UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

Commission File Number: 0-6814

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Company was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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).

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 definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

At August 5, 2015 there were 28,047,661 outstanding shares of the Company's common stock, $0.01 par value.

U.S. ENERGY CORP. and SUBSIDIARIES

INDEX

PART I.  FINANCIAL INFORMATION

ITEM 1.  Financial Statements

The accompanying unaudited condensed consolidated financial statements for the periods ended June 30, 2015 and June 30, 2014 have been prepared by U.S. Energy Corp. ("we," "us," "U.S. Energy" or the "Company") in accordance with generally accepted accounting principles in the United States of America ("U.S. GAAP").  The financial statements at June 30, 2015, June 30, 2014 and December 31, 2014 include the Company's wholly owned subsidiary Energy One LLC ("Energy One"), which owns the majority of the Company's oil and gas assets.  The Condensed Consolidated Balance Sheet at December 31, 2014 was derived from audited financial statements.  In the opinion of the Company, the accompanying condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the financial position of the Company for the reported periods.  Entities in which the Company holds at least 20% ownership or in which there are other indicators of significant influence are accounted for under the equity method, whereby the Company records its proportionate share of the entities' results of operations.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted and certain prior period amounts have been reclassified to conform to the current period presentation.  The unaudited condensed consolidated financial statements should be read in conjunction with the Company's Annual Report on Form 10-K for the year ended December 31, 2014 (the "2014 10-K").  Subsequent events have been evaluated for financial reporting purposes through the date of the filing of this Form 10-Q.

We follow accounting standards set by the Financial Accounting Standards Board, commonly referred to as the "FASB."  The FASB determines GAAP, which we follow to ensure we consistently report our financial condition, results of operations, and cash flows.

For detailed descriptions of our significant accounting policies, please see the 2014 10-K (Note B, pages 87 to 96).

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Significant estimates include oil and gas reserves used for depletion and impairment considerations, accrued revenue and related receivables, 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 under the circumstances.  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.

Oil and Gas Properties

The Company follows the full cost method in accounting for its 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 is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves.  Excluded from amounts subject to depletion are costs associated with unproved properties.

Full Cost Pool - Full cost pool capitalized costs are amortized over the life of production of proven properties.  Capitalized costs at June 30, 2015 and December 31, 2014 which were not included in the amortized cost pool were $8.2 million and $12.5 million, respectively.  These costs consist of exploratory wells in progress, seismic costs that are being analyzed for potential drilling locations and land costs related to unevaluated properties.  No capitalized costs related to unevaluated properties are included in the amortization base at June 30, 2015 or December 31, 2014.

Ceiling Test Analysis - Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling.  The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated average prices per barrel of oil and per MMbtu of natural gas at the first day of each month in the 12-month period prior to the end of the reporting period and costs, adjusted for contract provisions and financial derivatives that hedge our oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, reduced by (iv) the income tax effects related to differences between the book and tax basis of the crude oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs.

We perform a quarterly ceiling test for each of our oil and gas cost centers.  There is only one such cost center in 2015.  The reserves used in the ceiling test and the ceiling test itself incorporate assumptions regarding pricing and discount rates over which management has no influence in the determination of present value.  In arriving at the ceiling test for the quarter ended June 30, 2015, we used prices of $71.68 per barrel for oil and $3.390 per MMbtu for natural gas (and adjusted for property specific gravity, quality, local markets and distance from markets) to compute the future cash flows of our producing properties.  The discount factor used was 10%.

Primarily due to the lower oil prices, the Company recorded proved property impairments of $3.2 and $22.4 million related to its oil and gas assets during the three and six months ended June 30, 2015, respectively.  Management will continue to review our unproved properties based on market conditions and other changes and, if appropriate, unproved property amounts may be reclassified to the amortized base of properties within the full cost pool.  Recent declines in the price of oil have significantly increased the risk of ceiling test write-downs in future periods.

Wells in Progress - Wells in progress represent the costs associated with unproved wells that have not reached total depth or have not been completed as of period end.  They are classified as wells in progress and are withheld from the depletion calculation.  The costs for these wells are transferred to evaluated property when the wells reach total depth and are completed and the costs become subject to depletion and the ceiling test calculation in future periods.

Mineral Properties

We capitalize all costs incidental to the acquisition of mineral properties.  Mineral exploration costs are expensed as incurred.  When exploration work indicates that a mineral property can be economically developed as a result of establishing proved and probable reserves, costs for the development of the mineral property as well as capital purchases and capital construction are capitalized and amortized using units of production over the estimated recoverable proved and probable reserves. Costs and expenses related to general corporate overhead are expensed as incurred. All capitalized costs are charged to operations if we subsequently determine that the property is not economical due to permanent decreases in market prices of commodities, excessive production costs or depletion of the mineral resource. Mineral properties at June 30, 2015 and December 31, 2014 reflect capitalized costs associated with our Mt. Emmons molybdenum property near Crested Butte, Colorado.

Our carrying balance in the Mt. Emmons property at June 30, 2015 and December 31, 2014 is as follows:

⁽¹⁾On January 21, 2014, the Company acquired Thompson Creek Metals' ("TCM") 50% interest in 160 acres of fee land in the vicinity of the Mt. Emmons project mining claims for $1.2 million.  The property was originally acquired jointly by the Company and TCM in January 2009.

Properties and Equipment

Components of Property, Plant and Equipment as of June 30, 2015 and December 31, 2014 are as follows:

Land, buildings, improvements, machinery and equipment are carried at cost.  Depreciation of buildings, improvements, machinery and equipment is provided principally by the straight-line method over estimated useful lives ranging from 3 to 45 years.

Derivative Instruments

The Company uses derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk relating to its oil and gas production.  All derivative instruments are recorded in the consolidated balance sheets at fair value. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty. Although the Company does not designate any of its 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, the Company recognizes all unrealized and realized gains and losses related to these contracts currently in earnings and classifies them as gain (loss) on derivative instruments, on a net basis, in our consolidated statements of operations. The Company may also use puts, calls and basis swaps from time to time.

The Company's Board of Directors sets all risk management policies and reviews the status and results of derivative activities, including volumes, types of instruments and counterparties on a quarterly basis. These policies require that derivative instruments be executed only by the Chief Executive Officer or President. The agreements with approved counterparties identify the Chief Executive Officer and President as the only Company representatives authorized to execute trades. Please see Note 4, Commodity Price Risk Management, for further discussion.

Revenue Recognition

The Company records oil and natural 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. Natural gas balancing obligations as of June 30, 2015 were not significant.

Recent Accounting Pronouncements

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03").  The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset.  ASU 2015-03 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and should be applied retrospectively.  Early adoption is permitted.  The adoption of this standard will not have an impact on the Company's consolidated financial statements, other than balance sheet reclassifications.

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern ("ASU 2014-15").  The objective of ASU 2014-15 is to provide guidance on management's responsibility to evaluate whether there is substantial doubt about a company's ability to continue as a going concern and to provide related footnote disclosures.  ASU 2014-15 is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter.  The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company's consolidated financial statements and disclosures.

 

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers ("ASU 2014‑09").  The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards.  ASU 2014‑09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017.  The Company is currently evaluating the impact of adopting ASU 2014‑09, but the standard is not expected to have a significant effect on its consolidated financial statements.

There are no other new significant accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of June 30, 2015.

We record the fair value of the reclamation liability for our inactive mining properties and our operating oil and gas properties as of the date that the liability is incurred.  We review the liability each quarter and determine if a change in estimate is required, and we accrete the discounted liability on a quarterly basis for the future liability.  Final determinations are made during the fourth quarter of each year.  We deduct any actual funds expended for reclamation during the quarter in which it occurs.

 

The following is a reconciliation of the total liability for asset retirement obligations:

Through our wholly-owned subsidiary Energy One, we have entered into commodity derivative contracts ("economic hedges") with Wells Fargo, as described below.  The derivative contracts are priced using West Texas Intermediate ("WTI") quoted prices.  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 our future oil production, achieve more predictable cash flows in an environment of volatile oil and gas prices and manage our 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 our 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.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.  The Company's derivative contracts are currently held with a single counterparty.  The Company has a netting arrangement with the counterparty that provides for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination.  The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company's commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity price risk management assets and liabilities.  Derivative instruments are recorded at fair value on the condensed consolidated balance sheet and changes in fair value are recognized in the unrealized gain (loss) on risk management activities line on the condensed consolidated statement of operations. Realized gains and losses resulting from the settlement of derivatives are recorded in the realized (loss) gain on risk management activities line on the condensed consolidated statement of income.

Energy One's commodity derivative contracts as of June 30, 2015 are summarized below:

The following table details the fair value of the Company's derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the condensed consolidated balance sheet (in thousands):

The following table summarizes the unrealized and realized gains and losses presented in the accompanying statements of operations:

We follow authoritative guidance regarding fair value measurements for all assets and liabilities measured at fair value.  That guidance establishes a fair value hierarchy that prioritizes the inputs the Company uses to measure fair value based on the significance level of the following inputs:

·	Level 1 - Quoted prices (unadjusted) for identical assets or liabilities in active markets.

·	Level 2 - Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active and model-derived valuations whose inputs or significant value drivers are observable.

·	Level 3 - Significant inputs to the valuation model are unobservable.

Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels.  We determine our estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted prices in active markets, and quotes from third parties.

The following tables list the Company's assets and liabilities that are measured at fair value and their classification within the fair value hierarchy as of June 30, 2015 and December 31, 2014:

 

Fair Value of Available for Sale Securities

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

Fair Value of Commodity Derivative Instruments

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, 2015, derivative instruments utilized by the Company consist of "no premium" 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.

Fair Value of Executive Retirement Program

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.

Fair Value of Financial Instruments

Our other financial instruments include cash and cash equivalents, accounts receivable, accounts payable, other current liabilities and long-term debt.  The carrying amount of cash and cash equivalents, accounts receivable, accounts payable and other current liabilities approximate fair value because of their immediate or short-term maturities.  The carrying value of our debt approximates its fair market value as it bears interest at variable rates over the term of the loan.  The fair value and carrying value of our debt was $6.0 million as of June 30, 2015.

Revolving Credit Facility

Energy One, a wholly-owned subsidiary the Company, has in place a credit facility with Wells Fargo Bank, National Association ("Wells Fargo").  As of June 30, 2015, the maximum credit available under the credit facility was $100.0 million and the borrowing base under the facility was $7.5 million.  Effective July 16, 2015, the borrowing base was decreased to $7.0 million.

As of June 30, 2015, the Company had $6.0 million in outstanding borrowings under the credit facility.  Borrowings under the credit facility are collateralized by Energy One's oil and gas producing properties.  Each borrowing under the agreement has a term of six months, but can be continued at our election through July 2017 if we remain in compliance with the covenants under the facility.  The current weighted average interest rate on this debt is 2.94% at June 30, 2015.

At June 30, 2015, Energy One was not in compliance with the Current Ratio covenant of the credit facility.  In the third amendment to the credit agreement, executed on July 16, 2015, Wells Fargo granted a limited waiver of the breach of the Current Ratio covenant for the quarter ended June 30, 2015 and a prospective breach of the covenant for the quarter ended September 30, 2015 (see footnote 12 "Subsequent Events" below).  Because we project that it is unlikely that we will regain compliance with the Current Ratio covenant within the next 12 months, we have reflected the $6.0 million in debt under the credit facility as a current liability as of June 30, 2015 in the applicable balance sheets included in this report.  In the event that we are unable to obtain an amendment or waiver of the revolving credit facility to address potential future breaches, and other actual or potential future breaches that may occur, the lender under the facility  could elect to declare some or all of our debt to be immediately due and payable and could elect to terminate their commitments and cease making further loans.

 

Common Stock

The following table details the changes in common stock during the six months ended June 30, 2015:

 

Restricted Stock

The Company grants shares of restricted stock as part of its equity compensation program. Shares of restricted stock are valued at the closing price of the Company's common stock on the grant date and are recognized as general and administrative expense over the vesting period of the award.

During the six months ended June 30, 2015, the Company granted 340,711 shares of restricted stock under the 2012 Equity and Performance Incentive Plan (the "2012 Equity Plan") to certain employees.  The restricted shares vest in equal tranches over three years and had a fair value at issuance of $1.50 per share, which is equal to the closing price of the Company's stock on the date of grant.  Total compensation expense recorded for restricted stock for the three months ended June 30, 2015 and 2014 was $42,000 and $0, respectively. During the six months ended June 30, 2015 and 2014, we recorded $84,000 and $0, respectively, in compensation expense for restricted stock.  As of June 30, 2015, there was $427,000 of total unrecognized compensation expense related to unvested restricted stock awards, which will be amortized through 2017.

A summary of the status and activity of non-vested restricted stock for the six-month period ended June 30, 2015 is presented in the following table:

Stock Option Plans

The following table represents the activity in employee stock options and non-employee director stock options for the six months ended June 30, 2015:

Employee Stock Options.  During the six months ended June 30, 2015, we issued 340,711 options to certain employees under the 2012 Equity Plan.  The options were issued at the closing price of $1.50 on the date of grant, vest over a three year period and expire ten years from the date of grant.  These options were valued under the Black-Scholes pricing model using a risk free interest rate of 1.765%, expected life of six years and expected volatility of 63.3585%.  During the three months ended June 30, 2015 and 2014, we recorded $50,000 and $43,000, respectively, in compensation expense for employee stock options.  During the six months ended June 30, 2015 and 2014, we recorded $104,000 and $86,000, respectively, in compensation expense for employee stock options.  As of June 30, 2015, there was $314,000 of total unrecognized compensation cost related to employee stock options, which is expected to be amortized over a weighted average period of 2.20 years.

Director Stock Options.  During the three months ended June 30, 2015 and 2014, we recorded $15,000 and $44,000, respectively, in expense for options issued to non-employee directors.  During the six months ended June 30, 2015 and 2014, we recorded $35,000 and $60,000, respectively, in expense for options issued to non-employee directors.  As of June 30, 2015, there was $111,000 of total unrecognized compensation cost related to director stock options, which is expected to be amortized over a weighted average period of 2.08 years.

The Company uses the asset and liability method of accounting for deferred income taxes.  Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax bases of assets and liabilities.  Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time.

The deferred income tax assets or liabilities for an oil and gas exploration company are dependent on many variables such as estimates of the economic lives of depleting oil and gas reserves and commodity prices.  Accordingly, the asset or liability is subject to continual recalculation, and revision of the numerous estimates required, and may change significantly in the event of occurrences such as major acquisitions, divestitures, commodity price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.

The Company does not expect to pay any federal or state income tax for 2015 as a result of net operating loss carry forwards from prior years.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is "more likely than not" that some component or all of the benefits of deferred tax assets will not be realized.  As of June 30, 2015, the Company maintains a full valuation allowance on its net deferred tax assets. Based on these requirements, no provision or benefit for income taxes has been recorded for deferred taxes. There were no recorded unrecognized tax benefits at the end of the reporting period.

As of June 30, 2015, we had two reportable segments: Oil and Gas and Maintenance of Mineral Properties.  A summary of results of operations for the three and six months ended June 30, 2015 and 2014, and total assets as of June 30, 2015 and December 31, 2014 by segment, are as follows:

Basic net income per common share is calculated by dividing net income available to common stockholders by the basic weighted-average common shares outstanding for the relevant period.  The Company's earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.  Diluted net income per common share is calculated by dividing adjusted net income by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for this calculation consist of in-the-money outstanding stock options (which were assumed to have been exercised at the average market price of the common shares during the reporting period) and unvested restricted stock. The treasury stock method is used to measure the dilutive impact of unvested restricted stock and in-the-money stock options.

The following table sets forth the calculations of basic and diluted earnings per share (in thousands except share amounts and per share data):

The following options and unvested restricted stock, which could be potentially dilutive in future periods, were not included in the computation of diluted net loss per share because the effect would have been anti-dilutive for the periods indicated:

From time to time, we are 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 our financial position or results of operations.  Following are currently pending legal matters:

Water Rights Litigation –Mt. Emmons Project

On July 25, 2008, we filed an Application for Finding of Reasonable Diligence with the Colorado Water Court ("Water Diligence Application") concerning the conditional water rights associated with the Mt. Emmons Project (Case No. 2008CW81).  The conditional water decree ("Decree") required the Company to file its proposed plan of operations and associated permits with the Forest Service and BLM within six years of entry of the Decree, or within six years of the final determination of the pending patent application, whichever occurred later.  The BLM issued the mineral patents on April 2, 2004.  Although the issuance of the patents was appealed, on April 30, 2007, the United States Supreme Court made a final determination (by denial of certiorari) upholding BLM's issuance of the mineral patents.  The Company filed a plan of operations on March 31, 2010.  On April 20, 2015, the Colorado Water Court entered a decree granting the Water Diligence Application.  The decree continues the conditional water rights for a six-year period and requires the Company to submit a new Application for Finding of Reasonable Diligence in April 2021 if the water rights have not been applied to a beneficial use by that time.

Quiet Title Action – Dimmit County, TX

On October 4, 2013, Dimmit Wood Properties, Ltd. ("Dimmit") filed a quiet title, breach of contract, and trespass action against Chesapeake Exploration, LLC ("Chesapeake"), Crimson Exploration Operating, Inc. ("Crimson"), EXCO Operating Company, LP, OOGC America, Inc., Energy One and Liberty Energy, LLC ("Liberty") (jointly referred to as "Defendants") concerning an 800.77 gross acre oil and gas lease ("Lease") located in Dimmit County, Texas.  Crimson, Energy One and Liberty received an assignment from Chesapeake of the Lease, in which Energy One has a 30% working interest.  Dimmit alleged that the Lease terminated due to the failure to achieve production in paying quantities and for having non-existent production for allegedly significant time periods.  On April 27, 2015, the Company, Crimson and Liberty agreed to settle the action.  In accordance with the settlement agreement, the Company received $1.5 million in exchange for releasing its interest in the Lease.  The settlement agreement does not affect a similar case involving Dr. Darrell Willerson, Sue Willerson and Willerson Energy Partners, L.P.

Amendment to Credit Agreement

On July 16, 2015, the Company entered into a third amendment (the "Third Amendment") to its senior secured revolving credit facility, dated July 30, 2010 (as amended, the "Senior Credit Agreement"), among Energy One, the Company, as guarantor party thereto, the lender parties thereto and Wells Fargo Bank, National Association.  The Third Amendment provides for, among other things: (i) a limited waiver with respect to the restricted payments covenant pursuant to which a transfer of $5,000,000 from Energy One to the Company will be permitted in 2015; (ii) a limited waiver of the current ratio covenant as it relates to the fiscal quarters ending June 30, 2015 and September 30, 2015;  and (iii) a borrowing base of $7,000,000, subject to further adjustment from time to time in accordance with the Senior Credit Agreement.

The foregoing description of the Third Amendment is a summary only and is qualified in its entirety by reference to the Third Amendment, which was attached as an exhibit to the Company's Current Report on Form 8-K filed with the SEC on July 16, 2015.

Commodity Derivative Contracts

On July 14, 2015, Energy One entered into the following hedge transaction:

ITEM 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is Management's Discussion and Analysis of significant factors that have affected liquidity, capital resources and results of operations during the six months ended June 30, 2015 and 2014.  The following also updates information as to our financial condition provided in our Annual Report on Form 10-K for the year ended December 31, 2014 (the "2014 10-K").  Statements in the following discussion may be forward-looking and involve risk and uncertainty (see "Forward Looking Statements").  The following discussion should also be read in conjunction with our condensed consolidated financial statements and the notes thereto.

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 operations to other geographic 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.  We are in the process of developing operational capabilities and expect to pursue opportunities to acquire operated properties and/or operatorship of existing properties.

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

Our current capitalized amounts in the oil and gas and mining areas at June 30, 2015 and December 31, 2014 were as follows:

Oil and Gas Activities

We have active agreements with several oil and gas exploration and production companies.  Our working interest varies by project (and may vary over time depending on the terms of the relevant agreement), but typically ranges from approximately 1% to 62%.  These projects may result in numerous wells being drilled over the next three to five years, although currently depressed commodity prices have had and will likely continue to have an adverse effect on the level of drilling activity.  We are also

 

actively pursuing the potential acquisition of additional exploration, development or production stage oil and gas properties or companies.  The following table details our interests in producing wells as of June 30, 2015 and 2014.

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

Our net investment in Williston Basin, North Dakota wells was $219,000 during the six months ended June 30, 2015.

Rough Rider Prospect.  We participate in fifteen 1,280 acre drilling units in the Rough Rider prospect with Statoil Oil & Gas, L.P. ("Statoil").  From August 24, 2009 to June 30, 2015, we have drilled and completed 24 gross (6.39 net) Bakken formation wells and two gross (0.22 net) Three Forks formation wells under our Drilling Participation Agreement with Statoil.  Statoil operates all of the wells.

Yellowstone and SEHR Prospects.  We participate in twenty-seven gross 1,280 acre spacing units in the Yellowstone and SEHR prospects with Zavanna, LLC ("Zavanna").  Through June 30, 2015, we have drilled and completed 44 gross (3.11 net) Bakken formation wells and nine gross (0.33 net) Three Forks formation wells in these prospects.  The wells are operated by Zavanna (18 gross, 2.91 net), Emerald Oil, Inc. (30 gross, 0.35 net), Murex Petroleum (2 gross, 0.13 net), Kodiak Oil & Gas Corp. (2 gross, 0.04 net) and Slawson Exploration Company, Inc. (1 gross, 0.01 net).  During the first six months of 2015, we completed three gross (0.01 net) wells in the Yellowstone and SEHR prospects.

Bakken/Three Forks Asset Package.  In 2012, we acquired approximately 400 net acres in 23 drilling units in McKenzie, Williams and Mountrail Counties of North Dakota.  In June 2014, we sold our interest in eight of these 23 drilling units (approximately 285.7 net acres) for $12.2 million.   At June 30, 2015, there were 23 gross (0.24 net) producing wells in the remaining 15 drilling units.  At June 30, 2015, 14 additional gross (0.02 net) wells had been spud and were in progress.

Booth-Tortuga and Leona River Prospects.  We participate in the Booth-Tortuga and Leona River prospects with Contango Oil & Gas Company ("Contango").  At June 30, 2015, we have 30 gross (8.23 net) producing wells in these prospects, comprised of 16 gross (4.35 net) Buda limestone wells, three gross (0.90 net) Eagle Ford Shale wells and 11 gross (2.98 net) Austin Chalk wells.  One additional Buda limestone well (0.13 net) was in progress at June 30, 2015.  The wells are operated by Contango (28 gross, 8.08 net), WCS Oil & Gas Corporation (2 gross, 0.15 net) and CML Exploration (1 gross, 0.13 net).  Our net investment in these wells during the first six months of 2015, including lease acquisition and holding costs in the prospects, was $777,000.

Big Wells Prospect.   We participate in the Big Wells prospect with U.S. Enercorp.  At June 30, 2015, we have two gross (0.30 net) producing Buda limestone wells in this prospect.

Carrizo Creek and South McKnight Prospects.  We participate in the Carrizo Creek and South McKnight prospects with U.S. Enercorp.  At June 30, 2015, we have four gross (1.33 net) producing wells in these prospects.  One additional well (0.33 net) was in progress at June 30, 2015.  Our net investment in this acreage and wells during the six months ended June 30, 2015 was $1.0 million.

We participate with three different operators in the onshore U.S. Gulf Coast area.  At June 30, 2015, we had three gross (0.56 net) producing wells in this region.

The following table provides a regional summary of our net production during the first six months of 2015:

Uranium Properties

On June 30, 2015, the Company entered into Amendment No. 1 to the Amendment Assignment and Assumption Agreement dated as of August 14, 2014.  As amended, conditioned upon the closing of a purchase and sale transaction between Anfield Resources Inc. ("Anfield") and Uranium One Inc. ("Uranium One") by August 31, 2015 (the "Anfield-Uranium One Transaction"), the Company agreed to release Anfield from the future payment and royalty obligations stemming from the Company's 2007 sale of its uranium properties to Uranium One.  In return, Anfield has agreed to pay the Company the following:

1.	$750,000 in Anfield common shares upon closing of the Anfield-Uranium One Transaction.

2.	$750,000 in Anfield common shares on the first anniversary of the closing of the Anfield-Uranium One Transaction.

3.	$1.0 million in Anfield common shares on the second anniversary of the closing of the Anfield-Uranium One Transaction.

4.	$2.5 million in cash paid upon 18 months of continuous commercial production, and

5.	$2.5 million in cash paid upon 36 months of continuous commercial production.

If any of the share issuances result in the Company holding in excess of 20% of the then issued and outstanding shares of Anfield (the "Threshold"), such shares in excess of the Threshold will not be issued at that time, but will be deferred to the next scheduled share issuance.  If, upon the final scheduled share issuance the number of shares to be issued exceeds the Threshold, the value in excess of the Threshold shall be paid to the Company in cash.

As the Anfield-Uranium One Transaction has not closed as of the date of this report, the timing of any potential future receipt of funds from any of these contingencies is not known.

Mount Emmons Molybdenum Project

With respect to the Mount Emmons project, the Company expects to continue its scoping analysis of the Mine Plan of Operations with the U.S. Forest Service through the balance of 2015.

Additional Comparative Data

The following table provides information regarding selected production and financial information for the quarter ended June 30, 2015 and the immediately preceding three quarters.

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

During the three months ended June 30, 2015, we recorded a net loss after taxes of $6.3 million, or $0.22 per share basic and diluted, as compared to net income after taxes of $56,000, or $0.00 per share basic and diluted, during the same period of 2014.

Oil and Gas Operations.   Oil and gas operations generated an operating loss of $4.0 million during the quarter ended June 30, 2015 as compared to operating income of $3.0 million during the quarter ended June 30, 2014.  The following table summarizes production volumes, average sales prices and operating revenues for the three months ended June 30, 2015 and 2014: