US ENERGY CORP - Quarter Report: 2016 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

Commission File Number 000-6814

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES þ NO ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES þ NO ¨

Indicate by check mark 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.

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

The registrant had 28,233,068 shares of its $0.01 par value common stock outstanding as of May 12, 2016.

TABLE OF CONTENTS

Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

U.S. ENERGY CORP. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share and Per Share Amounts)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

U.S. ENERGY CORP. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2016 AND 2015

(In Thousands, Except Share and Per Share Amounts)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

U.S. ENERGY CORP. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2016

(In Thousands, Except Share Amounts)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements

U.S. ENERGY CORP. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 2016 AND 2015

(In Thousands)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

1.        ORGANIZATION, OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Organization and Operations

U.S. Energy Corp. (collectively with its subsidiaries referred to as the “Company” or “U.S. Energy”) was incorporated in the State of Wyoming on January 26, 1966. The Company’s principal business activities are focused in the acquisition, exploration and development of oil and gas properties in the United States.

Basis of Presentation.

The accompanying unaudited condensed consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles (“GAAP”) and have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) regarding interim financial reporting. Accordingly, certain information and footnote disclosures required by GAAP for complete financial statements have been condensed or omitted in accordance with such rules and regulations. In the opinion of management, all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation of the consolidated financial statements have been included.

For further information, refer to the consolidated financial statements and footnotes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015. Our financial condition as of March 31, 2016, and operating results for the three months ended March 31, 2016 are not necessarily indicative of the financial condition and results of operations that may be expected for any future interim period or for the year ending December 31, 2016.

As discussed in Note 5, during the fourth quarter of 2015 the Company began accounting for its mining operations as a Discontinued Operation. Accordingly, certain reclassifications have been made to the prior period balances in order to conform to the current period presentation. These and other reclassifications had no impact on working capital, net loss, shareholders’ equity or cash flows as previously reported.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include oil and gas reserves that are used in the calculation of depreciation, depletion, amortization and impairment of the carrying value of evaluated oil and gas properties; production and commodity price estimates used to record accrued oil and gas sales receivable; valuation of commodity derivative instruments; the impact of commodity prices and other events affecting impairment of mining properties; and the cost of future asset retirement obligations. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable. Due to inherent uncertainties, including the future prices of oil and gas, these estimates could change in the near term and such changes could be material.

Principles of Consolidation

The accompanying financial statements include the accounts of the Company and its wholly owned subsidiaries Energy One, LLC (“Energy One”), Highlands Ranch LLC (“Highlands Ranch”) and Remington Village, LLC (“Remington Village”). All inter-company balances and transactions have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform to the current period presentation of the accompanying financial statements.

Comprehensive Income (Loss)

Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders’ equity instead of net income (loss). Net loss was the only component of comprehensive income (loss) for the three months ended March 31, 2016 and 2015.

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

Recent Accounting Pronouncements

The following recently issued accounting standards are not yet effective; the Company is assessing the impact these standards will have on its consolidated financial statements as well as the period in which adoption is expected to occur:

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers”. This comprehensive guidance will replace all existing revenue recognition guidance and is effective for annual reporting periods beginning after December 15, 2018, and interim periods therein.

In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern” that will require management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. This ASU becomes effective for annual periods beginning in 2016 and for interim reporting periods starting in the first quarter of 2017.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities. This ASU is intended to improve the recognition and measurement of financial instruments. Among other things, this ASU requires certain equity investments to be measured at fair value with changes in fair value recognized in net income. This guidance is effective for fiscal years beginning after December 15, 2017, and interim periods therein.

In February 2016, the FASB issued ASU 2016-02, Leases, which will supersede the existing guidance for lease accounting. This ASU will require lessees to recognize leases on their balance sheets, and leaves lessor accounting largely unchanged. This guidance is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, and early adoption is permitted.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. The core change with ASU 2016-09 is the simplification of several aspects of the accounting for share-based payment transactions, including the income tax consequences, classifications of awards as either equity or liabilities, and classification in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years, and early adoption is permitted.

The following recently issued accounting standards were adopted effective January 1, 2016; the impact of adoption did not have a material impact on the Company’s consolidated financial statements:

In November 2014, the FASB issued ASU 2014-16, “Derivatives and Hedging: Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity”. This ASU does not change the current criteria in GAAP for determining when separation of certain embedded derivative features in a hybrid financial instrument is required, but clarifies how current GAAP should be interpreted in the evaluation of the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share, reducing existing diversity in practice.

In January 2015, the FASB issued ASU 2015-01, “Income Statement—Extraordinary and Unusual Items”, that simplifies income statement classification by removing the concept of extraordinary items from GAAP. The separate disclosure of extraordinary items after income from continuing operations in the income statement is no longer permitted.

In February 2015, the FASB issued ASU No. 2015-02, “Consolidation: Amendments to the Consolidation Analysis”. The new standard is intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations, and securitization structures.

During 2015, the FASB issued ASUs No. 2015-03 and No. 2015-15 titled “Interest-Imputation of Interest”, which generally requires the presentation of debt issuance costs as a direct deduction from the carrying amount of the related debt liabilities. However, for debt issuance costs related to line-of-credit arrangements, the Company is permitted to continue presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement. The Company elected to continue to present its deferred line of credit fees as an asset in its consolidated balance sheets.

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

2.        LIQUIDITY

As of March 31, 2016, the Company has a working capital deficit of $10,419 and an accumulated deficit of $120,307. Additionally, the Company incurred a net loss of $10,602 for the three months ended March 31, 2016. As of March 31, 2016, the Company failed to remain in compliance with financial covenants in its credit agreement and management does not expect the Company will regain compliance through the second quarter of 2016. Accordingly, the entire balance of $6,000 is required to be classified as a current liability. While no assurance can be provided, management believes the lender will not demand repayment until an alternative lender can be obtained.

During the period from September 2015 through February 2016, the Company completed the following actions which are expected to improve the Company’s operating results in 2016 and enable the Company to survive the current oil and gas industry price environment:

Management believes approximately $7,000 of annualized overhead and mining expense reductions have poised the Company to survive the current low commodity price environment, in combination with our attractive oil price risk derivative contracts for 87,050 barrels of oil which is 60% of expected production for the last nine months of 2016.

As of March 31, 2016, the Company had cash and equivalents of $1,921, management expects to maintain cash balances in this range for some time. Management also expects potential investors and lenders will find the Company’s new singular industry focus, combined with attractive producing properties and a low-cost overhead structure to be an attractive vehicle to partner with the Company during this industry downturn and low commodity price environment.

3.        OIL PRICE RISK DERIVATIVES

The Company’s wholly-owned subsidiary Energy One has entered into crude oil derivative contracts (“economic hedges”) with Wells Fargo, the Company’s lender as discussed further in Note 7. The derivative contracts are priced based on West Texas Intermediate (“WTI”) quoted prices for crude oil. The Company is a guarantor of Energy One’s obligations under the economic hedges. The objective of utilizing the economic hedges is to reduce the effect of price changes on a portion of the Company’s future oil production, achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage the Company’s exposure to commodity price risk. The use of these derivative instruments limits the downside risk of adverse price movements. However, there is a risk that such use may limit the Company’s ability to benefit from favorable price movements. Energy One may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of its existing positions. The Company does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features. Presented below is a summary of outstanding “costless collars” with Wells Fargo as of March 31, 2016 (which total an aggregate of 87,050 barrels of oil production during the last nine months of 2016):

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

As of March 31, 2016, the aggregate fair value of oil derivative put contracts was an asset of $1,079 and the aggregate fair value of oil derivative call contracts was a liability of $18. Since these contracts are with the same counterparty, the Company recognizes the net asset of $1,061 in the accompanying balance sheet as of March 31, 2016. Since all of the derivative contracts expire within nine months of the balance sheet date, the entire amount is included in current assets. As of December 31, 2015, the aggregate fair value of oil derivative put contracts was an asset of $1,674 and the aggregate fair value of oil derivative call contracts was a liability of $40, resulting in a net asset of $1,634.

Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are included in unrealized gain (loss) on oil price risk derivatives in the consolidated statements of operations.

4.        CEILING TEST FOR OIL AND GAS PROPERTIES

The reserves used in the Company’s full cost ceiling test incorporate assumptions regarding pricing and discount rates over which management has no influence in the determination of present value. In the calculation of the ceiling test as of March 31, 2016, the Company used a price of $46.26 per barrel for oil and $2.40 per MMbtu for natural gas (as further adjusted for property specific gravity, quality, local markets and distance from markets) to compute the future cash flows of the Company’s producing properties. These prices compare to $50.28 per barrel for oil and $2.59 per MMbtu for natural gas used in the calculation of the Ceiling Test as of December 31, 2015. The discount factor used was 10%.

For the three months ended March 31, 2016 and 2015, ceiling test impairment charges for the Company’s oil and gas properties amounted to $6,957 and $19,240, respectively. These impairment charges were primarily related to (i) a decline in the price of oil and reductions in the estimated quantities that are economically recoverable at the current low oil price environment, and (ii) the transfer of approximately $1,000 of unevaluated properties to the full cost pool due to impairment. Further ceiling test impairment charges are likely during the second quarter of 2016.

5.        DISCONTINUED OPERATIONS AND PREFERRED STOCK ISSUANCE

Disposition of Mining Segment

In February 2006, the Company reacquired the Mt. Emmons molybdenum mining properties (the “Property”). The Company has not conducted any extractive mining operations at the Property since its reacquisition but the Company was obligated under existing permits to operate a water treatment plant (“WTP”) and to incur holding costs associated with the retention of the mining properties, which resulted in aggregate annual expenses of approximately $3,000 during each of the three years in the period ended December 31, 2015.

The market price for molybdenum oxide was approximately $11 per pound during 2013 and 2014 with a decrease to approximately $5 per pound by the fourth quarter of 2015. In light of the considerable ongoing costs related to the Property and the deteriorating market for molybdenum, during 2015 the Company began to explore the viability of alternative structures to the development of the Property that could result in a sharing or elimination of the ongoing costs and liabilities.

In February 2016, the Company’s Board of Directors decided to dispose of the Property rather than continuing the Company’s long-term development strategy whereby the Company entered into the following agreements:

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

As a result of the subsequent disposition of the Property as described above, the Company determined that an impairment charge of $22,620 was required to be recorded in the fourth quarter of 2015. The disposal of a segment is reported as discontinued operations in the Company’s financial statements. Presented below are the assets and liabilities associated with the Company’s mining segment as of March 31, 2016 and December 31, 2015:

At the option of the holder, each share of Preferred Stock may initially be converted into 80 shares of the Company’s $0.01 par value Common Stock (the “Conversion Rate”) for an aggregate of 4,000,000 shares. The Conversion Rate is subject to anti-dilution adjustments for stock splits, stock dividends, certain reorganization events, and to price-based anti-dilution protections if the Company subsequently issues shares for less than 90% of fair value on the date of issuance. Each share of Preferred Stock will be convertible into a number of shares of Common Stock equal to the ratio of the initial conversion value to the conversion value as adjusted for accumulated dividends multiplied by the Conversion Rate. In no event will the aggregate number of shares of Common Stock issued upon conversion be greater than 4,760,095 shares. The Preferred Stock will generally not vote with the Company’s Common Stock on an as-converted basis on matters put before the Company’s shareholders. The holders of the Preferred Stock have the right to approve specified matters as set forth in the Certificate of Designations and have the right to require the Company to repurchase the Preferred Stock in connection with a change of control. However, the Company’s Board of Directors has the ability to prevent any change of control that could trigger a redemption obligation related to the Preferred Stock.

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

During the first quarter of 2016, the Company recorded the fair value of the Preferred Stock based on the initial liquidation preference of $2,000. Since the cash consideration paid by MEM for the Preferred Stock was $1, the Company recorded a charge to discontinued operations of approximately $1,999 associated with the issuance. This charge represents additional consideration to induce MEM to assume the Company’s previous obligations to operate the WTP.

Results of Operations for Discontinued Operations

The results of operations of the discontinued mining operations are presented separately in the accompanying financial statements. Presented below are the components for the three months ended March 31, 2016 and 2015:

6.        DEBT

Energy One, a wholly-owned subsidiary the Company, has a credit facility with Wells Fargo Bank, National Association (“Wells Fargo”). As of March 31, 2016 and December 31, 2015, outstanding borrowings under the credit facility amounted to $6,000, which is also the maximum amount of the borrowing base. Borrowings under the credit facility are collateralized by Energy One’s oil and gas producing properties and substantially all of the Company’s cash and equivalents. Each borrowing under the agreement has a term of six months, but can be continued at the Company’s election through July 2017 if the Company is in compliance with the covenants under the credit facility. The weighted average interest rate on this debt is 3.19% as of March 31, 2016.

Energy One is required to comply with customary affirmative covenants and with certain negative covenants. The principal negative financial covenants do not permit (i) the interest coverage ratio (EBITDAX to interest expense) to be less than 3.0 to 1; (ii) total debt to EBITDAX to be greater than 3.5 to 1; and (iii) the current ratio to be less than 1.0 to 1.0. EBITDAX is defined in the Credit Agreement as consolidated net income, plus non-cash charges. Additionally, the Credit Agreement prohibits or limits Energy One’s ability to incur additional debt, pay cash dividends and other restricted payments, sell assets, enter into transactions with affiliates, and to merge or consolidate with another company. The Company is a guarantor of Energy One’s obligations under the Credit Agreement.

In July 2015, the Company and Wells Fargo Bank entered into a third amendment (the "Third Amendment") to the agreement governing the credit facility (as amended, the "Senior Credit Agreement"). The Third Amendment provides for, among other things: (i) a limited waiver with respect to the restricted payments covenant pursuant to which a transfer of $5,000 from Energy One to the Company was permitted in 2015; (ii) a limited waiver of the current ratio covenant as it relates to the fiscal quarters ended June 30, 2015 and September 30, 2015; and (iii) a reduction in the borrowing base to $7,000, subject to further adjustment from time to time in accordance with the Senior Credit Agreement. In December 2015, Wells Fargo made a further reduction in the borrowing base to $6,000. As of March 31, 2016, Energy One was not in compliance with any of the negative covenants.

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

Because the Company projects that it is unlikely that Energy One will regain compliance with the covenant within the next 12 months, outstanding borrowings of $6,000 are presented as a current liability in the accompanying consolidated balance sheet as of March 31, 2016 and December 31, 2015. In the event that Energy One is unable to obtain an amendment to or waiver under the Senior Credit Agreement to address the anticipated future breaches of the Current Ratio covenant, and other actual or potential future breaches that may occur, Wells Fargo could elect to declare some or all of the Company’s debt to be immediately due and payable and could elect to terminate its commitment and cease making further loans.

7.        EXECUTIVE RETIREMENT PLAN

In October 2005, the Board of Directors adopted an Executive Retirement Policy (the “Retirement Plan”) for the benefit of certain executive officers of the Company. To be eligible to participate in the Retirement Plan, the executive officer was required to serve as one of the designated executive officers for at least 15 years, reached the age of 60, and been an employee of the Company on December 31, 2010. Upon retirement, the executive was entitled to cash payments equaling 50% of the greater of (i) the amount of compensation earned as base cash pay on the final regular pay check or (ii) the average annual pay, less all bonuses, received over the last five years of employment with the Company. The Company periodically engaged the services of a third party actuary to determine the estimated liability under the Retirement Plan. In December 2015, the Company and the Retirement Plan participants mutually agreed to terminate the Retirement Plan. As of December 31, 2015, the liability for retirement plan benefits was $583 and this entire balance was paid to participants during the three months ended March 31, 2016.

8.        COMMITMENTS AND CONTINGENCIES

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

Arbitration of Employment Claim. A former employee has asserted a claim that a change of control occurred and he was involuntarily terminated without cause, thereby entitling him to compensation under a purported Executive Severance and Non-Compete agreement (the “Agreement”). The Company claims that the Agreement is invalid because it was never authorized by the Board of Directors or ratified by the Company’s shareholders. The former employee has claimed that the Company owes up to $1,800 under the Agreement which requires that any disputes be submitted to binding arbitration. A request for arbitration was submitted by the former employee in March 2016 and, on April 15, 2016, the Company filed a complaint in Denver District Court seeking a stay of the arbitration and/or preliminary injunction against the employee from proceeding with the arbitration. As a result, administration of the arbitration proceeding has been suspended until June 15, 2016, until the outcome of the Company’s complaint is resolved. On May 10, 2016, the Company filed a motion for stay and/or preliminary injunction and the Court has scheduled a hearing on this matter on June 7, 2016.

Management does not believe there is any merit to the claim of termination without cause or that a change of control occurred. The ultimate outcome of this matter cannot presently be determined. Accordingly, adjustments, if any, that may result from the resolution of this matter have not been reflected in the accompanying consolidated financial statements.

Contingent Ownership Interests. As of March 31, 2016 and December 31, 2015, the Company had recognized a contingent liability associated with uncertain ownership interests of $4,011 and $3,108, respectively. This liability arises when the calculations of respective joint ownership interests by operators differs from the Company’s calculations. These differences relate to a variety of matters, including allocation of non-consent interests, complex payout calculations for individual wells and groups of wells, along with the timing of reversionary interests. Accordingly, these matters are subject to legal interpretation and the related obligations are presented as a contingent liability in the accompanying consolidated balance sheets. While the Company has classified these amounts as current liabilities, most of these issues are expected to be resolved through arbitration, mediation or litigation; due to the complexity of the issues involved, there can be no assurance that the outcome of these contingencies will be resolved in the next year.

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

9.        SHAREHOLDERS’ EQUITY

Stock Options

For the three months ended March 31, 2016 and 2015, total stock-based compensation expense related to stock options was $21 and $65, respectively. As of March 31, 2016, there was $120 of unrecognized expense related to unvested stock options, which will be recognized as stock-based compensation expense through January 2018. For the three months ended March 31, 2016, no stock options were granted, exercised, forfeited or expired. Presented below is information about stock options outstanding and exercisable as of March 31, 2016 and December 31, 2015:

The following table summarizes information for stock options outstanding and for stock options exercisable at March 31, 2016:

As of March 31, 2016, an aggregate of 2,108,578 shares are available for future grants under the Company’s stock option plans. Based upon the closing price for the Company’s common stock of $0.35 per share on March 31, 2016, there was no intrinsic value related to stock options outstanding as of March 31, 2016.

Restricted Stock Grants

In January 2015, the Board of Directors granted 340,711 shares of restricted stock under the 2012 Equity Plan to four officers of the Company. These shares originally vested annually over a period of three years. However, during 2015 vesting was accelerated for three of the four officers in connection with severance agreements for an aggregate of 240,711 shares. The remaining 100,000 shares vested for 33,333 shares in January 2016 and the remaining 66,667 shares will vest for 33,333 of the shares in January 2017 and 33,334 in January 2018. The fair market value of the 340,711 shares on the date of grant was approximately $511. For the three months ended March 31, 2016 and 2015, total stock-based compensation expense related to restricted stock grants was $13 and $42, respectively. As of March 31, 2016, there was $88 of unrecognized expense related to unvested restricted stock grants, which will be recognized as stock-based compensation expense through January 2018.

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

Employee Stock Ownership Plan

The Board of Directors of the Company adopted the U.S. Energy Corp. 1989 Employee Stock Ownership Plan ("ESOP") in 1989, for the benefit of all the Company’s employees. Employees become eligible to participate in the ESOP after one year of service which must consist of at least 1,000 hours worked. Employees become 20% vested after three years of service and increase their vesting by 20% each year thereafter until such time as they are fully vested after seven years of service.

An employee’s total compensation paid, which is subject to federal income tax (up to an annual limit of $265 for the year ended December 31, 2015) is the basis for computing how much of the total annual funding is contributed into each employee’s personal account. An employee’s compensation divided by the total eligible compensation paid to all plan participants is the percentage that each participant receives on an annual basis. All shares of the Company’s common stock contributed to the ESOP have been allocated to specific employees and are vested. Total shares held by the ESOP at March 31, 2016 and December 31, 2015 were 340,726 and 789,110, respectively.

For the three months ended March 31, 2015, total stock-based compensation expense related to the ESOP was $23. No expense related to the ESOP has been recorded for the three months ended March 31, 2016 since the Company’s Board of Directors has not determined if a discretionary contribution will be made for 2016. For the year ended December 31, 2015, the Company’s Board of Directors approved a mandatory contribution of $171 which is either payable in cash or may be settled through the issuance of common stock at the election of the Company. Accordingly, this amount is included in accrued compensation and benefits in the accompanying balance sheets as of March 31, 2016 and December 31, 2015.

10.        INCOME TAXES

For Federal income tax purposes, as of December 31, 2015 the Company had net operating loss and percentage depletion carryovers of approximately $57,000 and $7,000, respectively. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. The net operating losses may be used to offset future taxable income and expire in varying amounts through 2035. In addition, the Company has alternative minimum tax credit carry-forwards of approximately $700 which are available to offset future federal income taxes over an indefinite period. The Company has established a valuation allowance for all deferred tax assets including the net operating loss and alternative minimum tax credit carryforwards discussed above since the “more likely than not” realization criterion was not met as of March 31, 2016 and 2015. Accordingly, the Company did not recognize an income tax benefit for the three months ended March 31, 2016 and 2015.

The Company recognizes, measures, and discloses uncertain tax positions whereby tax positions must meet a “more-likely-than-not” threshold to be recognized. As of March 31, 2016, gross unrecognized tax benefits are immaterial and there was no change in such benefits during the three months ended March 31, 2016. The Company does not expect a significant increase or decrease to the uncertain tax positions within the next twelve months.

11.        EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per share is computed based on the weighted average number of common shares outstanding. For the three months ended March 31, 2016 and 2015, common stock equivalents excluded from the calculation of weighted average shares because they were antidilutive are as follows:

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

12.        SIGNIFICANT CONCENTRATIONS

The Company has exposure to credit risk in the event of nonpayment by the joint interest operators of the Company’s oil and gas properties. Approximately 40% of the Company’s proved developed oil and gas reserve quantities are associated with wells that are operated by a single operator (the “Major Operator”). As of March 31, 2016 and December 31, 2015, the Company had a liability to the Major Operator of $2,976 and $4,159, respectively, for accrued operating expenses and overpayments of net revenues when the Major Operator failed to recognize that the Company’s ownership interest reverted after payout was achieved for certain wells during 2014 and 2015. Beginning in the second quarter of 2015, the Major Operator began withholding the Company’s net revenues from all wells that it operates for the Company and management expects the Major Operator will continue to withhold the Company’s net revenues until this liability is paid in full. Based on the oil and gas prices and costs used in the Company’s reserve report as of March 31, 2016, this liability is not expected to be fully settled until the first quarter of 2020, but under higher pricing scenarios the Company expects the liability will be repaid from future production. Accordingly, the aggregate balances are presented as current liabilities in the accompanying consolidated balance sheets.

13.        FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  In determining fair value, the Company uses various methods including market, income and cost approaches. Based on these approaches, the Company often utilizes certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable inputs.  The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  Based on the observability of the inputs used in the valuation techniques the Company is required to provide the following information according to the fair value hierarchy. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values. Financial assets and liabilities carried at fair value will be classified and disclosed in one of the following three categories:

Level 1 - Quoted prices for identical assets and liabilities traded in active exchange markets, such as the New York Stock Exchange.

Level 2 - Observable inputs other than Level 1 including quoted prices for similar assets or liabilities, quoted prices in less active markets, or other observable inputs that can be corroborated by observable market data.  Level 2 also includes derivative contracts whose value is determined using a pricing model with observable market inputs or can be derived principally from or corroborated by observable market data.

Level 3 - Unobservable inputs supported by little or no market activity for financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation; also includes observable inputs for nonbinding single dealer quotes not corroborated by observable market data.

The Company has processes and controls in place to attempt to ensure that fair value is reasonably estimated. The Company performs due diligence procedures over third-party pricing service providers in order to support their use in the valuation process. Where market information is not available to support internal valuations, independent reviews of the valuations are performed and any material exposures are evaluated through a management review process.

While the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. The following is a description of the valuation methodologies used for complex financial instruments measured at fair value:

Oil Price Risk Derivative Valuation Methodologies

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of the counterparty and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the likelihood that the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At March 31, 2016 and December 31, 2015, derivative instruments utilized by the Company consisted of crude oil costless collars. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

Marketable Equity Securities Valuation Methodologies

The fair value of available for sale securities is based on quoted market prices obtained from independent pricing services. However, due to limited trading activity for both of the Company’s investments in marketable equity securities, the Company determined that they should be classified in Level 2 and Level 3 depending on the specific circumstances.

Executive Retirement Liability Valuation Methodologies

The executive retirement program is a standalone liability for which there is no available market price, principal market, or market participants. The Company records the estimated fair value of the long-term liability for estimated future payments under the executive retirement program based on the discounted value of estimated future payments associated with each individual in the program. The inputs available for this estimate are unobservable and are therefore classified as Level 3 inputs.

Other Financial Instruments

The carrying amount of cash and equivalents, oil and gas sales receivable, other current assets, accounts payable and accrued expenses approximate fair value because of the short-term nature of those instruments. The recorded amounts for the Senior Secured Revolving Credit Facility discussed in Note 6 approximates the fair market value due to the variable nature of the interest rates, and the fact that market interest rates have remained substantially the same since the latest amendment to the credit facility.

Recurring Fair Value Measurements

Recurring measurements of the fair value of assets and liabilities as of March 31, 2016 and December 31, 2015 are as follows:

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements. When used in this Form 10-Q, the words “will”, “expect”, “anticipate”, “intend”, “plan”, “believe”, “seek”, “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Forward-looking statements in this Form 10-Q include statements regarding our expected future revenue, income, production, liquidity, cash flows, reclamation and other liabilities, expenses and capital projects, future capital expenditures and future transactions. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements due to a variety of factors, including those associated with our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil, NGL and natural gas prices, declines in the values of our properties that have resulted in and may in the future result in additional ceiling test write downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for our participation in oil and gas properties and for future acquisitions, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters and the operating hazards attendant to the oil and gas and minerals businesses. In particular, careful consideration should be given to cautionary statements made in the “Risk Factors” section of our 2015 Annual Report on Form 10-K and other quarterly reports on Form 10-Q filed with the SEC, all of which are incorporated herein by reference. The Company undertakes no duty to update or revise any forward-looking statements.

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. Our long-term strategic focus is to develop operational capabilities through the pursuit of opportunities to acquire operated properties and/or operatorship of existing properties.

Recent Developments

In February 2016, we transferred to Mt. Emmons Mining Company, a subsidiary of Freeport-McMoRan Inc. (“MEM”), our Mt. Emmons mine site located in Gunnison County, Colorado, including the Keystone Mine, a related water treatment plant (the “WTP”) and other related properties (collectively, the “Purchased Assets”). MEM replaced the Company as the permittee and owner of the WTP and will discharge the obligation of the Company to operate the WTP in accordance with the applicable permits issued by the Colorado Department of Public Health and Environment.

As additional consideration for MEM to accept transfer of the Purchased Assets, including related obligations, the Company entered into a Series A Convertible Preferred Stock Purchase Agreement (the “Series A Purchase Agreement”) with MEM pursuant to which the Company issued to MEM 50,000 shares of newly designated Series A Convertible Preferred Stock (the “Preferred Stock”). The Preferred Stock accrues dividends at a rate of 12.25% per annum of the Adjusted Liquidation Preference (as defined), which are not payable in cash but are accrued and compounded quarterly in arrears. The “Adjusted Liquidation Preference” is initially $40 per share of Preferred Stock, increased each quarter by the accrued quarterly dividend. The Preferred Stock is senior to other classes or series of shares of the Company with respect to dividend rights and rights upon liquidation. No dividend or distribution will be declared or paid on junior stock, including the Company’s common stock, (1) unless approved by the holders of Preferred Stock, voting as a group and (2) unless and until a like dividend has been declared and paid on the Preferred Stock on an as-converted basis, unless waived by the holders of Preferred Stock.

Each share of Preferred Stock may initially be converted into 80 shares of the common stock of the Company at the option of the holder at any time. The conversion rate is subject to anti-dilution adjustments for stock splits, stock dividends and certain reorganization events and to price-based anti-dilution protections. Each share of Preferred Stock will be convertible into a number of shares of Common Stock equal to the product of (1) the conversion value as adjusted for accumulated dividends divided by the initial conversion value, multiplied by (2) the conversion rate (plus cash in lieu of fractional shares and dividends accrued since the last accrual date). The Preferred Stock will generally not vote with the common stock on an as-converted basis on matters put before the Company’s shareholders. The holders of the Preferred Stock have the right to approve specified matters and have the right to require the Company to repurchase the Preferred Stock in connection with a change of control.

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions. A summary of our significant accounting policies is detailed in Note 1 – Organization, Operations and Significant Accounting Polices in Item 8 of our 2015 Annual Report on Form 10-K filed with the SEC on April 14, 2016. We have outlined below those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.

Oil and Gas Reserve Estimates. Our estimates of proved reserves are based on quantities of oil and gas reserves which current engineering data indicates are recoverable from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are critical estimates in determining our depreciation, depletion and amortization expense (“DD&A”) and our full cost ceiling limitation (“Full Cost Ceiling”). Future cash inflows are determined by applying oil and gas prices, as adjusted for transportation, quality and basis differentials to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Future production and development costs are based on costs existing at the effective date of the report. Expected cash flows are discounted to present value using a prescribed discount rate of 10% per annum.

Estimates of proved reserves are inherently imprecise because of uncertainties in projecting rates of production and timing of developmental expenditures, interpretations of geological, geophysical, engineering and production data and the quality and quantity of available data. Changing economic conditions also may affect our estimates of proved reserves due to changes in developmental costs and changes in commodity prices that may impact reservoir economics. We utilize independent reserve engineers to estimate our proved reserves at the end of each fiscal quarter during the year.

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

The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center are amortized using the equivalent unit-of-production method, based on proved oil and gas reserves. The capitalized costs are amortized over the life of the reserves associated with the assets, with the DD&A recognized in the period that the reserves are produced. DD&A is calculated by dividing the period’s production volumes by the estimated volume of reserves associated with the investment and multiplying the calculated percentage by the sum of the capitalized investment and estimated future development costs associated with the investment. Changes in our reserve estimates will therefore result in changes in our DD&A per unit. Costs associated with production and general corporate activities are expensed in the period incurred.

Exploratory wells in progress are excluded from the DD&A calculation until the outcome of the well is determined. Similarly, unproved property costs are initially excluded from the DD&A calculation. Unproved property costs not subject to the DD&A calculation consist primarily of leasehold and seismic costs related to unproved areas. Unproved property costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved oil and gas properties are assessed quarterly for impairment to determine whether we are still actively pursuing the project and whether the project has been proven either to have economic quantities of reserves or that economic quantities of reserves do not exist.

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated DD&A and net of deferred income taxes may not exceed the Full Cost Ceiling. The Full Cost Ceiling is equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the unimpaired cost of unproved properties not subject to amortization, plus the lower of cost or fair value of unproved properties that are subject to amortization. When net capitalized costs exceed the Full Cost Ceiling, impairment is recognized.

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

Our Board of Directors sets all risk management policies and reviews the status and results of derivative activities, including volumes, types of instruments and counterparties. The master contracts with approved counterparties identify the CEO as the Company representative authorized to execute trades.

Discontinued Operations- Mining Properties. Due to the disposition of our mining properties in February 2016, all of our mining properties are included in discontinued operations. Effective January 1, 2015, we adopted new accounting guidance related to the recognition and presentation of discontinued operations in our financial statements. Under the revised guidance, beginning in 2015 only disposals of businesses that represent strategic shifts that have a major effect on our operations and financial results are reported in discontinued operations. Accordingly, the disposal of our mining segment qualified for reporting as discontinued operations.

We capitalized all costs incidental to the acquisition of mining properties and related equipment. The costs of operating a related water treatment plant on the mine property, holding costs to maintain permits, mining exploration costs and general corporate overhead were expensed as incurred. As of December 31, 2015, we recognized impairment of the carrying value of the mine property when we determined that the carrying value could not be recovered.

Joint Interest Operations. We do not serve as operator for any of our oil and gas properties. Therefore, we rely to a large extent on the operator of the property to provide us with timely and accurate information about the operations of the properties. Joint interest billings from the operators serve as our primary source of information to record revenue, operating expenses and capital expenditures for our properties on a monthly basis. Many of our properties are subject to complex participation and operating agreements where our working interests and net revenue interests are subject to change upon the occurrence of certain events, such as the achievement of “payout”. These calculations may be subject to error and differences of interpretation which can cause uncertainties about the proper amount that should be recorded in our accounting records. When these issues arise, we make every effort to work with the operators to resolve the issues promptly.

Revenue Recognition. We record oil and gas revenue under the sales method of accounting. Under the sales method, we recognize revenues based on the amount of oil or natural gas sold to purchasers, which may differ from the amounts to which we are entitled based on our interest in the properties. Gas balancing obligations as of March 31, 2016 and December 31, 2015 were not significant.

Stock Based Compensation. We measure the cost of employee services received in exchange for all equity awards granted, including stock options, based on the fair market value of the award as of the grant date. We recognize the cost of the equity awards over the period during which an employee is required to provide service in exchange for the award, usually the vesting period. For awards granted which contain a graded vesting schedule, and the only condition for vesting is a service condition, compensation cost is recognized as an expense on a straight-line basis over the requisite service period as if the award was, in substance, a single award.

Recently Issued Accounting Standards

Please refer to the section entitled Recent Accounting Pronouncements under Note 1 – Organization, Operations and Significant Accounting Policies in the Notes to the Financial Statements included in Item 1 of this report for additional information on recently issued accounting standards and our plans for adoption of those standards.

Results of Operations

Comparison of our Statements of Operations for the Three Months Ended March 31, 2016 and 2015

During the three months ended March 31, 2016, we recorded a net loss of $10.6 million as compared to a net loss of $23.7 million for the three months ended March 31, 2015. Our loss from continuing operations was $8.3 million for the three months ended March 31, 2016 compared to $22.9 million for the three months ended March 31, 2015. In the following sections we discuss our revenue, operating expenses, non-operating income, and discontinued operations for the three months ended March 31, 2016 compared to the three months ended March 31, 2015.

Revenue. Presented below is a comparison of our oil and gas sales, production quantities and average sales prices for the three months ended March 31, 2016 and 2015 (dollars in thousands, except average sales prices):

The decrease in our oil sales of $1.4 million for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015 resulted from a 33% reduction in our oil production quantity and a 44% reduction in the average oil price realized during the three months ended March 31, 2016. The decrease in our gas sales of $0.2 million for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015 was driven by a 59% decrease in our gas production which was partially offset by a 30% increase in the average gas price realized during the three months ended March 31, 2016. The reduction in our net realized oil price is reflective of the dramatic decrease in global commodity prices during 2015 which has intensified during 2016. During the last year, the differential between West Texas Intermediate (“WTI”) quoted prices for crude oil and the prices we realize for sales in the Williston Basin was approximately $8.00 per barrel lower. 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.

For the three months ended March 31, 2016, we produced 50,628 BOE, or an average of 556 BOE per day, as compared to 86,227 BOE or 958 BOE per day during the comparable period in 2015. This 41% reduction was attributable to several factors, including (i) the normal decline in production for wells in the area of our properties, (ii) we did not add significant reserves from drilling or acquisition over the past year, and (iii) in this low price environment operators have an incentive to scale back production until prices recover.

Oil and Gas Production Costs. Presented below is a comparison of our oil and gas production costs for the three months ended March 31, 2016 and 2015 (dollars in thousands):

For the three months ended March 31, 2016, production taxes decreased by $0.1 million compared to the comparable period in 2015. Substantially all of this decrease in production taxes resulted from lower oil and gas sales. For the three months ended March 31, 2016, lease operating expense decreased by $0.7 million which was primarily due to the implementation of cost reduction strategies by the operators of our wells. During 2016, we expect further well by well decreases as cost reduction programs continue during the industry downturn.

Depreciation, depletion and amortization. Our DD&A rate for the three months ended March 31, 2016 was $15.45 per BOE compared to $33.33 per BOE for the three months ended March 31, 2015. 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. The primary factor that resulted in a reduction in our DD&A rate for the three months ended March 31, 2016 was $57.7 million of aggregate quarterly impairment charges that resulted from our quarterly Full Cost Ceiling limitations during 2015. During each of the four quarters in 2015, we recognized impairment charges which reduced the net capitalized costs subject to future DD&A calculations. Accordingly, our DD&A rate per BOE decreased as we reduced the net capitalized costs by the quarterly impairment charges discussed below.

Impairment of oil and gas properties. During the three months ended March 31, 2016 and 2015, we recorded impairment charges related to our oil and gas properties of $7.0 million and $19.2 million, respectively, because the net capitalized costs were in excess of the Full Cost Ceiling limitation.  These quarterly impairment charges were primarily due to the deepening declines in the price of oil during 2015 and the first quarter of 2016. Additionally, during the three months ended March 31, 2016, we determined that unevaluated properties were impaired for approximately $1.0 million. Accordingly, we transferred these costs to the full cost pool which contributed to the Full Cost Ceiling limitation for the three months ended March 31, 2016. Presented below are the weighted average prices (before applying the impact of basis differentials between the benchmark prices and the actual prices realized for our wells) used to prepare our reserve estimates and to calculate our Full Cost Ceiling limitations for each of the last five calendar quarters, along with the impairment charges recognized during each of those quarters (dollars in thousands, except average prices):

Our quarterly reserve reports are prepared based on a trailing 12-month average for benchmark oil and gas prices; therefore, the weighted average oil price used to prepare our reserve estimates and to calculate our Full Cost Ceiling limitation for the second quarter of 2016 is expected to decline from $46.26 (before further deduction for basis differentials) used for reserve determinations and the Full Cost Ceiling limitation as of March 31, 2016.

General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the three months ended March 31, 2016 and 2015 (dollars in thousands):

General and administrative expenses decreased by $0.7 million for the three months ended March 31, 2016 compared to the three months ended March 31, 2015. This decrease was attributable to (i) a reduction of $0.7 million in compensation and benefits, which was driven by the termination of all except one employee by December 31, 2015, and (ii) a decrease in stock-based compensation which primarily resulted from the acceleration of vesting of stock options and restricted stock associated with employees who terminated employment in 2015. These decreases which totaled $0.8 million were partially offset by an increase in professional fees of $0.1 million as we replaced some of the services previously performed by employees with consultants.

Non-Operating Income (Expense). Presented below is a comparison of our non-operating income (expense) for the three months ended March 31, 2016 and 2015 (dollars in thousands):

We recognized a realized gain on oil price risk derivatives of $0.9 million for the three months ended March 31, 2016 compared to a loss of $0.1 million for the comparable period in 2015. We recognized an unrealized loss on oil price risk derivatives of $0.6 million for the three months ended March 31, 2016 compared to a loss of $0.1 million for the comparable period in 2015. The realized gains during the three months ended March 31, 2016 result from the significant decline in the market for crude oil after we entered into the derivative contracts. Unrealized gains or losses result from changes in the fair value of the derivatives as commodity prices increase or decrease. Unrealized losses are also recognized in the month when derivative contracts are settled in cash through the recognition of a realized gain. Similarly, unrealized gains are also recognized in the month when derivative contracts are settled in cash through the recognition of a realized loss.

Interest expense increased by $0.1 million during the three months ended March 31, 2016 compared to the comparable period in 2015. This decrease was attributable to the amortization of a debt issuance cost incurred in 2015 where we abandoned the source of financing associated with the cost incurred.

Discontinued Operations. In February 2016 we completed the disposition of our mining segment to Mt. Emmons Mining Company (“MEM”), including the Keystone Mine, the WTP and other related properties. A significant objective for completing the disposition was to improve future profitability through the elimination of the obligations to operate the WTP and mine holding costs, which are expected to result in estimated annual cash savings of $3.0 million. During the three months ended March 31, 2016, we began to realize the benefits of this disposition as aggregate operating expenses associated with the discontinued mining segment declined from $0.8 million for the three months ended March 31, 2015 to $0.3 million for the three months ended March 31, 2016, a decrease of $0.5 million or 58%.

In order to induce MEM to assume the Company’s obligations to operate the WTP we needed to issue additional consideration in the form of 50,000 shares of Series A Convertible Preferred Stock. We recorded the fair value of the Preferred Stock based on the initial liquidation preference of $2.0 million. Since the cash consideration paid by MEM for the Preferred Stock was $500, we recorded a charge to discontinued operations of approximately $2.0 million associated with the issuance.

Due to the disposition in February 2016, all of our mining properties are included in discontinued operations for all periods presented in this report. As of December 31, 2015, we recognized an impairment charge of $22.6 million when we determined that the carrying value of the mining property assets could not be recovered.

Non-GAAP Financial Measures- Adjusted EBITDAX

Adjusted EBITDAX represents income (loss) from continuing operations as further modified to eliminate impairments, depreciation, depletion and amortization, stock-based compensation expense, loss on investments and other non-operating income or expense, income taxes, unrealized derivative gains and losses, interest expense, exploration expense, and other items set forth in the table below. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally one-time in nature or whose timing and/or amount cannot be reasonably estimated, such as the employee severance charges incurred in 2015.

Adjusted EBITDAX is a non-GAAP measure that is presented because we believe it provides useful additional information to investors and analysts as a performance measure. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our wholly-owned subsidiary, Energy One LLC, is also subject to a debt to adjusted EBITDAX ratio as one of the financial covenants under its Credit Facility and the calculation for purposes of the Credit Facility differs from our financial reporting definition.

The following table provides reconciliations of income (loss) from continuing operations to adjusted EBITDAX for the three months ended March 31, 2016 and 2015:

Liquidity and Capital Resources

The following table sets forth certain measures of our liquidity as of March 31, 2016 and December 31, 2015:

As of March 31, 2016, we have a working capital deficit of $10.4 million compared to a working capital deficit of $9.8 million as of December 31, 2015, a decrease of $0.6 million. This decrease was primarily attributable to a reduction in current assets by $2.4 million, partially offset by a reduction in current liabilities of $1.8 million.

Our sole source of debt financing is a revolving Credit Facility with Wells Fargo Bank N.A. With lower oil and gas prices during 2015, Wells Fargo decreased the borrowing base by $18.5 million to $6.0 million, which is the borrowing base in effect as of March 31, 2016. Outstanding borrowings as of March 31, 2016 and December 31, 2015 were $6.0 million, and we did not have any unused borrowing availability at either date. During 2015 and for the first quarter of 2016, we violated certain covenants in our Credit Facility and we project that we may have further violations for the second quarter of 2016 and beyond. Accordingly, this debt is classified as a current liability as of March 31, 2016 and December 31, 2015. While no assurance can be provided, we believe the lender will not demand repayment until an alternative lender can be obtained. The ongoing availability of this Credit Facility through the maturity date of July 30, 2017, or our receipt of funding from alternative sources, is critical to our ability to survive until oil and gas prices recover.

During 2015 and 2014, we received significant overpayments due to an operator’s failure to timely recognize the payout implications of our joint operating agreements. During the second quarter of 2015, the operator corrected its records and has elected to begin withholding the net revenues from all of our wells that it operates to recover these overpayments. As of March 31, 2016, the balance of the overpayment was approximately $3.0 million. Based on the oil and gas prices and costs used in the Company’s reserve report as of March 31, 2016, this liability is not expected to be fully settled until the first quarter of 2020, but under higher pricing scenarios we expect the entire liability will be repaid sooner. Accordingly, the aggregate balances are presented as current liabilities in our consolidated balance sheets.

We believe certain operators have failed to allocate our share of non-consent ownership interests which results in contingent liabilities to the extent we have not been billed for our proportionate share of such interests, and contingent assets to the extent that we have not received our share of the net revenues. We record net contingent liabilities for the obligations that we believe are probable which amounted to $4.0 million as of March 31, 2016. The ultimate resolution of these uncertainties about our working interests and net revenue interests can extend over a long period of time and we cannot provide any assurance that these matters will be resolved within the next year.

The reduction in our total assets is primarily associated with our net loss of $10.6 million during the three months ended March 31, 2016, as discussed under Results of Operations herein. The reduction in our shareholders’ equity is primarily associated with our net loss of $10.6 million during the three months ended March 31, 2016, partially offset by the issuance of $2.0 million of Series A Convertible Preferred Stock, as discussed under Results of Operations herein.

Since September 2015, we completed the following actions which are expected to improve our operating results in 2016 and enable our survival:

We believe approximately $7.0 million of annualized overhead and mining expense reductions have poised the Company to survive the current low commodity price environment, in combination with our attractive oil price risk derivative contracts for 87,050 barrels of oil, comprising 60% of expected production for the remainder of 2016. As of March 31, 2016, the fair value of our oil price risk derivatives amounted to $1.1 million.

As of March 31, 2016, we had cash and equivalents of $1.9 million, and we expect to maintain cash balances in this range for some time. We also expect potential investors and lenders will find our new singular industry focus, combined with attractive producing properties and a low-cost overhead structure to be an attractive vehicle to partner with the Company during this industry downturn and low commodity price environment. However, there can be no assurance that we will be able to complete future transactions on acceptable terms or at all.

We project that our cash balances as of March 31, 2016, together with our expected 2016 cash flow from operating activities will be sufficient to fund operations and up to $0.2 million for workovers and other capital expenditures. In order to develop our proved undeveloped oil and gas properties, we are projecting expenditures of $1.0 million in 2017 and $4.8 million in 2018. Additionally, our long-term strategy is to acquire additional oil and gas properties at attractive prices. Our ability to finance our capital expenditure budgets for 2017 and 2018 and our ability to acquire additional producing properties is contingent upon our ability to obtain alternative financing to our Credit Facility and this alternative financing will need to provide for borrowing capacity substantially greater than our Credit Facility.

If we have unanticipated needs for financing in 2016, alternatives that we will consider if necessary include selling or joint venturing an interest in some of our oil and gas assets, selling our real estate assets in Wyoming, selling our marketable equity securities, issuing shares of our common stock for cash or as consideration for acquisitions, and other alternatives, as we determine how to best fund our capital programs and meet our financial obligations.

Our capital expenditure plan and our ability to obtain sufficient funding to make anticipated capital expenditures and satisfy our financial obligations are subject to numerous risks and uncertainties, including the risk of continued low commodity prices or further reductions in those prices, the risk that breaches of covenants in our Credit Facility will not be waived and will result in liquidation, bankruptcy or similar proceedings, the risk that we will be unable to enter into additional financing arrangements on acceptable terms or at all, and numerous other risks, including those discussed in Risk Factors in our 2015 Annual Report on Form 10-K.

Cash Flows

The following table summarizes our cash flows for the three months ended March 31, 2016 and 2015 (in thousands):

Operating Activities. Cash used by operating activities for the three months ended March 31, 2016 was $1.1 million as compared to cash provided by operating activities of $2.6 million for the comparable period in 2015, a decrease of $3.7 million. This decrease is primarily related to the cash impact between the periods caused by (i) changes in payables of $2.9 million, and (ii) lower oil and gas sales receivable of $1.2 million due to lower oil and gas prices.

Investing Activities. Cash used in investing activities for the three months ended March 31, 2016 was a nominal amount as compared to cash used in investing activities of $1.9 million for the comparable period in 2015. The primary use of cash in our investing activities for 2015 was for capital expenditures for our oil and gas drilling activities.

Financing Activities. For the three months ended March 31, 2016, our financing cash flows consisted of a nominal amount received for the issuance of Series A Convertible Preferred Stock. We did not have any financing cash flows for the three months ended March 31, 2015.

Discontinued Operations. Cash used in our discontinued operations was $0.3 million for the three months ended March 31, 2016 as compared to $0.8 million for the comparable period in 2015, an improvement of $0.5 million. The improvement in 2016 was due to the disposition of our discontinued mining segment in February 2016 as discussed above.

Off-balance Sheet Arrangements

As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We evaluate our transactions to determine if any variable interest entities exist. If it is determined that we are the primary beneficiary of a variable interest entity, that entity will be consolidated in our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during the periods covered by this report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

As a smaller reporting company, we are not required to provide the information under this Item.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of March 31, 2016, the Company's management, including its Chief Executive Officer and principal financial officer, completed an evaluation of the effectiveness of the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act).  Based on that evaluation, the Chief Executive Officer and principal financial officer concluded:

Changes in Internal Control over Financial Reporting

During the fiscal quarter ended March 31, 2016, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1.  Legal Proceedings

Except as set forth below, there have been no material changes from the legal proceedings as previously disclosed in Item 3 of our 2015 Annual Report on Form 10-K.

Employment Claim. A former employee has asserted a claim that the Company has undergone certain changes and he was involuntarily terminated without cause, thereby entitling him to compensation under a purported Executive Severance and Non-Compete agreement (the “Agreement”). The Company claims that the Agreement is invalid because it was never authorized by the Board of Directors or ratified by the Company’s shareholders. The former employee has claimed that the Company owes up to $1.8 million under the Agreement which requires that any disputes be submitted to binding arbitration. A request for arbitration was submitted by the former employee in March 2016 and, on April 15, 2016, the Company filed a complaint in Denver District Court seeking a stay of the arbitration and/or preliminary injunction against the employee from proceeding with the arbitration. As a result, administration of the arbitration proceeding has been suspended until June 15, 2016, until the outcome of the Company’s complaint is resolved. On May 10, 2016, the Company filed a motion for stay and/or preliminary injunction and the Court has scheduled a hearing on this matter on June 7, 2016.

Item 1A.   Risk Factors.

As a smaller reporting company, we are not required to provide the information under this Item.

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

None, except as disclosed in the Company’s Current Report on Form 8-K filed with the SEC on February 12, 2016.

Item 3.  Defaults Upon Senior Securities.

Not applicable.

Item 4.  Mine Safety Disclosures.

Not applicable.

Item 5.  Other Information.

Not applicable.

Item 6. Exhibits

* Filed herewith.

† In accordance with SEC Release 33-8238, Exhibit 32.1 is being furnished and not filed.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.