UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

Commission File Number 000-6814

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

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

None

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

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 ☑

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 ☑   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 ☑   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  ☑

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  ☑       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 ☑

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, 2014):  $111,157,000.

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 2015 annual meeting of stockholders to be filed within 120 days after December 31, 2014.

---

TABLE OF CONTENTS

Page

---

 

 

---

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information discussed in this Annual Report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act").  All statements other than statements of historical facts are forward-looking statements.

Examples of 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;

·	anticipated changes in oil and gas production;

·	drilling and completion activities and opportunities in the Buda, Eagle Ford and other formations in South Texas, the Williston Basin in North Dakota 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 payout-based milestones or similar thresholds will be reached for the purposes of our agreements with Statoil, Zavanna and other partners;

·	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 Buda, Bakken/Three Forks, Eagle Ford and other formations;

·	review, timing and potential approval of the plan of operations by the U.S. Forest Service 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;

·	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 declines in oil prices and/or natural gas 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 also could adversely impact the borrowing base available under our credit facility with Wells Fargo Bank (sometimes referred to as the "Credit Facility");

---

·	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;

·

risks associated with our plan to develop additional operating capabilities, including the potential inability to recruit and retain personnel with the requisite skills and experience and liabilities we could assume or incur as operator or to acquire operated properties or obtain operatorship of existing properties;

·	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; 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 for the project if necessary;

·	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 operation; and

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

 

---

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", 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 business activities are currently focused in South Texas and the Williston Basin in North Dakota.  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 have historically explored for and produced oil and gas through a non-operator business model.  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 currently developing our capability to operate properties, most notably with the appointment of David Veltri as President and Chief Operating Officer in December 2014.  Mr. Veltri has over 30 years of oil and gas operating experience.

U.S. Energy believes that additional value for stock holders and for the Company overall is available from having the ability to control drilling and production timing, capital costs and future planning of operations.  The Company plans to begin operating its own wells in the near future through acquisition of new assets and/or by consolidating ownership in and around the areas in which the Company currently participates. We believe the current price climate will make opportunities available for us to acquire and/or develop operated properties, and expect over time to operate over 50% of our production.

We are also involved in 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 mineral development project.  We continue to advance our plans for Mt. Emmons for monetization of the asset, actively mining the minerals or some other use acceptable to local, state and federal governments.

Industry Segments/Principal Products

At December 31, 2014, we have two operating segments:  Oil and Gas and Maintenance of Mineral Properties.  See Note K 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 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 depending on, among other things, commodity prices.  We are also actively pursuing potential acquisitions of exploration, development and production-stage oil and gas properties or companies.  Key attributes of our oil and gas properties include the following:

·	Estimated proved reserves of 4,654,944 BOE (89% oil and 11% natural gas) at December 31, 2014, with a standardized measure value of $81.9 million and a PV10 of $85.2 million.

·	At March 5, 2015, our oil and gas leases covered 118,188 gross and 11,524 net acres.

·	136 gross (20.02 net) producing wells at December 31, 2014 (138 gross (20.36 net) wells at March 5, 2015).

·	1,275 BOE/d average net production for 2014.

PV10 (defined in "Glossary of Oil and Gas Terms") is a non-GAAP measure that 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.  See also Note F to our consolidated financial statements.

 

 

 

-8-

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, to leasing, exploration drilling and development.  The Company engages in the prospect stages either for its own account or with prospective partners to enlarge its oil and gas lease ownership base.

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.  We anticipate that as we establish an operational center in an area, a limited amount of staff will be hired to supply critical aspects of the operations, such as drilling, completions and production.

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

Buda Limestone, Eagle Ford Shale and Austin Chalk Formations, South Texas Properties

Contango Oil & Gas Company.  In 2011, we entered into two participation agreements with Contango Oil & Gas Company ("Contango") 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 (2.98 net) wells 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 occurs on a heads up basis with no carry by the Company.  Both prospects are believed to be prospective for Buda, Eagle Ford , Austin Chalk, Pearsall and Georgetown formations.  Contango is the operator of the prospects.

As a result of subsequent acquisitions, our current total acreage in the Leona River and the Booth Tortuga prospects is approximately 18,878 gross acres (4,915 net acres).  Based upon assumed 120 acre spacing units, there is a potential for up to 157 gross and 41.0 net wells in each of the formations should we find commercial quantities of hydrocarbons.  Looking forward, the Company continues to seek additional leasing opportunities in this region.

 

Through the date of this report, we have drilled 15 gross (4.50 net) Buda formation horizontal wells and three gross (0.90 net) Eagle Ford formation horizontal wells.  Wells in these prospects produced an average of approximately 303 BOE/d net to the Company (41% oil and 59% natural gas and natural gas liquids) during the fourth quarter of 2014.

U.S. Enercorp.  On August 5, 2013, under an area of mutual interest election, the Company acquired a 15% working interest in 4,243 gross (636 net) acres (the "Big Wells prospect") from U.S. Enercorp ("Enercorp"), a private oil and gas company based in San Antonio, Texas.  This acreage is contiguous to the southwestern portion of the Booth-Tortuga acreage block held with Contango.  Under the terms of the election, the leasehold interest is subject to a 25% back-in upon project payout.

---

On May 7, 2014, the Company entered into a Participation Agreement with Enercorp to acquire 33% of Enercorp's interest in approximately 12,100 gross (3,384 net) acres in Dimmit County, Texas.  The acreage consists of 4,020 gross (1,181 net) acres of primary leasehold acreage and 8,080 gross (2,203 net) acres of farm-in acreage, to be earned through a continuous drilling program. The farm-in acreage has an initial two well commitment and a 12.5% working interest carry for the leaseholder (the "Farmor") in the first 10 wells. After 100% payout of all costs for the first 10 wells that are drilled under the farm-in program, the Farmor will back in for its 12.5% retained working interest in the prospect. Enercorp also retained a 25% working interest back-in after 115% of project payout has been received by the Company. The Company paid $3.9 million to enter into the transaction, which included leasehold and farm-in acquisition costs as well as our proportionate share of drilling costs for the initial test well in the prospect.

Through the date of this report, we have drilled four gross (0.97 net) Buda formation horizontal wells in these prospects and one gross (0.33 net) Eagle Ford formation horizontal well.  One additional gross (0.33 net) well was in progress at December 31, 2014.  During the fourth quarter of 2014, the wells in these prospects produced approximately 15 BOE/d net to the Company (99% oil and 1% natural gas).

For further information on the wells drilled in the Buda and Eagle Ford formations in Texas through the date of this Annual Report, see "Item 2 – Properties – Oil and Natural Gas" below.

Williston Basin, North Dakota Properties

Statoil.  On August 24, 2009, we entered into a Drilling Participation Agreement (the "DPA") with Brigham Oil & Gas, L.P., now a subsidiary of Statoil ("Statoil"), to jointly explore for oil and gas in up to 19,200 gross acres in a portion of Statoil's Rough Rider prospect in Williams and McKenzie Counties, North Dakota.  Under the DPA, we earned working interests, derived from Statoil's initial working interests, in fifteen 1,280-acre spacing units in Statoil's Rough Rider project area by participating in the drilling of one initial well in each spacing unit.  Accordingly, we have earned the rights to participate in additional drilling of Bakken and Three Forks formation wells within these units, based on current spacing rules in North Dakota.  If the spacing is ultimately increased to four wells per formation per 1,280 acre spacing unit, the potential number of drilling locations could increase to 120 gross wells.  In addition, if stacked horizons within the Three Forks formation are determined to be economical, the total gross potential wells could increase further as operators in this region are now drilling multiple wells to multiple zones within single drilling units.

In some areas, our interests under the DPA are depth limited to the Bakken and the upper part of the Three Forks formations under the terms of the leases obtained by Statoil from third parties, while other leases may have rights to all depths.  Working interests earned vary according to Statoil's initial working interest, after-payout provisions and the provisions governing each stage of the program.  Our working interests (or "WI") in these wells currently range from 3.5% to 48.0% and our net revenue interests (or "NRI") range from 2.8% to 38.2%.  Our WIs and NRIs in certain wells will be reduced pursuant to the terms of the DPA as payout-based milestones are achieved.  Our earn-in rights were staged in three groups of units and were earned upon paying our proportionate 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. Statoil 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.  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 Statoil 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.

---

From August 24, 2009 to December 31, 2014, we have drilled and completed 24 gross (6.39 net) Bakken formation wells and two gross (0.22 net) Three Forks formation wells under the DPA.  These wells produced an average of approximately 434 BOE/d net to the Company (74% oil and 26% natural gas and natural gas liquids) during the fourth quarter of 2014.  At this time, no drilling activity is scheduled for 2015.  Statoil's drilling plans beyond 2015 are not known at this time.

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. in January 2012 as noted below.  Approximately 1,225 net acres are currently subject to the agreements.

The acquired acreage is in two prospects – the Yellowstone Prospect and the SE HR Prospect and consists of 28 gross 1,280 acre spacing units.   If the spacing is ultimately increased to four wells per formation per 1,280 acre spacing unit, the potential number of drilling locations could increase to 224 gross wells.  In addition, if stacked horizons within the Three Forks formation are determined to be economical, the total gross potential wells could increase further as operators in this region are now drilling multiple wells to multiple zones within single drilling units.

Our interests in all the acreage in both prospects is subject to reduction by a 30% reversionary working interest under each prospect upon the achievement of certain payout-based milestones.  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 6.74% to 7.0%, proportionately reduced depending on Zavanna's actual working interest percentages in each unit.

As of December 31, 2014, we have interests in twenty-eight gross 1,280 acre spacing units in the Yellowstone and SEHR prospects with Zavanna.  We have drilled and completed 42 gross (3.10 net) Bakken formation wells and eight gross (0.33 net) Three Forks formation wells in these prospects.  The wells are operated by Zavanna (18 gross, 2.91 net), Emerald Oil, Inc. (27 gross, 0.34 net), Murex Petroleum (2 gross, 0.13 net), Kodiak Oil & Gas Corp. (2 gross, 0.04 net) and Slawson Exploration Company, Inc. (1 gross, 0.01 net).  These wells produced an average of approximately 235 BOE/d net to the Company (91% oil and 9% natural gas and natural gas liquids) during the fourth quarter of 2014.

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 1.67%.

 

---

On May 27, 2014, the Company entered into a Purchase and Sale Agreement to sell its interest in approximately 285.70 net acres and 16 gross (0.62 net) producing wells in this acreage package for $12.2 million. The transaction closed in June 2014 with an effective date of January 1, 2014.  All remaining acreage is held by production and produced approximately 12 BOE/d net to the Company (84% oil and 16% natural gas and natural gas liquids) during the fourth quarter of 2014.

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.

Louisiana Properties

PetroQuest Energy, L.L.C.  The Company has an interest in one 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 2014, average daily production from this well was approximately 75 BOE/d net to the Company (100% natural gas).

Texas Petroleum Investment Company.  The Company has an interest in one producing well with Texas Petroleum Investment Company with a 25% WI (17.63% NRI).  During the fourth quarter of 2014, average daily production from this well was approximately one BOE/d net to the Company (100% oil).

Other Texas Properties

Southern Resources Company.  Our agreement with Southern Resources Company 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, 2014 we had one gross (0.14 net) producing well in this project.  No drilling is currently scheduled on these properties in 2015.  During 2014, average daily net production from this well was less than one BOE/d (20% oil and 80% natural gas and natural gas liquids).

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.

 

Daniels County, Montana Acreage

In 2010 through 2012, the Company acquired a working interest in approximately 30,332 gross (18,939 net) mineral 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.  Under the terms of the agreement, we retained a 12.5% working interest in the acreage and reserved overriding royalty interests ("ORRI") in leases with an 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 2015 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.

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 of claims and fee lands.  For further information, see "Item 2 – Properties – Molybdenum - Mt. Emmons Project" below.

Renewable Energy — Geothermal

At December 31, 2014 we owned a 19.54% interest in Standard Steam Trust ("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 2011, 2012, 2013 or 2014, which diluted our ownership.  In December 2013, we recorded an impairment charge of $2.2 million to write off the carrying amount of the investment in SST at December 31, 2013 to zero.

Item 1A - Risk Factors

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

 

Risks Involving Our Business

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 that even a combination of experience, knowledge and careful evaluation may not be able to overcome.  The cost and timing 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;

·	uncertainty regarding our operating partners' drilling schedules;

·	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;

---

·	adverse weather;

·	reductions in commodity prices;

·	pipeline ruptures; and

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

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 that impair or prevent production.  We may participate in wells that are or become unproductive or, though productive, do not produce in economic quantities.  In addition, even commercial wells can produce less, or have higher costs, than we projected.

In addition, initial 24-hour or other limited-duration production rates announced regarding our oil and gas properties are not necessarily indicative of future production rates.

Dry holes and other unsuccessful or uneconomic exploration, exploitation and development activities can adversely affect our cash flow, profitability and financial condition, and can adversely affect our reserves. To the extent we act 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. Conversely, our anticipated transition to an operated business model entails risks as well.  For example, the benefits of this transition may be less, or the costs may be greater, than we currently anticipate.  In addition, we may be subject to a greater risk of drilling dry holes or encountering other operational problems until our operating capabilities are more fully developed.  Similarly, we may incur liabilities as an operator that we have historically avoided through a non-operated business model.

Our business may be impacted by adverse commodity prices.

In the three years ended December 31, 2014, oil prices have ranged from a high of $110.62 per barrel during September 2013 to a low of $53.45 per barrel during December 2014.  Global markets, in reaction to general economic conditions and perceived impacts of future global supply, have caused large fluctuations in price, including an almost 50% decline in the price of oil that occurred over the second half of 2014.  Significant future price swings are likely.  Natural gas prices have also been volatile, reaching a ten year high during December 2005 on the Henry Hub of $15.39 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 can adversely affect many aspects of our business, including our financial condition, revenues, results of operations, cash flows, liquidity, reserves, 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.  For example, due to recent significant decreases in the price of oil, we have reduced our capital expenditure budget for 2015 to $8.2 million from $30.2 million in 2014.  The reduction in drilling activity will likely result in lower production and, together with lower realized oil prices, lower revenue and EBITDAX.  Declines in the prices we receive for our oil and natural gas can also adversely affect our ability to finance capital expenditures, make acquisitions, raise capital and satisfy our financial obligations.  In addition, declines in prices can reduce the amount of oil and natural gas that we can produce economically and the estimated future cash flow from that production and, as a result, adversely affect the quantity and present value of our proved reserves.  Among other things, a reduction in the amount or present value of our reserves can limit the capital available to us, as the maximum amount of available borrowing under our Credit Facility is, and the availability of other sources of capital likely will be, based to a significant degree on the estimated quantity and value of the 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, 2014 was $9.31 per pound, compared to $9.75 per pound at year end 2013.  Price improvement in 2015 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, our realized oil prices in the Williston Basin generally have been from $13.00 to $21.00 less per barrel than prices for other areas in the United States, and averaged approximately $17.00 less per barrel during the fourth quarter of 2014.  This discount, or differential, may widen in the future, which would reduce the price we receive for our production.  We may also be adversely affected by widening differentials in other areas of operation.

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. This makes it more likely that a downturn in oil prices will result in a ceiling limitation write-down of our Williston Basin oil and gas properties.  A widening of the differential would reduce the cash flow from our Williston Basin properties and adversely impact our ability to participate fully in drilling with Statoil, Zavanna and other operators and to effect our strategy of transitioning to an operated business model.   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 may require funding in addition to working capital during 2015.

We were able to maintain adequate working capital in 2014 primarily through borrowing under our Credit Facility and cash flow from operations.  Working capital at December 31, 2014 was negative $466,000, an amount insufficient to continue substantial exploration and development work on our oil and gas properties without additional borrowing under our Credit Facility or other funding.  In 2015, we have budgeted $8.2 million for work on existing oil and gas programs.

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 elects not to 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 continue to evaluate various options to obtain additional capital, including borrowings under our Credit Facility, sales of one or more producing or non-producing oil and gas assets and/or the issuance of equity.

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, and a reduction in cash available for investment in other programs.

---

·	We are paying the annual costs (approximately $1.7 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 our 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 at 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, the issuance of equity would be dilutive to existing shareholders.

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 also 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 Buda formation, 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 Buda formation and the Bakken, Three Forks and Eagle Ford shales in many cases 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 (as applicable to the formation) and being able to run tools and other equipment consistently through the horizontal well bore.

---

For wells that are hydraulically fractured, completion risks include, but are not limited to, being able to fracture stimulate the planned number of frac stages, 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.

Currently, the typical cost for drilling and completing a horizontal well is estimated at approximately $3.0 million to $4.0 million for wells targeting the Buda formation, $8.1 million to $10.1 million for wells in the Williston Basin, and $7.5 million for wells in the Eagle Ford, in each case on a gross basis.  Costs for any individual well will vary due to a variety of factors.  These wells are 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.

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 other midstream 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 and related services, we or our operating partners 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 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 report, all but one of our Williston Basin wells is selling gas.

Continued drilling in the Williston Basin and South Texas has placed additional demands on the capacity of the various gathering and intrastate or interstate transportation pipelines or rail tankers and other midstream facilities available in these areas, and increased production from us and others could exceed available capacity in some areas from time to time. If this occurs, it will be necessary for new rail takeaway lines, pipelines, gathering systems and/or other types of infrastructure to be built.  The availability of new or existing infrastructure or services depends on many factors outside of our control.  For example, well-publicized accidents involving trains carrying crude oil may lead to new regulations that limit the number of rail cars available to transport our production.  In addition, 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 sell our production for significantly lower prices or shut in our wells until a pipeline connection or rail capacity is available.  In the case of natural gas, we may have to flare the gas we produce or shut the well in.

---

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

We may not be able to participate in all or even a substantial portion of the many locations we have potentially available through our agreements with our partners.  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.  Significant recent declines in the price of oil may reduce the number of potential locations that we will ultimately drill.

Lower oil and natural gas prices may cause us to record ceiling test 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 (a charge often referred to as a "ceiling test 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 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, 2014, 2013 and 2012, which were not included in the amortized cost pool, were $12.5 million, $7.5 million and $9.2 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, 2014 and 2013, 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, 2014, we used $94.99 per barrel for oil and $4.35 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 the first quarter of 2013, capital costs for oil and gas properties exceeded the ceiling test limit and we recorded a ceiling test write-down of $5.8 million primarily due to a decline in the price of oil, additional capitalized well costs and changes in production. We recorded a similar write-down of $5.2 million in 2012.  We may be required to recognize additional ceiling test 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.

Recent declines in the price of oil have significantly increased the risk of a ceiling test write-down.  For example, we expect to use $82.72 per barrel for oil and $3.84 per MMbtu for natural gas to compute the ceiling test limit as of March 31, 2015.  Had these prices been used to compute the ceiling test limit as of December 31, 2014 and all other variables (including applicable differentials) remained unchanged, we would have incurred a ceiling test write-down of approximately $14 million.  Further, if we assume that the oil price is $50 per barrel for the remainder of 2015, the oil prices used in the ceiling test limit calculation would be approximately $70.06, $57.63 and $50.11 at June 30, 2015, September 30, 2015 and December 31, 2015, respectively.  Had these oil prices been used to compute the ceiling test limit as of December 31, 2014, we would have incurred ceiling test write-downs of approximately $31 million, $44 million and $51 million, respectively.

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 currently operate 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. Our ability to grow our production and reserves depends on decisions by our partners to drill wells in which we have an interest, and they may elect to reduce or suspend the drilling of those wells.

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 report represent estimates only.  Estimating quantities of, and future cash flows from, 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, 2014, 43% of our estimated proved reserves were producing, 1% were proved developed non-producing and 56% 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.  If prices as of December 31, 2014 were used to derive the estimated quantity and present value of our reserves, those estimates would have been significantly lower than those included in this report, which are based on a 12-month average price under applicable SEC rules.

Further, 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.

From time to time, we use derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk underlying our oil 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.

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 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. The risk that our leases may expire will generally increase when commodity prices fall, as lower prices may cause our operating partners to reduce the number of wells they drill. 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.

Our producing properties are primarily located in the Williston Basin and South Texas, making us vulnerable to risks associated with having operations concentrated in these geographic areas.

Because our operations are geographically concentrated in the Williston Basin and South Texas (94% of our production in the fourth quarter of 2014 was from these areas), the success and profitability of our operations may be disproportionally exposed to the effect of regional events. These include, among others, regulatory issues, natural disasters and 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.  Any 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. 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 services, infrastructure and equipment during months when drilling is possible and may result in periodic shortages. 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 than we do.  The following are some of the risks associated with acquisitions, including any completed or future acquisitions:

·	acquired properties may not produce revenues, reserves, earnings or cash flow at anticipated levels, or at all;

·	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 two areas, each of which presents potential liability exposure: oil and gas exploration and development and permitting and limited exploration of the Mt. Emmons molybdenum property.  We also have potential exposure to 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 properties to obtain and maintain liability insurance for our working interest in our oil and gas 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 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 Mt. Emmons project.  These policies provide coverage for bodily injury and property damage as well as costs to remediate events adversely impacting the environment.  See "Insurance" below.

We would be liable for claims in excess of coverage and for any deductible provided for in the relevant policy.  If uncovered liabilities are substantial, payment 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.

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.

---

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 to not move forward with the project.

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

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 otherwise without negligence on our part 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.

Federal, state and local legislation and regulations relating to hydraulic fracturing could result in increased costs, additional drilling and operating restrictions or delays in the production of natural gas and crude oil, and could prohibit hydraulic fracturing activities.

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 typically are created through the injection of water and chemicals into the rock formation.

Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the oil and natural gas industry in fracturing fluids under the Safe Drinking Water Act ("SDWA"), and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, the Emergency Planning and Community Right-to-Know Act ("EPCRA"), or other laws. Sponsors of these bills, which have been subject to various proceedings in the legislative process, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. In March 2011, the Environmental Protection Agency ("EPA") announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. EPA issued an initial report about the study in December 2012. The initial report described the focus of the continuing study but did not include any data concerning EPA's efforts to date, nor did it draw any conclusions about the safety of hydraulic fracturing. A draft report including data and conclusions is expected in 2015 and a final, peer-reviewed report is expected in 2016.

---

EPA also has begun a Toxic Substances Control Act ("TSCA") rulemaking which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors.  In addition, in January 2015, several national environmental advocacy groups filed a lawsuit requesting that EPA add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under EPCRA's Toxics Release Inventory (TRI) program. Concurrently, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.

EPA also finalized major new Clean Air Act standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells in August 2012 known as "Quad O." The standards require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions during hydraulically fractured natural gas well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators at gas well affected facilities. Following a legal challenge and several petitions for administrative reconsideration of the Quad O rules, EPA issued final amendments related to storage tanks, green completions, and other provisions of the rule in September 2013 and December 2014, respectively. Most key provisions in Quad O take effect in 2015. The rules associated with such standards are substantial and will likely increase future costs of our operations and will require us to make modifications to our operations or install new equipment.

EPA has also issued permitting guidance under the SDWA for the underground injection of liquids from hydraulically fractured (and other) wells where diesel is used. This guidance may create duplicative requirements, further slow down the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by EPA depending on how it is implemented. Certain other federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. Most notably, the U.S. Department of the Interior, through the Bureau of Land Management ("BLM"), is currently conducting a rulemaking that will require, among other things, disclosure of chemicals and more stringent well integrity measures associated with hydraulic fracturing operations on public land. BLM has not indicated when it will issue a final rule, but an Advanced Notice of Proposed Rulemaking is expected in Spring 2015. BLM also is expected to continue assessing the need for additional rules and regulations to address venting and flaring associated with oil and natural gas production on BLM land.

Currently, hydraulic fracturing is regulated primarily at the state level through permitting and other compliance requirements. For example, North Dakota, Montana, Texas, and Louisiana require disclosure of information concerning the chemicals used in hydraulic fracturing fluids. In Montana, disclosure of information about hydraulic fracturing fluids is on a well-by-well basis. Further, in Montana and Louisiana, operators must generally obtain approval from the state before hydraulic fracturing occurs and submit a report after the work is performed. Montana, Texas, and North Dakota also require specific construction and testing requirements for wells that will be hydraulically fractured. Certain state governments have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control requirements, disclosure, wastewater disposal, baseline sampling, well construction and well location requirements on hydraulic fracturing operations or otherwise seek to ban underground injection of fracturing wastewater or fracturing activities altogether. At the local level, some municipalities and local governments have adopted or are considering similar actions.

---

In addition, lawsuits have been filed against unrelated third parties in a number of states alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to natural gas and crude oil production activities using hydraulic fracturing techniques. Additional legislation, litigation, regulation, or moratoria could also lead to operational delays or lead us to incur increased operating costs in the production of crude oil and natural gas, including from the development of our shale plays, or could make it more difficult to perform hydraulic fracturing or other drilling activities. If these legislative, regulatory, litigation, and other initiatives cause a material decrease in the drilling of new wells and in related servicing activities, our profitability could be materially impacted.

Certain federal income tax deductions currently available with respect to crude oil and natural gas and exploration and development may be eliminated as a result of future legislation.

President Obama has made 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.

Climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

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 and release of fugitive emissions of natural gas could have a significant impact on our future operations. 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 has allowed 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. In June 2014, however, the United States Supreme Court invalidated a portion of EPA's GHG program in the case Utility Air Regulatory Group v. EPA. Specifically, under the Supreme Court's UARG opinion, sources that are subject to the federal Title V and/or the Prevention of Significant Deterioration ("PSD") programs because of emissions of non-GHG pollutants may still be subject to GHG permitting, including requirements to install Best Available Control Technology ("BACT"). Sources that would be subject to Title V or PSD because of GHG emissions only, however, are no longer subject to GHG permitting requirements, including GHG BACT requirements. Upon remand, EPA currently is considering how to implement the Court's decision.

The U.S. Congress also 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. Similarly, President Obama has indicated that climate change and GHG regulation is a significant priority for his second term. The President issued a Climate Action Plan in June 2013 that, among other things, calls for a reduction in methane emissions from the oil and gas sector. In Spring 2014, EPA issued five "Methane White Papers" exploring methane emissions from, and possible controls for, various aspects of the oil and natural gas production process. As noted above, building on these white papers, in January 2015, EPA announced a comprehensive strategy to further reduce methane emissions

 

---

from the U.S. oil and gas industry, which will likely include some additional mandatory requirements, including potentially leak detection and repair obligations, controls for hydraulically fractured oil wells, as well as other control, monitoring, and recordkeeping requirements applicable to a variety of oil and gas facility processes and associated equipment.

In November 2013, the President released an Executive Order charging various federal agencies, including EPA, with devising and pursuing strategies to improve the country's preparedness and resilience to climate change.  In part through these executive actions, the direct regulation of methane emissions from the oil and gas sector continues to be a focus of regulation. 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.

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 can be 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 and Texas.  During periods of high oil and gas prices, the demand for drilling rigs and equipment tends to increase along with increased activity levels, and this may result in shortages of equipment.  Higher oil and natural gas prices generally stimulate increased demand for equipment and services and subsequently often result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel in 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 activities that we currently have planned and budgeted, causing us to miss our forecasts and projections.

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 deposit contains 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.

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 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 fee property, associated ancillary activities will occur on USFS land.  The Company submitted a full mine plan of operations to the USFS in part to satisfy the requirements of the conditional water rights decree on October 10, 2012.  The USFS has notified us that it will prepare an environmental analysis under the procedures mandated by NEPA 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 on 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 treating water flowing from the historic Keystone Mine workings and for stormwater discharges associated with the Mt. Emmons Project, but this project is not related to the proposed mining activities.

In addition, the Colorado Division of Reclamation, Mining and Safety ("DRMS") 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 likely to be 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.

In July 2009, the EPA announced that it will develop financial assurance requirements under CERCLA § 108(b) for the hardrock mining industry, specifically including molybdenum mining.  EPA expects to publish its proposed financial responsibility regulations in 2016.  EPA's notice did not indicate what the anticipated scope of these requirements will be, or whether they will be duplicative of existing bonding and other financial assurance requirements applicable to the hardrock mining industry.  However, the promulgation of regulations that require significant additional financial assurance could adversely impact the economic viability of the Mt. Emmons project.

We depend on key personnel.

Our employees have experience in dealing with the acquisition of and financing of oil and gas as well as mineral properties, but we have a limited technical staff.  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 common stock, warrants and convertible debt to investors in private placements and public offerings.  These transactions caused dilution to existing shareholders.  Also, from time to time, we issue options and warrants to employees, directors and third parties as incentives, with exercise prices equal to the market price at the date of issuance.  Exercise of 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.  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, 2014, the stock has traded as high as $5.00 per share and as low as $1.17 per share. The principal factors which have contributed and/or in the future could contribute to this volatility include:

·	price volatility 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, and oil and natural gas prices have declined significantly. 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.

Item 2 – Properties

Oil and Natural Gas

The following table sets forth our net proved reserves as of the dates indicated.  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 reserve engineers.

Our reserve estimates as of December 31, 2014, 2013 and 2012 are based on reserve reports prepared by Cawley, Gillespie & Associates, Inc., or CGA.  CGA is a nationally recognized independent petroleum engineering firm and 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).  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.  A copy of CGA's report is filed as an exhibit to this report.

---

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

		December 31,
		2014		2013		2012
Net proved reserves
Oil (Bbls)
Developed		1,754,668		1,875,528		1,770,659
Undeveloped		2,365,069		1,584,187		842,984
Total		4,119,737		3,459,715		2,613,643
Natural gas (Mcf)
Developed		1,892,446		1,701,282		1,420,295
Undeveloped		1,318,801		670,628		377,791
Total		3,211,247		2,371,910		1,798,086
Total proved reserves (BOE)		4,654,944		3,855,033		2,913,324

 

(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, 2014 are based on prices of $94.99 per barrel of oil and $4.35 per MMbtu of natural gas, in each case adjusted for regional price differentials and other factors.

As of December 31, 2014, our proved reserves totaled 4,654,944 BOE (44% developed and 56% undeveloped), comprised of 4,119,737 Bbls of oil (89% of the total) and 3,211,247 Mcf of natural gas (11% 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.

We maintain an effective system of internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based.  The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data.  All field and reservoir technical information is assessed for validity when meetings are held with management, land personnel and third party operators to discuss field performance and to validate future development plans.  Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and their own set of internal controls over financial reporting.  All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete.  Our current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated into the reserve database as well and verified

 

---

to ensure their accuracy and completeness.  Our reserve database is maintained by CGA.  CGA works with our personnel to review field performance, future development plans, current revenues and expense information.  Following these reviews, the reserve database and supporting data is updated so that CGA can prepare its independent reserve estimates and final report.

As of December 31, 2014, we had 2,584,869 BOE (91% oil and 9% natural gas) of proved undeveloped reserves, which is an increase of 888,911 BOE, or 52%, compared with 1,695,958 BOE of proved undeveloped reserves at December 31, 2013.  This increase was primarily due to increased density in the Bakken formation in North Dakota.  Due to lower oil prices, drilling activity in North Dakota has slowed.  However, this slowdown has resulted in increased competition among drilling and completion services companies and lower drilling and completion costs.  In addition, there has been an overall longer term trend of lower drilling and completion costs; since 2012, drilling and completion costs for horizontal wells on our properties in the Williston Basin have dropped from approximately $11.5 million to a range of approximately $8.1 to $10.1 million.  Our development plan contemplates an increase in Bakken drilling after 2015 as a result of reduced costs and commodity prices moving closer to forward strip prices.

We invested approximately $8.3 million to convert 381,187 BOE of proved undeveloped reserves to proved developed reserves in 2014 (representing 22.5% of our beginning of year proved undeveloped reserves).  The following table details the changes in the quantity of proved undeveloped reserves during the year ended December 31, 2014:

As of December 31, 2014, 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 initial booking.  As of December 31, 2014, estimated future development costs relating to proved undeveloped reserves are projected to be approximately $70.8 million over the next five years.

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 report.  The information set forth below is not necessarily indicative of future results.

---

⁽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.

---

The following table provides a regional summary of our production for the years ended December 31, 2014, 2013 and 2012:

---

The following table sets forth information with respect to development and exploration wells we completed from January 1, 2012 through December 31, 2014.  The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells.

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."

The following table details our working interests in producing wells as of December 31, 2014.  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			135.00				19.85				14.70	%
Natural Gas			1.00				0.17				17.00	%
Total (1)			136.00				20.02				14.72	%

(1)	The average working interest for the ninety-nine Williston Basin wells producing at December 31, 2014 is 10.4%; the remaining thirty-seven wells (in Texas and Louisiana) have an average working interest of 26.3%.

---

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

The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2014.

---

 

As a non-operator, we are subject to lease expiration if the 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 test or 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 2015 and 2018 are set forth below:

As of March 5, 2015, five gross (0.02 net) wells 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.

 

---

---

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 BLM; the total amount paid for mining and millsite claim maintenance fees in 2014 was $214,000.

The breakdown of the property is as follows:

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 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.

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 BLM 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 also are 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 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, 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.

In December 2008, an additional 160 acres of fee land in the vicinity of the claims was purchased by the Company and Thompson Creek Metals Company USA ("Thompson Creek" or "TCM") for $4 million ($2 million in January 2009, $400,000 annually for five years).  On January 21, 2014, the Company purchased TCM's interest in the property for $1.2 million.

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 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.

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 currently plans to use the mine water treatment plant in the milling operations for the Mt. Emmons Project.  We also are investigating reclamation strategies that may be used to reduce the quantity of discharge water and improve the quality of treated water and stormwater subject to permit-related requirements.

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.  The existing permit is under administrative extension awaiting renewal.  Modifications and improvements to the treatment system were tested and implemented in 2012 and 2013.  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 required ongoing monitoring of stormwater discharges and the reporting of

 

---

monitoring results to the CDPHE.  In 2013, we commenced a more comprehensive study of natural and human-induced conditions in the region that may be affecting water quality in Coal Creek.  Those efforts continued in 2014, and will continue through 2015.

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 $1.7 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.

On October 10, 2012, the Company submitted a full mine plan of operations to the USFS to satisfy the requirements of the conditional water rights decree.  In 2014, we submitted a Plan of Operations to the USFS related to hydrology data collection from areas of proposed activity in proximity to the proposed project infrastructure sites.  This Plan of Operations includes field work such as borings, test pits and ground water monitoring wells.  The USFS will have to review the Plan of Operations and follow the NEPA process before approval will be given.  Field work is expected to commence following approval by the USFS and providing weather allows access to the field sites.

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.

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 for molybdenum averaged $11.60 in 2014, compared to $10.40 in 2013.

---

Real Estate

Remington Village Sale

We previously owned Remington Village, a nine-building multifamily apartment complex with 216 units on 10.015 acres in Gillette, Wyoming. On September 11, 2013, the Company, through its wholly owned subsidiary Remington Village LLC, completed the sale of Remington Village to an affiliate of the Miller Frishman Group, LLC for $15.0 million.  The $9.5 million balance on the commercial note due on Remington Village was paid in full at closing.  After deduction of payment of the note, commission and other closing costs, net proceeds to the Company were approximately $5.0 million.  The proceeds were allocated to the Company's oil and gas business, reduction of debt and general corporate purposes.

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 one unrelated vacant lot covering approximately 9.41 acres in Fremont County, Wyoming.  We intend to sell these properties without development. However, there can be no assurance that sales of any of these properties will be completed on the terms, or in the time frame, we expect or at all.

Corporate Aircraft and Related Facilities Sale

On January 10, 2013, the Company sold its corporate aircraft for $1.9 million and related facilities for $767,000.  The proceeds were allocated to our oil and gas business and general corporate purposes.

Sold Uranium Properties – Possible Future Revenues

In 2007, we sold all of our uranium assets for cash and stock of the purchaser, Uranium One Inc. ("Uranium One").  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 Uranium One:

·	$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.

---

On August 14, 2014, conditioned upon the closing of a purchase and sale transaction between Anfield Resources Inc. ("Anfield") and Uranium One, the Company agreed to release Anfield from the future payment and royalty obligations stemming from the Company's 2007 sale of its uranium properties to Uranium One as described above.  In return, Anfield has agreed to pay the Company the following:

1.	$2.5 million in Anfield common shares upon closing of the transactions contemplated by the asset purchase agreement between Anfield and Uranium One.  The shares will be held in escrow and released in tranches over a 36 month period,

2.	$2.5 million in cash paid upon 18 months of continuous commercial production, and

3.	$2.5 million in cash paid upon 36 months of continuous commercial production.

Should Anfield be unsuccessful in closing the purchase and sale transaction with Uranium One, the original payment and royalty obligations will remain unchanged.

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

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

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, 2014.

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 and 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 also is possible that unanticipated developments or changes in the law could require us to make environmental expenditures significantly greater than those we currently expect.  See "Federal, state and local legislation and regulations relating to hydraulic fracturing could result in increased costs, additional drilling and operating restrictions or delays in the production of natural gas and crude oil, and could prohibit hydraulic fracturing activities" and "Climate change legislation or regulations restricting emissions of 'greenhouse gases' could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce" in "Risk Factors" for a discussion of certain regulatory developments that may have an adverse effect on us.

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 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 may impose more stringent requirements when the permit is renewed (the prior permit expired as of August 31, 2013, and the CDPHE administratively extended the permit, including all existing discharge limitations, pending renewal).  In addition, we will continue monitoring activities at and surrounding the Mt. Emmons Project in 2015 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. We also are investigating reclamation strategies that may be used to reduce the quantity of discharge water and improve the quality of treated water and stormwater subject to permit-related requirements.  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.

---

Although all of our currently producing oil and gas properties are currently 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 our operations, close and cover disposal pits, and plug abandoned wells.  Violations by the operator could result in substantial liabilities for which we could be responsible. Based on the current regulatory environment in those states in which 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.

Oil and gas operations also are subject to various federal, state and local regulations governing oil and natural gas production and state limits on allowable rates of production by well.  These regulations may affect the amount of oil and natural gas 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 oil and natural gas, protect groundwater resources, protect rights to produce oil and natural gas 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, regulatory agencies and legislative bodies make various proposals 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.

Wells in the Bakken and Three Forks formations in North Dakota produce natural gas as well as crude oil. Constraints in the current gas gathering network in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. The North Dakota Industrial Commission, the State's chief energy regulator, recently issued an order to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. In addition, the Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals.

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:

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.

---

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.

Employees

As of December 31, 2014, we had 14 full-time employees.

Item 3 – Legal Proceedings

Material legal proceedings pending at December 31, 2014 and developments in those proceedings from that date to the date of this Annual Report are summarized below.

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") required 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 occurred 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 a 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 USFS regulations and did not satisfy certain "reality check" limitations contained in the Decree.  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 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.  We have settled with every Opposer except Crested Butte Land Trust.  The claims of Crested Butte land Trust have been referred to the Colorado Water Court for further proceedings.

---

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 with respect to the undistributed suspended royalty 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 suspended payment of certain royalty proceeds of production related to the minerals in and under this property pending resolution of the apparent dispute.  Energy One owns a working interest, not royalty interest, in this well so no funds owed to Energy One have been withheld.

On January 28, 2013, the District Court Northwest Judicial District issued an Order for Partial Summary Judgment holding that the State of North Dakota as part of its title to the beds of navigable waterways owns the minerals in the area between the ordinary high and low watermarks on these waterways, and that this public title excludes ownership and any proprietary interest by riparian landowners.  This issue has been appealed to the North Dakota Supreme Court.  Energy One's legal position is aligned with Brigham, who will continue to provide legal counsel in this case for the benefit of all working interest owners.

On October 4, 2013, Dimmit Wood Properties, Ltd. ("Dimmit") filed a Quiet Title Action against Chesapeake Exploration, LLC ("Chesapeake"), Crimson Exploration Operating, Inc. ("Crimson"), EXCO Operating Company, LP, OOGC America, Inc., Energy One and Liberty Energy, LLC ("Liberty") (jointly referred to as "Defendants") concerning an 800.77 gross acre oil and gas lease ("Lease") located in Dimmit County, Texas.  Crimson, Energy One and Liberty received an assignment from Chesapeake of the Lease, in which Energy One has a 30% working interest.  Dimmit alleges that the Lease has terminated due to the failure to achieve production in paying quantities.  On October 28, 2013, the Defendants filed an answer, asserting that production in paying quantities was achieved in the primary term of the Lease with an existing producing well and that the Lease has remained in good standing and has not terminated.  The Defendants also filed Counterclaims against Dimmit, including but not limited to breach of contract.  No new wells have been drilled by the Defendants on the Lease.  Crimson, Energy One and Liberty filed a declaratory judgment action in the District Court of Dimmit County in 2014 regarding similar allegations relating to a lease on adjacent acreage that was also assigned to those parties by Chesapeake.  The lessors in that case are Dr. Darrell Willerson, Sue Willerson and Willerson Energy Partners, L.P.  Crimson, Energy One and Liberty are seeking a determination from the court that the lease remains valid and in effect.

---

PART II

Item 5 - Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases 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:

Holders

At March 5, 2015 the closing market price was $1.34 per share.  On that date, there were approximately 908 shareholders of record, with 28,388,372 shares of common stock issued and outstanding.

Dividends

We did not declare or pay any cash dividends on common stock during fiscal years 2014 and 2013 and do not intend to declare any cash dividends in the foreseeable future.  Our ability to pay dividends in the future is subject to limitations under state law and the terms of the Credit Facility, which restricts the ability of Energy One to pay dividends to the Company.

Issuance of Securities in 2014

During 2014, we issued a total of 311,783 shares of common stock.  These issuances were comprised of 141,721 shares issued pursuant to the terms of our ESOP, 151,939 shares issued pursuant to the 2001 Incentive Stock Option Plan, 6,011 shares issued pursuant to the 2012 Equity and Performance Incentive Plan and 12,112 shares issued pursuant to the 2008 Stock Option Plan for U.S. Energy Corp. Independent Directors and Advisory Board Members.  The ESOP funding represents the minimum required amount during 2014.

---

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, 2014, 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 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

---

ITEM 6. SELECTED FINANCIAL DATA

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

---

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 changes in commodity prices, political or regulatory events, and other matters, including as discussed below.  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

We are 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 South Texas and the Williston Basin in North Dakota.  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, 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.  As discussed in Item 1. Business, we are in the process of developing operational capabilities and expect to pursue opportunities to acquire operated properties and/or operatorship of existing properties.

We are also involved in the exploration for and development of minerals (molybdenum) through our ownership of the Mt. Emmons Project in Colorado.

Our carrying capitalized dollar amounts in each of these areas at December 31, 2014 and December 31, 2013 were as follows:

---

Oil & Gas Activities

In 2014, we had the following financial and operational results:

Revenue.  In 2014, we recognized revenues from oil and natural gas production of $32.4 million as compared to $33.6 million during the year ended December 31, 2013.

Reserves.  At December 31, 2014, our proved reserves were 4,654,944 BOE as compared to 3,855,033 BOE at December 31, 2013.  The following table details our proved reserves by state for the years ended December 31, 2014 and 2013:

Production.  Our 2014 annual production was 465,342 BOE, or 1,275 BOE/d, as compared to 424,933 BOE, or 1,164 BOE/d, in 2013.

---

Financial flexibility.  Our Credit Facility has a maximum loan amount of $100.0 million, a current borrowing base of $24.5 million and a maturity date of July 30, 2017.  At December 31, 2014, we had $6.0 million outstanding under the Credit Facility.  See "Capital Resources – Wells Fargo Senior Credit Facility" below.

Commodity prices.  Our average realized oil price in 2014 was $85.89 per Bbl (excluding the impact of our economic hedges), $4.92 lower than the 2013 price of $90.81.  Our average natural gas price realized during 2014 was $4.72 per Mcf, $0.06 per Mcf higher than the 2013 price of $4.66.  Commodity prices are affected by changes in market demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors.  Our financial results are significantly dependent on commodity prices, particularly oil prices, which are beyond our control and have been and are expected to remain volatile.  In addition, recent declines in the price of oil have significantly increased the risk of a ceiling test write-down.

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.  The ultimate effect on our business of rules adopted under the Dodd-Frank Act 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 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 may vary over time depending on the terms of the relevant agreement), but typically ranges from approximately 1% to 48%.  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, 2014 and 2013.

---

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

Rough Rider Prospect.  We participate in fifteen 1,280 acre drilling units in the Rough Rider prospect with Statoil Oil & Gas, L.P. ("Statoil").  From August 24, 2009 to December 31, 2014, we have drilled and completed 24 gross (6.39 net) Bakken formation wells and two gross (0.22 net) Three Forks formation wells under the DPA with Statoil.

During the year ended December 31, 2014, we drilled and completed three gross (0.14 net) Bakken formation wells in the Rough Rider prospect.  Our net investment in the Rough Rider prospect wells was $1.3 million for the year ended December 31, 2014.  Statoil operates all of the wells.

Yellowstone and SEHR Prospects.  We participate in twenty-eight gross 1,280 acre spacing units in the Yellowstone and SEHR prospects with Zavanna, LLC ("Zavanna").  Through December 31, 2014, we have drilled and completed 42 gross (3.10 net) Bakken formation wells and eight gross (0.33 net) Three Forks formation wells in these prospects.  The wells are operated by Zavanna (18 gross, 2.91 net), Emerald Oil, Inc. (27 gross, 0.34 net), Murex Petroleum (2 gross, 0.13 net), Kodiak Oil & Gas Corp. (2 gross, 0.04 net) and Slawson Exploration Company, Inc. (1 gross, 0.01 net).  During the year ended December 31, 2014, we completed 15 gross (0.17 net) wells in the Yellowstone and SEHR prospects.  At December 31, 2014, three additional gross (0.02 net) wells had been spud and were in progress.

Our net investment in the Yellowstone and SEHR prospect wells was $1.8 million during the year ended December 31, 2014.

Bakken/Three Forks Asset Package.  In 2012, we acquired approximately 400 net acres in 23 drilling units in McKenzie, Williams and Mountrail Counties of North Dakota.  In June 2014, we sold our interest in eight of these 23 drilling units (approximately 285.7 net acres) for $12.2 million.  At December 31, 2014, there were 23 gross (0.24 net) producing wells in the remaining 15 drilling units.

---

During the year ended December 31, 2014, our net investment in wells under the remaining drilling units in this program was $84,000.

Booth-Tortuga and Leona River Prospects.  We participate in the Booth-Tortuga and Leona River prospects with Contango Oil & Gas Company ("Contango").  At December 31, 2014, we have 30 gross (8.23 net) producing wells in these prospects, comprised of 16 gross (4.35 net) Buda limestone wells, three gross (0.90 net) Eagle Ford Shale wells and 11 gross (2.98 net) Austin Chalk wells.  During the year ended December 31, 2014, we drilled and completed ten gross (3.0 net) Buda limestone wells in the Booth-Tortuga prospect.  During 2014, one additional well (0.30 net) was drilled as a vertical pilot well to evaluate the Eagle Ford formation.  The wells are operated by Contango (28 gross, 8.08 net) and WCS Oil & Gas Corporation (2 gross, 0.15 net).  Our net investment in these wells during the year ended December 31, 2014, including lease acquisition costs in the prospects, was $12.3 million.

Big Wells Prospect.   We participate in the Big Wells prospect with U.S. Enercorp.  At December 31, 2014, we have two gross (0.30 net) producing Buda limestone wells in this prospect.  During the year ended December 31, 2014, we drilled and completed one gross (0.15 net) well in the Big Wells prospect.  Our net investment in this well during the year ended December 31, 2014 was $827,000.

Carrizo Creek and South McKnight Prospects.  In May 2014, the Company acquired 33.3% of U.S. Enercorp's interest in approximately 12,100 gross (3,384 net) acres in Dimmit County, Texas.  The acreage consists of 4,020 gross (1,181 net) acres of primary leasehold acreage and 8,080 gross (2,203 net) acres of farm-in acreage, to be earned through a continuous drilling program.  The farm-in acreage had an initial two well commitment and a 12.5% working interest carry for the leaseholder (the "Farmor") in the first 10 wells. After 100% payout of all costs for the first 10 wells that are drilled under the farm-in program, the Farmor will back in for its 12.5% retained working interest in the prospect. U.S. Enercorp retained a 25% working interest back-in after 115% of project payout has been received by the Company. The Company paid $3.9 million to enter into the transaction, which included leasehold and farm-in acquisition costs as well as our proportionate share of drilling costs for the initial test well in the prospect.

Two gross (0.67 net) wells were drilled and completed on the acquired acreage during the year ended December 31, 2014.  One additional well (0.33 net) was in progress at December 31, 2014.  Our net investment in this acreage and wells through December 31, 2014 was $10.0 million.

We participate with three different operators in the onshore U.S. Gulf Coast area.  At December 31, 2014, we had three gross (0.56 net) producing wells in this region.  Our net investment in Gulf Coast wells and properties was $130,000 during the year ended December 31, 2014.

---

The following table provides a regional summary of our production during the year ended December 31, 2014:

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, 2014 was $21.9 million.

Geothermal.  We own a 19.54% interest in SST, a geothermal limited partnership.  In 2013, we recorded an equity loss from SST in 2013 of $104,000.  Based on historical losses, lack of current marketability of the properties and current market conditions, management determined that the Company's investment in SST was impaired as of December 31, 2013.  As a result, the Company recorded an impairment charge of $2.2 million to write off the carrying amount of the investment in SST at December 31, 2013, to zero.  We have notified SST that we do not intend to fund any cash calls, which will result in a dilution of our ownership in SST if future cash calls are made.

---

Comparative Data

The following table provides information regarding selected production and financial information for the quarter ended December 31, 2014 and the immediately preceding three quarters.

During the three months ended December 31, 2014, we recorded a net loss after taxes of $2.3 million, or $0.08 per share basic and diluted, as compared to a net loss after taxes of $1.2 million, or $0.04 per share basic and diluted, during the same period of 2013.

Oil and Gas Operations.   Oil and gas operations generated an operating loss of $1.2 million during the quarter ended December 31, 2014 as compared to operating income of $3.3 million during the quarter ended December 31, 2013.  The following table summarizes production volumes, average sales prices and operating revenues for the three months ended December 31, 2014 and 2013:

---

During the three months ended December 31, 2014, we produced 101,265 BOE, or an average of 1,101 BOE/d, as compared to 123,246 BOE and 1,340 BOE/d during the three months ended December 31, 2013.  In our South Texas region, production decreased 21%, from 40,010 BOE to 31,565 BOE, between the two periods as a result of production declines in our Buda limestone drilling program.  Production in our Bakken region decreased 17%, from 75,146 BOE to 62,663 BOE, between the two periods as a result of normal production declines and lower working interests in wells drilled in this region.  We expect these regional production trends to continue.  Portions of our natural gas production are sent to gas processing plants to extract from the gas various natural gas liquids ("NGLs") that are sold separately from the remaining natural gas. We sell some of our gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGLs and the remaining natural gas. In the table above, our share of processing costs is classified as oil and gas production expense.

We recognized $5.1 million in revenues during the three months ended December 31, 2014 as compared to $9.3 million during the same period of the prior year.  The $4.2 million decrease in revenue is primarily due to lower realized oil prices and lower oil sales volumes in the three months ended December 31, 2014 when compared to the same period in 2013.  Lower production volumes are primarily due to declines in production from both Bakken and Buda formation wells.

---

Our average net realized price (operating revenue per BOE) for the three months ended December 31, 2014 was $50.04 per BOE compared with $75.22 for the same period in 2013.  The decrease in our equivalent realized price for production corresponds with lower average oil and natural gas prices in 2014 when compared with the same period in 2013.  Due to takeaway constraints, the discount, or differential, for oil prices in the Williston Basin ranged from $15.00 to $19.00 per barrel during the fourth quarter of 2014.  Until additional takeaway capacity is available, we expect this differential to continue (with the amount of the differential varying over time) and that our oil sales revenue will be affected by lower realized prices.

Oil and gas production expense of $2.6 million for the three months ended December 31, 2014 was comprised of $2.3 million in lease operating expense and $307,000 in workover expense.  The $1.2 million increase in total oil and gas production expense in the three months ended December 31, 2014 as compared to the same period in 2013 results from of an increase in lease operating expense of $1.0 million and an increase in workover expense of $192,000.

Our depletion, depreciation and amortization (DD&A) rate for the three months ended December 31, 2014 was $31.47 per BOE compared to $30.38 per BOE for the same period in 2013.  Our DD&A rate can fluctuate as a result of changes in drilling and completion costs, impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.

Mt. Emmons and Water Treatment Plant Operations.  We recorded $475,000 in costs and expenses for the water treatment plant and $166,000 for holding costs for the Mt. Emmons molybdenum property during the three months ended December 31, 2014.  During the three months ended December 31, 2013, we recorded $603,000 in operating costs related to the water treatment plant and $294,000 in holding costs.

General and Administrative.  General and administrative expenses decreased by $286,000 during the three months ended December 31, 2014 as compared to general and administrative expenses for the three months ended December 31, 2013.  Lower general and administrative costs in 2014 are primarily a result of decreases of $249,000  in compensation expenses, $103,000 in professional services and $28,000 in insurance costs.  The decreases were partially offset by increases of $66,000 in contract services and $30,000 in director fees and related options expense.

Other Income and Expenses.  We recognized an unrealized and realized derivative gain of $829,000 in the fourth quarter of 2014 compared to a gain of $255,000 for the same period in 2013.  The 2014 amount includes a loss on unrealized changes in the fair value of our commodity derivative contracts of $103,000 and a realized cash settlement gain on derivatives of $932,000.

Gain on the sale of assets increased to $84,000 during the quarter ended December 31, 2014 compared to $31,000 during the quarter ended December 31, 2013.

During the three months ended December 31, 2013, we recorded an equity loss of $64,000 from our unconsolidated investment in SST.  Additionally, at December 31, 2013, the Company recorded an impairment loss of $2.2 million to fully impair its investment in SST.  Subsequently, we no longer record our share of equity in earnings or losses of SST and recorded no equity income or losses related to SST in 2014.

Interest income was $1,000 and $4,000 during the quarters ended December 31, 2014 and 2013, respectively.

---

Interest expense decreased to $71,000 during the quarter ended December 31, 2014 from $89,000 during the quarter ended December 31, 2013.

Discontinued Operations.  During the three months ended December 31, 2013, we recorded a loss of $3,000, net of taxes, from Remington Village.  We sold this property in 2013 and had no income or losses from discontinued operations during the three months ended December 31, 2014.

During the year ended December 31, 2014, we recorded a net loss after taxes of $2.1 million, or $0.08 per share basic and diluted, as compared to a net loss after taxes of $7.4 million, or $0.27 per share basic and diluted, during 2013.

Oil and Gas Operations.   Oil and gas operations generated operating income of $7.1 million during the year ended December 31, 2014 as compared to operating income of $9.6 million during the year ended December 31, 2013, excluding a $5.8 million non-cash impairment charge taken on our oil and gas properties during the year ended December 31, 2013.  The following table summarizes production volumes, average sales prices and operating revenues for the year ended December 31, 2014 and 2013:

---

During the year ended December 31, 2014, we produced 465,342 BOE, or an average of 1,275 BOE/day.  In our South Texas region, production increased 148%, from 76,773 BOE to 190,760 BOE, between the two periods as a result of our Buda limestone drilling program.  Due to lower oil prices which has resulted in a slower pace of drilling in this region, we currently do not expect this regional production trend to continue; as discussed above, production from this region declined in the fourth quarter of 2014 relative to the same period of the prior year.  Production in our Bakken region decreased 22%, from 314,707 BOE to 245,116 BOE, between the two periods as a result of normal production declines and lower working interests in wells drilled in this region.  Due to normal production declines, we expect this regional production trend to continue.  Portions of our natural gas production are sent to gas processing plants to extract from the gas various natural gas liquids ("NGLs") that are sold separately from the remaining natural gas. We sell some of our gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGLs and the remaining natural gas. In the table above, our share of processing costs is classified as oil and gas production expense.

We recognized $32.4 million in revenues during the year ended December 31, 2014 as compared to $33.6 million during the same period in 2013.  The $1.2 million decrease in revenue is primarily due to lower oil sales volumes and lower average oil prices in 2014 as compared to 2013.

Our average net realized price (operating revenue per BOE) for the year ended December 31, 2014 was $69.58 per BOE compared with $79.18 per BOE for the same period in 2013.  Due to takeaway constraints, the discount to West Texas Intermediate ("WTI") quoted prices, or differential, for oil prices in the Williston Basin ranged from $13.00 to $21.00 per barrel during 2014.  Until additional takeaway capacity is available, we expect this differential to continue (with the amount of the differential varying over time) and that our oil sales revenue will be affected by lower realized prices from this region.

Oil and gas production expense of $7.9 million for the year ended December 31, 2014 was comprised of $7.2 million in lease operating expense and $675,000 in workover expense.  The $750,000 increase in total oil and gas production expense in the year ended December 31, 2014 as compared to the same period in 2013 results from of an increase in lease operating expense of $558,000 and an increase in workover expense of $192,000 and is primarily due to an increase in the number of producing wells in 2014 as compared to 2013.

Our depletion, depreciation and amortization (DD&A) rate for the year ended December 31, 2014 was $31.56 per BOE compared to $32.06 per BOE for the same period in 2013.  Our DD&A rate can fluctuate as a result of changes in drilling and completion costs, impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.

Mt. Emmons and Water Treatment Plant Operations.  We recorded $1.9 million in costs and expenses for the water treatment plant and $1.1 million for holding costs for the Mt. Emmons molybdenum property during the year ended December 31, 2014.  During the year ended December 31, 2013, we recorded $1.8 million in operating costs related to the water treatment plant and $1.2 million in holding costs.

General and Administrative Expenses.  General and administrative expenses increased by $1.0 million during the year ended December 31, 2014 compared to general and administrative expenses for the year ended December 31, 2013.  The increase in general and administrative costs in 2014 is primarily a result of a $200,000 severance payment made to the General Counsel upon his retirement, $500,000 in non-cash accretion expense related to the acceleration of the Chief Operating Officer's executive retirement benefit upon announcement of his plan to retire at the end of 2014, and increases of $295,000

 

---

in professional services and $74,000 in director fees and related options expense. The following table details the changes in the Company's general and administrative costs for the year ended December 31, 2014 compared to the year ended December 31, 2013: