XNAS:USEG U.S. Energy Corp. Quarterly Report 10-Q Filing - 6/30/2012
Effective Date 6/30/2012
| • 10-Q 6-30-12 • CEO CERT • PAO CERT • CEO SOX CERT • PAO SOX CERT • INSTANCE DOCUMENT • SCHEMA DOCUMENT • CALCULATION DOCUMENT • LABEL DOCUMENT • PRESENTATION DOCUMENT • DEFINITION DOCUMENT | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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.
YES x NO o
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 x NO o
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).
YES o NO x
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
At August 6, 2012 there were issued and outstanding 27,475,978 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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The accompanying notes are an integral part of these statements.
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The accompanying notes are an integral part of these statements.
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The accompanying notes are an integral part of these statements.
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The accompanying notes are an integral part of these statements.
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The accompanying notes are an integral part of these statements.
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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)
1) Basis of Presentation
The accompanying unaudited condensed consolidated financial statements for the periods ended June 30, 2012 and June 30, 2011 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, 2012 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, 2011 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 by 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. The unaudited condensed consolidated financial statements should be read in conjunction with the Company's December 31, 2011 Annual Report on Form 10-K. Subsequent events have been evaluated for financial reporting purposes through the date of the filing of this Form 10-Q.
2) Summary of Significant Accounting Policies
We follow accounting standards set by the Financial Accounting Standards Board, commonly referred to as the “FASB.” The FASB sets generally accepted accounting principles (U.S. GAAP) that 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 Form 10-K for the year ended December 31, 2011 (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 and the cost of future asset retirement obligations. 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.
Properties and Equipment
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.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
Components of Property and Equipment as of June 30, 2012 and December 31, 2011 are as follows:
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, 2012 and December 31, 2011 which were not included in the amortized cost pool were $12.7 million and $20.0 million, respectively. These costs consist of exploratory wells in progress, seismic costs that are being analyzed for potential drilling locations as well as land costs related to unevaluated properties. No capitalized costs related to unevaluated properties are included in the amortization base at June 30, 2012 and December 31, 2011. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are proved, drilled or abandoned.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
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 was only one such cost center in 2012. 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, 2012, we used $95.67 per barrel for oil and $3.13 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%.
At June 30, 2012, the Company recorded a proved property impairment of $523,000 related to its oil and gas assets, primarily due to a decline in natural gas prices. There were no proved property impairments recorded during the first six months of 2011. 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 withheld from the depletion calculation. The costs for these wells are then 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, 2012 and December 31, 2011 reflect capitalized costs associated with our Mt. Emmons molybdenum property near Crested Butte, Colorado.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
Our carrying balance in the Mt. Emmons property at June 30, 2012 and December 31, 2011 is as follows:
Derivative Instruments
The Company uses derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk underlying 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 a cash flow hedge, 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 they are classified as gain (loss) on derivative instruments, net 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 master contracts with approved counterparties identify the Chief Executive Officer and President as the only Company representatives authorized to execute trades. See Note 6, 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, 2012 were not significant.
Revenues from real estate operations are reported on a gross revenue basis and are recorded at the time the service is provided.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
Recent Accounting Pronouncements
On January 1, 2012, the Company adopted Accounting Standards Update No. 2011-05 (“ASC No. 2011-05”), an update to ASC Topic 220 issued by the FASB that states that an entity that reports items of other comprehensive income has the option to present the components of comprehensive income in either one continuous financial statement, or two consecutive financial statements, including reclassification adjustments. Subsequent to the issuance of the authoritative guidance, the FASB issued additional authoritative accounting guidance (“ASC No. 2011-12”) that effectively deferred the requirement to present the reclassification adjustments on the face of the financial statements, as well as the requirement to present the individual components of other comprehensive income for interim periods. The Company has elected to present a separate statement of comprehensive income, including the individual components, titled Condensed Consolidated Statements of Comprehensive Loss, as part of Item 1 to this report.
In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. ASU 2011-11 is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. The adoption of this standard is not expected to have an impact on the Company’s consolidated financial statements.
In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which provides amendments to FASB ASC Topic 820, Fair Value Measurement. The objective of ASU 2011-04 is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements. These amendments are not expected to have a significant impact on companies applying GAAP. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this standard did not have an impact on the Company’s consolidated financial statements other than additional disclosures.
3) Mineral Property Transactions
Bakken/Three Forks Shale Sale. On January 24, 2012 (but effective December 1, 2011), we sold an undivided 75% of our undeveloped acreage with Zavanna, LLC (“Zavanna”) in the Yellowstone and SEHR prospects to GeoResources, Inc. (56.25%) and Yuma Exploration and Production Company, Inc. (18.75%) for $16.7 million and $1.4 million in reimbursed well costs. These amounts were recorded as credits to our full cost pool. In addition we transferred $5.3 million in costs from unevaluated properties to proved properties as a result of this sale. Under the terms of the agreement, we retained the remaining 25% of our interest in the undeveloped acreage and our original working interest in the initial 10 developed wells in the prospects. Our average working interest in the remaining locations will be approximately 8.75% and net revenue interests in new wells after the sale are expected to be in the range of 6.7375% to 7.0%, proportionately reduced depending on Zavanna’s actual working interest percentages.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
Woodbine Acquisition. In May 2012, we entered into a participation agreement with a private entity, Mueller Exploration, Inc. ("Mueller") to participate in the Woodbine Sub-Clarksville 7 Project located in Anderson and Cherokee Counties, Texas. Under the terms of the agreement, we acquired a 26.5% initial working interest (19.6% net revenue interest) in approximately 6,766 gross acres (1,274 net acres to USE) for $1.7 million. The promoted amount covers our portion of the costs for land, geological and geophysical work, as well as all dry hole costs for an initial test well in each of the seven prospects. Upon payout of our initial well costs in each unit, our interest will be reduced to a 19.8% working interest (14.7% net revenue interest). Future infill drilling will be on a heads up basis, and our interest will be a 19.8% working interest (14.7% net revenue interest).
Montana Acreage Sale. On June 8, 2012, we sold an undivided 87.5% of our acreage in Daniels County, Montana to a third party for $3.7 million. This amount was recorded as a credit to our full cost pool. In addition we transferred $1.0 million in costs from unevaluated properties to proved properties as a result of this sale. Under the terms of the agreement, we retained a 12.5% working interest in the acreage and reserved overriding royalty interests (“ORRI”) in leases we owned that had in excess of 81% NRI. The purchaser also committed to drill a vertical test well to depths sufficient to core the Bakken and Three Forks formations on or before December 31, 2015. We delivered an 80% NRI to the purchaser and a 1% ORRI to a land broker. We also paid the land broker a 10% commission for the cash consideration paid by the purchaser.
4) Assets Held for Sale
In January 2011, we made the decision to sell our Remington Village multifamily project in Gillette, Wyoming and plan to use the proceeds to further the development of our oil and gas business. On July 9, 2012, the Company entered into a Letter of Intent (“LOI”) to sell Remington Village for $16.0 million. As a result of the anticipated sale amount, at June 30, 2012, the Company recorded a non-cash impairment of $2.0 million to adjust the carrying value of the project to the expected sale value. Ultimately, we could not reach mutually agreeable terms for the sale and the LOI was terminated. We will continue to market the property for sale.
As of June 30, 2012, the accompanying condensed consolidated balance sheets present approximately $16 million in book value of assets held for sale, net of accumulated depreciation, and $10.2 million in liabilities held for sale. Because Remington Village has been classified as an asset held for sale, scheduled depreciation of $448,000 for the first six months of 2012 and $473,000 for the first six months of 2011 was not recorded. Remington is pledged as collateral on a $10.0 million note. At such time as Remington is sold, the debt balance will be retired.
Operations related to Remington Village are shown in discontinued operations on the accompanying condensed consolidated statements of operations.
5) Asset Retirement Obligations
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 as well as 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.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
The following is a reconciliation of the total liability for asset retirement obligations:
6) Commodity Price Risk Management
Through our wholly-owned subsidiary Energy One, we have entered into commodity derivative contracts (“economic hedges”) with BNP Paribas (“BNP”), 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 to 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.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
Energy One's commodity derivative contracts as of June 30, 2012 are summarized below:
The following table details the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category:
Unrealized gains and losses resulting from derivatives 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 contract settlement of derivatives are recorded in the commodity price risk management activities line on the condensed consolidated statement of income.
7) Fair Value Measurements
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:
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
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. As of June 30, 2012, we held $221,000 of investments in marketable securities. We determine our estimate of the fair value of derivate instruments using a market approach based on several factors, including quoted prices in active markets, and quotes from third parties. The fair values of our other accrued liabilities that are reflected on the balance sheet are detailed below. Other accrued liabilities decreased to $795,000 at June 30, 2012 as a result of payments of the liability. The other accrued liabilities are the long term portion of the executive retirement program.
The following table summarizes, by major security type, the fair value and any unrealized gain of our available for sale securities. The unrealized gain is recorded on the condensed consolidated balance sheets as other comprehensive income, a component of shareholders’ equity.
The following table summarizes the change in the fair value of our Level 3 Fair Value measurements for the six months ended June 30, 2012.
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 since interest rates have remained generally unchanged from the issuance of the debt. The fair value and carrying value of our debt was $15.2 million as of June 30, 2012.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
8) Debt
At June 30, 2012, total debt in the amount of $15.2 million consists of $9.8 million in debt on our multifamily housing project, $5.0 million in debt from our reserve based senior credit facility and $400,000 in debt related to the purchase of land near our Mt. Emmons molybdenum property.
On May 5, 2011 we borrowed $10.0 million from a commercial bank against Remington Village. At June 30, 2012, the balance due on this note is $9.8 million. The note is collateralized by the Company’s multi-family property in Gillette, Wyoming. The note is amortized over 20 years with a balloon payment at the end of five years with an interest rate of 5.50% per annum. Proceeds of the note were used to fund general business obligations. When Remington is sold, the proceeds from the sale will first be applied to the retirement of the debt and the remainder applied to general corporate overhead and project development. Therefore, the debt is included in current liabilities held for sale.
On May 1, 2012, we borrowed $5.0 million under our reserve based senior credit facility to fund our oil and gas programs. The debt has a term of six months and is due in November 2012, but can be continued at our election through July 2014 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 interest rate on this debt is 2.98%. As of June 30, 2012, Energy One was in compliance with all the covenants under the senior credit facility.
The land debt of $400,000 bears an interest rate of 6.0% per annum and is due in two equal annual payments of $200,000 plus accrued interest. The next payment is due on January 2, 2013.
9) Shareholders’ Equity
Common Stock
During the six months ended June 30, 2012, the Company issued 51,070 shares of common stock. These shares consist of (a) 30,000 shares issued to officers of the Company pursuant to the 2001 Stock Compensation Plan, (b) 20,000 shares issued as a result of options being exercised by a former director of the Company and (c) a net of 1,070 shares issued as a result of the exercise of options by an employee of the Company.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
The following table details the changes in common stock during the three months ended June 30, 2012:
Employee Stock Option Plans
All options outstanding at June 30, 2012 were granted pursuant to the U.S. Energy Corp. 2001 Incentive Stock Option Plan (the "2001 ISOP"). The 2001 ISOP had a term of 10 years, and expired on December 6, 2011. Options issued prior to that date will survive to their expiration date which does not exceed a ten year period from date of grant and are subject to vesting and forfeiture provisions.
During the three and six months ended June 30, 2012, we recorded $2,000 in compensation expense for employee stock options. As of June 30, 2012, there was no unrecognized compensation expense related to employee stock option awards. As a result of the exercise of 4,167 options held by a former employee, 1,070 shares of common stock were issued during the six months ended June 30, 2012.
Director Option Plans
From time to time we issue stock options to non-employee directors for services. During the six months ended June 30, 2012, we issued 70,000 options to non-employee directors. The options were issued at the closing price of $2.85 on the date of grant; 60,000 options vest over a three year period and expire ten years from the date of grant or one year after the Board member no longer serves on the Board and 10,000 options vested immediately and expire ten years from the date of grant or one year after the Board member no longer serves on the Board. The options were valued under Black-Scholes using a risk free interest rate of 1.13% to 1.41%, expected life of 5 to 6 years and expected volatility of 62.75% to 63.59%.
During the three and six months ended June 30, 2012, we recorded $15,000 and $37,000, respectively, in expense for options issued to non-employee directors. We will recognize an additional $130,000 in expense over the vesting period of the outstanding options. During the six months ended June 30, 2012, we issued 20,000 shares of common stock to a former director of the Company as the result of the exercise of 20,000 outstanding options.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
The following table represents the activity in employee stock options and non-employee director stock options for the six months ended June 30, 2012:
10) Income Taxes
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 basis 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 liability for an oil and gas exploration company is dependent on many variables such as estimating the economic lives of depleting oil and gas reserves and commodity prices. Accordingly, the liability is subject to continual recalculation, 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.
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
11) Segment Information
As of June 30, 2012, we had two reportable segments: Oil and Gas and Maintenance of Mineral Properties. A summary of results of operations for the six months ended June 30, 2012, and 2011, and total assets as of June 30, 2012 and December 31, 2011 by segment are as follows:
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U.S. ENERGY CORP.
Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)
12) Equity Income in Unconsolidated Investment
We recorded an equity loss from our unconsolidated investment in Standard Steam, LLC (“SST”) during the three and six months ended June 30, 2012 of $91,000 and $151,000, respectively.
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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 six months ended June 30, 2012 and 2011. The following also updates information as to our financial condition provided in our 2011 Annual Report on Form 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 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 the Rocky Mountain region (specifically the Williston Basin of North Dakota and Montana), Texas and Louisiana, 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 recently operated a Colorado oil and gas property for our own account and may expand our operations to 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.
We are also involved in the exploration for and development of minerals (molybdenum) through our ownership of the Mt. Emmons Molybdenum Project in Colorado. Gross capitalized dollar amounts invested in each of these areas at June 30, 2012 and December 31, 2011 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, but typically ranges from approximately 5% 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 June 30, 2012 and 2011.
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Williston Basin, North Dakota
Rough Rider Prospect. We participate in fifteen 1,280 acre drilling units in the Rough Rider prospect with Brigham Oil & Gas, L.P. (“Brigham”), a subsidiary of Statoil. From August 24, 2009 to June 30, 2012, we have drilled and completed 20 gross Bakken Formation wells (7.34 net) and one gross Three Forks formation well (0.18 net) under the Drilling Participation Agreement with Brigham. Two additional gross wells (0.10 net) are expected to be drilled during the balance of 2012. Brigham operates all of the wells.
During the first six months of 2012, the Company completed three gross wells (0.45 net) in the Rough Rider prospect. Our net investment in the Rough Rider prospect wells was $3.9 million for the six months ended June 30, 2012.
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, 2012, we have drilled and completed 11 gross Bakken formation wells (2.31 net) in these prospects, including two gross wells (0.12 net) operated by Murex Petroleum and one gross well (0.01 net) operated by Slawson Exploration Company, Inc. Zavanna operates the remaining wells. At June 30, 2012, three additional gross wells (0.25 net) had been drilled and were awaiting completion.
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During the first six months of 2012, we completed six gross wells (1.28 net) and drilled three gross wells (0.25 net) in the Yellowstone and SEHR prospects. Our net investment in the Yellowstone and SEHR prospect wells was $13.9 million during the six months ended June 30, 2012.
On January 24, 2012 (but effective December 1, 2011), we sold an undivided 75% of our undeveloped acreage in the Yellowstone and SEHR prospects to GeoResources, Inc. (56.25%) and Yuma Exploration and Production Company, Inc. (18.75%) for $16.7 million. Under the terms of the agreement, we retained the remaining 25% of our interest in the undeveloped acreage and our original working interest in the initial 10 developed wells in the prospects. Our average working interest in the remaining locations will be approximately 8.75% and net revenue interests in new wells after the sale are expected to be in the range of 6.7375% to 7.0%, proportionately reduced depending on Zavanna’s actual working interest percentages.
On June 8, 2012, we sold an undivided 87.5% of our acreage in Daniels County, Montana to a third party for $3.7 million. Under the terms of the agreement, we retained a 12.5% working interest in the acreage and reserved overriding royalty interests (“ORRI”) in leases we owned that had in excess of 81% NRI. The purchaser also committed to drill a vertical test well to depths sufficient to core the Bakken and Three Forks formations on or before December 31, 2015. The Company delivered an 80% NRI to the purchaser and a 1% ORRI to a land broker. The Company also paid the land broker a 10% commission for the cash consideration paid by the purchaser.
U.S. Gulf Coast (Onshore) / South Texas
We participate with several different operators in the U.S. Gulf Coast (onshore). At June 30, 2012, we had three gross producing wells (0.56 net) in this region. During the six months ended June 30, 2012, we drilled three gross wells (0.63 net) that were deemed to be nonproductive. Our net costs for these wells through June 30, 2012 were $585,000. One gross well (0.20 net) was in progress at June 30, 2012 and was determined to be non-productive.
In May 2012, we acquired a 26.5% initial working interest in approximately 6,766 gross acres in this area through a cash payment of $1.7 million. The promoted amount covers our portion of the costs for land, geological and geophysical work, as well as the dry hole costs for an initial test well in each of seven different prospects. Upon payout, our working interest will be reduced to 19.8%.
Our net investment in Gulf Coast / South Texas wells and properties was $2.0 million during the six months ended June 30, 2012.
Eagle Ford Shale
We participate in up to 114 gross (34 net) drilling locations in the Leona River and Booth-Tortuga Eagle Ford prospects with Crimson Exploration Inc. ("Crimson"). During the six months ended June 30, 2012, we drilled and completed one gross well (0.30 net) and drilled one gross well (0.30 net) that is expected to be completed during the third quarter of 2012. Our net investment in these wells during the first six months of 2012 was $2.9 million.
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2012 Production Results
The following table provides a regional summary of our production during the first six months of 2012:
Additional Comparative Data
The following table provides information regarding selected production and financial information for the quarter ended June 30, 2012 and the immediately preceding three quarters.
Results of Operations
Three Months Ended June 30, 2012 compared to Three Months Ended June 30, 2011
During the three months ended June 30, 2012, we recorded a net loss after taxes of $990,000 as compared to a net loss after taxes of $75,000 during the same period of 2011. Significant components of the change in operating revenues and results of operations for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011 are as follows:
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Oil and Gas Operations. Oil and gas operations produced operating income of $1.4 million during the quarter ended June 30, 2012 and 2011. The following table summarizes production volumes, average sales prices and operating revenues for the three months ended June 30, 2012 and 2011:
During the three months ended June 30, 2012, we produced approximately 118,783 barrels of oil equivalent (BOE), or an average of 1,305 BOE/day. Portions of our natural gas production are sent to gas processing plants to extract from the gas various natural gas liquids (“NGLs”) that are sold separately from the remaining natural gas. We sell some of our gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGLs and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses.
We recognized $8.5 million in revenues during the three months ended June 30, 2012 as compared to $7.0 million during the same period of the prior year. This $1.5 million increase in revenue is primarily due to higher oil sales volumes in 2012 when compared to 2011. Revenue from gas sales was lower in the three months ended June 30, 2012 when compared to the same period in 2011, primarily due to production declines from wells in the Gulf Coast.
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Our average net realized price for the three months ended June 30, 2012 was $71.74 per BOE compared with $68.59 for the same period in 2011. The increase in our equivalent realized price for production corresponds with a higher percentage of our production coming from oil in 2012 when compared with 2011. Due to takeaway constraints, the discount, or differential, for oil prices in the Williston Basin has ranged from $10 to $25 per barrel during the first six months of 2012. Until additional takeaway capacity is available, we expect this differential to continue and that our oil sales revenue will be affected by the lower prices.
Lease operating expense of $1.6 million for the three months ended June 30, 2012 was comprised of $1.3 million in lease operating expense and $321,000 in workover expense. The $341,000 increase in total lease operating expense in 2012 as compared to 2011 is primarily a result of an increase in the number of producing wells.
At June 30, 2012, the Company recorded a proved property impairment of $523,000 related to its oil and gas assets, primarily due to a decline in natural gas prices. There were no proved property impairments recorded during the three months ended June 30, 2011.
Our depletion, depreciation and amortization (DD&A) rate for the three months ended June 30, 2012 was $33.92 per BOE compared to $30.46 per BOE for the same period in 2011. We have been impacted by higher DD&A rates related to our Williston Basin wells due to increases in drilling and completion costs for wells in this region. Our DD&A rate can also fluctuate as a result of impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.
During the balance of 2012 we anticipate completing wells that were drilled during the first two quarters of 2012 as well as drilling and completing new wells. We also anticipate that our production rates will increase as a result of these activities. In particular, we expect that oil volumes will increase as we drill and complete oil wells in the Williston Basin and other areas. The anticipated net increase in production is projected to add additional cash flows from operations. However, natural gas and natural gas liquids volumes are expected to continue to decrease as production declines from the Gulf Coast producing wells. However, various factors, including extensive workover costs on existing wells, lower commodity prices, commodity price differentials, cost overruns on projected drilling projects, unsuccessful wells or other development activities and/or faster than expected declines in production from existing wells, would have a negative effect on production, cash flows and earnings from the oil and gas segment and could cause actual results to differ materially from those we expect.
Mt. Emmons and Water Treatment Plant Operations. We recorded $436,000 in costs and expenses for the water treatment plant and $206,000 for holding costs for the Mt. Emmons molybdenum property during the three months ended June 30, 2012. During the three months ended June 30, 2011, we recorded $498,000 in operating costs related to the water treatment plant and $37,000 in holding costs. Holding costs during 2011 were partially funded by another party under an operating agreement. As a result of the termination of this agreement in 2011, our 2012 costs are higher as we now bear all the costs associated with the project.
General and Administrative. General and administrative expenses decreased by $378,000 during the three months ended June 30, 2012 as compared to general and administrative expenses for the three months ended June 30, 2011. Lower general and administrative costs in 2012 are primarily a result of $254,000 lower stock option expense, $142,000 lower bonus accrual and $110,000 lower compensation expense. These decreases in costs were partially offset by an increase in contract services of $137,000.
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Other income and expenses. We recognized an unrealized and realized derivative gain of $1.8 million in the second quarter of 2012 compared to a gain of $1.1 million for the same period in 2011. The 2012 amount includes a gain on unrealized changes in the fair value of our commodity derivative contracts of $1.8 million and realized cash settlement losses on derivatives of $6,000.
Gain on the sale of marketable securities from the sale of shares of Sutter Gold Mining decreased to $7,000 during the quarter ended June 30, 2012 from $9,000 during the quarter ended June 30, 2011.
There was no gain on the sale of assets during the quarter ended June 30, 2012 as compared to a gain of $137,000 during the quarter ended June 30, 2011 from the sale of surplus equipment.
We recorded equity losses of $91,000 and $65,000 from the investment in SST during the quarters ended June 30, 2012 and 2011, respectively. Equity losses from the investment in SST are expected to continue until such time as SST properties are sold, equity losses reduce our investment to zero or we sell the investment.
Interest income decreased to $1,000 during the quarter ended June 30, 2012 from $10,000 during the quarter ended June 30, 2011. The decrease is a result of lower amounts of cash invested in interest bearing instruments during the quarter, and lower interest rates received on those investments.
Interest expense increased to $36,000 during the quarter ended June 30, 2012 from $34,000 during the quarter ended June 30, 2011.
Discontinued operations. We recorded income of $26,000, net of taxes from Remington Village during the quarter ended June 30, 2012 and income of $123,000, net of taxes for the quarter ended June 30, 2011. The decrease in income when comparing the quarter ended June 30, 2012 to the quarter ended June 30, 2011 is primarily a result of an increase in the benefit of deferred taxes. The increase was partially offset by higher interest expense and higher contract services costs for the drainage system. On July 9, 2012, the Company entered into a Letter of Intent (“LOI”) to sell Remington Village for $16.0 million. As a result of the anticipated sales amount, at June 30, 2012, the Company recorded a non-cash impairment of $1.3 million net of taxes to adjust the carrying value of the project to the expected sales value. Ultimately, we could not reach mutually agreeable terms for the sale and the LOI was terminated. We will continue to market the property for sale.
We therefore recorded a net loss after taxes of $990,000, or $0.04 per share basic and diluted, during the quarter ended June 30, 2012 as compared to a net loss after taxes of $75,000, or less than $0.01 per share basic and diluted, during the quarter ended June 30, 2011.
Six Months Ended June 30, 2012 compared to Six Months Ended June 30, 2011
During the six months ended June 30, 2012, we recorded a net loss after taxes of $1.4 million as compared to a net loss after taxes of $2.3 million during the same period of 2011. Significant components of the change in operating revenues and results of operations for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011 are as follows:
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Oil and Gas Operations. Oil and gas operations produced operating income of $3.2 million during the six months ended June 30, 2012 as compared to operating income of $1.8 million during the six months ended June 30, 2011. The increase in earnings from oil and gas operations is primarily due to (a) a $4.7 million increase in oil revenues during 2012 compared to 2011 and (b) $1.0 million lower lease operating expenses in the six months ending June 30, 2012 as compared to the same period of the prior year. This increase was partially offset by $1.8 million higher depletion expense in 2012 and a $1.6 million decrease in natural gas and natural gas liquids revenues. The following table summarizes production volumes, average sales prices and operating revenues for the six months ended June 30, 2012 and 2011:
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