Edgar Filing: US ENERGY CORP

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ	Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period Ended June 30, 2016

¨	Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
	For the transition period from to

Commission File Number 000-6814

U.S. ENERGY CORP.

(Exact Name of Registrant as Specified in its Charter)

Wyoming		83-0205516
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

4643 S. Ulster Street, Suite 970, Denver, CO		80237
(Address of principal executive offices)		(Zip Code)

Registrant's telephone number, including area code:		(303) 993-3200

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.

Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company þ

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 4,769,571 shares of its $0.01 par value common stock outstanding as of August 11, 2016.

TABLE OF CONTENTS

	Page
Part I. FINANCIAL INFORMATION

Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015	3
Condensed Consolidated Statements of Operations and Comprehensive Loss for the Three and Six Months Ended June 30, 2016 and 2015	4
Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Six Months Ended June 30, 2016	5
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2016 and 2015	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Result of Operations	20
Item 3. Quantitative and Qualitative Disclosures About Market Risk	32
Item 4. Controls and Procedures	32

Part II. OTHER INFORMATION

Item 1. Legal Proceedings	33
Item 1A. Risk Factors	33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3. Defaults Upon Senior Securities	33
Item 4. Mine Safety Disclosures	33
Item 5. Other Information	33
Item 6. Exhibits	33

Signatures	34

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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)

	June 30,			December 31,
	2016			2015
ASSETS
Current assets:
Cash and equivalents	$	1,360		$	3,354
Marketable equity securities		1,178			251
Oil and gas sales receivable		834			1,143
Assets held for sale		653			-
Prepaid expenses and other		319			136
Oil price risk derivatives		174			1,634
Discontinued operations - assets of mining segment		135			318

Total current assets		4,653			6,836

Oil and gas properties under full cost method:
Unevaluated properties		4,665			5,664
Evaluated properties		89,402			97,912
Less accumulated depreciation, depletion and amortization		(81,774	)		(80,144	)
Net oil and gas properties		12,293			23,432

Other assets:
Property and equipment, net		1,934			2,658
Other assets		158			206

Total other assets		2,092			2,864

Total assets	$	19,038		$	33,132

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Payable to major operator	$	3,302		$	4,159
Contingent ownership interests		3,593			3,108
Trade payables and accrued expenses		1,216			1,791
Accrued compensation and benefits		51			1,352
Current portion of long-term debt		6,000			6,000
Discontinued operations of mining properties		-			204
Total current liabilities		14,162			16,614

Noncurrent liabilities:
Asset retirement obligations		1,054			1,038
Other accrued liabilities		173			5
Total noncurrent liabilities		1,227			1,043

Commitments and contingencies (Note 9)

Shareholders' equity:
Preferred stock, par value $0.01 per share. Authorized 100,000 shares, issued and outstanding 50,000 shares of Series A Convertible Preferred Stock in 2016; liquidation preference of $2,034 as of June 30, 2016		1			-
Common stock, $0.01 par value; unlimited shares authorized; issued and outstanding 4,704,267 shares in 2016 and 4,699,956 shares in 2015		47			47
Additional paid-in capital		127,197			125,133
Accumulated deficit		(124,523	)		(109,705	)
Other comprehensive income		927			-

Total shareholders' equity		3,649			15,475

Total liabilities and shareholders' equity	$	19,038		$	33,132

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

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U.S. ENERGY CORP. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

(In Thousands, Except Share and Per Share Amounts)

	Three Months Ended						Six Months Ended
	June 30:						June 30:
	2016			2015			2016			2015

Revenue:
Oil	$	1,677		$	2,934		$	2,541		$	5,231
Natural gas and liquids		319			351			521			733

Total revenue		1,996			3,285			3,062			5,964

Operating expenses:
Oil and gas operations:
Production costs		1,434			2,021			2,464			3,873
Depreciation, depletion and amortization		864			2,055			1,646			4,929
Impairment of oil and gas properties		2,611			3,208			9,568			22,448
General and administrative:
Compensation and benefits, including directors		172			676			311			1,530
Stock-based compensation		34			109			68			224
Professional services		541			274			768			540
Insurance, rent and other		16			162			183			407

Total operating expenses		5,672			8,505			15,008			33,951

Operating loss		(3,676	)		(5,220	)		(11,946	)		(27,987	)

Other income (expense):
Realized gain (loss) on oil price risk derivatives		380			(25	)		1,262			(139	)
Change in unrealized gain (loss) on oil price risk derivatives		(887	)		(272	)		(1,460	)		(335	)
Gain on sale of assets		100			-			100			16
Rental and other income, net of expenses		(48	)		10			(79	)		50
Interest expense		(75	)		(66	)		(247	)		(129	)

Loss from continuing operations		(4,206	)		(5,573	)		(12,370	)		(28,524	)

Loss from discontinued operations		(10	)		(707	)		(2,448	)		(1,459	)

Net loss		(4,216	)		(6,280	)		(14,818	)		(29,983	)
Other comprehensive loss:
Unrealized gain in marketable equity securities		927			5			927			5

Comprehensive loss	$	(3,289)		$	(6,275	)	$	(13,891	)	$	(29,978)

Loss from continuing operations applicable to common shareholders:
Loss from continuing operations	$	(4,206	)	$	(5,573	)	$	(12,370	)	$	(28,524	)
Accrued dividends related to Series A Convertible Preferred Stock		(62	)		-			(96	)		-

Loss from continuing operations applicable to common shareholders	$	(4,268	)	$	(5,573	)	$	(12,466	)	$	(28,524	)

Earnings (loss) per share applicable to common shareholders (basic and diluted):
Continuing operations	$	(0.89	)	$	(1.19	)	$	(2.63	)	$	(6.10	)
Discontinued operations		-			(0.15	)		(0.52	)		(0.31	)

Total	$	(0.90	)	$	(1.34	)	$	(3.15	)	$	(6.41	)

Weighted average shares outstanding- basic and diluted		4,705,000			4,675,000			4,705,000			4,675,000

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

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U.S. ENERGY CORP. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2016

(In Thousands, Except Share Amounts)

																Accumulated
										Additional						Other
	Preferred Stock				Common Stock					Paid-in			Accumulated			Comprehensive
	Shares		Amount		Shares			Amount		Capital			Deficit			Income		Total

Balances, December 31, 2015		-	$	-		4,699,956		$	47	$	125,133		$	(109,705	)	$	-	$	15,475
Issuance of common stock upon vesting of restricted common stock, net		-		-		5,556			-		-			-			-		-
Stock-based compensation		-		-		-			-		68			-			-		68
Issuance of Series A Convertible Preferred Stock in disposition of mining segment		50,000		1		-			-		1,999			-			-		2,000
Cash payment for fractional shares in reverse stock split		-		-		(1,245	)		-		(3	)		-			-		(3	)
Unrealized gain on marketable equity securities		-		-		-			-		-			-			927		927
Net loss		-		-		-			-		-			(14,818	)		-		(14,818	)

Balances, June 30, 2016		50,000	$	1		4,704,267		$	47	$	127,197		$	(124,523	)	$	927	$	3,649

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

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U.S. ENERGY CORP. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2016 AND 2015

(In Thousands)

	2016			2015

Cash flows from operating activities:
Net loss	$	(14,818	)	$	(29,983	)
Loss from discontinued operations		2,448			1,459
Loss from continuing operations		(12,370	)		(28,524	)
Adjustments to reconcile loss from continuing operations to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		1,718			5,002
Impairment of oil and gas properties		9,568			22,448
Change in fair value of oil price risk derivative		1,460			335
Amortization of debt issuance costs		152			28
Stock-based compensation		68			224
Gain on sale of assets		(100	)		(16	)
Changes in operating assets and liabilities:
Decrease (increase) in:
Oil and gas sales receivable		309			1,399
Other assets		(160	)		50
Increase (decrease) in:
Accounts payable and other liabilities		(948	)		2,580
Accrued compensation and benefits		(1,131	)		(10	)

Net cash provided by (used in) operating activities		(1,434	)		3,516

Cash flows from investing activities:
Capital expenditures		(86	)		(3,547	)
Proceeds from settlement of lawsuit involving oil and gas properties		-			1,500
Proceeds from sale of property and equipment		-			16
Net change in restricted investments		-			(30	)

Net cash used in investing activities:		(86	)		(2,061	)
Cash flows from financing activities:
Proceeds from issuance of preferred stock		1			-
Payments for debt issuance costs		(24	)		-
Cash payment for fractional shares in reverse stock split		(3	)		-

Net cash used in financing activities		(26	)		-

Discontinued operations:
Net cash used in operating activities for discontinued operations		(448	)		(1,398	)

Net increase (decrease) in cash and equivalents		(1,994	)		57

Cash and equivalents, beginning of period		3,354			4,010

Cash and equivalents, end of period	$	1,360		$	4,067

Supplemental disclosures of cash flow information:
Income tax paid	$	-		$	-

Interest paid	$	108		$	129

Non-cash investing and financing activities:
Issuance of preferred stock in disposition of mining segment	$	1,999		$	-

Elimination of asset retirement obligations in disposition of mining segment	$	204		$	-

Unrealized gain on marketable equity securities	$	927		$	5


Net additions to oil and gas properties through asset retirement obligations	$	1		$	61

Increase (decrease) in accrued capital expenditures	$	-		$	1,325

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

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U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands, Except Per Share Amounts)

ORGANIZATION, OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Organization and Operations

U.S. Energy Corp. (collectively with its subsidiaries referred to as the “Company” or “U.S. Energy”) was incorporated in the State of Wyoming on January 26, 1966. The Company’s principal business activities are focused 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, refer to the consolidated financial statements and footnotes thereto included in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2015. The Company’s financial condition as of June 30, 2016, and operating results for the three and six months ended June 30, 2016 are not necessarily indicative of the financial condition and results of operations that may be expected for any future interim period or for the year ending December 31, 2016.

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

Reverse Stock Split

The Company held its annual meeting of shareholders on June 20, 2016. At the meeting, the Company’s shareholders approved Articles of Amendment to Restated Articles of Incorporation (the “Amendment”) to effect a six shares for one share reverse stock split of the Company’s $0.01 par value common stock (the “Reverse Stock Split”). The Amendment was filed with the Wyoming Secretary of State and was effective on June 20, 2016.

As a result of the Reverse Stock Split, every six shares of issued and outstanding common stock were automatically combined into one issued and outstanding share of common stock, without any change in the par value per share or the number of shares of common stock authorized. No fractional shares were issued as a result of the Reverse Stock Split. Fractional shares that would otherwise have resulted from the Reverse Stock Split were paid in a proportionate amount based on the average closing price of $2.23 for the five trading days immediately preceding the date of the Reverse Stock Split. The aggregate number of fractional shares canceled in the Reverse Stock Split was 1,245 shares, resulting in a total cash payment of $3. All references in the accompanying financial statements to the number of shares of common stock and per share amounts have been retroactively adjusted to give effect to the Reverse Stock Split.

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.

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U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

Principles of Consolidation

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

Comprehensive Income (Loss)

Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders’ equity instead of net income (loss).

Recent Accounting Pronouncements

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

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

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

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

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

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

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

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

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U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

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

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

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

LIQUIDITY

As of June 30, 2016, the Company has a working capital deficit of $9,509 and an accumulated deficit of $124,523. Additionally, the Company incurred a net loss of $14,818 for the six months ended June 30, 2016. During 2015 and 2016, compliance was not maintained with certain financial ratio covenants in the credit agreement with Wells Fargo as discussed in Note 7. In July 2015, Wells Fargo agreed to enter into a third amendment to the credit agreement and provided waivers for non-compliance with the financial ratio covenants for the fiscal quarters ended June 30, 2015 and September 30, 2015.

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

During the third quarter of 2015, the Company began to implement restructuring actions to reduce corporate overhead through a reduction in the size of the Company’s workforce from 14 employees at the end of 2014 to one employee by January 2016. Additionally, in December 2015 the Company completed a move of its corporate headquarters to Denver, Colorado for better access to financial services and to improve access to oil and gas deal flow. Management expects its restructuring and other cost-cutting actions will result in an overhead reduction of approximately $4,000 on an annualized basis. During the six months ended June 30, 2016, the Company began to realize the benefits of these actions as aggregate general and administrative expenses were reduced by more than 50% as compared to the six months ended June 30, 2015.

As discussed in Note 5, in February 2016 the Company completed the disposition of its mining segment, including the Keystone Mine, a related water treatment plant 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 water treatment plant and mine holding costs, which are expected to result in estimated annual cash savings of $3,000. During the six months ended June 30, 2016, the Company began to realize the benefits of this disposition as aggregate operating expenses associated with the mining segment were reduced from $1,459 for the six months ended June 30, 2015 to $373 for the six months ended June 30, 2016. Management believes the disposition of the Company’s mining segment is a major step in the transformation of U.S. Energy to solely focus on its existing oil and gas business.

In April 2016, Wells Fargo provided a waiver for non-compliance with the covenants in the credit agreement for the fiscal quarter ended December 31, 2015. As discussed in Note 7, in August 2016 Wells Fargo agreed to enter into a fourth amendment to the credit agreement that provides for, among other things, a limited waiver of the negative financial covenants as it relates to the fiscal quarters ended March 31, 2016 and June 30, 2016. Management believes that Wells Fargo will not demand repayment until an alternative lender can be obtained. However, no assurance can be provided and the entire principal balance of $6,000 is classified as a current liability as of June 30, 2016, due to management’s expectation that further non-compliance with the financial ratio covenants is likely for the third quarter of 2016. The ongoing availability of borrowings under this credit agreement through the maturity date of July 30, 2017, or the receipt of funding from alternative sources, is critical to the Company’s ability to survive until oil and gas prices recover.

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U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

The Company expects that its share of the drilling and completion costs associated with proved undeveloped oil and gas properties that it will be required to fund is approximately $1,000 in 2017 and $3,800 in 2018. However, the specific timing and amount of these expenditures is controlled by the operators of the respective properties and can change based on a variety of economic and operating conditions. The Company’s ability to finance these planned capital expenditures is contingent upon its ability to repay $6,000 of outstanding borrowings under the Wells Fargo credit agreement and to obtain alternative sources of financing. In order to reduce the financing commitments, the Company intends to pursue sales of non-core assets to generate near-term liquidity. Alternatives that may be pursued include selling or joint venturing an interest in certain oil and gas properties, selling real estate assets in Wyoming, selling marketable equity securities, issuing shares of common stock for cash or as consideration for acquisitions, and other alternatives, as the Company determines how to best fund its capital programs and meet its financial obligations.

As of June 30, 2016, the Company had cash and equivalents of $1,360. Management believes approximately $7,000 of annualized overhead and mining expense reductions have poised the Company to survive the current low commodity price environment. Management believes the Company’s new singular industry focus, combined with attractive producing properties and a low-cost overhead structure, makes the Company an attractive vehicle to partner with for potential investors and lenders during this industry downturn and 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.

OIL PRICE RISK DERIVATIVES

The Company’s wholly-owned subsidiary Energy One has entered into crude oil derivative contracts (“economic hedges”) with Wells Fargo, the Company’s lender as discussed further in Note 7. The derivative contracts are priced based on West Texas Intermediate (“WTI”) quoted prices for crude oil. The Company is a guarantor of Energy One’s obligations under the economic hedges. The objective of utilizing the economic hedges is to reduce the effect of price changes on a portion of the Company’s future oil production, achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage the Company’s exposure to commodity price risk. The use of these derivative instruments limits the downside risk of adverse price movements. However, there is a risk that such use may limit the Company’s ability to benefit from favorable price movements. Energy One may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of its existing positions. The Company does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features. Presented below is a summary of outstanding “costless collars” with Wells Fargo as of June 30, 2016 (which total an aggregate of 55,200 barrels of oil production during the last six months of 2016):

Settlement Period

Quantity

Contract Price

Begin

End

(bbls/ day)

Put

Call

7/1/16

12/31/16

300

50.00

65.25

As of June 30, 2016, the aggregate fair value of oil derivative put contracts was an asset of $189 and the aggregate fair value of oil derivative call contracts was a liability of $15. Since these contracts are with the same counterparty, the Company recognizes the net asset of $174 in the accompanying balance sheet as of June 30, 2016. Since all of the derivative contracts expire within six months of the balance sheet date, the entire amount is included in current assets. As of December 31, 2015, the aggregate fair value of oil derivative put contracts was an asset of $1,674 and the aggregate fair value of oil derivative call contracts was a liability of $40, resulting in a net asset of $1,634.

Unrealized gains and losses resulting from derivatives are recorded at fair value 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.

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U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

CEILING TEST FOR OIL AND GAS PROPERTIES

The reserves used in the Company’s full cost ceiling test incorporate assumptions regarding pricing and discount rates over which management has no influence in the determination of present value. In the calculation of the ceiling test as of June 30, 2016, the Company used a price of $43.12 per barrel for oil and $2.24 per MMbtu for natural gas (as further adjusted for property specific gravity, quality, local markets and distance from markets) to compute the future cash flows of the Company’s producing properties. These prices compare to $50.28 per barrel for oil and $2.59 per MMbtu for natural gas used in the calculation of the ceiling test as of December 31, 2015. The discount factor used was 10%.

For the three months ended June 30, 2016 and 2015, ceiling test impairment charges for the Company’s oil and gas properties amounted to $2,611 and $3,208, respectively. For the six months ended June 30, 2016 and 2015, ceiling test impairment charges for the Company’s oil and gas properties amounted to $9,568 and $22,448, respectively. These impairment charges were primarily related to (i) a decline in the price of oil, (ii) reductions in the estimated quantities that are economically recoverable in the current low oil price environment, and (iii) the transfer of approximately $1,000 of unevaluated properties during the first quarter of 2016 to the full cost pool due to impairment.

DISCONTINUED OPERATIONS AND PREFERRED STOCK ISSUANCE

Disposition of Mining Segment

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

The market price for molybdenum oxide was approximately $11 per pound during 2013 and 2014 with a decrease to approximately $5 per pound by the fourth quarter of 2015. In light of the considerable ongoing costs related to the Property and the deteriorating market for molybdenum, during 2015 the Company began to explore the viability of alternative structures to the development of the Property that could result in a sharing or elimination of the ongoing costs and liabilities. In February 2016, the Company’s Board of Directors decided to dispose of the Property rather than continuing the Company’s long-term development strategy whereby the Company entered into the following agreements:

An Acquisition Agreement (the “Acquisition Agreement”) was entered into with Mt. Emmons Mining Company, a subsidiary of Freeport-McMoRan Inc. (“MEM”), whereby MEM acquired the Property which consists of the Mt. Emmons mine site located in Gunnison County, Colorado, including the Keystone Mine, the WTP and other related properties. Under the Acquisition Agreement, MEM replaced the Company as the permittee and operator of the WTP and will discharge the obligation of the Company to operate the WTP from and after the closing in accordance with the applicable permits issued by the Colorado Department of Public Health and Environment. The Company did not receive any cash consideration for the disposition; the sole consideration for the transfer was that MEM assumed the Company’s obligations to operate the WTP and to pay the future mine holding costs for portions of the Property that it desires to retain.

As a result of the February 2016 disposition of the Property, the Company determined that an impairment charge of $22,620 was required to be recorded in the fourth quarter of 2015 and the disposal of the Company’s mining segment was 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 June 30, 2016 and December 31, 2015:

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U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

	2016		2015

Assets retained by the Company:
Performance bonds and refundable deposits	$	135	$	114

Net assets conveyed to Purchaser:
Undeveloped mining claims		-		21,942
Mining equipment		-		1,774
Less accumulated depreciation of mining equipment		-		(892	)
Less write-down due to impairment		-		(22,620	)

Net book value of assets conveyed		-		204

Total assets of discontinued operations	$	135	$	318

Asset retirement obligations assumed by Purchaser	$	-	$	204

Concurrent with entry into the Acquisition Agreement and as additional consideration for MEM to accept transfer of the Property, the Company entered into a Series A Convertible Preferred Stock Purchase Agreement (the “Series A Purchase Agreement”) with MEM, whereby the Company issued 50,000 shares of newly designated Series A Convertible Preferred Stock (the “Preferred Stock”) in exchange for (i) MEM accepting the transfer of the Property and replacing the Company as the permittee and operator of the WTP, and (ii) the payment of approximately $1 to the Company. The Series A Purchase Agreement contains customary representations and warranties on the part of the Company. As contemplated by the Acquisition Agreement and the Series A Purchase Agreement and as approved by the Company’s Board of Directors, the Company filed with the Secretary of State of the State of Wyoming Articles of Amendment containing a Certificate of Designations with respect to the Preferred Stock (the “Certificate of Designations”). Pursuant to the Certificate of Designations, the Company designated 50,000 shares of its authorized preferred stock as Series A Convertible Preferred Stock. The Preferred Stock accrues dividends at a rate of 12.25% per annum of the Adjusted Liquidation Preference (as defined); such dividends are not payable in cash but are accrued and compounded quarterly in arrears on the first business day of the succeeding calendar quarter. At issuance, the aggregate fair value of the Preferred Stock was $2,000 based on the initial liquidation preference of $40 per share. The “Adjusted Liquidation Preference” is initially $40 per share of Preferred Stock, with increases each quarter by the accrued quarterly dividend. The Preferred Stock is senior to other classes or series of shares of the Company with respect to dividend rights and rights upon liquidation. No dividend or distribution will be declared or paid on junior stock, including the Company’s common stock, (1) unless approved by the holders of Preferred Stock and (2) unless and until a like dividend has been declared and paid on the Preferred Stock on an as-converted basis.

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 $1, the Company recorded a charge to discontinued operations of approximately $1,999 associated with the issuance. This charge represents additional consideration to induce MEM to assume the Company’s previous obligations to operate the WTP. As of June 30, 2016, the aggregate Adjusted Liquidation Preference was $2,034 which was convertible into 678,009 shares of common stock, and accrued dividends not yet included in the Adjusted Liquidation Preference amounted to $62.

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U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

Concurrent with entry into the Acquisition Agreement and the Series A Purchase Agreement, the Company and MEM entered into an Investor Rights Agreement, which provides MEM with the rights to certain information and Board observer rights. MEM has agreed that it, along with its affiliates, will not acquire more than 16.86% of the Company’s issued and outstanding shares of common stock. In addition, MEM has the right to request registration of the shares of common stock issuable upon conversion of the Preferred Stock under the Securities Act of 1933, as amended.

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 and six months ended June 30, 2016 and 2015:

	Three Months Ended						Six Months Ended
	June 30:						June 30:
	2016			2015			2016			2015

Issuance of preferred stock to induce dispostion	$	-		$	-		$	(1,999	)	$	-
Operating expenses of mining segment:
Water treatment plant		-			(424	)		(256	)		(852	)
Mine property holding costs		-			(252	)		(117	)		(545	)
Depreciation of mine equipment		-			(31	)		-			(62	)
Professional fees related to disposition		(10	)		-			(76	)		-
Total results for discontinued operations	$	(10	)	$	(707	)	$	(2,448	)	$	(1,459	)

ASSETS HELD FOR SALE

As of June 30, 2016, the Company owns three parcels of land in Wyoming for an aggregate of approximately 13 acres of land with a carrying value of $653. This land is currently listed for sale and management expects to sell the land within the following year at prices in excess of the carrying value.

DEBT

Energy One, a wholly-owned subsidiary the Company, has a credit facility with Wells Fargo Bank, National Association (“Wells Fargo”). As of June 30, 2016 and December 31, 2015, outstanding borrowings under the credit agreement amounted to $6,000, which is also the maximum amount of the borrowing base. Borrowings under the credit agreement are collateralized by Energy One’s oil and gas producing properties and substantially all of the Company’s cash and equivalents. Each borrowing under the agreement has a term of six months, but can be continued at the Company’s election through July 2017 if the Company is in compliance with the covenants under the credit agreement. The weighted average interest rate on this debt is 3.19% as of June 30, 2016.

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

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U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

On August 11, 2016, the Company and Wells Fargo entered into a fourth amendment (the "Fourth Amendment") to the credit agreement. The Fourth Amendment provides for, among other things: (i) a limited waiver of the negative financial covenants as it relates to the fiscal quarters ended March 31, 2016 and June 30, 2016, (ii) implementation of a new negative covenant that prohibits the Company’s consolidated general and administrative expenses (as defined) from exceeding $3,000 for each of the years ending December 31, 2016 and 2017, (iii) deferral of the next borrowing base redetermination until December 1, 2016, and (iv) the pledge of additional collateral by U.S. Energy consisting of certain real estate assets with a net carrying value of $1,860, and its shares of Anfield Resources, Inc., which had a fair value of $1,147 as of June 30, 2016.

Because the Company projects that it is unlikely that Energy One will regain compliance with the negative financial covenants for the entirety of the next 12 months, outstanding borrowings of $6,000 are presented as a current liability in the accompanying consolidated balance sheets as of June 30, 2016 and December 31, 2015. In the event that Energy One is unable to obtain further waivers under the credit agreement to address the anticipated future breaches of the negative financial covenants, and other actual or potential future breaches that may occur, Wells Fargo could elect to declare some or all of the Company’s debt to be immediately due and payable and could elect to terminate its commitment and cease making further loans.

EXECUTIVE RETIREMENT PLAN

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

COMMITMENTS AND CONTINGENCIES

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

Arbitration of Employment Claim. A former at-will employee has asserted a claim that a change of control occurred and he was involuntarily terminated without cause, thereby entitling him to compensation under a purported Executive Severance and Non-Compete agreement (the “Agreement”). The Company claims that the Agreement is invalid because it was never authorized by the Board of Directors or ratified by the Company’s shareholders. Furthermore, the Company contends that no change of control occurred that would entitle the former at-will employee to benefits under the Agreement. The former employee has claimed that the Company owes up to $1,800 under the Agreement which requires that any disputes be submitted to binding arbitration. A request for arbitration was submitted by the former employee in March 2016 and, on April 15, 2016, the Company filed a complaint in Denver District Court seeking a stay of the arbitration and/or preliminary injunction against the employee from proceeding with the arbitration. As a result, administration of the arbitration proceeding was suspended until the outcome of the Company’s complaint could be resolved. On August 12, 2016, the Court refused to stay the arbitration or grant the Company a preliminary injunction on the grounds that the Agreement had not been authorized by the Board of Directors or ratified by the Company’s shareholders and the Court ordered the parties to proceed with the arbitration.

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

Contingent Ownership Interests. As of June 30, 2016 and December 31, 2015, the Company had recognized a contingent liability associated with uncertain ownership interests of $3,203 and $3,108, respectively. This liability arises when the calculations of respective joint ownership interests by operators differs from the Company’s calculations. These differences relate to a variety of matters, including allocation of non-consent interests, complex payout calculations for individual wells and groups of wells, along with the timing of reversionary interests. Accordingly, these matters are subject to legal interpretation and the related obligations are presented as a contingent liability in the accompanying consolidated balance sheets. While the Company has classified these amounts as current liabilities, most of these issues are expected to be resolved through arbitration, mediation or litigation; due to the complexity of the issues involved, there can be no assurance that the outcome of these contingencies will be resolved in the next year.

-14-

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

10.

SHAREHOLDERS’ EQUITY

Stock Options

For the three months ended June 30, 2016 and 2015, total stock-based compensation expense related to stock options was $22 and $65, respectively. For the six months ended June 30, 2016 and 2015, total stock-based compensation expense related to stock options was $43 and $140, respectively. As of June 30, 2016, there was $99 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 June 30, 2016, no stock options were granted, exercised, forfeited or expired. Presented below is information about stock options outstanding and exercisable as of June 30, 2016 and December 31, 2015:

	June 30, 2016				December 31, 2015
	Shares		Price ⁽¹⁾		Shares		Price ⁽¹⁾

Stock options outstanding		390,525	$	20.64		390,525	$	20.64

Stock options exercisable		371,248	$	20.99		365,693	$	21.17

⁽¹⁾

Represents the weighted average price.

The following table summarizes information for stock options outstanding and for stock options exercisable at June 30, 2016:

Options Outstanding										Options Exercisable
Number		Exercise Price						Remaining		Number		Weighted
of		Range				Weighted		Contractual		of		Average
Shares		Low		High		Average		Term (years)		Shares		Exercise Price

	56,786	$	9.00	$	9.00	$	9.00		8.5		45,675	$	9.00
	49,504		12.48		12.48		12.48		7.0		48,004		12.48
	98,396		13.92		17.10		15.01		3.3		98,396		15.01
	185,839		22.62		30.24		29.35		1.6		179,174		29.60

	390,525	$	9.00	$	30.24	$	20.64		3.7		371,249	$	20.99

As of June 30, 2016, an aggregate of approximately 351,000 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 $1.70 per share on June 30, 2016, there was no intrinsic value related to stock options outstanding as of June 30, 2016.

Restricted Stock Grants

In January 2015, the Board of Directors granted 56,786 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 40,119 shares. The remaining 16,667 shares vested for 5,556 shares in January 2016 and the remaining 11,111 shares will vest for 5,556 shares in January 2017 and 5,555 shares in January 2018. The fair market value of the 56,786 shares on the date of grant was approximately $511. For the three months ended June 30, 2016 and 2015, total stock-based compensation expense related to restricted stock grants was $13 and $42, respectively. For the six months ended June 30, 2016 and 2015, total stock-based compensation expense related to restricted stock grants was $25 and $84, respectively. As of June 30, 2016, there was $75 of unrecognized expense related to unvested restricted stock grants, which will be recognized as stock-based compensation expense through January 2018.

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U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

Employee Stock Ownership Plan

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

An employee’s total compensation paid, which is subject to federal income tax (up to an annual limit of $265 for the year ended December 31, 2015) is the basis for computing how much of the total annual funding is contributed into each employee’s personal account. An employee’s compensation divided by the total eligible compensation paid to all plan participants is the percentage that each participant receives on an annual basis. All shares of the Company’s common stock contributed to the ESOP have been allocated to specific employees and are vested. Total shares held by the ESOP at June 30, 2016 and December 31, 2015 were 340,726 and 789,110, respectively.

For the three months ended June 30, 2015, total stock-based compensation expense related to the ESOP was $23. No expense related to the ESOP has been recorded for the three months ended June 30, 2016 since the Company’s Board of Directors has not determined if a discretionary contribution will be made for 2016. For the year ended December 31, 2015, the Company’s Board of Directors approved a mandatory contribution of $170 which is either payable in cash or may be settled through the issuance of common stock at the election of the Company. On July 7, 2016, the Board of Directors elected to issue 65,748 shares of the Company’s common stock with a fair value of $2.58 per share to settle this obligation. Accordingly, this liability is included in other long-term liabilities in the accompanying balance sheet as of June 30, 2016.

11.

INCOME TAXES

For Federal income tax purposes, as of December 31, 2015 the Company had net operating loss and percentage depletion carryovers of approximately $57,000 and $7,000, respectively. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. The net operating losses may be used to offset future taxable income and expire in varying amounts through 2035. In addition, the Company has alternative minimum tax credit carry-forwards of approximately $700 which are available to offset future federal income taxes over an indefinite period. The Company has established a valuation allowance for all deferred tax assets including the net operating loss and alternative minimum tax credit carryforwards discussed above since the “more likely than not” realization criterion was not met as of June 30, 2016 and 2015. Accordingly, the Company did not recognize an income tax benefit for the three and six months ended June 30, 2016 and 2015.

The Company recognizes, measures, and discloses uncertain tax positions whereby tax positions must meet a “more-likely-than-not” threshold to be recognized. As of June 30, 2016, gross unrecognized tax benefits are immaterial and there was no change in such benefits during the three and six months ended June 30, 2016. The Company does not expect a significant increase or decrease to the uncertain tax positions within the next twelve months.

12.

EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per share is computed based on the weighted average number of common shares outstanding. For the three and six months ended June 30, 2016 and 2015, common stock equivalents excluded from the calculation of weighted average shares because they were antidilutive are as follows:

-16-

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

	Three Months Ended						Six Months Ended
	June 30:						June 30:
	2016			2015			2016			2015

Stock options		390,525			436,132	⁽¹⁾		390,525			436,132	⁽¹⁾
Unvested shares of restricted common stock		11,111			56,785	⁽¹⁾		11,141	⁽¹⁾		56,785	⁽¹⁾
Series A convertible preferred stock		678,009	⁽¹⁾		-			522,155	⁽¹⁾		-

Total		1,079,645			492,917			923,821			492,917

⁽¹⁾

Includes weighted average number of shares for options issued during the period and shares of restricted stock that vested during the period.

13.

SIGNIFICANT CONCENTRATIONS

The Company has exposure to credit risk in the event of nonpayment by the joint interest operators of the Company’s oil and gas properties. Approximately 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 June 30, 2016 and December 31, 2015, the Company had a liability to the Major Operator of $3,302 and $4,159, respectively, for accrued operating expenses and overpayments of net revenues when the Major Operator failed to recognize that the Company’s ownership interest reverted after payout, which 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 to calculate the Company’s estimated reserves as of June 30, 2016, this liability is not expected to be fully settled. However, 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.

14.

FAIR VALUE MEASUREMENTS

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

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

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

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

-17-

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

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

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

Oil Price Risk Derivative Valuation Methodologies

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of the counterparty and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the likelihood that the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At June 30, 2016 and December 31, 2015, derivative instruments utilized by the Company consisted of crude oil costless collars. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Marketable Equity Securities Valuation Methodologies

The fair value of available for sale securities is based on quoted market prices obtained from independent pricing services. In consideration of the increase in the trading volumes for the Company’s investments in marketable equity securities, the Company determined that they should be classified in Level 1 as of June 30, 2016.

Executive Retirement Liability Valuation Methodologies

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

Other Financial Instruments

The carrying amount of cash and equivalents, oil and gas sales receivable, other current assets, accounts payable and accrued expenses approximate fair value because of the short-term nature of those instruments. The recorded amounts for borrowings under the credit agreement discussed in Note 7 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 agreement.

Recurring Fair Value Measurements

Recurring measurements of the fair value of assets and liabilities as of June 30, 2016 and December 31, 2015 are as follows:

-18-

U.S. ENERGY CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, Continued

(Dollars in Thousands, Except Per Share Amounts)

	June 30, 2016								December 31, 2015
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

Marketable equity securities:
Sutter Gold Mining Company	$	31	$	-	$	-	$	31	$	-	$	13	$	-	$	13
Anfield Resources, Inc. ⁽¹⁾		1,147		-		-		1,147		-		-		238		238
Crude oil price risk derivatives		-		174		-		174		-		1,634		-		1,634

Total	$	1,178	$	174	$	-	$	1,352	$	-	$	1,647	$	238	$	1,885

Executive retirement liability	$	-	$	-	$	-	$	-	$	-	$	-	$	584	$	584

⁽¹⁾

For the period from September 1, 2015 when the Company acquired its investment in Anfield Resources, Inc. (“Anfield”) through March 31, 2016, average daily trading volume was approximately 10,000 shares and management concluded that the quoted marked price was not an accurate indicator of fair value. Accordingly, alternative methods were used to determine fair value upon receipt of the shares in September 2015, which required classification under Level 3 of the fair value hierarchy. During the second quarter of 2016, average daily trading volume increased to more than 240,000 shares and management now classifies its investment in Anfield under Level 1 of the fair value hierarchy. As a result of the reclassification of Anfield to Level 1, the Company recognized an unrealized gain of $909 during the three and six months ended June 30, 2016.

15.

SUBSEQUENT EVENTS

As discussed in Note 10, on July 7, 2016, the Board of Directors elected to issue 65,748 shares of the Company’s common stock with a fair value of $2.49 per share to settle the liability to fund the ESOP contribution for 2015.

As discussed in Note 7, on August 11, 2016, the Company entered into an amendment to the credit agreement with Wells Fargo which, among other things, provided limited waivers for financial ratio covenant noncompliance for the fiscal quarters ended March 31, 2016 and June 30, 2016.

In July 2016, the Company entered into a non-binding letter of intent with IronHorse Resources LLC (“IronHorse”) pursuant to which the Company may obtain the right to acquire a 40% interest in a farmout agreement to participate in developing three core areas in the Wattenberg Field in Weld County, Colorado. The development program is slated to begin in the fourth quarter of 2016 with drilling to continue until the middle of 2017. If the participation agreement is entered into, the Company's commitment for drilling and completing the wells is expected to cost approximately $9,600. A director of the Company is one of the owners of IronHorse.

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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, risks arising from defaults under our credit facility, 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, as amended, and other quarterly reports on Form 10-Q filed with the SEC, all of which are incorporated herein by reference. The Company undertakes no duty to update or revise any forward-looking statements.

General Overview

We are an independent energy company focused on the acquisition and development of oil and gas producing properties in the continental United States. Our business is currently focused in South Texas and the Williston Basin in North Dakota. However, we do not intend to limit our focus to these geographic areas. We continue to focus on increasing production, reserves, revenues and cash flow from operations while managing our level of debt.

We currently explore for and produce oil and gas through a non-operator business model; however, we may operate oil and gas properties for our own account and may expand our holdings or operations into other areas. As a non-operator, we rely on our operating partners to propose, permit and manage wells. Before a well is drilled, the operator is required to provide all oil and gas interest owners in the designated well the opportunity to participate in the drilling costs and revenues of the well on a pro-rata basis. After the well is completed, our operating partners also transport, market and account for all production. Our long-term strategic focus is to develop operational capabilities through the pursuit of opportunities to acquire operated properties and/or operatorship of existing properties.

Recent Developments

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

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

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Each share of Preferred Stock may initially be converted into 13.33 shares of the common stock of the Company at the option of the holder at any time. The conversion rate is subject to anti-dilution adjustments for stock splits, stock dividends and certain reorganization events and to price-based anti-dilution protections. Each share of Preferred Stock will be convertible into a number of shares of Common Stock equal to the product of (1) the conversion value as adjusted for accumulated dividends divided by the initial conversion value, multiplied by (2) the conversion rate (plus cash in lieu of fractional shares and dividends accrued since the last accrual date). The Preferred Stock will generally not vote with the common stock on an as-converted basis on matters put before the Company’s shareholders. The holders of the Preferred Stock have the right to approve specified matters and have the right to require the Company to repurchase the Preferred Stock in connection with a change of control.

Critical Accounting Policies and Estimates

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

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

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

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

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

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

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

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

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

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

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

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

Revenue Recognition. We record oil and gas revenue under the sales method of accounting. Under the sales method, we recognize revenues based on the amount of oil or natural gas sold to purchasers, which may differ from the amounts to which we are entitled based on our interest in the properties. Gas balancing obligations as of June 30, 2016 and December 31, 2015 were not significant.

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

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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 June 30, 2016 and 2015

During the three months ended June 30, 2016, we recorded a net loss of $4.2 million as compared to a net loss of $6.3 million for the three months ended June 30, 2015. Our loss from continuing operations was $4.2 million for the three months ended June 30, 2016 compared to $5.6 million for the three months ended June 30, 2015. In the following sections we discuss our revenue, operating expenses, non-operating income (expense), and discontinued operations for the three months ended June 30, 2016 compared to the three months ended June 30, 2015.

Revenue. Presented below is a comparison of our oil and gas sales, production quantities and average sales prices for the three months ended June 30, 2016 and 2015 (dollars in thousands, except average sales prices):

					Change
	2016		2015		Amount			Percent

Revenue:
Oil	$	1,677	$	2,934	$	(1,257	)		-43	%
Natural gas and liquids		319		351		(32	)		-9	%

Total	$	1,996	$	3,285	$	(1,289	)		-39	%

Production quantities:
Oil (Bbls)		43,032		58,021		(14,989	)		-26	%
Gas (Mcfe)		167,897		141,578		26,319			19	%
BOE		71,015		81,617		(10,603	)		-13	%

Average sales prices:
Oil (Bbls)	$	38.97	$	50.57	$	(11.60	)		-23	%
Gas (Mcfe)		1.90		2.48		(0.58	)		-23	%
BOE		28.11		40.25		(12.14	)		-30	%

The decrease in our oil sales of $1.3 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015 was attributable to a 26% reduction in our oil production quantity and a 23% reduction in the average oil price realized during the three months ended June 30, 2016. The reduction in our net realized oil price is reflective of the dramatic decrease in global commodity prices during 2015 which has intensified during 2016. During the last year, the differential between West Texas Intermediate (“WTI”) quoted prices for crude oil and the prices we realize for sales in the Williston Basin was approximately $8.00 per barrel. 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.

Our natural gas and liquids sales were approximately $0.3 million for each of the three months ended June 30, 2016 and 2015. Our natural gas and liquids production was 19% higher for the three months ended June 30, 2016, but this increase was offset by a 23% reduction in the average price realized during this period.

For the three months ended June 30, 2016, we produced 71,015 BOE, or an average of 780 BOE per day, as compared to 81,617 BOE or 897 BOE per day during the comparable period in 2015. This 13% 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 acquisitions 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 June 30, 2016 and 2015 (dollars in thousands):

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					Change
	2016		2015		Amount			Percent

Production taxes	$	179	$	305	$	(126	)		-41	%
Marketing and transportation		92		41		51			124	%
Lease operating expense		1,163		1,675		(512	)		-31	%

Total	$	1,434	$	2,021	$	(587	)		-29	%

For the three months ended June 30, 2016, production taxes decreased by $0.1 million compared to the same period in 2015. Substantially all of this decrease in production taxes resulted from lower oil and gas sales. For the three months ended June 30, 2016, 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. For the three months ended June 30, 2016, lease operating expense includes $0.3 million for workovers that were implemented to maintain production levels. We expect further well by well decreases as cost reduction programs continue during the industry downturn.

Depreciation, depletion and amortization. Our DD&A rate for the three months ended June 30, 2016 was $12.17 per BOE compared to $25.18 per BOE for the three months ended June 30, 2015. Our DD&A rate can fluctuate as a result of changes in drilling and completion costs, impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves. The primary factor that resulted in a reduction in our DD&A rate for the three months ended June 30, 2016 was $44.8 million of aggregate quarterly impairment charges that resulted from our quarterly Full Cost Ceiling limitations during the 12-month period ended June 30, 2016. Such impairment charges 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.

Impairment of oil and gas properties. During the three months ended June 30, 2016 and 2015, we recorded impairment charges related to our oil and gas properties of $2.6 million and $3.2 million, respectively, because the net capitalized costs were in excess of the Full Cost Ceiling limitation. These quarterly impairment charges were primarily due to the deepening declines in the price realized from the sale of oil during the 18-month period ended June 30, 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 six calendar quarters, along with the impairment charges recognized during each of those quarters (dollars in thousands, except average prices):

	Average Price ⁽¹⁾
	Oil		Gas		Impairment
	(Bbl)		(MMbtu)		Charge

First quarter of 2015	$	82.72	$	3.88	$	19,240
Second quarter of 2015		71.68		3.39		3,208
Third quarter of 2015		59.21		3.06		21,446
Fourth quarter of 2015		50.28		2.59		13,782
First quarter of 2016		46.26		2.40		6,957
Second quarter of 2016		43.12		2.24		2,611

⁽¹⁾

Represents the trailing 12-month average for benchmark oil and gas prices ending in the last month of the calendar quarter shown.

At this time, it cannot be determined if further impairment charges will be required for the remainder of the year ending December 31, 2016.

General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the three months ended June 30, 2016 and 2015 (dollars in thousands):

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					Change
	2016		2015		Amount			Percent

Compensation and benefits, including directors	$	172	$	676	$	(504	)		-75	%
Stock-based compensation		34		109		(75	)		-69	%
Professional services		541		274		267			97	%
Insurance, rent and other		16		162		(146	)		-90	%

Total	$	763	$	1,221	$	(458	)		-38	%

General and administrative expenses decreased by $0.5 million for the three months ended June 30, 2016 compared to the three months ended June 30, 2015. This decrease was attributable to (i) a reduction of $0.5 million in compensation and benefits, which was driven by the termination of all except one employee by December 31, 2015, (ii) a decrease in stock-based compensation expense of $0.1 million, which primarily resulted from the acceleration of vesting of stock options and restricted stock associated with employees who terminated employment in 2015, and (iii) a reduction in insurance, rent and other expenses of $0.1 million. These decreases, which totaled $0.7 million, were partially offset by an increase in professional services of $0.2 million which was driven by incremental costs as we replaced some of the services previously performed by employees with consultants. Professional services for the three months ended June 30, 2016 also include one-time charges of approximately $0.1 million to effect the reverse stock split that was approved by shareholders on June 20, 2016.

Non-Operating Income (Expense). Presented below is a comparison of our non-operating income (expense) for the three months ended June 30, 2016 and 2015 (dollars in thousands):

							Change
	2016			2015			Amount			Percent

Realized gain (loss) on oil price risk derivatives	$	380		$	(25	)	$	405			1620	%
Change in unrealized gain (loss) on oil price risk derivatives		(887	)		(272	)		(615	)		-226	%
Gain on sale of assets		100			-			100			n/a
Rental and other income, net of expenses		(48	)		10			(58	)		-580	%
Interest expense		(75	)		(66	)		(9	)		-14	%

Total	$	(530	)	$	(353	)	$	(177	)		-50	%

We had a realized gain on oil price risk derivatives of $0.4 million for the three months ended June 30, 2016 compared to a loss of $25,000 for the comparable period in 2015. We had an unrealized loss on oil price risk derivatives of $0.9 million for the three months ended June 30, 2016 compared to a loss of $0.3 million for the comparable period in 2015. The realized gains during the three months ended June 30, 2016 result from the significant decline in the market for crude oil after we entered into the derivative contracts. The change in unrealized gains or losses results from changes in the fair value of the derivatives as commodity prices increase or decrease. Unrealized losses also result in the months when derivative contracts are settled in cash whereby previously unrealized gains become realized gains. Similarly, unrealized gains are recognized in the months when derivative contracts are settled in cash whereby previously unrealized losses become realized losses.

For the three months ended June 30, 2016, we recognized a gain of $0.1 million from the sale of certain data that was generated from previous exploration activities. We did not have any cost basis in the data which resulted in a gain for the entire amount of the consideration received.

Interest expense did not change significantly during the three months ended June 30, 2016 compared to the comparable period in 2015. Interest rates charged under our revolving line of credit only increased slightly for the three months ended June 30, 2016 compared to the same period in 2015.

Discontinued Operations. In February 2016, we completed the disposition of our mining segment to 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 approximately $3.0 million. During the three months ended June 30, 2016, we began to realize the benefits of this disposition as aggregate operating expenses associated with the discontinued mining segment declined by $0.7 million compared to the three months ended June 30, 2015.

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Due to the disposition in February 2016, all of our mining properties are included in discontinued operations for all periods presented in this report.

Comparison of our Statements of Operations for the Six Months Ended June 30, 2016 and 2015

During the six months ended June 30, 2016, we recorded a net loss of $14.8 million as compared to a net loss of $30.0 million for the six months ended June 30, 2015. Our loss from continuing operations was $12.4 million for the six months ended June 30, 2016 compared to $28.5 million for the six months ended June 30, 2015. In the following sections we discuss our revenue, operating expenses, non-operating income (expense), and discontinued operations for the six months ended June 30, 2016 compared to the six months ended June 30, 2015.

Revenue. Presented below is a comparison of our oil and gas sales, production quantities and average sales prices for the six months ended June 30, 2016 and 2015 (dollars in thousands, except average sales prices):

					Change
	2016		2015		Amount			Percent

Revenue:
Oil	$	2,541	$	5,231	$	(2,690	)		-51	%
Natural gas and liquids		521		733		(212	)		-29	%

Total	$	3,062	$	5,964	$	(2,902	)		-49	%

Production quantities:
Oil (Bbls)		82,680		117,228		(34,548	)		-29	%
Gas (Mcfe)		233,776		303,699		(69,923	)		-23	%
BOE		121,643		167,845		(46,202	)		-28	%

Average sales prices:
Oil (Bbls)	$	30.73	$	44.62	$	(13.89	)		-31	%
Gas (Mcfe)		2.23		2.41		(0.18	)		-8	%
BOE		25.17		35.53		(10.36	)		-29	%

The decrease in our oil sales of $2.7 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, resulted from a 29% reduction in our oil production quantity and a 31% reduction in the average oil price realized. The decrease in our natural gas and liquids sales of $0.2 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, was driven by a 23% decrease in our natural gas and liquids production and an 8% decrease in the average price realized. The reduction in our net realized oil price is reflective of the dramatic decrease in global commodity prices during 2015 which has intensified during 2016. During the last year, the differential between West Texas Intermediate (“WTI”) quoted prices for crude oil and the prices we realize for sales in the Williston Basin was approximately $8.00 per barrel. 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 six months ended June 30, 2016, we produced 121,643 BOE, or an average of 668 BOE per day, as compared to 167,845 BOE or 927 BOE per day during the comparable period in 2015. This 28% 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 acquisitions 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 six months ended June 30, 2016 and 2015 (dollars in thousands):

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					Change
	2016		2015		Amount			Percent

Production taxes	$	338	$	563	$	(225	)		-40	%
Marketing and transportation		142		121		21			17	%
Lease operating expense		1,984		3,189		(1,205	)		-38	%

Total	$	2,464	$	3,873	$	(1,409	)		-36	%

For the six months ended June 30, 2016, production taxes decreased by $0.2 million compared to the comparable period in 2015. Substantially all of this decrease in production taxes resulted from lower oil and gas sales. For the six months ended June 30, 2016, 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. For the six months ended June 30, 2016, lease operating expense includes $0.3 million for workovers that were implemented to maintain production levels. We expect further well by well decreases as cost reduction programs continue during the industry downturn.

Depreciation, depletion and amortization. Our DD&A rate for the six months ended June 30, 2016 was $13.53 per BOE compared to $29.37 per BOE for the six months ended June 30, 2015. Our DD&A rate can fluctuate as a result of changes in drilling and completion costs, impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves. The primary factor that resulted in a reduction in our DD&A rate for the six months ended June 30, 2016 was $63.6 million of aggregate quarterly impairment charges that resulted from our quarterly Full Cost Ceiling limitations during 2015 and for the first quarter of 2016. During each of the four quarters in 2015 and the first quarter of 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 six months ended June 30, 2016 and 2015, we recorded impairment charges related to our oil and gas properties of $9.6 million and $22.4 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 realized from oil sales during the 18-month period ended June 30, 2016. Additionally, during the six months ended June 30, 2016, we determined that unevaluated properties were impaired for approximately $1.0 million. Accordingly, we transferred these costs to the full cost pool which contributed to the Full Cost Ceiling limitation for the six months ended June 30, 2016.

General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the six months ended June 30, 2016 and 2015 (dollars in thousands):

					Change
	2016		2015		Amount			Percent

Compensation and benefits, including directors	$	311	$	1,530	$	(1,219	)		-80	%
Stock-based compensation		68		224		(156	)		-70	%
Professional services		768		540		228			42	%
Insurance, rent and other		183		407		(224	)		-55	%

Total	$	1,330	$	2,701	$	(1,371	)		-51	%

General and administrative expenses decreased by $1.4 million for the six months ended June 30, 2016 compared to the six months ended June 30, 2015. This decrease was attributable to (i) a reduction of $1.2 million in compensation and benefits, which was driven by the termination of all except one employee by December 31, 2015, (ii) a decrease in stock-based compensation expense of $0.2 million, which primarily resulted from the acceleration of vesting of stock options and restricted stock associated with employees who terminated employment in 2015, and (iii) a reduction in insurance, rent and other expenses of $0.2 million. These decreases which totaled $1.6 million were partially offset by an increase in professional services of $0.2 million which was driven by incremental costs as we replaced some of the services previously performed by employees with consultants. Professional services for the three months ended June 30, 2016 also include one-time charges of approximately $0.1 million to effect the reverse stock split that was approved by shareholders on June 20, 2016.

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Non-Operating Income (Expense). Presented below is a comparison of our non-operating income (expense) for the six months ended June 30, 2016 and 2015 (dollars in thousands):

							Change
	2016			2015			Amount			Percent

Realized gain (loss) on oil price risk derivatives	$	1,262		$	(139	)	$	1,401			1008	%
Change in unrealized gain (loss) on oil price risk derivatives		(1,460	)		(335	)		(1,125	)		-336	%
Gain on sale of assets		100			16			84			525	%
Rental and other income, net of expenses		(79	)		50			(129	)		-258	%
Interest expense		(247	)		(129	)		(118	)		-91	%

Total	$	(424	)	$	(537	)	$	113			21	%

We had a realized gain on oil price risk derivatives of $1.3 million for the six months ended June 30, 2016 compared to a loss of $0.1 million for the comparable period in 2015. We had an unrealized loss on oil price risk derivatives of $1.5 million for the six months ended June 30, 2016 compared to a loss of $0.3 million for the comparable period in 2015. The realized gains during the six months ended June 30, 2016 result from the significant decline in the market for crude oil after we entered into the derivative contracts. The change in unrealized gains or losses results from changes in the fair value of the derivatives as commodity prices increase or decrease. Unrealized losses also result in the months when derivative contracts are settled in cash whereby previously unrealized gains become realized gains. Similarly, unrealized gains are recognized in the months when derivative contracts are settled in cash whereby previously unrealized losses become realized losses.

For the six months ended June 30, 2016, we recognized a gain of $0.1 million from the sale of certain data that was generated from previous exploration activities. We did not have any cost basis in the data which resulted in a gain for the entire amount of the consideration received.

Interest expense increased by $0.1 million during the six months ended June 30, 2016 compared to the comparable period in 2015. This increase was attributable to the amortization of a debt issuance cost incurred in 2015 for $0.1 million when we determined that this source of financing would no longer be pursued.

Discontinued Operations. In February 2016 we completed the disposition of our mining segment to 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 six months ended June 30, 2016, we began to realize the benefits of this disposition as aggregate operating expenses associated with the discontinued mining segment declined from $1.4 million for the six months ended June 30, 2015 to $0.4 million for the six months ended June 30, 2016, a decrease of $1.0 million or 73%.

In order to induce MEM to assume the Company’s obligations to operate the WTP we needed to issue additional consideration in the form of 50,000 shares of Series A Convertible Preferred Stock. We recorded the fair value of the Preferred Stock based on the initial liquidation preference of $2.0 million. Since the cash consideration paid by MEM for the Preferred Stock was $500, we recorded a charge to discontinued operations of approximately $2.0 million associated with the issuance. In connection with the disposition, we also incurred professional fees of $0.1 million for the six months ended June 30, 2016.

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

Non-GAAP Financial Measures- Adjusted EBITDAX

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

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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. In addition, 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 agreement. The calculation of EBITDAX for purposes of the credit agreement differs from our financial reporting definition.

The following table provides reconciliations of income (loss) from continuing operations to adjusted EBITDAX for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015

Loss from continuing operations (GAAP)	$	(4,206	)	$	(5,573	)	$	(12,370	)	$	(28,524	)
Impairment of oil and gas properties		2,611			3,208			9,568			22,448
Depreciation, depletion and amortization:
Oil and gas operations		864			2,055			1,646			4,929
Other		36			36			72			73
Unrealized loss on oil price risk derivatives		887			272			1,460			335
Stock-based compensation		34			109			68			224
Gain on sale of assets		(100	)		-			100			(16	)
Rental and other income (expense), net		48			(10	)		79			(50	)
Interest expense		69			66			247			129

Adjusted EBITDAX (Non-GAAP)	$	243		$	163		$	870		$	(452	)

Liquidity and Capital Resources

The following table sets forth certain measures of our liquidity as of June 30, 2016 and December 31, 2015:

	2016			2015			Change

Cash and equivalents	$	1,360		$	3,354		$	(1,994	)
Working capital deficit ⁽¹⁾		(9,509	)		(9,778	)		269
Total assets		19,038			33,132			(14,094	)
Outstanding debt under Credit Facility		6,000			6,000			-
Borrowing base under Credit Facility		6,000			7,000			(1,000	)
Total shareholders' equity		3,649			15,475			(11,826	)

Select Ratios

Current ratio ⁽²⁾		0.33 to 1.00			0.41 to 1.00
Debt to equity ratio ⁽³⁾		1.64 to 1.00			0.39 to 1.00

⁽¹⁾

Working capital deficit is computed by subtracting total current liabilities from total current assets.

⁽²⁾

The current ratio is computed by dividing total current assets by total current liabilities.

⁽³⁾

The debt to equity ratio is computed by dividing total debt by total shareholders’ equity.

As of June 30, 2016, we have a working capital deficit of $9.5 million compared to a working capital deficit of $9.8 million as of December 31, 2015, an improvement of $0.3 million. This improvement was primarily attributable to a reduction in current liabilities of $2.5 million, partially offset by a reduction in current assets by $2.2 million.

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The reduction in our total assets is primarily associated with our net loss of $14.8 million during the six months ended June 30, 2016, as discussed under Results of Operations herein. The reduction in our shareholders’ equity is primarily associated with our net loss of $14.8 million during the six months ended June 30, 2016, partially offset by the issuance of $2.0 million of Series A Convertible Preferred Stock, as discussed under Results of Operations herein.

Our sole source of debt financing is a revolving credit agreement with Wells Fargo Bank N.A. (“Wells Fargo”). With lower oil and gas prices during 2015, Wells Fargo decreased the borrowing base by $18.5 million to $6.0 million, which is the borrowing base in effect as of June 30, 2016. Outstanding borrowings as of June 30, 2016 and December 31, 2015 were $6.0 million, and we did not have any unused borrowing availability at either date.

During 2015 and 2016, we violated certain financial ratio covenants in our credit agreement. In July 2015, Wells Fargo agreed to enter into a third amendment to the credit agreement and provide waivers for our non-compliance with the financial ratio covenants for the fiscal quarters ended June 30, 2015 and September 30, 2015. In April 2016, Wells Fargo provided a waiver for our non-compliance with the covenants for the fiscal quarter ended December 31, 2015. In August 2016, Wells Fargo agreed to enter into a fourth amendment (the "Fourth Amendment") to the credit agreement. The Fourth Amendment provides for, among other things: (i) a limited waiver of the negative financial covenants as it relates to the fiscal quarters ended March 31, 2016 and June 30, 2016, (ii) implementation of a new negative covenant that prohibits the Company’s consolidated general and administrative expenses (as defined) from exceeding $3.0 million for each of the fiscal years ending December 31, 2016 and 2017, (iii) an extension of the next borrowing base redetermination until December 1, 2016, and (iv) the pledge of additional collateral, consisting of certain real estate assets and our shares of Anfield Resources, Inc. common stock.

We believe that Wells Fargo will not demand repayment until an alternative lender can be obtained and we expect that Wells Fargo will continue to work with us as we attempt to obtain alternative sources of financing. However, no assurance can be provided and we are continuing to classify this debt as a current liability as of June 30, 2016 and December 31, 2015, due to our expectation that further non-compliance with our financial ratio covenants is likely for the third quarter of 2016. The ongoing availability of borrowings under this credit agreement through the maturity date of July 30, 2017, or our receipt of funding from alternative sources, is critical to our ability to survive until oil and gas prices recover.

During 2015 and 2014, we received significant overpayments due to an operator’s failure to timely recognize the payout implications of our joint operating agreements. During the second quarter of 2015, the operator corrected its records and has elected to begin withholding the net revenues from all of our wells that it operates to recover these overpayments. As of June 30, 2016, the balance of the overpayment was approximately $3.3 million. Based on the oil and gas prices and costs used to calculate our estimated reserves as of June 30, 2016, this liability is not expected to be fully settled, but under higher pricing scenarios we expect the entire liability will be repaid. Accordingly, the aggregate overpayment liability is presented as a current liability in our consolidated balance sheets as of June 30, 2016 and December 31, 2015.

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 $3.6 million as of June 30, 2016. The ultimate resolution of these uncertainties about our working interests and net revenue interests can extend over a long period of time and we cannot provide any assurance that these matters will be resolved within the next year.

Since September 2015, we completed the following actions which are expected to improve our operating results in 2016 and beyond to enable our survival and begin to grow our oil and gas reserve base:

During the third quarter of 2015, we began to implement restructuring actions to reduce corporate overhead through a reduction in the size of the Company’s workforce from 14 employees at the end of 2014 to one employee by January 2016. Additionally, in December 2015 we completed a move of our corporate headquarters to Denver, Colorado for better access to financial services and to improve access to oil and gas deal flow. We expect our restructuring and other cost-cutting actions will result in an overhead reduction of approximately $4.0 million on an annualized basis.

In February 2016, we completed the disposition of our mining segment, including the Keystone Mine, a related water treatment plant and other related properties. A significant objective for completing the disposition was to improve future profitability. Following the disposition, we are no longer required to operate the water treatment plant and will not be responsible for mine holding costs, which are expected to result in estimated annual cash savings of $3.0 million. We believe the disposition of our mining segment is a major step in the transformation of the Company to solely focus on our existing oil and gas business.

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As of June 30, 2016, we had cash and equivalents of $1.4 million. We believe approximately $7.0 million of annualized administrative overhead and mining expense reductions have poised the Company to survive the current low commodity price environment. We also expect our new singular industry focus, combined with attractive producing properties and a low-cost overhead structure, will make the Company an attractive vehicle to partner with for potential investors and lenders during this industry downturn and low commodity price environment. However, there can be no assurance that we will be able to complete future transactions on acceptable terms or at all.

We are projecting capital expenditures of $1.0 million in 2017 and $3.8 million in 2018 for estimated drilling costs associated with our proved undeveloped oil and gas properties. In July 2016, we entered into a non-binding letter of intent to continue negotiations with IronHorse Resources LLC (“IronHorse”) pursuant to which we may obtain the right to acquire a 40% interest in a farmout agreement to participate in developing three core areas in the Wattenberg Field in Weld County, Colorado. A member of our board of directors has an ownership interest in IronHorse and no assurance can be provided that a formal agreement will be entered into. If a formal participation agreement is entered into, our commitment for drilling and completing the wells is expected to cost approximately $9.6 million. This development program is slated to begin in the fourth quarter of 2016 with drilling to continue until the middle of 2017.

The specific timing of these expenditures is controlled by the operators of the respective properties and can change based on a variety of economic and operating conditions. Additionally, our long-term strategy is to acquire additional oil and gas properties at attractive prices. Our ability to finance our planned capital expenditures and our ability to acquire additional producing properties is contingent upon our ability to repay $6.0 million of outstanding borrowings under our Wells Fargo credit agreement and to obtain alternative sources of financing. In order to reduce the financing commitments needed to carry out our plans, we intend to pursue sales of non-core assets to generate near-term liquidity. Alternatives that we intend to pursue 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 future breaches of covenants in our credit agreement will not be waived and will result in liquidation, bankruptcy or similar proceedings, the risk that we will be unable to enter into additional financing arrangements on acceptable terms or at all, and numerous other risks, including those discussed in Risk Factors in our 2015 Annual Report on Form 10-K, as amended, and our quarterly reports on Form 10-Q as filed with the SEC.

Cash Flows

The following table summarizes our cash flows for the six months ended June 30, 2016 and 2015 (in thousands):

	2016			2015			Change

Net cash provided by (used in):
Operating activities	$	(1,434	)	$	3,516		$	(4,950	)
Investing activities		(86	)		(2,061	)		1,975
Financing activities		(26	)		-			(26	)
Discontinued operations		(448	)		(1,398	)		950

Operating Activities. Cash used by operating activities for the six months ended June 30, 2016 was $1.4 million as compared to cash provided by operating activities of $3.5 million for the comparable period in 2015, a decrease of $4.9 million. This decrease is primarily related to the cash impact between the periods caused by (i) reductions in accounts payable and accrued liabilities, and (ii) lower oil and gas sales receivable due to lower oil and gas prices.

Investing Activities. Cash used in investing activities for the six months ended June 30, 2016 was $0.1 million as compared to cash used in investing activities of $2.1 million for the comparable period in 2015. The primary use of cash in our investing activities for 2015 was for capital expenditures for our oil and gas drilling activities.

Financing Activities. For the six months ended June 30, 2016, our financing cash flows consisted primarily of payments of $24,000 for debt issuance costs related to our Wells Fargo credit agreement. We did not have any financing cash flows for the six months ended June 30, 2015.

Discontinued Operations. Cash used in our discontinued operations was $0.4 million for the six months ended June 30, 2016 as compared to $1.4 million for the comparable period in 2015, an improvement of $1.0 million. The improvement in 2016 was due to the disposition of our discontinued mining segment in February 2016 as discussed above.

Off-balance Sheet Arrangements

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

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of June 30, 2016, the Company's management, including its Chief Executive Officer and principal financial officer, completed an evaluation of the effectiveness of the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on that evaluation, the Chief Executive Officer and principal financial officer concluded:

That the Company's disclosure controls and procedures are designed to ensure (a) that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms, and (b) that such information is accumulated and communicated to the Company's management, including the Chief Executive Officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure; and

ii.

That the Company's disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

During the fiscal quarter ended June 30, 2016, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Employment Claim. A former at-will employee has asserted a claim that a change of control occurred and he was involuntarily terminated without cause, thereby entitling him to compensation under a purported Executive Severance and Non-Compete agreement (the “Agreement”). The Company claims that the Agreement is invalid because it was never authorized by the Board of Directors or ratified by the Company’s shareholders. Furthermore, the Company contends that no change of control occurred that would entitle the former at-will employee to benefits under the Agreement. The former employee has claimed that the Company owes up to $1.8 million under the Agreement which requires that any disputes be submitted to binding arbitration. A request for arbitration was submitted by the former employee in March 2016 and, on April 15, 2016, the Company filed a complaint in Denver District Court seeking a stay of the arbitration and/or preliminary injunction against the employee from proceeding with the arbitration. As a result, administration of the arbitration proceeding was suspended until the outcome of the Company’s complaint could be resolved. On August 12, 2016, the Court refused to stay the arbitration or grant the Company a preliminary injunction on the grounds that the Agreement had not been authorized by the Board of Directors or ratified by the Company’s shareholders and the Court ordered the parties to proceed with the arbitration.

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.

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits

3.1	Articles of Amendment to Restated Articles of Incorporation (incorporated by reference from Exhibit 3.1 to the Company’s Form 8-K filed June 21, 2016)
10.1*	Fourth Amendment to Credit Agreement with Wells Fargo Bank, N.A.
10.2*∆	Executive Employment Agreement with David Veltri
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
31.2*	Certification of principal financial officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
32.1*†	Certification under Rule 13a-14(b) of Chief Executive Officer and principal financial officer
101.INS	XBRL Instance Document
101.SCH	XBRL Schema Document
101.CAL	XBRL Calculation Linkbase Document
101.DEF	XBRL Definition Linkbase Document
101.LAB	XBRL Label Linkbase Document
101.PRE	XBRL Presentation Linkbase Document

* Filed herewith.

∆ Exhibit constitutes a management contract or compensatory plan or agreement.

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

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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.

	U.S. ENERGY CORP. (Registrant)

Date: August 15, 2016	By:	/s/ David A. Veltri
		DAVID A. VELTRI, Chief Executive Officer

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