10-K 1 form10_k.htm 12-31-12 10-K 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.
 
 
 
-23-

 

 
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
 
 
-40-

 
 
 
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
 
 
-41-

 
 
 
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.


 
-42-

 


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

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.

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