non-cash impairment of $2,955, $3,063, and $1,540		1,794			2,629			1,314
(Loss) income from continuing operations		(9,451	)		(2,178	)		542
Adjustments to reconcile net (loss) income to
net cash provided by operations
Depreciation, depletion & amortization		15,457			14,593			11,184
Change in fair value of commodity price
risk management activities, net		(1,070	)		(1,126	)		1,725
Accretion of discount on treasury investment		--			--			(78	)
Impairment of oil and gas properties		5,189			--			--
Impairment of corporate aircraft		2,299			--			--
Gain on sale of marketable securities		(82	)		(529	)		(438	)
Equity (gain)/loss from Standard Steam		359			211			(1,014	)
Net change in deferred income taxes		(60	)		(3,990	)		(1,533	)
Loss (gain) on sale of assets		12			(137	)		(115	)
Noncash compensation		518			1,604			1,710
Noncash services		69			6			66
Net changes in assets and liabilities
Accounts receivable		315			(1,493	)		(174	)
Income tax receivable		113			(9	)		249
Other current assets		230			148			(386	)
Accounts payable		(476	)		(3,368	)		(498	)
Accrued compensation expense		(336	)		(1,194	)		6
Other liabilities		53			29			149
Net cash provided by operating activities		13,139			2,567			11,395
Cash flows from investing activities:
Net redemption of treasury investments		--			17,843			4,293
Cash distributions from Standard Steam		--			--			1,138
Acquisition & development of oil & gas properties		(42,311	)		(50,265	)		(45,933	)
Acquisition & development of mining properties		--			(221	)		(123	)
Mining property option payment		--			354			1,000
Acquisition of property and equipment		(102	)		(42	)		(624	)
Proceeds from sale of oil and gas properties		21,475			13,574			--
Proceeds from sale of marketable securities		101			846			602
Proceeds from sale of property and equipment		76			147			142
Net change in restricted investments		(116	)		(11	)		(330	)
Net cash used in investing activities:		(20,877	)		(17,775	)		(39,835	)

The accompanying notes are an integral part of these statements.

-90-

U.S. ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
	(In thousands)
	For the years ended December 31,
	2012			2011			2010
Cash flows financing activities:
Issuance of common stock		51			(146	)		294
Proceeds from new debt		10,000			33,069			--
Repayments of debt		(12,484	)		(11,365	)		(200	)
Net cash (used in) provided by financing activities		(2,433	)		21,558			94

Net cash provided by operating activities
of discontinued operations		122			767			779
Net used in investing activities
of discontinued operations		--			(55	)		(24	)

Net (decrease) increase in cash and cash equivalents		(10,049	)		7,062			(27,591	)

Cash and cash equivalents at beginning of period		12,874			5,812			33,403


Cash and cash equivalents at end of period	$	2,825		$	12,874		$	5,812

Supplemental disclosures:
Income tax received	$	--		$	--		$	(353	)

Interest paid	$	179		$	290		$	22

Non-cash investing and financing activities:

Unrealized gain	$	101		$	78		$	642

Acquisition and development of oil and gas
properties through accounts payable	$	6,202		$	2,092		$	8,983

Acquisition and development of oil and gas
through asset retirement obligations	$	142		$	186		$	75

The accompanying notes are an integral part of these statements.

-91-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

A. BUSINESS ORGANIZATION AND OPERATIONS

U.S. Energy Corp. (“USE”, the “Company”, “we” or “us”) was incorporated in the State of Wyoming on January 26, 1966. U.S. Energy Corp. engages in the acquisition, exploration and development of oil and gas properties and the exploration, holding, sale and/or development of mineral properties. Principal asset interests at December 31, 2012 are in oil and gas, molybdenum, real estate and a minority ownership in a private geothermal company.

B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP 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, 2012 and 2011 include the accounts of USE and its wholly owned subsidiaries Energy One, LLC (“Energy One”) and Remington Village, LLC (“Remington Village”). All inter-company balances and transactions have been eliminated in consolidation. The financial statements as of December 31, 2012, 2011 and 2010 reflect USE’s ownership in a geothermal company, Standard Steam Trust LLC (“SST”) which is accounted for using the equity method. At December 31, 2012 USE’s ownership interest in SST was 19.54%.

Cash and Cash Equivalents

USE considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. USE maintains its cash and cash equivalents in bank deposit accounts which exceed federally insured limits. USE has not experienced any losses in such accounts and believes 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 of available-for-sale securities 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. As of December 31, 2012 and 2011, USE had unrealized gains in the marketable securities before tax effect of $159,000 and $122,000, respectively.

-92-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(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 years ended December 31, 2012 and 2011, USE recorded $13,000 and $56,000, respectively, in bad debt expense related to its multifamily housing project. The balance of accounts receivable at December 31, 2012 and 2011 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, 2012 or 2011.

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
	Aircraft	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

-93-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

Components of Property and Equipment as of December 31, 2012 and 2011 are as follows:

	(In thousands)
	December 31,			December 31,
	2012			2011
Oil & Gas properties
Unproved	$	9,169		$	17,098
Wells in progress		-			2,909
Proved		119,919			99,496
		129,088			119,503
Less accumulated depreciation
depletion and amortization		(43,454	)		(28,561	)
Net book value		85,634			90,942

Mining properties		20,739			20,739

Building, land and equipment		8,469			8,474
Less accumulated depreciation		(4,034	)		(3,746	)
Net book value		4,435			4,728
Totals	$	110,808		$	116,409

Oil and Gas Properties

The Company follows the full cost method in accounting for its oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from 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.

Full Cost Pool – Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at December 31, 2012 and 2011 which were not included in the amortized cost pool were $9.2 million and $20.0 million, respectively. These costs consist of exploratory wells in progress, seismic costs that are being analyzed for potential drilling locations as well as land costs related to unevaluated properties. No capitalized costs related to unproved properties are included in the amortization base at December 31, 2012 and 2011. It is anticipated that these costs will be added to the full cost amortization pool within the next two years as properties are evaluated, drilled or abandoned.

-94-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

Ceiling Test Analysis – 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 USE’s oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, less (iv) income tax effects related to differences between the book and tax basis of the natural gas and crude oil properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs.

We perform a quarterly ceiling test for each of our oil and gas cost centers. There was only one such cost center in 2012. The reserves used in the ceiling test and the ceiling test itself incorporate assumptions regarding pricing and discount rates over which management has no influence in the determination of present value. In arriving at the ceiling test for the year ended December 31, 2012, USE used $94.71 per barrel for oil and $2.757 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 properties. The discount factor used was 10%.

During the year ended December 31, 2012, the Company recorded proved property impairments totaling $5.2 million, related to its oil and gas assets, primarily due to a decline in natural gas prices, higher actual and projected capitalized well costs and higher projected lease operating expenses. Management will continue to review the Company’s 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.

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.

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.

-95-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

Mineral properties at December 31, 2012 and 2011 reflect capitalized costs associated with our Mt. Emmons molybdenum property near Crested Butte, Colorado. Our carrying balance in the Mt. Emmons property at December 31, 2012 and 2011 is as follows:

	(In thousands)
	December 31,		December 31,
	2012		2011
Costs associated with Mount Emmons
beginning of year	$	20,739	$	21,077
Development costs		--		16
Option payment from Thompson Creek		--		(354	)
Costs at the end of the period	$	20,739	$	20,739

Long-Lived Assets

We evaluate our 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 our financial position and results of operations.

Assets Held for Sale

In accordance with authoritative accounting guidance regarding property plant and equipment, assets are classified as held for sale when we commit to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to determine if there is any excess of carrying value over fair value less costs to sell. Subsequent changes to estimated fair value less the cost to sell will impact the measurement of assets held for sale if the fair value is determined to be less than the carrying value of the assets.

In January 2011, we made the decision to sell our Remington Village multifamily project in Gillette, Wyoming and in September 2012, we made the decision to sell our corporate aircraft and related facilities to reduce overhead costs. We plan to use the proceeds to further the development of our oil and gas business, reduction of debt or for general corporate purposes. Operations related to Remington Village are shown in discontinued operations on the accompanying consolidated statements of operations. For additional discussion on assets held for sale, please refer to Note H – Assets Held for Sale.

	(In thousands)
	December 31,		December 31,
	2012		2011
Assets held for sale
Remington Village	$	15,167	$	18,132
Corporate aircraft and facilities		1,884		4,468
	$	17,051	$	22,600

-96-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

Derivative Instruments

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

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

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.

-97-

U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

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

	(In thousands)
	December 31,		December 31,
	2012		2011
Beginning asset retirement obligation	$	510	$	303
Accretion of discount		34		23
Liabilities incurred		142		187
Liabilities sold		--		(3	)
Ending asset retirement obligation	$	686	$	510

Mining properties	$	162	$	149
Oil & Gas wells		524		361
Ending asset retirement obligation	$	686	$	510

Revenue Recognition

USE derives revenue primarily from the sale of produced oil, gas, and NGLs. The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported separately as expenses and are included in oil and gas production expense in the accompanying statements of operations. USE records natural gas and oil revenue under the sales method of accounting. Revenue is recorded in the month that the production is delivered to the purchaser. Payment is generally received between 30 and 90 days after the date of production. At the end of each month, we estimate the amount of production delivered to the purchaser and the price we will receive. USE uses its knowledge of its properties, their historical performance, market prices, and other factors as the basis for these estimates.

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 and director 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 computes the fair values of its options granted to employees using the Black Scholes pricing model and the following weighted average assumptions:

	Year Ended December 31,
	2012	2011	2010
Risk-free interest rate	0.82% to 1.41%	1.77%	2.24%
Expected lives (years)	5.0 to 6.0	6.0	6.0
Expected volatility	61.87% to 63.59%	59.64%	63.79%
Expected dividend yield	--	--	--

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

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.

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 not be realized and a valuation allowance has 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, 2012, 2011, and 2010 were 824,123, 684,643, and 685,382, 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 are excluded from the computation of diluted loss per share for the years ending December 31, 2012, 2011 and 2010 because they were anti-dilutive. There were no dilutive options at December 31, 2012. Dilutive options totaled 486,371 and 994,067 at December 31, 2011 and 2010, respectively.

Recent Accounting Pronouncements

On January 1, 2012, the Company adopted Accounting Standards Update No. 2011-05 (“ASC No. 2011-05”), an update to ASC Topic 220 issued by the FASB that states that an entity that reports items of other comprehensive income has the option to present the components of comprehensive income in either one continuous financial statement, or two consecutive financial statements, including reclassification adjustments. Subsequent to the issuance of the authoritative guidance, the FASB issued additional authoritative accounting guidance (“ASC No. 2011-12”) that effectively deferred the requirement to present the reclassification adjustments on the face of the financial statements, as well as the requirement to present the individual components of other comprehensive income for interim periods. The Company has elected to present a separate statement of comprehensive income, including the individual components, titled Consolidated Statements of Comprehensive Loss, as part of Item 8 to this report.

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. ASU 2011-

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

11 is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. The adoption of this standard is not expected to have an impact on the Company’s consolidated financial statements.

In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which provides amendments to FASB ASC Topic 820, Fair Value Measurement. The objective of ASU 2011-04 is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements. ASU 2011-04 is effective beginning after December 15, 2011. The adoption of this standard did not have an impact on the Company’s consolidated financial statements other than additional disclosures.

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. FAIR VALUE

We follow authoritative guidance regarding fair value measurements for all assets and liabilities measured at fair value. That guidance establishes a fair value hierarchy that prioritizes the inputs the Company uses to measure fair value based on the significance level of the following inputs:

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

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

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

Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. As of December 31, 2012, we held $183,000 of investments in marketable securities. The fair value of our commodity risk management assets and other accrued liabilities are determined using a market approach based on several factors, including observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. The fair value of our property held for sale is determined based on anticipated future cash flows, costs and comparables to the extent they are available, less estimated selling costs. The fair values of our other accrued liabilities that are reflected on the balance sheet are detailed below. Other accrued liabilities decreased to $771,000 at December 31, 2012 as a net result of a full year of payments from the retirement and the accretion of the liability. The other accrued liabilities are the long term portion of the executive retirement program.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

	(In thousands)
			Fair Value Measurements at December 31, 2012 Using
	December 31,		Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	2012		(Level 1)		(Level 2)		(Level 3)

Commodity risk management assets	$	472	$	--	$	472	$	--
Available for sale securities		183		183		--		--
Assets held for sale		17,051		--		--		17,051

Total assets	$	17,706	$	183	$	472	$	17,051

Commodity risk management liability	$	--	$	--	$	--	$	--
Other accrued liabilities		771		--		--		771

Total	$	771	$	--	$	--	$	771

	(In thousands)
			Fair Value Measurements at December 31, 2011 Using
	December 31,		Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	2011		(Level 1)		(Level 2)		(Level 3)

Commodity risk management assets	$	3	$	--	$	3	$	--
Available for sale securities		166		166		--		--
Assets held for sale		18,132		--		--		18,132

Total assets	$	18,301	$	166	$	3	$	18,132

Commodity risk management liability	$	601	$	--	$	601	$	--
Other accrued liabilities		822		--		--		822

Total	$	1,423	$	--	$	601	$	822

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

The following table summarizes the change in the fair value of our Level 3 Fair Value measurements for the year ended December 31, 2012.

	Change in Level 3 Fair Value Measurements
	(In thousands)
	December 31,		Scheduled						December 31,
Description	2011		Depreciation			Revision of Value			2012

Assets held for sale
Remington Village	$	18,132	$	--		$	(2,965	)	$	15,167
Corporate aircraft and facilities		4,468		(235	)		(2,349	)		1,884

Total	$	22,600	$	(235	)	$	(5,314	)	$	17,051

	December 31,		Additions and			December 31
Description		2011	Payments				2012

Other accrued liabilities	$	821	$	(50	)	$	771

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, 2012
	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	$	183	$	159	$	--	$	--	$	183	$	159

Total	$	183	$	159	$	--	$	--	$	183	$	159


December 31, 2011
	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	$	166	$	122	$	--	$	--	$	166	$	122

Total	$	166	$	122	$	--	$	--	$	166	$	122

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

Our other financial instruments include cash and cash equivalents, accounts receivable, accounts payable, other current liabilities and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable and other current liabilities approximate fair value because of their immediate or short-term maturities. The carrying value of our debt approximates its fair market value since interest rates have remained generally unchanged from the issuance of the debt. The fair value and carrying value of our debt was $19.8 million as of December 31, 2012.

D. COMMODITY PRICE RISK MANAGEMENT

Through our wholly-owned subsidiary Energy One, we have entered into commodity derivative contracts (“economic hedges”) with BNP Paribas (“BNP”) and Wells Fargo, as described below. The derivative contracts are priced using West Texas Intermediate (“WTI”) quoted prices. The Company is a guarantor of Energy One’s obligations under the economic hedges. The objective of utilizing the economic 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 its existing positions. The Company does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features.

Energy One's commodity derivative contracts as of December 31, 2012 are summarized below:

			Quantity
Settlement Period	Counterparty	Basis	(Bbl/d)		Strike Price

Crude Oil Costless Collar
10/01/12 - 03/31/13	Wells Fargo	WTI		200	Put:	$	85.00
					Call:	$	101.00
Crude Oil Costless Collar
01/01/13 - 06/30/13	Wells Fargo	WTI		200	Put:	$	90.00
					Call:	$	105.75
Crude Oil Costless Collar
10/01/12 - 09/30/13	BNP Paribas	WTI		200	Put:	$	95.00
					Call:	$	116.60
Crude Oil Costless Collar
04/01/13 - 06/30/13	Wells Fargo	WTI		200	Put:	$	90.00
					Call:	$	97.50
Crude Oil Costless Collar
07/01/13 - 09/30/13	Wells Fargo	WTI		400	Put:	$	90.00
					Call:	$	97.50
Crude Oil Costless Collar
10/01/13 - 12/31/13	Wells Fargo	WTI		600	Put:	$	90.00
					Call:	$	97.50

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

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

	As of December 31, 2012
	(in thousands)
	Derivative Assets			Derivative Liabilities
	Balance Sheet	Fair		Balance Sheet	Fair
	Classification	Value		Classification	Value

Crude oil costless collars	Current Asset	$	472	Current Liability	$	--


	As of December 31, 2011
	(in thousands)
	Balance Sheet	Fair		Balance Sheet	Fair
	Classification	Value		Classification	Value

Crude oil costless collars	Current Asset	$	3	Current Liability	$	601

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, 2012 we had a recognized gain of $21,000 from the contract settlements of derivatives and an unrealized gain of $1.1 million.

E. MINERAL PROPERTY TRANSACTIONS

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 1% to 62%. These projects may result in numerous wells being drilled over the next three to five years.

2012 Acquisition and Divestiture Activity:

Bakken/Three Forks Shale Sale. On January 24, 2012 (but effective December 1, 2011), we sold an undivided 75% of our undeveloped acreage with Zavanna, LLC (“Zavanna”) in the Yellowstone and SEHR prospects to GeoResources, Inc. (56.25%) and Yuma Exploration and Production Company, Inc. (18.75%) for $16.7 million and $1.4 million in reimbursed well costs. These amounts were recorded as reductions to our full cost pool. In addition we transferred $5.3 million in costs from unevaluated properties to proved properties as a result of this sale. Under the terms of the agreement, we retained the remaining 25% of our interest in the undeveloped acreage and our original working interest in the initial

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

10 developed wells in the prospects. Our average working interest in the remaining locations is approximately 8.75% and net revenue interests in new wells after the sale are in the range of 6.7375% to 7.0%, proportionately reduced depending on Zavanna’s actual working interest percentages.

Woodbine Acquisition. In May 2012, we entered into a participation agreement with a private entity, Mueller Exploration, Inc. ("Mueller") to participate in the Woodbine Sub-Clarksville 7 Project located in Anderson and Cherokee Counties, Texas. Under the terms of the agreement, we acquired a 26.5% initial working interest (19.6% net revenue interest) in approximately 6,766 gross acres (1,274 net acres to USE) for $1.7 million. The promoted amount covers our portion of the costs for land, geological and geophysical work, as well as all dry hole costs for an initial test well in each of the seven prospects. Upon payout of our initial well costs in each unit, our interest will be reduced to a 19.8% working interest (14.7% net revenue interest). Future infill drilling will be on a heads up basis, and our interest will be a 19.8% working interest (14.7% net revenue interest).

Montana Acreage Sale. On June 8, 2012, we sold an undivided 87.5% of our acreage in Daniels County, Montana to Greehey & Company Ltd. ("Greehey”) for $3.7 million. This amount was recorded as a credit to our full cost pool. In addition we transferred $1.0 million in costs from unevaluated properties to proved properties as a result of this sale. Under the terms of the agreement, we retained a 12.5% working interest in the acreage and reserved overriding royalty interests (“ORRI”) in leases we owned that had in excess of 81% NRI. Greehey also committed to drill a vertical test well to depths sufficient to core the Bakken and Three Forks formations on or before December 31, 2015. We delivered an 80% NRI to Greehey and a 1% ORRI to Energy Investments, Inc. (“EII”) in connection with the sale. We also paid EII a commission equal to 10% of the cash consideration paid by Greehey.

Mount Emmons Molybdenum Properties

Mineral properties at December 31, 2012 and December 31, 2011 reflect capitalized costs associated with our Mt. Emmons molybdenum property near Crested Butte, Colorado.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

F. 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,
	2012		2011
Unproved oil and gas properties	$	9,169	$	20,007
Proved oil and gas properties		119,919		99,496
	$	129,088	$	119,503

USE’s DD&A per equivalent BOE was $33.49 in 2012, $31.64 in 2011 and $23.64 in 2010.

Undeveloped properties as of December 31, 2012 include costs incurred in the following years:

	(In thousands)
	Acquisitions		Exploration		Development		Total
2010	$	994	$	--	$	--	$	994
2011		7,947		--		--		7,947
2012		228		--		--		228
Total	$	9,169	$	--	$	--	$	9,169

Costs Incurred

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

	(In thousands)
	For the years ending December 31,
	2012		2011		2010
Property acquisition costs:
Proved	$	2,987	$	1,288	$	--
Unproved		1,416		10,679		14,237
Exploration costs		10,943		32,787		35,899
Development costs		20,134		4,550		4,846
Total costs incurred	$	35,480	$	49,304	$	54,982

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

Results of Operations

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

	(In thousands)
	For the years ending December 31,
	2012		2011		2010
Oil and gas revenues	$	32,534	$	30,958	$	26,548
Less:
Operating expenses		10,788		11,552		6,073
Depreciation, depletion and amortization		14,893		13,997		10,610
Impairment		5,189		--		--
		30,870		25,549		16,683
Operating income	$	1,664	$	5,409	$	9,865

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, 2012 and the related discounted future net cash flows before income taxes are based on the estimates prepared by Cawley, Gillespie & Associates, Inc. The reserve reports for the period ended December 31, 2011 were prepared by Cawley, Gillespie & Associates, Inc., Ryder Scott Company, L.P and Netherland, Sewell & Associates, Inc. The reserve reports for the period ended December 31, 2010 were prepared by Cawley, Gillespie & Associates, Inc. and 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:

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

December 31, 2012	Oil (BBLS)	Natural Gas or NGL (MCFE)
Beginning of year	2,737,969	2,744,128
Revisions of previous quantity estimates	(145,596)	(481,583)
Extensions, discoveries and improved recoveries	763,125	369,169
Purchase of reserves in place	75,948	30,457
Sales of reserves in place	(444,272)	(437,057)
Production	(373,531)	(427,026)
End of year	2,613,643	1,798,088

Proved developed reserves at end of year	1,770,659	1,420,295


December 31, 2011	Oil (BBLS)	Natural Gas or NGL (MCFE)
Beginning of year	1,546,446	2,450,968
Revisions of previous quantity estimates	4,913	(864,513)
Extensions, discoveries and improved recoveries	1,516,797	2,004,535
Purchase of reserves in place	48,615	49,065
Sales of reserves in place	(78,477)	(43,716)
Production	(300,325)	(852,211)
End of year	2,737,969	2,744,128

Proved developed reserves at end of year	1,884,068	1,983,581

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,
	2012			2011			2010
Future cash inflows	$	237,148		$	259,533		$	124,629
Future costs:
Production		(96,616	)		(77,813	)		(36,299	)
Development		(21,461	)		(42,972	)		(6,774	)
Future income tax expense		(8,483	)		(19,790	)		(11,622	)
Future net cash flows		110,588			118,958			69,934
10% discount factor		(39,571	)		(56,767	)		(25,281	)
Standardized measure of discounted future net cash flows	$	71,017		$	62,191		$	44,653

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

Future cash flows 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. Prices used in computing year end 2012, 2011 and 2010 future cash flows were $94.71/barrel, $96.19/barrel and $79.43/barrel, respectively, for oil and $2.757/MMbtu, $4.12/MMbtu and $4.38/MMbtu for natural gas, respectively, in each case adjusted for regional price differentials and other factors. 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.

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,
	2012			2011			2010
Balance at beginning of period	$	62,191		$	44,653		$	19,984
Sales of oil and gas, net of production costs		(21,747	)		(19,406	)		(20,476	)
Net change in prices and production costs		(4,548	)		1,401			3,895
Net change in future development costs		--			--			--
Extensions and discoveries		23,297			26,574			40,011
Purchase of reserves in place		2,573			3,082			--
Sale of reserves in place		(13,573	)		(1,947	)		--
Revisions of previous quantity estimates		(5,927	)		(3,158	)		(2,519	)
Development costs incurred during year		22,808			14,930			--
Previously estimated development costs incurred		(9,706	)		(2,719	)		--
Net change in income taxes		7,261			(4,270	)		(2,138	)
Accretion of discount		7,254			5,207			2,576
Changes in production rates, timing and other		1,134			(2,156	)		3,320
Balance at end of period	$	71,017		$	62,191		$	44,653

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.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

G. GEOTHERMAL

During the year ended December 31, 2012, USE’s minority interest investment in SST, a Denver, Colorado based private geothermal resource acquisition and development company, decreased. Due to not funding cash calls from SST during 2012, USE’s ownership interest decreased from 22.4% to 19.54%.

H. ASSETS HELD FOR SALE

As of December 31, 2012, the accompanying condensed consolidated balance sheets include approximately $17.1 million in book value of assets held for sale, which consists of $15.2 million related to Remington Village and $1.9 million related to the corporate aircraft and related facilities.

In January 2011, we made the decision to sell our Remington Village multifamily project in Gillette, Wyoming and plan to use the proceeds to further the development of our oil and gas business. On March 5, 2013, the Company entered into a Purchase and Sale Agreement to sell Remington Village for $15.0 million. During the year ended December 31, 2012, the Company recorded non-cash impairments totaling $3.0 million to adjust the carrying value of the project to the expected sale value less selling costs.

As of December 31, 2012, the accompanying condensed consolidated balance sheets include approximately $15.2 million in book value of assets held for sale related to Remington Village, net of accumulated depreciation, and $10.0 million in liabilities held for sale. Because Remington Village has been classified as an asset held for sale, scheduled depreciation of $747,000 for the year ended December 31, 2012 and $946,000 for the year ended December 31, 2011 was not recorded. Remington Village is pledged as collateral on a $10.0 million note. At such time as Remington Village is sold, the debt balance will be retired.

The Company's real estate operations for the year ending December 31, 2010 were reported as an operating segment. For the years ended December 31, 2012 and 2011 these operations have been reclassified as discontinued operations in the current financial statements. Results of discontinued operations for the years ended December 31, 2012, 2011 and 2010 were as follows:

	(In thousands)
	For the years ending December 31,
	2012			2011			2010
Revenues	$	2,037		$	2,147		$	2,411
Operating expenses		1,885			1,468			2,062
Impairment		2,955			3,063			1,540
		4,840			4,531			3,602

Loss before income taxes		(2,803	)		(2,384	)		(1,191	)

Income tax benefit from (provision for)		1,009			(245	)		(123	)

Net loss from discontinued operations	$	(1,794	)	$	(2,629	)	$	(1,314	)

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

In September 2012, we made the decision to sell our corporate aircraft and related facilities to reduce overhead costs and plan to use the proceeds to further the development of our oil and gas business, reduction of debt or for general corporate purposes. As of December 31, 2012 the accompanying consolidated balance sheets include approximately $1.9 million in book value of assets held for sale, net of accumulated depreciation. Because the aircraft and related facilities have been classified as an asset held for sale, we will no longer record any scheduled depreciation. During the year ended December 31, 2012, the Company recorded non-cash impairments totaling $2.3 million to adjust the carrying value to the expected sale value.

The following assets and liabilities have been segregated and included in the Assets Held for Sale and Liabilities Held for Sale, as appropriate, in the consolidated balance sheets as of December 31, 2012 and 2011:

	(In thousands)
	December 31,		December 31,
	2012		2011
Cash and cash equivalents	$	211	$	170
Accounts receivable		19		13
Prepaid expenses		42		99
Property, plant and equipment, net		14,775		17,730
Restricted investment		120		120
Assets of discontinued operations		15,167		18,132

Corporate aircraft and related facilities		1,884		4,468
Assets held for sale	$	17,051	$	22,600

Accounts payable	$	144	$	117
Accrued and other liabilities		257		220
Long term debt		9,621		9,904
Liabilities held for sale	$	10,022	$	10,241

I. WELLS FARGO RESERVE CREDIT FACILITY

On July 30, 2010, USE established a Senior Secured Revolving Credit Facility (the “Facility”) to borrow up to $100 million from a syndicate of banks, financial institutions and other entities, including BNP Paribas, who was replaced as a lender by Wells Fargo Bank, NA (“Wells Fargo”) on April 24, 2012. At present, Wells Fargo is the only lender under the Facility. In the future, the facility may include other members of a lending syndicate (the “Lenders”) as provided for in the Facility. Wells Fargo 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. The summary is qualified by reference to the complete text of the documents.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

USE’s wholly-owned subsidiary, Energy One, is 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 is 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 Wells Fargo), and any proposed Borrowing Base decrease will require approval by Lenders holding not less than two-thirds of outstanding loans and loan commitments.

Interest is payable quarterly at the greater of the Prime Rate, the Federal Funds Effective Rate (plus 0.5%), and the adjusted LIBO rate 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 Wells Fargo 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. We pay Wells Fargo a fee each time the Borrowing Base is increased.

In addition, on a quarterly basis, Energy One will pay Wells Fargo, 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 certain negative covenants. The principal negative financial covenants (measured at various times as provided in the Credit Agreement) do not permit (i) the 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) the 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. At all times during the year ended December 31, 2012 Energy One was in compliance with all the affirmative and negative covenants.

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

As of December 31, 2012, the Borrowing Base was $30.0 million and we had borrowed $10.0 million under the Facility.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

J. OTHER LIABILITIES AND DEBT

As of December 31, 2012 and 2011, USE had current and long term liabilities associated with the following funding commitments:

	(In thousands)
	December 31,			December 31,
	2012			2011
Other liabilities and debt:
Other liabilities
Deferred rent		12			14
Employee health insurance self funding		32			10
	$	44		$	24

Other long term liabilities:
Accrued executive retirement costs	$	771		$	822

Debt:
Credit Facility - collateralized by
oil and gas reserves, at 2.92%	$	10,000		$	12,000
Long term Debt
Real estate note - collateralized by
property, interest at 5.5%		9,621			9,904
Real estate note - collateralized by
property, interest at 6%		200			400
		19,821			22,304
Less current portion		(526	)		(481	)
Totals	$	19,295		$	21,823

In December 2008, USE and Thompson Creek Metals (“TCM”) jointly purchased land for $4.0 million ($2.0 million paid in January 2009, $400,000 annually for five years). USE is responsible for one-half the purchase price. As of December 31, 2012, USE has paid $1.8 million, leaving $200,000 to be paid on or before January 2, 2014. On December 6, 2011, TCM notified the Company that it wishes to sell its interest in the property. The Company has until June 5, 2013 to decide whether to purchase TCM’s 50% interest in the property, at cost, and close such purchase.

On May 5, 2011, USE borrowed $10.0 million from a commercial bank against Remington Village. At the date of filing of this annual report $9.6 million is due on the note. The note is collateralized by the Company's multi-family property in Gillette, WY. The note is amortized over 20 years with a balloon payment at the end of five years with an interest rate of 5.50% per annum. Proceeds of the note were used to fund general business obligations. When Remington Village is sold, the proceeds from the sale will first be applied to the retirement of the debt and the remainder applied to general corporate overhead and project development. Therefore, the debt related to Remington Village is included in current liabilities held for sale.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

	(In thousands)
	Payments due by period
	Total		2013		2014		2015		2016		2017 and thereafter

Credit facility 3.2%	$	10,000	$	--	$	10,000	$	--	$	--	$	--

Real estate note 5.5%		9,621		308		326		8,987		--		--

Real estate note 6.0%		200		200		--		--		--		--

Total	$	19,821	$	508	$	10,326	$	8,987	$	--	$	--

K. INCOME TAXES

The provision for income taxes is composed of the following:

	(in thousands)
	Years ended December 31,
	2012			2011			2010
Current income tax expense (benefit)
Federal	$	--		$	--		$	(104	)
State		--			--			--
	$	--		$	--		$	(104	)

Deferred income tax expense (benefit)
Federal	$	(1,093	)	$	(3,316	)	$	(1,543	)
State		(64	)		(195	)		(91	)
	$	(1,157	)	$	(3,511	)	$	(1,634	)

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,
	2012			2011			2010

Federal statutory income tax rate	$	(4,164	)	$	(2,828	)	$	(853	)
State income taxes, net of federal benefit		(245	)		(166	)		(50	)
Incentive stock options		12			246			258
Percent depletion carryover		(177	)		(807	)		(1,067	)
Valuation allowance		3,512			--			--
Other		(95	)		44			(26	)
	$	(1,157	)	$	(3,511	)	$	(1,738	)

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

The components of deferred tax assets and liabilities as of December 31, 2012 and 2011 are as follows:

	(in thousands)
	December 31,			December 31,
	2012			2011
Deferred tax assets:
Net operating loss	$	2,899		$	2,547
Derivative instruments		(170	)		215
Asset retirement obligation		247			184
Stock based compensation		313			288
Deferred compensation		382			357
Alternative minimum tax credit		706			706
Contribution carryover		37			28
Equity investments		(91	)		37
Percentage depletion carryover		2,100			1,924
	$	6,423		$	6,286

Deferred tax liabilities:
Property and equipment		(2,854	)		(7,385	)
Marketable securities		(57	)		(44	)
	$	(2,911	)	$	(7,429	)

Net deferred tax assets (liabilities)		3,512			(1,143	)
Less: Valuation Allowance		(3,512	)		--
Deferred tax liability	$	--		$	(1,143	)

During the year ended December 31, 2012, deferred tax assets increased $137,000 and deferred tax liabilities decreased by $4.5 million. The change in net deferred tax liabilities was a decrease of $4.7 million compared to the previous year. This resulted in a net deferred asset of $3.5 million, which is fully offset by a valuation allowance. The change from a net deferred liability of $1.2 million at December 31, 2011 to net zero deferred assets at December 31, 2012 reesulted in a deferred tax benefit of $1.2 million.

USE has net operating loss carryovers as of December 31, 2012 of $9.5 million for federal income tax purposes and $6.9 million for financial reporting purposes. The difference of $2.6 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 2031. In addition, USE has alternative minimum tax credit carry-forwards of $706,000 which are available to offset future federal income taxes over an indefinite period.

The statute of limitations is closed for the tax years through 2008.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

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, 2011, 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 or penalties related to uncertain tax positions have been accrued.

L. SEGMENTS AND MAJOR CUSTOMERS

During the years ended December 31, 2012, 2011, and 2010, USE, for financial reporting purposes, operated two business segments, the exploration for and sale of oil and gas, and mining. USE’s operating segments are reflected in the tables below:

	(In thousands)
	For the years ended December 31,
	2012			2011			2010
Revenues:
Oil and gas	$	32,534		$	30,958		$	26,548
Total revenues:		32,534			30,958			26,548

Operating expenses:
Oil and gas		30,870			25,549			16,683
Mineral properties		2,899			2,364			1,878
Total operating expenses:		33,769			27,913			18,561

Interest expense
Oil and gas		169			268			--
Mineral properties		24			36			48
Total interest expense:		193			304			48

Operating (loss) income
Oil and gas	$	1,495		$	5,141		$	9,865
Mineral properties		(2,923	)		(2,400	)		(1,926	)
Operating income (loss)
from identified segments		(1,428	)		2,741			7,939

General and administrative expenses		(9,109	)		(8,261	)		(8,973	)
Add back interest expense		193			304			48
Other revenues and expenses:		849			(717	)		(332	)

(Loss) income before income taxes	$	(9,495	)	$	(5,933	)	$	(1,318	)

Depreciation depletion and amortization expense:
Oil and gas	$	14,893		$	13,997		$	10,610
Mineral properties		127			102			77
Corporate		436			494			380
Total depreciation expense	$	15,456		$	14,593		$	11,067

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

	(In thousands)
	December 31,		December 31,		December 31,
	2012		2011		2010
Assets by segment
Oil and gas	$	93,839	$	109,141	$	75,639
Mineral		20,747		20,755		20,800
Corporate		26,241		32,543		59,577
Total assets	$	140,827	$	162,439	$	156,016

M. SHAREHOLDERS’ EQUITY

Stock Option Plans

Employee Stock Option Plans. In December 2001, the Board of Directors adopted (and the shareholders subsequently 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 with the approval of the shareholders in 2004 and 2007) reserved for issuance 25% of USE’s shares of common stock issued and outstanding at any time. The 2001 ISOP had a term of 10 years and expired on December 6, 2011. Options issued under the 2001 ISOP remain exercisable until their expiration date under the terms of the 2001 ISOP.

In June 2012, the Board of Directors adopted (and the shareholders approved) the U.S. Energy Corp. 2012 Equity and Performance Incentive Plan (the “2012 Equity Plan”) for the benefit of USE’s employees. The 2012 Equity Plan reserved for issuance 1,200,000 shares of USE’s common stock. The 2012 Equity Plan has a term of 10 years.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

A summary of the Employee Stock Option Plans activity in all plans for the year ended December 31, 2012, 2011 and 2010 is as follows:

	Year ended December 31,
	2012					2011					2010
	Employee Options			Weighted Average Exercise Price		Employee Options			Weighted Average Exercise Price		Employee Options			Weighted Average Exercise Price
Outstanding at beginning
of the period		2,318,399		$	3.94		3,011,647		$	3.87		3,711,114		$	3.64
Granted		150,000		$	2.32		--		$	--		--		$	--
Forfeited		(10,000	)	$	2.32		--		$	--		--		$	--
Expired		(194,950	)	$	4.47		(200,000	)	$	3.90		--		$	--
Exercised		(4,167	)	$	2.52		(493,248	)	$	3.51		(699,467	)	$	2.63
Outstanding at period end		2,259,282		$	3.80		2,318,399		$	3.94		3,011,647		$	3.87
Exercisable at period end		2,119,282		$	3.90		2,108,399		$	3.84		2,404,148		$	3.78

Weighted average fair
value of options
granted during
the period				$	1.30				$	--				$	--

During the year ended December 31, 2012, a total of 4,167 options were exercised by employees by the surrender of 3,097 shares valued at $10,000. In the year ended December 31, 2011, 493,248 options were exercised by the payment of $34,000 in cash and surrender of 368,804 shares valued at $1.9 million. In the year ended December 31, 2010, 699,467 options were exercised by the payment of $63,000 in cash and surrender of 325,195 shares valued at $1.8 million.

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. The total expense associated with employee stock options for the years ended December 31, 2012, 2011 and 2010 was $33,000, $947,000 and $1.0 million, respectively. As of December 31, 2012, there was $165,000 of total unrecognized expense related to unvested stock options, which is being amortized through 2015.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

The following table summarizes information about employee stock options outstanding and exercisable at December 31, 2012:

Grant Price Range		Employee Options Outstanding at December 31, 2012		Weighted average remaining contractual life in years		Weighted average exercise price		Employee Options exercisable at December 31, 2012		Weighted average exercise price

$	2.32		140,000		9.53	$	2.32		--	$	--
$	2.33 - $2.46		386,869		1.50	$	2.46		386,869	$	2.46
$	2.47 - $2.52		408,645		5.72	$	2.52		408,645	$	2.52
$	2.53 - $3.86		273,768		2.78	$	3.86		273,768	$	3.86
$	3.87 - $4.97		1,050,000		4.57	$	4.97		1,050,000	$	4.97
			2,259,282		4.34	$	3.82		2,119,282	$	3.90

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

	2012		2011		2010
Available for future grant		1,060,000		--		3,765,506
Intrinsic value of option exercised	$	4,000	$	888,000	$	1,956,000
Aggregate intrinsic value of options outstanding	$	--	$	351,000	$	6,660,000
Aggregate intrinsic value of options exercisable	$	--	$	351,000	$	5,526,000

Director Option Plan. As of December 31, 2012, there were 150,000 director options outstanding to purchase shares of USE's common stock. Of the total outstanding options, 63,335 were exercisable. USE values these options 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, 2012, 2011 and 2010 for director options is presented in the following table:

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

	Year ended December 31,
	2012					2011					2010
	Director Options			Weighted Average Exercise Price		Director Options			Weighted Average Exercise Price		Director Options			Weighted Average Exercise Price
Outstanding at beginning
of the period		210,000		$	3.10		320,000		$	2.95		581,367		$	2.91
Granted		80,000		$	2.78		20,000		$	4.19		10,000		$	5.04
Forfeited		--		$	2.52		(20,000	)	$	2.52		(20,000	)	$	2.52
Expired		(120,000	)	$	3.05		(5,000	)	$	3.90		--		$	--
Exercised		(20,000	)	$	2.52		(105,000	)	$	2.92		(251,367	)	$	2.97
Outstanding at period end		150,000		$	3.05		210,000		$	3.10		320,000		$	2.95
Exercisable at period end		63,335		$	3.01		183,334		$	2.91		276,667		$	2.93

Weighted average fair
value of options
granted during
the period				$	1.59				$	2.34				$	2.99

During the year ended December 31, 2012, a total of 20,000 director options were exercised by the payment of $50,000 in cash. In the year ended December 31, 2011, 105,000 options were exercised by the payment of $62,000 in cash and the surrender of 62,104 shares valued at $245,000. In the year ended December 31, 2010, 251,367 warrants were exercised by the payment of $746,000 in cash. The total expense associated with director stock options for the years ended December 31, 2012, 2011 and 2010 was $69,000, $6,000 and $66,000, respectively. As of December 31, 2012, there was $112,000 of total unrecognized expense related to unvested stock options, which is being amortized through 2015.

The following table summarizes information about director options outstanding and exercisable at December 31, 2012:

Grant Price Range		Director Options Outstanding at December 31, 2012		Weighted average remaining contractual life in years		Weighted average exercise price		Director Options exercisable at December 31, 2012		Weighted average exercise price

$	2.32		10,000		9.53	$	2.32		--	$	-
$	2.33 - $2.52		40,000		5.72	$	2.52		40,000	$	2.52
$	2.53 - $2.85		70,000		9.22	$	2.85		10,000	$	2.85
$	2.86 - $4.19		20,000		8.48	$	4.19		6,668	$	4.19
$	4.20 - $5.04		10,000		7.48	$	5.04		6,667	$	5.04

			150,000		8.10	$	3.05		63,335	$	3.01

These options are held by current and former directors of USE.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

USE has computed the fair values of its employee and director options using the Black Scholes pricing model and the following weighted average assumptions:

	Year Ended December 31,
	2012	2011	2010
Risk-free interest rate	0.82% to 1.41%	1.77%	2.24%
Expected lives (years)	5.0 to 6.0	6.0	6.0
Expected volatility	61.87% to 63.59%	59.64%	63.79%
Expected dividend yield	--	--	--

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 $250,000 for the year ended December 31, 2012, and $245,000 for the years ended December 31, 2011 and 2010, 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 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, 2012, 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 $27,000.

During the year ended December 31, 2012, the Board of Directors of USE approved a contribution of 161,624 shares to the ESOP at the price of $1.50 for a total expense of $242,000. This compares to contributions to the ESOP during the year ended December 31, 2011 and 2010 of 98,958 and 42,802 shares to the ESOP at prices of $2.91 and $6.08 per share, respectively. The expense for the contributions during the years ended December 31, 2011 and 2010 were $287,000 and $260,000, respectively.

N. 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:

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

Water Rights Litigation –Mt. Emmons Project

On August 11, 2010, High Country Citizen’s Alliance (“HCAA”), 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 United States Forest Service (“USFS”) regulations and did not satisfy certain “reality check” limitations contained in the Decree. On September 24, 2010, we filed a response to the motion for summary judgment responding that the plan of operations complied with USFS and BLM regulations and satisfied the reality check limitations. The U.S. Department of Justice also filed a response on behalf of the USFS and BLM asserting that the Court cannot second guess the USFS’s determination that the plan of operations satisfied USFS and BLM regulations.

Appeal of Approval of Notice of Intent to Conduct Prospecting for the Mt. Emmons Project

On March 8, 2008, HCCA filed a request for hearing before the Colorado Mine Land Reclamation Board (“Board”) of the approval of a “Notice of Intent to Conduct Prospecting” (“NOI”) for the Mt. Emmons Project, which was approved by the Division of Reclamation, Mining and Safety of the Colorado Department of Natural Resources (“DRMS”) on January 3, 2008. 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 1970s. On May 14, 2008, the MLRB denied HCCA’s request for hearing and also denied its request for a declaratory order. Citing Colorado law, the Board determined that HCCA did not have standing or the right to appeal DRMS’s approval of the NOI under Colorado law.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

and its 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.

Appeal of Modification – Notice of Intent to Conduct Prospecting for the Mt. Emmons Project

On January 12, 2011, the Board on a vote 4-1 vote upheld DRMS’s approval of MD-03 and its 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, which is currently pending.

Brigham Oil & Gas, L.P.

Mining Permits

The Mount Emmons molybdenum property is located on fee property within the boundary of USFS land. Although mining of the mineral resource will occur on the fee property, associated ancillary activities will occur on USFS land. USE submitted a full mine plan of operations in part to satisfy the requirements of the conditional water rights decree on October 10, 2012. Under the procedures mandated

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

by National Environmental Protection Act (“NEPA”), the USFS will prepare an environmental analysis in the form of 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 our control, or changes in agency policy and Federal and State law, could further affect the successful permitting of the mine operations.

Although USE believes that the plan of operations for Mount Emmons will ultimately be approved by the USFS, this cannot be guaranteed. Moreover, the timing and cost, and ultimate success of the mining operation, cannot be predicted.

401(K) Plan

The Board of Directors of USE adopted the U.S. Energy Corp. 401(K) Plan in 2004. USE matches 50% of an employee’s salary deferrals up to a maximum contribution per employee of $4,000 annually. USE expensed $54,000, $57,000, and $49,000 for the years ended December 31, 2012, 2011 and 2010, respectively, related to these contributions.

Executive Officer Compensation

In December 2001, the Board of Directors adopted (and the shareholders subsequently approved) the 2001 Stock Award Plan to compensate its executive officers. The Stock Award Plan was amended on June 22, 2007 with shareholder approval. Under the plan, 20,000 shares may be issued annually to each officer during his employment. During the years ended December 31, 2012, 2011 and 2010, USE collectively issued 60,000, 75,000, and 80,000 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. With the approval of the 2012 Equity Plan by the shareholders at the June 29, 2012 Annual Meeting, the 2001 Stock Compensation Plan (the “2001 SCP”) terminates on April 20, 2013. The last shares issued under the 2001 SCP will be issued in April 2013. All future stock awards will be issued pursuant to the 2012 Equity Plan.

USE committed to pay the surviving spouse 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, 2012, 2011, and 2010, USE paid $0, $57,000, and $85,000, respectively. 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 has paid $85,000 annually under this agreement beginning at the date of retirement, January 12, 2007, to January 12, 2012.

On October 20, 2005, the Board of Directors 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)

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

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. Under 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, 2012, USE had funded the executive retirement account with the amount calculated by a third party actuary, of $1.0 million, which is recorded as Other Long Term Assets. Additional amounts will be deposited annually until each executive’s 60th birthday. As of June 30, 2011 the former CFO/Treasurer/V.P. Finance retired. During the year ended December 31, 2012 and 2011 the former CFO/Treasurer/V.P. Finance received payments totaling $122,000 and $50,000, respectively from the Retirement Plan. At December 31, 2012, there were two officers who were included in the Retirement Plan and three that may qualify for the health insurance benefit.

Compensation expense for executives under the retirement plan for the year ended December 31, 2012, 2011 and 2010 was $80,000, $72,000, and $314,000, respectively. The total accrued liability for executive retirement under all plans at December 31, 2012, 2011 and 2010 was $903,000, $947,000, and $1.0 million, 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 provide for minimum monthly receipts of $8,000 through December 31, 2013. Rental income under the agreements was $170,000, $101,000, and $98,000 for the years ended December 31, 2012, 2011 and 2010, respectively. Future minimum receipts for non-cancelable operating leases are $77,000 for the year ended December 31, 2013.

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

O. SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

	(In thousands except per share data)
	Three Months Ended
	December 31,			September 30,			June 30,			March 31,
	2012			2012			2012			2012
Operating revenues	$	8,038		$	7,639		$	8,522		$	8,335

Operating (loss)	$	(5,932	)	$	(2,709	)	$	(991	)	$	(712	)

Income (loss) before income tax and discontinued operations	$	(6,131	)	$	(3,155	)	$	624		$	(833	)

Benefit from (provision for) income taxes	$	(1,250	)	$	1,285		$	(379	)	$	388

Discontinued operations, net of tax	$	(548	)	$	(75	)	$	(1,235	)	$	64

Net income (loss)	$	(7,929	)	$	(1,945	)	$	(990	)	$	(381	)

Loss per share, basic
Continuing operations	$	(0.27	)	$	(0.07	)	$	0.01		$	(0.01	)
Discontinued operations		(0.02	)		--			(0.05	)		--
	$	(0.29	)	$	(0.07	)	$	(0.04	)	$	(0.01	)

Basic weighted average shares outstanding		27,475,813			27,468,355			27,460,483			27,438,584

Loss per share, diluted
Continuing operations	$	(0.27	)	$	(0.07	)	$	0.01		$	(0.01	)
Discontinued operations		(0.02	)		--			(0.05	)		--
	$	(0.29	)	$	(0.07	)	$	(0.04	)	$	(0.01	)

Diluted weighted average shares outstanding		27,475,813			27,468,355			27,460,483			27,438,584

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

	(In thousands except per share data)
	Three Months Ended
	December 31,			September 30,			June 30,			March 31,
	2011			2011			2011			2011
Operating revenues	$	7,107		$	9,972		$	8,148		$	4,883

Operating income (loss)	$	(2,475	)	$	875		$	400		$	(4,864	)

Income (loss) before income tax and discontinued operations	$	(2,362	)	$	1,022		$	339		$	(4,932	)

Benefit from (provision for) income taxes	$	2,671		$	(892	)	$	(618	)	$	2,594

Discontinued operations, net of tax	$	(3,100	)	$	138		$	204		$	129

Net income (loss)	$	(2,791	)	$	268		$	(75	)	$	(2,209	)

Income (loss) per share, basic
Continuing operations	$	0.01		$	--		$	(0.01	)	$	(0.08	)
Discontinued operations		(0.12	)		0.01			0.01			--
	$	(0.11	)	$	0.01		$	--		$	(0.08	)

Basic weighted average shares outstanding		27,288,470			27,259,174			27,220,049			27,186,438

Income (loss) per share, diluted
Continuing operations	$	0.01		$	--		$	(0.01	)	$	(0.08	)
Discontinued operations		(0.12	)		0.01			0.01			--
	$	(0.11	)	$	0.01		$	--		$	(0.08	)

Diluted weighted average shares outstanding		27,288,470			27,862,098			27,866,544			27,186,438

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U.S. ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2012, 2011, and 2010

(Continued)

	(In thousands except per share data)
	Three Months Ended
	December 31,			September 30,			June 30,			March 31,
	2010			2010			2010			2010
Operating revenues	$	5,023		$	5,717		$	6,218		$	7,709

Operating income (loss)	$	(2,862	)	$	(958	)	$	(297	)	$	1,250

Income (loss) before income tax and discontinued operations	$	(2,359	)	$	(950	)	$	(176	)	$	2,340

Benefit from (provision for) income taxes	$	1,975		$	634		$	17		$	(888	)

Discontinued operations, net of tax	$	(1,549	)	$	81		$	28		$	75

Net income (loss)	$	(1,933	)	$	(235	)	$	(131	)	$	1,527

Income (loss) per share, basic
Continuing operations	$	(0.02	)	$	(0.01	)	$	--		$	0.06
Discontinued operations		(0.05	)		--			--			--
	$	(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
Continuing operations	$	(0.02	)	$	(0.01	)	$	--		$	0.05
Discontinued operations		(0.05	)		--			--			--
	$	(0.07	)	$	(0.01	)	$	--		$	0.05

Diluted weighted average shares outstanding		26,973,834			26,855,513			26,734,636			27,785,572

P. SUBSEQUENT EVENTS

Asset Sales

During the first quarter of 2013, the Company sold its corporate aircraft for $1.9 million and its aircraft hangar and related facilities for $767,000.

On March 5, 2013, the Company entered into a Purchase and Sale Agreement (“PSA”) with an undisclosed buyer to sell its Remington Village apartment complex located in Gillette, Wyoming for $15.0 million. The PSA is subject to a 30 day due diligence period whereby $150,000 in earnest money will be non-refundable. The transaction is anticipated to close on May 6, 2013 although there is no assurance that the transaction will close at this time. If the closing takes place, after selling costs, the Company expects to net $14.8 million from this sale and will retire a $9.6 million note related to this asset with the proceeds from the sale.

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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 designed 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, 2012 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, 2012.

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 the Company; (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, 2012. 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, 2012, our internal control over financial reporting was effective based on those criteria.

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Our internal control over financial reporting as of December 31, 2012, 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 133 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, 2012 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. and subsidiaries' internal control over financial reporting as of December 31, 2012, 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. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, 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 sheets of U.S. Energy Corp. and subsidiaries as of December 31, 2012 and 2011 and the related consolidated statements of operations, comprehensive loss, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012, and our report dated March 15, 2013 expressed an unqualified opinion.

HEIN & ASSOCIATES LLP

Denver, Colorado

March 15, 2013

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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, 2012, we will file such information under cover of a Form 10-K/A.

Item 10 – Directors, Executive Officers and Corporate Governance

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 on June 21, 2013, under the captions “Proposal 1: Election of Directors”, “Filing of Reports under Section 16(a)”, and “Business Experience of Directors, Nominees and Officers”.

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 the Company. Mr. Youngbauer (age 63) has been the General Counsel and Corporate Secretary of the Company 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 officers or directors of the Company. During the past five years, Mr. Youngbauer has not been involved in any Reg. S-K Item 401(f) proceeding.

Steven D. Richmond is not a director of the Company. Mr. Richmond (age 42) has been Chief Financial Officer of the Company since September 7, 2012. He serves at the will of the board of directors. There are no understandings between Mr. Richmond and any other person pursuant to which he was named an officer. He has no family relationships with any of the other executive officers or directors of the Company. During the past five years, Mr. Richmond 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 on June 21, 2013, under the captions “Executive Compensation” and “Non-Employee Director Compensation”.

Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by Item 12 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders to be held on June 21, 2013, under the caption "Principal Holders of Voting Securities" and “Ownership by Officers and Directors”.

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Item 13 - Certain Relationships and Related Transactions, and Director Independence

The information required by Item 13 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders to be held on June 21, 2013, under the caption “Certain Relationships and Related Transactions.”

Item 14 - Principal Accounting 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 on June 21, 2013, 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.

-133-

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.

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 SEC 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.

-134-

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 SEC 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 and Financial Statement Schedules

(a)(1) and (a)(2)	Page
Report of Independent Registered Public Accounting Firm	81
Financial Statements
Consolidated Balance Sheets as of December 31, 2012 and 2011	82
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010	84
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2012, 2011 and 2010	86
Statement of Stockholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010	87
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010	90
Notes to Consolidated Financial Statements	92

All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statement and Notes thereto.

(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K:

3.1**	Restated Articles of Incorporation (incorporated by reference form Exhibit 4.1 to the Company’s Registration Statement on Form S-3, [333-162607] filed October 21, 2009)

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(a)**	Wells Fargo Bank, National Association – Credit Agreement (incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed August 2, 2010)

4.1(b)**	Wells Fargo Bank, National Association – Mortgage Agreement (incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K filed August 2, 2010)

4.1(c)**	Wells Fargo Bank, National Association – Guaranty (incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K filed August 2, 2010)

10.1**†	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)

10.2**†	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)

10.3**	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)

10.4**	U.S. Energy Corp. Employee Stock Option Plan (incorporated by reference from Exhibit 4.1 to the Company’s S-8 filed April 13, 2012)

10.5**	2012 Equity Plan (incorporated by reference from Appendix A to the Company’s Proxy Statement Form DEF14A filed April 30, 2012)

10.5.1*	Form of Grant to the 2012 Equity Plan

-136-

10.6**	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)

10.7(a)**†	Executive Employment Agreement – Keith G. Larsen (effective 4-20-12) (incorporated by reference from Exhibit 10.1 to the Form 8-K filed January 17, 2012)

10.7(b)**†	Executive Employment Agreement – Mark J. Larsen (effective 4-20-12) (incorporated by reference from Exhibit 10.2 to the Form 8-K filed January 17, 2012)

10.7(c)**†	Executive Employment Agreement – Steven R. Youngbauer (effective 4-20-12) (incorporated by reference from Exhibit 10.3 to the Form 8-K filed January 17, 2012)

10.8**	Agreement for Purchase of Leasehold Interests in McKenzie and Williams Counties, North Dakota (Brigham Oil & Gas, L.P.) (incorporated by reference from Exhibit 10.6 to the Company’s Annual Report on Form 10-K filed March14, 2012)

10.9(a)**	Agreement for Purchase of Leasehold Interests in McKenzie County, North Dakota (Geo Resources, Inc.) (incorporated by reference from Exhibit 10.7(a) to the Company’s Annual Report on Form 10-K filed March14, 2012)

10.9(b)**	Amendments (5) to Agreement for Purchase of Leasehold Interest in McKenzie County, North Dakota (Geo Resources, Inc.) (incorporated by reference from Exhibit 10.7(b) to the Company’s Annual Report on Form 10-K filed March14, 2012)

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)

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 Netherland, Sewell & Associates, Inc.

23.3*	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) Steven D. Richmond

32.1*	Certification under Rule 13a-14(b) Keith G. Larsen

32.2*	Certification under Rule 13a-14(b) Steven D. Richmond

99.1*	Reserve Report (Cawley, Gillespie & Associates, Inc.)

101.INS	XBRL Instance Document

101.SCH	XBRL Schema Document

101.CAL	XBRL Calculation Linkbase Document

101.DEF	XBRL Definition Linkbase Document

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101.LAB	XBRL Label Linkbase Document

101.PRE	XBRL Presentation Linkbase Document

* Filed herewith. ** Previously filed. † Exhibit constitutes a management contract or compensatory plan or agreement.

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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 15, 2013	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 15, 2013	By:	/s/ Keith G. Larsen
		KEITH G. LARSEN, Director, Chairman and CEO (Principal Executive Officer)

Date: March 15, 2013	By:	/s/ Steven D. Richmond
		STEVEN D. RICHMOND
		Chief Financial Officer (Principal Financial Officer)

Date: March 15, 2013	By:	/s/ Bryon G. Mowry
		BRYON G. MOWRY
		Principal Accounting Officer

Date: March 15, 2013	By:	/s/ Mark J. Larsen
		MARK J. LARSEN, President and Director

Date: March 15, 2013	By:	/s/ Robert Scott Lorimer
		ROBERT SCOTT LORIMER, Director

Date: March 15, 2013	By:	/s/ Stephen V. Conrad
		STEPHEN V. CONRAD, Director

Date: March 15, 2013	By:	s/ Jerry W. Danni
		JERRY W. DANNI, Director

Date: March 15, 2013	By:	/s/ Leo A. Heath
		LEO A. HEATH, Director

Date: March 15, 2013	By:	/s/ Thomas R. Bandy
		THOMAS R. BANDY, Director

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