US ENERGY CORP - Quarter Report: 2017 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the Quarterly Period Ended March 31, 2017

For the transition period from                 to

Commission File Number 000-6814

U.S. ENERGY CORP.

(Exact Name of Registrant as Specified in its Charter)

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 6,134,506 shares of its $0.01 par value common stock outstanding as of May 15, 2017.

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, 2017 AND 2016

(In Thousands, Except Share and Per Share Amounts)

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

Please note that 2016 “Loss per share- basic & diluted” may differ from results reported on the Company’s quarterly report on Form 10-Q for the period ending March 31, 2016 due to fractional shares associated with the Company’s 6 for 1 stock split in June 2016.

U.S. ENERGY CORP. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 2017 AND 2016

(In Thousands)

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

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.

We have substantial debt obligations and our ongoing capital and operating expenditures will exceed the revenue we expect to receive from our oil and natural gas operations in the near future. If we are unable to raise substantial additional funding, refinance existing indebtedness or consummate significant asset sales on a timely basis and/or on acceptable terms, we may be required to significantly curtail our business and operations. The consolidated financial statements included in this report on Form 10-Q have been prepared on a going concern basis of accounting, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The consolidated financial statements do not reflect any adjustments that might be necessary should we be unable to continue as a going concern. Our ability to continue as a going concern is subject to, among other factors, our ability to monetize assets, our ability to obtain financing or refinance existing indebtedness, our ability to continue our cost cutting efforts, oil and gas commodity prices, our ability to recognize, acquire and develop strategic interests and prospects, the speed and cost with which we can develop our prospects and the ability to adapt our business by integrating specific operations associated with operating companies. There can be no assurance that we will be able to obtain additional funding on a timely basis and on satisfactory terms, or at all. In addition, no assurance can be given that any such funding, if obtained, will be adequate to meet our capital needs and support our growth. If additional funding cannot be obtained on a timely basis and on satisfactory terms, then our operations would be materially negatively impacted and we may be unable to continue as a going concern. If we become unable to continue as a going concern, we may find it necessary to file a voluntary petition for reorganization under the Bankruptcy Code in order to provide us additional time to identify an appropriate solution to our financial situation and implement a plan of reorganization aimed at improving our capital structure.

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, 2016. Our financial condition as of March 31, 2017, and operating results for the three months ended March 31, 2017 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, 2017.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include oil and gas reserves 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 subsidiary Energy One LLC (“Energy One”). 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).

Recent Accounting Pronouncements

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, 2017, and interim periods therein. This update is not expected to have a significant impact on the Company’s financial statements.

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. This update is not expected to have a significant impact on the Company’s financial statements.

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. This update is not expected to have a significant impact on the Company’s financial statements.

2016-05

In March 2016, the FASB issued ASU 2016-06, Derivatives and Hedging: Contingent Put and Call Options in Debt Instruments. The amendments clarify the steps required to assess whether a call or put option meets the criteria for bifurcation as an embedded derivative. The amendment is effective for fiscal years and interim periods beginning after December 1, 2016. This amendment did not have a significant impact on the Company’s financial statements.

2016-11

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting ("ASU 2016-11"). The SEC Staff is rescinding the following SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Specifically, registrants should not rely on the following SEC Staff Observer comments upon adoption of Topic 606: a) Revenue and Expense Recognition for Freight Services in Process which is codified in 605-20-S99-2; b) Accounting for Shipping and Handling Fees and Costs, which is codified in paragraph 605-45-S99-1; c) Accounting for Consideration Given by a Vendor to a Customer, which is codified in paragraph 605-50-S99-1 and d) Accounting for Gas-Balancing Arrangements (that is, use of the “entitlements method”), which is codified in paragraph 932-10-S99-5. We do not use the entitlements method of accounting and are not impacted by this specific SEC Staff Observer comment; however, we are assessing the potential impact of other SEC Staff Observer comments included in ASU 2016-11 on our consolidated financial condition and results of operations.

2016-15

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments ("ASU 2016-15"). ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-15 on our consolidated financial condition and results of operations.

2017-03

In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments – Equity Method and Joint Ventures (Topic 323), which stated additional qualitative disclosures should be considered to assess the significance of the impact upon adoption. This ASU is effective for the annual period beginning after December 15, 2018, and for annual and interim periods thereafter. Early adoption is permitted. The Company is currently evaluating the new guidance to determine the impact it will have on its consolidated financial condition and results of operations.

As of March 31, 2017, the Company has a working capital deficit of $6.8 million and an accumulated deficit of $124.6 million. Additionally, the Company incurred a net loss of $0.7 million for the three months ended March 31, 2017. As of March 31, 2017, the Company failed to remain in compliance with financial covenants in its credit agreement. Accordingly, the entire balance of $6.0 million is required to be classified as a current liability. On May 2, 2017, the credit facility between U.S. Energy Corp.’s wholly-owned subsidiary, Energy One and Wells Fargo was sold, assigned and transferred to APEG Energy II, L.P. (“APEG”). APEG purchased and assumed all of Wells Fargo’s rights and obligations as the lender to Energy One under the credit facility. Concurrently, U.S. Energy Corp., Energy One and APEG entered into a Limited Forbearance Agreement dated May 2, 2017. The Company believes that the Forbearance Agreement will provide the parties sufficient time to work toward a long-term solution that enables the Company to execute its operational strategy and ensure value for existing shareholders. Please refer to Note 13 entitled “Subsequent Events” for further information.

As of March 31, 2017, the Company had cash and equivalents of $2.2 million. Management believes overhead and mining expense reductions have poised the Company to survive the current low commodity price environment. However, there can be no assurance that the Company will be able to complete future financings, dispositions or acquisitions on acceptable terms or at all.

The significantly lower oil price environment that we have experienced since late 2014 has substantially decreased our cash flows from operating activities. Sustained low oil prices could significantly reduce or eliminate our planned capital expenditures. If production is not replaced through the acquisition or drilling of new wells our production levels will lower due to the natural decline of production from existing wells.

Our strategy is to continue to (1) maintain adequate liquidity and selectively participate in new drilling and completion activities, subject to economic and industry conditions, (2) pursue acquisition and disposition opportunities as available liquidity permits and (3) evaluate various avenues to strengthen our balance sheet and improve our liquidity position. We expect to fund any near-term capital requirements and working capital needs from current cash on hand. Our activity could be further curtailed if our cash flows decline from expected levels. Because production from existing oil and natural gas wells declines over time, further reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.

The Company’s wholly-owned subsidiary Energy One has historically entered into crude oil derivative contracts (“economic hedges”). 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. As of March 31, 2017, the Company did not have any outstanding crude oil derivative contracts.

Unrealized gains and losses resulting from derivatives are recorded at fair value in the consolidated balance sheet. Changes in fair value, as well as realized gains (losses) arising upon derivative contract settlements, are included in the “change in unrealized gain (loss) on oil price risk derivatives” in the consolidated statements of operations. For the three months ended March 31, 2017 and 2016, the Company’s unrealized losses from derivatives amounted to $0 and $0.6 million, respectively.

Please refer to Note 13 entitled “Subsequent Events” for more information.

The reserves used in the Company’s full cost ceiling test incorporate assumptions regarding pricing and discount rates in the determination of present value. In the calculation of the ceiling test as of March 31, 2017, the Company used a price of $42.09 per barrel for oil and $2.65 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 $42.75 per barrel for oil and $2.48 per MMbtu for natural gas used in the calculation of the Ceiling Test as of December 31, 2016. The discount factor used was 10%.

For the three months ended March 31, 2017 and 2016, ceiling test impairment charges for the Company’s oil and gas properties amounted to $0 and $6,957, respectively.

Disposition of Mining Segment

In February 2006, the Company reacquired the Mt. Emmons molybdenum mining properties (the “Property”). 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:

Under U.S. GAAP, 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, 2017 and December 31, 2016:

At the option of the holder, each share of Preferred Stock was initially convertible into approximately 13.33 shares of the Company’s $0.01 par value common stock (the “Conversion Rate”) for an aggregate of 666,667 shares of common stock. 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 approximately 793,000 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.

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 a nominal amount, the Company recorded a charge to operations of approximately $2,000 associated with the issuance.

Combined 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, 2017 and 2016:

Energy One, a wholly-owned subsidiary the Company, has a credit facility with Wells Fargo Bank, National Association (“Wells Fargo”). As of March 31, 2017 and 2016, outstanding borrowings under the credit facility amounted to $6.0 million. As of March 31, 2017 and 2016, the borrowing base was $6.0 million. 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 remains in compliance with the covenants under the credit facility. The weighted average interest rate on this debt is 7.39% as of March 31, 2017.

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.

As of March 31, 2017, Energy One and the Company were not in compliance with any of the financial covenants.

Because the Company projects that it is unlikely that Energy One will regain compliance with all of the financial covenants before the July 30, 2017 maturity date, outstanding borrowings of $6.0 million are presented as a current liability in the accompanying consolidated balance sheet as of March 31, 2017.

On May 2, 2017, the credit facility between U.S. Energy Corp.’s wholly-owned subsidiary, Energy One and Wells Fargo was sold, assigned and transferred to APEG Energy II, L.P. (“APEG”). APEG purchased and assumed all of Wells Fargo’s rights and obligations as the lender to Energy One under the credit facility. Concurrently, U.S. Energy Corp., Energy One and APEG entered into a Limited Forbearance Agreement dated May 2, 2017. The Company believes that the Forbearance Agreement will provide the parties sufficient time to work toward a long-term solution that enables the Company to execute its operational strategy and ensure value for existing shareholders.

The credit facility requires the Company’s compliance with certain restricted financial covenants. The Company previously violated the financial ratio covenants for the fiscal quarters ended September 30, 2016 and December 31, 2016, which constituted an event of default under the credit agreement, and the violation of said covenants has continued in 2017. Subject to continued performance and compliance by the Company and Energy One with the terms and conditions of the Forbearance Agreement and credit facility, APEG has agreed not to exercise its rights and remedies arising as a result of certain existing and prospective events of default under the credit facility until July 30, 2017. Commencing on May 2, 2017, interest shall accrue on the outstanding principal balance of the loans under the credit facility at a rate of 8.75% per annum. In the event of default under the Forbearance Agreement, the forbearance period will terminate immediately and, without further notice or opportunity to cure, APEG will be entitled to exercise all of its rights and remedies under the credit facility and Forbearance Agreement, including acceleration of the debt and foreclosure. Please refer to Note 13 entitled “Subsequent Events” for more information.

Commitments

Lessee Operating Leases. In November 2015, the Company took assignment of a lease agreement for office space in Denver, Colorado. The future minimum rental commitment under this sublease requires payments of $59,000 in 2017, when the sublease expires.

Letter of Credit. In connection with the Company’s sublease of office space in Denver, Colorado, a security deposit was provided in the form of an irrevocable letter of credit for $35,000. The letter of credit expires in September 2017. Collateral for the letter of credit is a certificate of deposit for $35,000 that is included in other assets in the accompanying balance sheet as of March 31, 2017.

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 are currently pending legal matters:

North Dakota Properties. 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. Brigham was subsequently sold to Statoil ASA (“Statoil”) who assumed Brigham’s rights and obligations under this case. The Company owns a working interest, not royalty interest, in this well and no funds 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. The Company’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.

The Company is also a party to litigation that seeks to reform certain assignments of mineral interests it acquired from Brigham. This matter involves the depth below the surface to which the assignments were effective. The plaintiff is seeking to reform the agreement such that the Company’s assignment would be revised to be 12 feet closer to the surface. This dispute affects one of the Company’s producing wells.

The ultimate outcome of these matters is ongoing and cannot presently be determined. However, in management’s opinion the likelihood of a material adverse outcome is remote. Accordingly, adjustments, if any, that might result from the resolution of this matter have not been reflected in the accompanying consolidated financial statements.

Quiet Title Action – Willerson Lease. In September 2013, the Company acquired from Chesapeake a 15% working interest in approximately 4,244 gross mineral acres referred to as the Willerson lease. In January 2014, Willerson inquired if their lease had terminated due to the failure to achieve production in paying quantities pursuant to the terms of the lease. The Company along with Crimson and Liberty filed a declaratory judgment action in the District Court of Dimmit County in May 2014 seeking a determination from the court that the lease remains valid and in effect. The lessors counterclaimed for breach of contract, trespass, and related causes of action. In January 2016, the lessors filed a third-party petition alleging breach of contract, trespass, and related causes of action against Chesapeake and EXCO Operating Company, LP. As of March 31, 2017 unevaluated oil and gas properties include $1,171,000 related to the leasehold costs that are subject to this matter. The matter has settled in 2017 with the Company’s portion being $75,000 plus the related legal fees of $165,000 as reflected in the Company’s financial statements under “Professional fees, insurance and other” as of March 31, 2017.

Arbitration of Employment Claim. A former employee has claimed that the Company owes up to $1.8 million under an Executive Severance and Non-Compete agreement (the “Agreement”) due to a change of control and termination of employment without cause. The Agreement requires that any disputes be submitted to binding arbitration and a request for arbitration was submitted by the parties in March 2016. This matter was settled in May 2017 for $175,000 plus non-essential equipment of $13,000 as reflected in the Company’s financial statements under “Rental and other income/(loss)” as of March 31, 2017.

Contingent Ownership Interests. As of March 31, 2017, the Company had recognized a contingent liability associated with uncertain ownership interests of $1,383. 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 condensed consolidated balance sheet as of March 31, 2017. While the Company has classified this entire amount as a current liability, 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 during 2017.

Anfield Gain Contingency. In 2007, the Company sold all of our uranium assets for cash and stock of the purchaser, Uranium One Inc. (“Uranium One”). The assets sold included a uranium mill in Utah and unpatented uranium claims in Wyoming, Colorado, Arizona and Utah. Pursuant to the asset purchase agreement, the Company was entitled to additional consideration from Uranium One up to $40,000 based on the performance of the mill, achievement of commercial production and royalties, but no additional consideration was ever received from Uranium One. In August 2014, the Company entered into an agreement with Anfield Resources Inc. (“Anfield”) whereby if Anfield was successful in acquiring the property from Uranium One, Anfield would be released from the future payment obligations stemming from the 2007 sale to Uranium One. On September 1, 2015, Anfield acquired the property from Uranium One and is now obligated to provide the following consideration to the Company:

The first tranche of common shares resulted in the issuance of 7,436,505 shares of Anfield with a market value of $750,000 and such shares were delivered to us in September 2015. The second tranche of shares resulted in the issuance of 3,937,652 additional shares of Anfield with a market value of $750,000, and such shares were delivered to us in September 2016. Since the trading volume in Anfield shares has increased beginning primarily in the quarterly period ending June 30, 2016, we determined a mark-to-market technique would be the most appropriate method to determine the fair value for Anfield shares. The primary factor in using a mark-to-market valuation in determining the fair value of Anfield shares is justified because of our belief that due to the increased liquidity in the stock, using current market prices for Anfield shares reflects the most accurate fair value calculation. At March 31, 2017, we determined the fair value of the Anfield shares to be approximately $0.9 million. The timing of any future receipt of cash from Anfield is not determinable and there can be no assurance that any cash will ever be received from Anfield or that the shares received from Anfield will ever be liquidated for cash.

Preferred Stock

The Company’s articles of incorporation authorize the issuance of up to 100,000 shares of preferred stock, $0.01 par value. Shares of preferred stock may be issued with such dividend, liquidation, voting and conversion features as may be determined by the Board of Directors without shareholder approval.  As discussed in Note 5, in February 2016 the Board of Directors approved the designation of 50,000 shares of Series A Convertible Preferred Stock in connection with the disposition of the Company’s mining segment.

Warrants

On December 21, 2016, the Company completed a registered direct offering of 1.0 million shares of common stock at a net price of $1.50 per share. Concurrently, the investors received warrants to purchase 1.0 million shares of Common Stock of the Company at an exercise price of $2.05 per share, subject to adjustment, for a period of five years from closing. The total net proceeds received by the Company was approximately $1.32 million. The fair value of the warrants upon issuance was $1.24 million, with the remaining $0.08 million being attributed to common stock. The warrants contain a dilutive issuance and other liability provisions which cause the warrants to be accounted for as a liability. Such warrant instruments are initially recorded as a liability and are accounted for at fair value with changes in fair value reported in earnings.

Stock Options

For the three months ended March 31, 2017 and 2016, total stock-based compensation expense related to stock options was $18,000 and $21,000 respectively. As of March 31, 2017, there was $62,000 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, 2017, no stock options were granted, exercised, forfeited or expired. Presented below is information about stock options outstanding and exercisable as of March 31, 2017 and December 31, 2016:

The following table summarizes information for stock options outstanding and exercisable at March 31, 2017:

As of March 31, 2017, no 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 $0.89 per share on March 31, 2017, there was no intrinsic value related to stock options outstanding as of March 31, 2017.

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 both January 2016 and January 2017 and the remaining shares will vest for 33,334 shares in January 2018. The fair market value of the 340,711 shares on the date of grant was approximately $511,000. On September 23, 2016, the Board of Directors granted restricted stock to each member of the Board for 58,500 shares per Board member for an aggregate grant of 351,000 shares. The vesting of 292,500 of such shares was accelerated in May 2017 in connection with the resignations of members of the Company’s Board of Directors. The closing price of the Company’s common stock on the grant date was $1.74, which is expected to result in an aggregate compensation charge of $611,000 as the stock vests. For the three months ended March 31, 2017 and 2016, total stock-based compensation expense related to restricted stock grants was $88,000 and $13,000 respectively. As of March 31, 2017, there was $84,000 of unrecognized expense related to unvested restricted stock grants, which will be recognized as stock-based compensation expense through January 2018.

For Federal income tax purposes, as of December 31, 2016 the Company had net operating loss and percentage depletion carryovers of approximately $74.7 million and $2.5 million, 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 $0.7 million 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, 2017 and 2016. Accordingly, the Company did not recognize an income tax benefit for the three months ended March 31, 2017 and 2016.

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, 2017, gross unrecognized tax benefits are immaterial and there was no change in such benefits during the three months ended March 31, 2017. The Company does not expect significant increase or decrease to the uncertain tax positions within the next twelve months.

Basic earnings (loss) per share is computed based on the weighted average number of common shares outstanding. For the three months ended March 31, 2017 and 2016, common stock equivalents excluded from the calculation of weighted average shares because they were antidilutive are as follows:

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 27% 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, 2017 and December 31, 2016, the Company had a liability to the Major Operator of $2,923,000 and $2,710,000 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, 2017, 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.

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:

Marketable Equity Securities Valuation Methodologies

The fair value of available for sale securities is based on quoted market prices obtained from independent pricing services. Accordingly, the Company has classified these instruments as Level 1.

Warrant Valuation Methodologies

The warrants contain a dilutive issuance and other liability provisions which cause the warrants to be accounted for as a liability. Such warrant instruments are initially recorded and valued as a level 3 liability and are accounted for at fair value with changes in fair value reported in earnings.

The Company estimated the value of the warrants issued with the Securities Purchase Agreement on December 31, 2016 to be $1,030,000, or $1.03 per warrant, using the Monte Carlo model with the following assumptions: a term expiring June 21, 2022, exercise price of $2.05, stock price of $1.28, average volatility rate of 90%, and a risk-free interest rate of 2.01%. The Company re-measured the warrants as of March 31, 2017, using the same Monte Carlo model, using the following assumptions: a term expiring June 21, 2022, exercise price of $2.05, stock price of $0.89, average volatility rate of 88%, and a risk-free interest rate of 1.97%. As of March 31, 2017, the fair value of the warrants was $690,000, or $0.69 per warrant, and was recorded as a liability on the accompanying consolidated balance sheets. An increase in any of the variables would cause an increase in the fair value of the warrants. Likewise, a decrease in any variable would cause a decrease in the value of the warrants.

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, 2017 and December 31, 2016 are as follows:

The following table presents a reconciliation of changes in assets and liabilities measured at fair value on a recurring basis for the period ended March 31, 2017 and the year ended December 31, 2016.

On April 5, 2017, for the period beginning May 1, 2017 through December 31, 2017, the Company entered into crude oil swap contracts for 300 barrels per day at $52.40 per barrel.

On May 2, 2017, the credit facility between U.S. Energy Corp.’s wholly-owned subsidiary, Energy One and Wells Fargo was sold, assigned and transferred to APEG Energy II, L.P. (“APEG”). APEG purchased and assumed all of Wells Fargo’s rights and obligations as the lender to Energy One under the credit facility. Concurrently, U.S. Energy Corp., Energy One and APEG entered into a Limited Forbearance Agreement dated May 2, 2017. The Company believes that the Forbearance Agreement will provide the parties sufficient time to work toward a long-term solution that enables the Company to execute its operational strategy and ensure value for existing shareholders.

The credit facility requires the Company’s compliance with certain restricted financial covenants. The Company previously violated the financial ratio covenants for the fiscal quarters ended September 30, 2016 and December 31, 2016, which constituted an event of default under the credit agreement, and the violation of said covenants has continued in 2017. Subject to continued performance and compliance by the Company and Energy One with the terms and conditions of the Forbearance Agreement and credit facility, APEG has agreed not to exercise its rights and remedies arising as a result of certain existing and prospective events of default under the credit facility until July 30, 2017. Commencing on May 2, 2017, interest shall accrue on the outstanding principal balance of the loans under the credit facility at a rate of 8.75% per annum. In the event of default under the Forbearance Agreement, the forbearance period will terminate immediately and, without further notice or opportunity to cure, APEG will be entitled to exercise all of its rights and remedies under the credit facility and Forbearance Agreement, including acceleration of the debt and foreclosure. For additional information please see the 8-K filed by the Company on May 8, 2017.

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 lease 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, 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

Effective May 1, 2017 through December 31, 2017, the Company entered into crude oil swap contracts for 300 barrels per day at $52.40 per barrel.

On May 2, 2017, the credit facility between U.S. Energy Corp.’s wholly-owned subsidiary, Energy One and Wells Fargo was sold, assigned and transferred to APEG Energy II, L.P. (“APEG”). APEG purchased and assumed all of Wells Fargo’s rights and obligations as the lender to Energy One under the credit facility. Concurrently, U.S. Energy Corp., Energy One and APEG entered into a Limited Forbearance Agreement dated May 2. The Company believes that the Forbearance Agreement will provide the parties sufficient time to work toward a long-term solution that enables the Company to execute its operational strategy and ensure value for existing shareholders.

The credit facility requires the Company’s compliance with certain restricted financial covenants. The Company previously violated the financial ratio covenants for the fiscal quarters ended September 30, 2016 and December 31, 2016, which constituted an event of default under the credit agreement, and the violation of said covenants has continued in 2017. Subject to continued performance and compliance by the Company and Energy One with the terms and conditions of the Forbearance Agreement and credit facility, APEG has agreed not to exercise its rights and remedies arising as a result of certain existing and prospective events of default under the credit facility until July 30, 2017. Commencing on May 2, 2017, interest shall accrue on the outstanding principal balance of the loans under the credit facility at a rate of 8.75% per annum. In the event of default under the Forbearance Agreement, the forbearance period will terminate immediately and, without further notice or opportunity to cure, APEG will be entitled to exercise all of its rights and remedies under the credit facility and Forbearance Agreement, including acceleration of the debt and foreclosure. For additional information please see the 8-K filed by the Company on May 8, 2017.

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 2016 Annual Report on Form 10-K filed with the SEC on April 17, 2017.

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, 2017 and 2016

During the three months ended March 31, 2017, we recorded a net loss of $0.7 million as compared to a net loss of $10.6 million for the three months ended March 31, 2016. Our loss from continuing operations was $0.7 million for the three months ended March 31, 2017 compared to $8.3 million for the three months ended March 31, 2016. In the following sections we discuss our revenue, operating expenses, non-operating income, and discontinued operations for the three months ended March 31, 2017 compared to the three months ended March 31, 2016.

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, 2017 and 2016 (dollars in thousands, except average sales prices):

The increase in our oil sales of $0.4 million for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016 was primarily the result of a 96% increase in the average oil price realized during the three months ended March 31, 2017. The increase in the average oil price realized offset a 27% reduction in our oil production quantity during the three months ended March 31, 2017. The increase in our gas sales of $0.3 million for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016 was driven by a 90% increase in our gas production combined with a 32% increase in the average gas price realized during the three months ended March 31, 2017. The increase in our net realized oil price is reflective of the partial recovery in global commodity prices during the first quarter of 2017. 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, 2017, we produced 49,885 BOE, or an average of 554 BOE per day, as compared to 50,628 BOE or 556 BOE per day during the comparable period in 2016. This 1% 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, 2017 and 2016 (dollars in thousands):

For the three months ended March 31, 2017, production taxes and other expenses increased by $0.2 million compared to the comparable period in 2016. Substantially all of this increase in production taxes resulted from increased oil and gas sales. For the three months ended March 31, 2017, lease operating expense decreased by $0.2 million which was primarily due to the implementation of cost reduction strategies by the operators of our wells. During 2017, we expect cost reduction implementation programs to continue during the prolonged global commodity price downtown.

Depreciation, depletion and amortization. Our DD&A rate for the three months ended March 31, 2017 was $5.25 per BOE compared to $15.45 per BOE for the three months ended March 31, 2016. 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, 2017 was $9.6 million of aggregate quarterly impairment charges that resulted from our quarterly Full Cost Ceiling limitations during 2016. During each of the quarters ended March 31, 2016 and June 30, 2016, 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, 2017 and 2016, we recorded impairment charges related to our oil and gas properties of $0.0 million and $7.0 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 beginning in 2015 and continuing through 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.

General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the three months ended March 31, 2017 and 2016 (dollars in thousands):

General and administrative expenses increased by $0.5 million for the three months ended March 31, 2017 compared to the three months ended March 31, 2016. This increase was primarily attributable to (i) an increase of $0.5 million in professional fees as we replaced some of the services previously performed by employees with consultants combined with a legal settlement on the Willerson lease (See Note 7 Commitments and Contingencies), and (ii) an increase in stock-based compensation which primarily resulted from the amortization of restricted stock grants issued in September 2016.

Non-Operating Income (Expense). Presented below is a comparison of our non-operating income (expense) for the three months ended March 31, 2017 and 2016 (dollars in thousands):

During the three months ending March 31, 2017, the Company had no outstanding crude derivative contacts outstanding and therefore did not recognize any gain or loss compared to a gain of $0.9 million for the comparable period in 2016. 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.

During the three months ending March 31, 2017, we realized a non-cash gain on the revaluation of our outstanding warrants of $0.3 million. Our warrant liability is accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. No warrants were outstanding for the period ending March 31, 2016. We will continue to revalue our outstanding warrants on a quarterly basis.

Interest expense decreased by $0.04 million during the three months ended March 31, 2017 compared to the comparable period in 2016. The decrease was attributable to the one-time amortization of a debt issuance cost that was recognized in the three months March 31, 2016. The average interest rate increased to 7.39% for the three months ended March 31, 2017 in comparison to 2.95% for the three months ended March 31, 2016. See Note 8 for additional information on the Employee Arbitration Settlement.

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, 2017 and 2016, we incurred operating expenses associated with the discontinued mining segment of $0 and $0.3 million, respectively.

In order to induce MEM to assume the Company’s obligations to operate the WTP we issued additional consideration in the form of 50,000 shares of Series A Convertible Preferred Stock. For the three months ended March 31, 2016, 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. There were no charges associated with discontinued operations for the period ended March 31, 2017.

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.

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, 2017 and 2016:

Liquidity and Capital Resources

The following table sets forth certain measures of our liquidity as of March 31, 2017 and December 31, 2016:

As of March 31, 2017, we have a working capital deficit of $6.8 million compared to a working capital deficit of $6.0 million as of December 31, 2016, an increase of $0.7 million. This increase was primarily attributable to a reduction in cash by $0.4 million, primarily driven by an increase in professional service fees, and an increase in payables to operators of $0.3 million, and an accrual for the settlement of the Employee Arbitration (See Note 7 Commitments and Contingencies).

As of March 31, 2017, Energy One and the Company were not in compliance with any of the financial covenants under its credit facility. Because the Company projects that it is unlikely that Energy One will regain compliance with all of the financial covenants before the July 30, 2017 maturity date, outstanding borrowings of $6.0 million are presented as a current liability in the accompanying consolidated balance sheet as of March 31, 2017.

On May 2, 2017, the credit facility between U.S. Energy Corp.’s wholly-owned subsidiary, Energy One and Wells Fargo was sold, assigned and transferred to APEG Energy II, L.P. (“APEG”). APEG purchased and assumed all of Wells Fargo’s rights and obligations as the lender to Energy One under the credit facility. Concurrently, U.S. Energy Corp., Energy One and APEG entered into a Limited Forbearance Agreement dated May 2, 2017. The Company believes that the Forbearance Agreement will provide the parties sufficient time to work toward a long-term solution that enables the Company to execute its operational strategy and ensure value for existing shareholders.

The credit facility requires the Company’s compliance with certain restricted financial covenants. The Company previously violated the financial ratio covenants for the fiscal quarters ended September 30, 2016 and December 31, 2016, which constituted an event of default under the credit agreement, and the violation of said covenants has continued in 2017. Subject to continued performance and compliance by the Company and Energy One with the terms and conditions of the Forbearance Agreement and credit facility, APEG has agreed not to exercise its rights and remedies arising as a result of certain existing and prospective events of default under the credit facility until July 30, 2017. Commencing on May 2, 2017, interest shall accrue on the outstanding principal balance of the loans under the credit facility at a rate of 8.75% per annum. In the event of default under the Forbearance Agreement, the forbearance period will terminate immediately and, without further notice or opportunity to cure, APEG will be entitled to exercise all of its rights and remedies under the credit facility and Forbearance Agreement, including acceleration of the debt and foreclosure. For additional information please see the 8-K filed by the Company on May 8, 2017.

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, 2017, the balance of the overpayment was approximately $2.9 million. Based on the oil and gas prices and costs used in the Company’s reserve report as of March 31, 2017, 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. 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 $1.4 million as of March 31, 2017. 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.

As of March 31, 2017, we had cash and equivalents of $2.2 million, and we expect to maintain cash balances in this range for some time. We also expect potential investors and lenders will find our 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 continued 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.

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 2017, 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 2016 Annual Report on Form 10-K.

Cash Flows

The following table summarizes our cash flows for the three months ended March 31, 2017 and 2016 (in thousands):

Operating Activities. Cash used in operating activities for the three months ended March 31, 2017 was $0.3 million as compared to cash used by operated activities $1.1 million for the comparable period in 2016, an improvement of $0.8 million. The improvement is primarily attributed to severance agreements with previous employees being paid in the period ended March 31, 2016.

Investing Activities. Cash used in investing activities for the three months ended March 31, 2017 was $0.02 million as compared to cash used in investing activities of $0.01 million for the comparable period in 2016. The primary use of cash in our investing activities for 2017 was for capital workovers for our oil and gas drilling activities.

Financing Activities. For the three months ended March 31, 2017, we had no cash flow from financing compared to March 31, 2016 of a nominal amount received for the issuance of Series A Convertible Preferred Stock.

Discontinued Operations. We had no cash used for discontinued operations for the three months ended of March 31, 2017. Cash used in discontinued operations was $0.3 million for the three months ended March 31, 2016.

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

Based on an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of our quarter ended March 31, 2017, our Chief Executive Officer and Principal Financial Officer (both roles are currently held by the same individual) determined that our controls were not adequate due to a vacancy in certain accounting and finance consulting positions that the Company has historically utilized to implement the Company’s review of key controls in a timely manner. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. Accordingly, based on this material weakness, our Chief Executive Officer and Principal Financial Officer concluded that our disclosure controls and procedures were not effective as of the end of the period covered by this Quarterly Report on Form 10-Q, March 31, 2017 as it relates to the timely implementation of the Company’s review of key controls. The Company has addressed this weakness by filling the consulting vacancy with professionals with experience in implementing a full review of key controls on an ongoing basis.

Changes in Internal Control over Financial Reporting

During the fiscal quarter ended March 31, 2017, 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 above in Note 7 to the Financial Statements as to the Willerson matter and an employment claim, there have been no material changes from the legal proceedings as previously disclosed in Item 3 of our 2016 Annual Report on Form 10-K.

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

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.