US ENERGY CORP - Quarter Report: 2017 September (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 ☑ NO ☐

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

Indicate by check mark 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 ☑

The registrant had 5,983,498 shares of its $0.01 par value common stock outstanding as of November 14, 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)

U.S. ENERGY CORP. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE LOSS

(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 previous quarterly reports on Form 10-Q 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 NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016

(In Thousands)

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

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands, Except Per Share Amounts)

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 on 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, please refer to the consolidated financial statements and footnotes thereto included in our Annual Report on Form 10-K, 10-K/A for the year ended December 31, 2016 filed on April 17, 2017 and April 28, 2017. Our financial condition as of September 30, 2017, and operating results for the nine months ended September 30, 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 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; 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

Revenue recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The adoption of this guidance is not expected to impact the Company’s financial position or results of operations.

Financial instruments. In January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The adoption of this guidance is not expected to impact the Company’s financial position or results of operations.

Statement of cash flows. In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations, but could result in presentation changes on the Company’s statement of cash flows.

Business combinations. In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Stock-based compensation. In May 2017, the FASB issued Accounting Standards Update No. 2017-09, Scope of Modification Accounting (“ASU 2017-09”), which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The adoption of ASU 2017-09 will become effective for annual periods beginning after December 15, 2017, and the Company is currently evaluating the impact that it will have on its financial position, cash flows and results of operations.

As of September 30, 2017, the Company has a working capital deficit of $0.8 million and an accumulated deficit of $124.6 million. Additionally, the Company incurred a net loss of $0.4 million and $0.8 million for the three and nine months ended September 30, 2017, respectively.

On May 2, 2017, the Amended and Restated Credit Agreement, dated July 30, 2010, between U.S. Energy Corp.’s wholly-owned subsidiary, Energy One and Wells Fargo Bank N.A. was sold, assigned and transferred to APEG Energy II, L.P. (“APEG”) (the “Credit Agreement”). 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. On June 28, 2017, U.S. Energy Corp., Energy One and APEG entered into a Fifth Amendment to the Credit Agreement providing for, among other things, an extension of the maturity date to July 19, 2019, new financial coverage ratio covenants and a limited release and waiver with respect to any historical Company non-compliance with any and all financial covenants by the Company. As of September 30, 2017, the Company was in compliance with all financial covenants and fully conforming with all requirements under its credit agreement. On October 5, 2017, U.S. Energy Corp. announced that the Company, the Company’s wholly owned subsidiary Energy One LLC and APEG, entered into an exchange agreement (the “Exchange Agreement”), pursuant to which, on the terms and subject to the conditions of the Exchange Agreement, APEG will exchange $4,463,380 of outstanding borrowings under the Company’s Credit Facility, for 5,819,270 new shares of common stock of the Company. Please refer to Note 13 entitled “Subsequent Events” for further information.

As of September 30, 2017, the Company had cash and equivalents of $1.8 million. Management believes overhead and mining expense eliminations have poised the Company to survive the continued 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 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, 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 existing cash on hand. 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. Presented below is a summary of outstanding crude oil and natural gas swaps as of September 30, 2017.

Unrealized gains and losses resulting from derivatives are recorded at fair value in the consolidated balance sheet. Changes in fair value are included in the “change in unrealized gain (loss) on oil price risk derivatives” in the consolidated statements of operations. For the nine months ended September 30, 2017 and 2016, the Company’s unrealized gains (losses) from derivatives amounted to $0.03 and $(1.6) million, respectively. Derivative contract settlements are included in the “realized gain (loss) on oil price risk derivatives” in the consolidated statement of operations. All derivative positions are carried at their fair value on the condensed consolidated balance sheet and are included in “Commodity price risk derivatives.” For the nine months ended September 30, 2017 and 2016, the Company’s realized gains from derivatives amounted to $0.2 and $1.4 million, respectively.

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 September 30, 2017, the Company used a price of $43.89 per barrel for oil and $2.92 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 Company used a discount factor of 10%.

For the nine months ended September 30, 2017 and 2016, ceiling test impairment charges for the Company’s oil and gas properties amounted to $0 and $9.6 million, 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 September 30, 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 nine months ended September 30, 2017 and 2016:

Energy One, a wholly-owned subsidiary the Company, has a credit facility with APEG Energy II, L.P. (“APEG”). As of September 30, 2017 and 2016, outstanding borrowings under the credit facility amounted to $6.0 million. U.S. Energy Corp., Energy One and APEG entered into a Limited Forbearance Agreement dated May 2, 2017. On June 28, 2017, U.S. Energy Corp., Energy One and APEG entered into a Fifth Amendment to the credit facility providing for, among other things, an extension of the maturity date to July 19, 2019, new financial coverage ratio covenants and a waiver with respect to any historical Company non-compliance with any and all financial covenants. As of September 30, 2017 and 2016, the borrowing base was $6.0 million. Borrowings under the credit facility are secured 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 2019 if the Company remains in compliance with the covenants under the credit facility. The interest rate on the credit facility is currently fixed at 8.75%. Please refer to Note 13 entitled “Subsequent Events” for further information.

Energy One is required to comply with customary affirmative covenants and with certain negative covenants. The principal negative financial covenants do not permit (as the following terms are defined in the Fifth Amendment) (i) PDP Coverage Ratio to be less than 1.2 to 1; and (ii) the current ratio to be less than 1.0 to 1.0. Please note that the liabilities carried on the Company’s balance sheet under “Payable to major operator” and “Contingent ownership interests” are excluded from any covenant calculations. As of September 30, 2017, the Company is in compliance with all credit facility covenants. 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.

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:

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 matter was settled on July 7, 2017 with the court ruling in favor Brigham and therefore U.S. Energy will retain all interests in all subject leases.

Texas 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. The matter has settled in 2017 with the Company’s portion of such settlement being $75,000 plus related legal fees of $165,000 as reflected in the Company’s financial statements under “Professional fees, insurance and other” as of September 30, 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 $15,000 as reflected in the Company’s financial statements under “Rental and other income/(loss)” as of September 30, 2017.

Contingent Ownership Interests. As of September 30, 2017, the Company had recognized a contingent liability associated with uncertain ownership interests of $1.6 million. 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 and group wells and 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 September 30, 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. This matter was settled on October 4, 2017. Please refer to Note 13 entitled “Subsequent Events” for further information.

Anfield Gain Contingency. In 2007, the Company sold all of its 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, among other things, the performance of the mill, and achievement of commercial production and royalties, however no additional consideration has been 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 the Company 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 the Company in September 2016. Since the trading volume in Anfield shares has increased, beginning primarily in the quarter ended June 30, 2016, the Company 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 the Company’s 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 September 30, 2017, we determined the fair value of the Anfield shares to be approximately $0.5 million. Please refer to Note 13 entitled “Subsequent Events” for further information.

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

From time to time, the Company grants stock options under its incentive plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. These awards typically expire ten years from the grant date.

During the nine months ended September 30, 2017, the Company granted its board of directors 60,000 options in aggregate at an exercise price of $0.72 per share with a 10-year term. The shares were immediately vested and are included in the stock-based compensation expense related to stock options for the nine months ended September 30, 2017 of $65,000 in comparison to $34,000 recorded for the comparable period in 2016. Management used a Black-Scholes valuation model to assess the stock-based compensation expense related to the options using the following input assumptions: 80% volatility rate, 2.34% risk free rate, and no associated dividend payments. The Company had $15,000 of unrecognized compensation expense related to non-vested stock options to be recognized through January 2018 as of September 30, 2017 and $80,000 of unrecognized compensation expense related to non-vested stock options as of September 30, 2016.

As of September 30, 2017, the Company had 279,687 stock options outstanding with exercise prices ranging from $0.72 to $30.24 with a weighted average exercise price of $10.76 and a remaining weighted-average period of 5.7 years. These shares include 274,132 shares which are exercisable as September 30, 2017 with a weighted average price of $10.79 per share.

Presented below is information about stock options outstanding and exercisable as of September 30, 2017 and December 31, 2016:

The following table summarizes information for stock options outstanding and exercisable at September 30, 2017:

As of September 30, 2017, 1,151,000 shares are available for future grants under the Company’s stock option plans.

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. As of September 30, 2017, there was $12,671 of unrecognized expense related to unvested restricted stock grants issued in January 2015, which will be recognized as stock-based compensation expense through January 2018.

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. In connection with the resignations of four members of the Company’s Board of Directors, the restricted stock grants were amended and the members of the Board of Directors subsequently agreed to accept 33,332 fully-vested shares each, in lieu of the 58,500 share grants for a total of 199,992 shares. The closing price of the Company’s common stock on the grant date was $1.05, resulting in an aggregate compensation charge of $209,000. As of September 30, 2017, the Company has accrued for the entire aggregate compensation charge over prior quarters and there was $0 of unrecognized expense related to the September 23, 2016 grants. For the nine months ended September 30, 2017 and 2016, total stock-based compensation expense related to restricted stock grants was $189,000 and $25,000 respectively.

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 September 30, 2017 and 2016. Accordingly, the Company did not recognize an income tax benefit for the nine months ended September 30, 2017 and 2016. Furthermore, the Company projects a net loss for the fiscal year ended December 31, 2017.

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 September 30, 2017, gross unrecognized tax benefits are immaterial and there was no change in such benefits during the three months ended September 30, 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. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of unvested restricted stock awards and contingently issuable shares during the periods presented, unless their effect is anti-dilutive. For the three and nine months ended September 30, 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 38% 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 September 30, 2017 and December 31, 2016, the Company had a liability to the Major Operator of $2,442,176 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. Accordingly, the aggregate balances are presented as current liabilities in the accompanying consolidated balance sheets. This matter was settled on October 4, 2017. Please refer to Note 13 entitled “Subsequent Events” for further information.

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 September 30, 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 $0.77, average volatility rate of 90%, and a risk-free interest rate of 2.00%. As of September 30, 2017, the fair value of the warrants was $580,000, or $0.58 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 September 30, 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 September 30, 2017 and the year ended December 31, 2016.

On October 4, 2017, U.S. Energy Corp. (the “Company”), the Company’s wholly owned subsidiary Energy One LLC and Statoil Oil and Gas LP (“Statoil”) entered into a purchase and sale agreement (the “Purchase Agreement”), pursuant to which, on the terms, and subject to the conditions of the Purchase Agreement, the Company assigned, sold, and conveyed certain non-operated assets in the Williston Basin, North Dakota in consideration for the elimination of $4.0 million in outstanding liabilities and payment by Statoil to the Company of $2.0 million in cash. U.S. Energy has historically accounted for the eliminated liabilities on the Company’s balance sheet under “Payable to major operator” and “Contingent ownership interests.” The Purchase Agreement was unanimously approved by the board of directors of the Company and closed on October 5, 2017, with an effective date of August 1, 2017.

On October 5, 2017, U.S. Energy Corp. announced that the Company, the Company’s wholly owned subsidiary Energy One LLC and APEG Energy II, L.P., (“APEG”), an entity controlled by Angelus Private Equity Group, LLC entered into an exchange agreement (the “Exchange Agreement”), pursuant to which, on the terms and subject to the conditions of the Exchange Agreement, APEG will exchange $4,463,380 of outstanding borrowings under the Company’s Credit Facility, for 5,819,270 new shares of common stock of the Company, par value $0.01 per share, representing an exchange price of $0.767 representing a 1.3% premium over the 30-day volume weighted average price of the Company’s common stock on September 20, 2017 (the “Exchange Shares”). Accrued, unpaid interest on the Credit Facility held by APEG will be paid in cash at the closing of the transaction. Immediately following the close of the transaction, APEG will hold approximately 49.3% of the outstanding Common Stock of U.S. Energy. The Company expects to close the Transaction in the fourth quarter of 2017. The Transaction is subject to certain customary closing conditions, including approval by the Company’s shareholders of the Transaction.

On November 6, 2017 U.S. Energy Corp. announced it has received scheduled proceeds from a previously announced August 2014 transaction regarding the divestment of uranium mining assets in exchange for $2.5 million of stock in Anfield Resources Inc. Pursuant to the agreement, payments for the divestiture were structured as three issuances of stock with the most recent and final $1.0 million issuance consisting of 24,942,200 shares of Anfield. The recently received shares are restricted until March 2, 2018. U.S. Energy now holds 36,316,357 shares of Anfield representing approximately 19.2% of the common stock outstanding.

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 2016 Annual Report on Form 10-K, 10-K/A 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

On October 4, 2017, U.S. Energy Corp. (the “Company”), the Company’s wholly owned subsidiary Energy One LLC and Statoil Oil and Gas LP (“Statoil”) entered into a purchase and sale agreement (the “Purchase Agreement”), pursuant to which, on the terms, and subject to the conditions of the Purchase Agreement, the Company assigned, sold, and conveyed certain non-operated assets in the Williston Basin, North Dakota in consideration for the elimination of $4.0 million in outstanding liabilities and payment by Statoil to the Company of $2.0 million in cash. U.S. Energy has historically accounted for the eliminated liabilities on the Company’s balance sheet under “Payable to major operator” and “Contingent ownership interests.” The Purchase Agreement was unanimously approved by the board of directors of the Company and closed on October 5, 2017, with an effective date of August 1, 2017.

On October 5, 2017, U.S. Energy Corp. announced that the Company, the Company’s wholly owned subsidiary Energy One LLC and APEG Energy II, L.P., (“APEG”), an entity controlled by Angelus Private Equity Group, LLC entered into an exchange agreement (the “Exchange Agreement”), pursuant to which, on the terms and subject to the conditions of the Exchange Agreement, APEG will exchange $4,463,380 of outstanding borrowings under the Company’s Credit Facility, for 5,819,270 new shares of common stock of the Company, par value $0.01 per share, representing an exchange price of $0.767 representing a 1.3% premium over the 30 day volume weighted average price of the Company’s common stock on September 20, 2017 (the “Exchange Shares”). Accrued, unpaid interest on the Credit Facility held by APEG will be paid in cash at the closing of the transaction. Immediately following the close of the transaction, APEG will hold approximately 49.9% of the outstanding Common Stock of U.S. Energy. The Company expects to close the transaction in the fourth quarter of 2017. The transaction is subject to certain customary closing conditions, including approval by the Company’s shareholders of the transaction.

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, 10-K/A filed with the SEC on April 17, 2017 and April 28, 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 September 30, 2017 and 2016

During the three months ended September 30, 2017, we recorded a net loss of $0.4 million as compared to a net loss of $0.3 million for the three months ended September 30, 2016. In the following sections we discuss our revenue, operating expenses, non-operating income, and discontinued operations for the three months ended September 30, 2017 compared to the three months ended September 30, 2016.

Revenue. Presented below is a comparison of our oil and gas sales, production quantities and average sales prices for the three months ended September 30, 2017 and 2016 (dollars in thousands, except average sales prices):

The decrease in our oil sales of $0.2 million for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016 was primarily the result of a 28% decrease in oil production during the three months ended September 30, 2017. The 22% increase in the average oil price realized partially offset the reduction in our oil production quantity during the three months ended September 30, 2017. The decrease in our gas sales of $0.1 million for the three months September 30, 2017 as compared to the three months ended September 30, 2016 was driven by a 56% decrease in our gas production during the three months ended September 30, 2017. The primary driver in the decrease in our gas production was the performance of necessary maintenance on a specific gas producing well that the Company holds a significant working interest in during the months of July and August 2017. The decrease in gas production was partially offset by a 39% increase in the average gas price realized. The increase in our net realized oil price is reflective of the partial recovery in global commodity prices during 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 $6.00 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 September 30, 2017, we produced 42,637 BOE, or an average of 463 BOE per day, as compared to 70,410 BOE or 765 BOE per day during the comparable period in 2016. This 36% reduction was attributable to several factors, including (i) the normal decline in production for wells in the area of our properties, (ii) downtime associated with the maintenance of a gas producing well of which the Company holds a significant working interest, (iii) the Company did not add significant reserves from drilling or acquisition over the past year, and (iv) the low commodity price environment incentivizes operators to scale back production until prices recover.

Oil and Gas Production Costs. Presented below is a comparison of the Company’s oil and gas production costs for the three months ended September 30, 2017 and 2016 (dollars in thousands):

For the three months ended September 30, 2017, production taxes and other expenses slightly decreased compared to the comparable period in 2016. The decrease in production taxes resulted from decreased revenues from oil and gas sales. For the three months ended September 30, 2017, lease operating expense decreased by $0.5 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 September 30, 2017 was $3.23 per BOE compared to $9.50 per BOE for the three months ended September 30, 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 September 30, 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 September 30, 2017 and 2016, we did not record any impairment charges related to our oil and gas properties. 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 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 September 30, 2017 and 2016 (dollars in thousands):

General and administrative expenses decreased by $0.1 million for the three months ended September 30, 2017 compared to the three months ended September 30, 2016. This decrease was primarily attributable a decrease of $0.2 million in professional fees associated with the Company’s operations. The decrease in professional fees was partially offset by a $0.1 million increase in stock based compensation.

Non-Operating Income (Expense). Presented below is a comparison of our non-operating income (expense) for the three months ended September 30, 2017 and 2016 (dollars in thousands):

During the three months ending September 30, 2017, the Company had a realized gain on oil price risk derivatives of $0.1 million compared to a gain of $0.1 million for the comparable period in 2016. The Company had an unrealized loss on oil price risk derivatives of $0.3 million for the three months ended September 30, 2017 compared to a loss of $0.1 million for the comparable period for 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 September 30, 2017, the Company recognized $0.1 million on rental and other income (expense), an increase of $0.1 million over the comparable period in 2016. The increase was primarily due to an increase in office occupancy in the Company’s Riverton, WY office building.

During the three months ending September 30, 2017, we realized a non-cash loss on the revaluation of our outstanding warrants of $0.1 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 September 30, 2016. We will continue to revalue our outstanding warrants on a quarterly basis.

Interest expense increased by $0.02 million during the three months ended September 30, 2017 compared to the comparable period in 2016. The increase was attributable to an increase in average interest rate which was partially offset by one-time amortization of debt issuance costs associated with the amendment of our credit agreement during the third quarter of 2016. The average interest rate increased to 8.75% for the three months ended September 30, 2017 in comparison to 3.19% for the three months ended September 30, 2016.

Discontinued Operations. In February 2016 the Company 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 September 30, 2017 and 2016, we did not incur any operating expenses associated with the discontinued mining segment.

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 September 30, 2017.

Comparison of our Statements of Operations for the Nine Months Ended September 30, 2017 and 2016

During the nine months ended September 30, 2017, we recorded a net loss of $0.8 million as compared to a net loss of $15.0 million for the nine months ended September 30, 2016. Our loss from continuing operations was $0.8 million for nine months ended September 30, 2017 compared to $12.6 million for the nine months ended September 30, 2016. In the following sections we discuss our revenue, operating expenses, non-operating income, and discontinued operations for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016.

Revenue. Presented below is a comparison of our oil and gas sales, production quantities and average sales prices for the nine months ended September 30, 2017 and 2016 (dollars in thousands, except average sales prices):

The increase in our oil sales of $0.1 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 was primarily the result of a 34% increase in the average oil price realized during the nine months ended September 30, 2017. The increase in the average oil price realized offset a 24% reduction in our oil production quantity during the nine months ended September 30, 2017. The increase in our gas sales of $0.2 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 was driven by a 55% increase in the average gas price realized during the nine months ended September 30, 2017 which offset a 18% decrease in our gas production quantity for the same period. The increase in our net realized commodity prices is reflective of the partial recovery in global commodity prices during 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 $6.00 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 nine months ended September 30, 2017, we produced 150,890 BOE, or an average of 553 BOE per day, as compared to 192,053 BOE or 702 BOE per day during the comparable period in 2016. This 21% reduction was attributable to several factors, including (i) the normal decline in production for wells in the area of our properties, (ii) downtime associated with the maintenance of a gas producing well that the Company holds a significant working interest, (iii) the Company did not add significant reserves from drilling or acquisition over the past year, and (iv) the low price environment incentivizes operators 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 nine months ended September 30, 2017 and 2016 (dollars in thousands):

For the nine months ended September 30, 2017, production taxes and other expenses increased by $0.1 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 nine months ended September 30, 2017, lease operating expense decreased by $1.2 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 nine months ended September 30, 2017 was $3.93 per BOE compared to $12.05 per BOE for the nine months ended September 30, 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 nine months ended September 30, 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 nine months ended September 30, 2017 and 2016, we recorded impairment charges related to our oil and gas properties of $0.0 million and $9.6 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):

General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the nine months ended September 30, 2017 and 2016 (dollars in thousands):

General and administrative expenses increased by $0.7 million for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016. This increase was primarily attributable to (i) an increase of $0.4 million in professional fees primarily driven by increased legal costs associated with our debt refinancing efforts 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 previously issued stock grants.

Non-Operating Income (Expense). Presented below is a comparison of our non-operating income (expense) for the nine months ended September 30, 2017 and 2016 (dollars in thousands):

During the nine months ending September 30, 2017, the Company had a realized gain on oil price risk derivatives of $0.2 million and of $1.4 million for the comparable period in 2016. We had an unrealized gain on oil price risk derivatives of $0.03 million for the nine months ended September 30, 2017 compared to a loss of $1.6 million for the comparable period for 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 nine months ending September 30, 2017, the Company realized an expense of $0.3 million on rental and other income (expense), an increase of $0.2 million over the comparable period in 2016. The increased expense was primarily due to an increase in office rental expenses of $0.1 million combined with a $0.2 million settlement associated with a former employee claim. Please refer to Note 7 entitled “Commitment and Contingencies” for more information.

During the nine months ending September 30, 2017, we realized a non-cash gain on the revaluation of our outstanding warrants of $0.5 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 nine months ended September 30, 2016. We will continue to revalue our outstanding warrants on a quarterly basis.

Interest expense increased by $0.02 million during the nine months ended September 30, 2017 compared to the comparable period in 2016. The increase was attributable to an increase in average interest rate which was partially offset by one-time amortization of debt issuance costs associated with the amendment of our credit agreement during the third quarter of 2016. The average interest rate increased to 7.68% for the nine months ended September 30, 2017 in comparison to 3.19% for the nine months ended September 30, 2016.

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 nine months ended September 30, 2017 and 2016, we incurred operating expenses associated with the discontinued mining segment of $0 and $2.5 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 nine month period ended September 30, 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.

The following table provides reconciliations of income (loss) from continuing operations to adjusted EBITDAX for the three and nine months ended September 30, 2017 and 2016:

Liquidity and Capital Resources

The following table sets forth certain measures of our liquidity as of September 30, 2017 and December 31, 2016: