US ENERGY CORP - Quarter Report: 2014 September (Form 10-Q)

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).

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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 November 7, 2014 there were issued and outstanding 27,905,940 shares of the Company's common stock, $0.01 par value.

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U.S. ENERGY CORP. and SUBSIDIARIES

INDEX

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PART I.  FINANCIAL INFORMATION

ITEM 1.  Financial Statements

 

 

 

 

 

The accompanying notes are an integral part of these statements.

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U.S. ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except share and per share data)
		Three months ended September 30,								Nine months ended September 30,
		2014				2013				2014				2013
Income taxes:
Current (provision for)			--				--				--				--
Deferred benefit from			--				--				--				--
			--				--				--				--
Income (loss) from continuing operations			(63	)			(706	)			243				(6,469	)
Discontinued operations:
Discontinued operations, net of taxes			--				(8	)			--				430
Loss on sale of discontinued
operations, net of taxes			--				(120	)			--				(120	)
			--				(128	)			--				310
Net income (loss)		$	(63	)		$	(834	)		$	243			$	(6,159	)
Earnings (loss) per share basic and diluted
Earnings (loss) from continuing operations		$	--			$	(0.03	)		$	0.01			$	(0.23	)
Earnings from discontinued operations			--				--				--				0.01
		$	--			$	(0.03	)		$	0.01			$	(0.22	)
Weighted average shares outstanding
Basic			27,899,505				27,682,602				27,808,231				27,677,382
Diluted			27,899,505				27,682,602				28,200,388				27,677,382

 

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The accompanying notes are an integral part of these statements.

 

 

 

The accompanying notes are an integral part of these statements.

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

The accompanying unaudited condensed consolidated financial statements for the periods ended September 30, 2014 and September 30, 2013 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 September 30, 2014 and December 31, 2013 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, 2013 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, 2013 (the "2013 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 2013 10-K (Note B, pages 86 to 94).

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.

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

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 September 30, 2014 and December 31, 2013 which were not included in the amortized cost pool were $10.1 million and $7.5 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 September 30, 2014 or December 31, 2013.

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 2014.  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 September 30, 2014, we used prices of $99.08 per barrel for oil and $4.236 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%.

The Company recorded no proved property impairments related to its oil and gas assets during the three and nine months ended September 30, 2014.  During the three and nine months ended September 30, 2013, the Company recorded proved property impairments of $0 and $5.8 million, respectively.  The impairment recorded for the nine months ended September 30, 2013 was primarily due to a decline in the price of oil, additional capitalized well costs and changes in production.  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.

 

 

 

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 September 30, 2014 and December 31, 2013 reflect capitalized costs associated with our Mt. Emmons molybdenum property near Crested Butte, Colorado.

Our carrying balance in the Mt. Emmons property at September 30, 2014 and December 31, 2013 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 September 30, 2014 and December 31, 2013 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 in the future.

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 5, 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 September 30, 2014 were not significant.

Recent Accounting Pronouncements

In April 2014, the FASB issued new authoritative accounting guidance related to the recognition and presentation of discontinued operations in the financial statements. The guidance is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity's operations and financial results. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2014, and is to be applied prospectively. The Company is currently evaluating the provisions of this authoritative guidance and assessing its impact, but does not currently believe it will have a material effect on the Company's financial statements or disclosures.

In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue. This authoritative accounting guidance is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period, and is to be applied using one of two acceptable methods.  The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company's financial statements and disclosures.

 

In June 2014, the FASB issued new authoritative accounting guidance related to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied either prospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company's financial statements and disclosures.

In August 2014, the FASB issued new authoritative guidance that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity's ability to continue as a going concern within one year after the date that the entity's financial statements are issued, or within one year after the date that the entity's financial statements are available to be issued, and to provide disclosures when certain criteria are met.  This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted.  The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company's financial statements and disclosures.

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 September 30, 2014.

Acquisitions

On May 7, 2014, the Company entered into a Participation Agreement with a private South Texas based oil and gas company ("Seller") to acquire 33% of the Seller's interest in approximately 12,100 gross (3,384 net) acres in Dimmit County, Texas.  The acreage consists of 4,020 gross (1,181 net) acres of primary leasehold acreage and 8,080 gross (2,203 net) acres of farm-in acreage, to be earned through a continuous drilling program. The farm-in acreage has an initial two well commitment and a 12.5% working interest carry for the leaseholder (the "Farmor") in the first 10 wells. After 100% payout of all costs for the first 10 wells that are drilled under the farm-in program, the Farmor will back in for its 12.5% retained working interest in the prospect. The Seller also retained a 25% working interest back-in after 115% of project payout has been received by the Company. The Company paid $3.9 million to enter into the transaction, which included leasehold and farm-in acquisition costs as well as our proportionate share of drilling costs for the initial test well in the prospect.

Divestitures

On May 27, 2014, the Company entered into a Purchase and Sale Agreement to sell certain Williston Basin assets. Under the terms of the sale agreement, the Company sold its interest in approximately 285.70 net acres and 16 gross (0.62 net) producing wells in Williams and McKenzie Counties, North Dakota. The transaction closed in June 2014 with an effective date of January 1, 2014.  The Company received $12.2 million at closing which included $681,000 in adjustments related to revenue receivable and accounts payable through the date of closing.  The $11.5 million balance of the sale proceeds was recorded as a credit to our full cost pool.

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

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 with one 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 September 30, 2014 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 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 September 30, 2014 and December 31, 2013:

 

 

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

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 September 30, 2014 and December 31, 2013, 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 $8.0 million as of September 30, 2014.

Revolving Credit Facility

Energy One, a wholly-owned subsidiary the Company, has in place a credit facility with Wells Fargo Bank, National Association.  As of September 30, 2014, the maximum credit available under the credit facility was $100.0 million and the borrowing base under the facility was $24.5 million.

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

As of September 30, 2014, the Company had $8.0 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.  Our intent is to extend this debt and therefore we have classified it as a long-term liability.  The current weighted average interest rate on this debt is 2.72%.  As of September 30, 2014, Energy One was in compliance with all the covenants under the credit facility.

Common Stock

2001 Stock Compensation Plan.  The 2001 Stock Compensation Plan terminated on April 23, 2013 and, accordingly, no shares have been issued under this plan subsequent to that date.  During the nine months ended September 30, 2013, the Company issued 30,000 shares of common stock to eligible officers of the Company under the plan and recorded $48,000 in compensation expense.

The following table details the changes in common stock during the nine months ended September 30, 2014:

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

Stock Option Plans

The following table represents the activity in employee stock options and non-employee director stock options for the nine months ended September 30, 2014:

Employee Stock Option Plans.  During the three months ended September 30, 2014 and 2013, we recorded $106,000 and $44,000, respectively, in compensation expense for employee stock options.  During the nine months ended September 30, 2014 and 2013, we recorded $192,000 and $76,000, respectively, in compensation expense for employee stock options.  As of September 30, 2014, there was $200,000 of total unrecognized compensation cost related to employee stock options, which is expected to be amortized over a weighted average period of 1.53 years.  The aggregate intrinsic value of employee stock options exercised during the three and nine months ended September 30, 2014 was $19,000 and $743,000, respectively.

Director Stock Option Plans.  During the three and nine months ended September 30, 2014, we issued 60,000 options to non-employee directors under the 2008 Stock Option Plan for Independent Directors.  The options were issued at the closing price of $3.77 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 2.06%, expected life of six years and expected volatility of 65.4469%.  During the three months ended September 30, 2014 and 2013, we recorded $15,000 and $16,000, respectively, in expense for options issued to non-employee directors.  During the nine months ended September 30, 2014 and 2013, we recorded $75,000 and $47,000, respectively, in expense for options issued to non-employee directors.  As of September 30, 2014, there was $168,000 of total unrecognized compensation cost related to director stock options, which is expected to be amortized over a weighted average period of 2.60 years.  The aggregate intrinsic value of director stock options exercised during the three and nine months ended September 30, 2014 was $17,000 and $45,000, respectively.

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued

 

 

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 such things as major acquisitions, divestitures, product 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 2014 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 September 30, 2014, 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 September 30, 2014, we had two reportable segments: Oil and Gas and Maintenance of Mineral Properties.  A summary of results of operations for the three and nine months ended September 30, 2014 and 2013, and total assets as of September 30, 2014 and December 31, 2013 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). The treasury stock method is used to measure the dilutive impact of 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, which could be potentially dilutive in future periods, were not included in the computation of diluted net income per share because the effect would have been anti-dilutive for the periods indicated:

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U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)

(Continued)

The Company owns 19.54% of Standard Steam Trust, LLC ("SST"), a Denver, Colorado based private geothermal resource acquisition and development company.  At December 31, 2013, we recorded an impairment of $2.2 million on the investment in SST, which reduced the carrying amount of our investment in SST to zero.  Subsequently, we no longer record our share of equity in earnings or losses.  During the three and nine months ended September 30, 2013, we recorded an equity gain of $11,000 and an equity loss of $40,000, respectively, from our unconsolidated investment in SST.

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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 three and nine months ended September 30, 2014 and 2013.  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, 2013 (the "2013 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 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 September 30, 2014 and December 31, 2013 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.  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 September 30, 2014 and 2013.

 

 

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

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 September 30, 2014, we have drilled and completed 24 gross (6.32 net) Bakken formation wells and two gross (0.22 net) Three Forks formation wells under our Drilling Participation Agreement with Statoil.

During the nine months ended September 30, 2014, we completed three gross (0.07 net) Bakken formation wells.   Our net investment in the Rough Rider prospect wells was $527,000 for the nine months ended September 30, 2014.  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 September 30, 2014, we have drilled and completed 38 gross (3.08 net) Bakken formation wells and seven gross (0.32 net) Three Forks formation wells in these prospects.  The wells are operated by Zavanna (18 gross, 2.91 net), Emerald Oil, Inc. (22 gross, 0.32 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 nine months of 2014, we completed eight gross (0.09 net) wells in the Yellowstone and SEHR prospects.  At September 30, 2014, six additional gross (0.02 net) wells had been spud and were in progress.

Our net investment in the Yellowstone and SEHR prospect wells was $1.7 million during the nine months ended September 30, 2014.

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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 September 30, 2014, there were 23 gross (0.24 net) producing wells in the remaining 15 drilling units.

During the nine months ended September 30, 2014, our net investment in wells under the remaining drilling units in this program was $43,000.

Booth-Tortuga and Leona River Prospects.  We participate in the Booth-Tortuga and Leona River prospects with Contango Oil & Gas Company ("Contango").  At September 30, 2014, 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.  During the nine months ended September 30, 2014, we drilled and completed ten gross (3.0 net) Buda limestone wells in the Booth-Tortuga prospect.  One additional Buda limestone well (0.30 net) was in progress at September 30, 2014.  The wells are operated by Contango (28 gross, 8.08 net) and WCS Oil & Gas Corporation (2 gross, 0.15 net).  Our net investment in these wells during the first nine months of 2014, including lease acquisition costs in the prospects, was $11.1 million.

Big Wells Prospect.   We participate in the Big Wells prospect with U.S. Enercorp.  At September 30, 2014, we have two gross (0.30 net) producing Buda limestone wells in this prospect.  During the nine months ended September 30, 2014, we drilled and completed one gross (0.15 net) well in the Big Wells prospect.  Our net investment in this well during the nine months ended September 30, 2014 was $810,000.

Q2 2014 Acquisition.  In May 2014, the Company acquired 33% of a private South Texas based oil and gas company's (the "Seller") interest in approximately 12,100 gross (3,384 net) acres in Dimmit County, Texas.  The acreage consists of 4,020 gross (1,181 net) acres of primary leasehold acreage and 8,080 gross (2,203 net) acres of farm-in acreage, to be earned through a continuous drilling program.  The farm-in acreage has an initial two well commitment and a 12.5% working interest carry for the leaseholder (the "Farmor") in the first 10 wells. After 100% payout of all costs for the first 10 wells that are drilled under the farm-in program, the Farmor will back in for its 12.5% retained working interest in the prospect. The Seller also retained a 25% working interest back-in after 115% of project payout has been received by the Company. The Company paid $3.9 million to enter into the transaction, which included leasehold and farm-in acquisition costs as well as our proportionate share of drilling costs for the initial test well in the prospect.

Two gross (0.67 net) wells were drilled and completed on the acquired acreage during the nine months ended September 30, 2014.  One additional well (0.33 net) was in progress at September 30, 2014.  Our net investment in this acreage and wells through September 30, 2014 was $7.8 million.

We participate with three different operators in the onshore U.S. Gulf Coast area.  At September 30, 2014, we had three gross producing (0.56 net) wells in this region.  Our net investment in Gulf Coast wells and properties was $30,000 during the nine months ended September 30, 2014.

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The following table provides a regional summary of our net production during the first nine months of 2014:

Uranium Properties

On August 14, 2014, conditioned upon the closing of a purchase and sale transaction between Anfield Resources Inc. ("Anfield") and Uranium One Inc. ("Uranium One"), 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.	$2.5 million in Anfield common shares upon closing of the transactions contemplated by the asset purchase agreement between Anfield and Uranium One.  The shares will be held in escrow and released in tranches over a 36 month period,

2.	$2.5 million in cash paid upon 18 months of continuous commercial production, and

3.	$2.5 million in cash paid upon 36 months of continuous commercial production.

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 scoping analysis of the Mine Plan of Operations with the U.S. Forest Service through the balance of 2014.

Additional Comparative Data

The following table provides information regarding selected production and financial information for the quarter ended September 30, 2014 and the immediately preceding three quarters.

 

 

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