XNAS:USEG Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

x
Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the quarter ended March 31, 2012 or
   
o
Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the transition period from ___________ to ____________

Commission File Number: 0-6814



U.S. ENERGY CORP.
(Exact name of registrant as specified in its charter)

Wyoming
 
83-0205516
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
     
877 North 8th West, Riverton, WY
 
82501
(Address of principal executive offices)
 
(Zip Code)
     
Registrant's telephone number, including area code:
 
(307) 856-9271

Not Applicable
(Former name, address and fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the 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.

Large accelerated filer    o
Accelerated filer    x
Non-accelerated filer   o  (Do not check if a smaller reporting company)
Smaller reporting company o

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 May 09, 2012 there were issued and outstanding 27,460,978 shares of the Company’s common stock, $0.01 par value.



 
 
-2-

 


U.S. ENERGY CORP. and SUBSIDIARIES

INDEX

   
Page No.
PART I.
FINANCIAL INFORMATION
 
     
Item 1.
Financial Statements.
 
     
 
Condensed Consolidated Balance Sheets as of March 31, 2012 (unaudited) and December 31, 2011 (unaudited)
4-5
     
 
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011 (unaudited)
6-7
     
 
Condensed Consolidated Statements of Other Comprehensive Loss for the Three Months Ended March 31, 2012 and 2011 (unaudited)
8
     
 
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011 (unaudited)
9-10
     
 
Notes to Condensed Consolidated Financial Statements (unaudited)
11-23
     
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
24-35
     
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
35-36
     
Item 4.
Controls and Procedures
37
     
PART II.
OTHER INFORMATION
 
     
Item 1.
Legal Proceedings
37
     
Item 1A.
Risk Factors
37
     
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
37
     
Item 3.
Defaults Upon Senior Securities
37
     
Item 4.
Mine Safety Disclosures
38
     
Item 5.
Other Information
38
     
Item 6.
Exhibits
38
     
 
Signatures
39
     
 
Certifications
See Exhibits



 
 
-3-

 

PART I.  FINANCIAL INFORMATION

ITEM 1.  Financial Statements
 
U.S. ENERGY CORP.
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
(Unaudited)
 
(In thousands, except shares)
 
             
   
March 31,
   
December 31,
 
   
2012
   
2011
 
Current assets:
           
Cash and cash equivalents
  $ 7,784     $ 12,874  
Available for sale securities
    179       166  
Accounts receivable
               
Trade
    4,751       5,496  
Income taxes
    9       113  
Commodity risk management asset
    101       3  
Assets held for sale
    18,075       18,132  
Other current assets
    282       352  
Total current assets
    31,181       37,136  
                 
Investment
    2,563       2,623  
                 
Properties and equipment
               
Oil & gas properties under full cost method,
               
net of $32,202 and $28,561 accumulated
               
depletion, depreciation and amortization
    82,856       90,942  
Undeveloped mining claims
    20,739       20,739  
Property, plant and equipment, net
    9,031       9,196  
Net properties and equipment
    112,626       120,877  
                 
Other assets
    1,851       1,803  
Total assets
  $ 148,221     $ 162,439  
                 
 
 
 
The accompanying notes are an integral part of these statements.
 
-4-

 
 
 
U.S. ENERGY CORP.
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
(Unaudited)
 
(In thousands, except shares)
 
             
   
March 31,
   
December 31,
 
   
2012
   
2011
 
Current liabilities:
           
Accounts payable
  $ 7,892     $ 9,370  
Accrued compensation
    343       501  
Commodity risk management liability
    758       601  
Current portion of debt
    200       200  
Liabilities held for sale
    10,147       10,241  
Other current liabilities
    24       24  
Total current liabilities
    19,364       20,937  
                 
Long-term debt, net of current portion
    200       12,200  
                 
Deferred tax liability
    744       1,189  
                 
Asset retirement obligations
    564       510  
                 
Other accrued liabilities
    809       822  
                 
Commitment and contigencies
               
                 
Shareholders' equity
               
Common stock, $.01 par value; unlimited shares
               
authorized; 27,445,978 and 27,409,908
               
shares issued, respectively
    274       274  
Additional paid-in capital
    122,645       122,523  
Accumulated surplus
    3,525       3,906  
Unrealized gain on marketable securities
    96       78  
Total shareholders' equity
    126,540       126,781  
Total liabilities and shareholders' equity
  $ 148,221     $ 162,439  
                 
 
 
 
The accompanying notes are an integral part of these statements.
 
-5-

 
 
 
U.S. ENERGY CORP.
 
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
(Unaudited)
 
(In thousands except per share data)
 
             
   
Three months ended March 31,
 
   
2012
   
2011
 
Oil, gas, and NGL production revenues:
  $ 8,335     $ 6,679  
                 
Operating expenses:
               
Oil and gas
    2,893       4,079  
Oil and gas depreciation, depletion and amortization
    3,641       2,785  
Water treatment plant
    509       429  
Mineral holding costs
    110       43  
General and administrative
    1,894       2,411  
      9,047       9,747  
Loss from operations
    (712 )     (3,068 )
Other income and expenses:
               
Realized loss on risk management activities
    (143 )     (555 )
Unrealized loss on risk management activities
    (59 )     (1,241 )
Gain on the sale of assets
    10       --  
Equity loss in unconsolidated investment
    (60 )     (64 )
Gain on sale of marketable securities
    47       --  
Miscellaneous income and (expenses)
    118       (1 )
Interest income
    5       20  
Interest expense
    (39 )     (23 )
      (121 )     (1,864 )
Loss before income taxes and discontinued operations
    (833 )     (4,932 )
                 
 
 
 
The accompanying notes are an integral part of these statements.
 
-6-

 
 
 
U.S. ENERGY CORP.
 
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
(Unaudited)
 
(In thousands except per share data)
 
             
   
Three months ended March 31,
 
   
2012
   
2011
 
Income taxes:
           
Current benefit from (provision for)
    (104 )     --  
Deferred benefit from (provision for)
    492       2,594  
      388       2,594  
                 
Loss from continuing operations
    (445 )     (2,338 )
                 
Discontinued operations:
               
Discontinued operations, net of taxes
    64       129  
      64       129  
Net loss
  $ (381 )   $ (2,209 )
                 
Net loss per share basic and diluted
               
Loss from continuing operations
  $ (0.01 )   $ (0.08 )
Income from discontinued operations
    --       --  
Net loss
  $ (0.01 )   $ (0.08 )
                 
Weighted average shares outstanding
               
Basic and Diluted
    27,438,584       27,186,438  
                 
 
 
 
The accompanying notes are an integral part of these statements.
 
-7-

 
 
 
U.S. ENERGY CORP.
 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
 
(Unaudited)
 
(In thousands)
 
             
   
Three months ended March 31,
 
   
2012
   
2011
 
Net loss
  $ (381 )   $ (2,209 )
                 
Other comprehensive income (loss):
               
Marketable securities, net of tax
    18       (9 )
Total comprehensive loss
    (363 )     (2,218 )
                 
 
 
 
The accompanying notes are an integral part of these statements.
 
-8-

 
 
 
U.S. ENERGY CORP.
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
   
(In thousands)
 
   
For the three months ended March 31,
 
   
2012
   
2011
 
Cash flows from operating activities:
           
Net loss
  $ (381 )   $ (2,209 )
(Gain) from discontinued operations
    (64 )     (129 )
Loss from continuing operations
    (445 )     (2,338 )
Adjustments to reconcile net loss to
               
net cash provided by operations
               
Depreciation, depletion & amortization
    3,798       2,937  
Change in fair value of commodity price
               
risk management activities, net
    59       1,241  
Accretion of discount on treasury investment
    --       (15 )
Gain on sale of marketable securities
    (47 )     --  
Equity loss from Standard Steam
    60       64  
Net change in deferred income taxes
    (455 )     (2,452 )
(Gain) on sale of assets
    (10 )     --  
Noncash compensation
    50       376  
Noncash services
    23       (30 )
Net changes in assets and liabilities
    (2,269 )     1,626  
Net cash provided by operating activities
    764       1,409  
Cash flows from investing activities:
               
Net redemption of treasury investments
    --       11,009  
Acquisition & development of oil & gas properties
    (12,047 )     (13,584 )
Acquisition of property and equipment
    (3 )     (16 )
Proceeds from sale of oil and gas properties
    18,119       --  
Proceeds from sale of marketable securities
    62       --  
Proceeds from sale of property and equipment
    22       --  
Net change in restricted investments
    (84 )     (33 )
Net cash provided by (used in) investing activities:
    6,069       (2,624 )
                 
 
 
 
The accompanying notes are an integral part of these statements.
 
-9-

 
 
 
U.S. ENERGY CORP.
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
   
(In thousands)
 
   
For the three months ended March 31,
 
   
2012
   
2011
 
Cash flows from financing activities:
           
Issuance of common stock
    50       (186 )
Tax benefit from the exercise of stock options
    --       3,000  
Repayments of debt
    (12,065 )     --  
Net cash (used in) provided by financing activities
    (12,015 )     2,814  
                 
Net cash provided by operating activities
               
of discontinued operations
    92       66  
Net cash used in investing activities
               
of discontinued operations
    --       (1 )
                 
Net (decrease) increase in cash and cash equivalents
    (5,090 )     1,664  
                 
Cash and cash equivalents at beginning of period
    12,874       5,812  
                 
                 
Cash and cash equivalents at end of period
  $ 7,784     $ 7,476  
                 
Supplemental disclosures:
               
Income tax paid
  $ --     $ --  
                 
Interest paid
  $ 64     $ 5  
                 
Non-cash investing and financing activities:
               
                 
Unrealized gain
  $ 96     $ 633  
                 
Acquisition and development of oil and gas
               
properties through accounts payable
  $ 1,581     $ 4,088  
                 
Acquisition and development of oil and gas
               
through asset retirement obligations
  $ 45     $ 4  
                 
 
 
 
The accompanying notes are an integral part of these statements.
 
-10-

 
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 March 31, 2012 and March 31, 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 March 31, 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.  See Note 13.

2)       Summary of Significant Accounting Policies

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).

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.

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.



 
-11-

 
U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)



Components of Property and Equipment as of March 31, 2012 and December 31, 2011 are as follows:
 
   
(In thousands)
 
   
March 31,
   
December 31,
 
   
2012
   
2011
 
 Oil & Gas properties
           
 Unproved
  $ 11,667     $ 17,098  
 Wells in progress
    5,795       2,909  
 Proved
    97,596       99,496  
      115,058       119,503  
 Less accumulated depreciation
               
 depletion and amortization
    (32,202 )     (28,561 )
 Net book value
    82,856       90,942  
                 
 Mining properties
    20,739       20,739  
                 
 Building, land and equipment
    14,972       14,984  
 Less accumulated depreciation
    (5,941 )     (5,788 )
 Net book value
    9,031       9,196  
 Totals
  $ 112,626     $ 120,877  
                 

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 March 31, 2012 and December 31, 2011 which were not included in the amortized cost pool were $17.5 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 March 31, 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.
 
 
 
-12-

 
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.  At March 31, 2012, the book value of our oil and gas properties did not exceed the cost center ceiling.

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 March 31, 2012, we used $98.15 per barrel for oil and $3.73 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 March 31, 2012 and 2011, the ceiling was in excess of the net capitalized costs as adjusted for related deferred income taxes and no impairment was required.  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 March 31, 2012 and December 31, 2011 reflect capitalized costs associated with our Mt. Emmons molybdenum property near Crested Butte, Colorado.


 
 
-13-

 
U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)



Our carrying balance in the Mt. Emmons property at March 31, 2012 and December 31, 2011 is as follows:
 
   
(In thousands)
 
   
March 31,
   
December 31,
 
   
2012
   
2011
 
 Costs associated with Mount Emmons
           
 beginning of year
  $ 20,739     $ 21,077  
 Development costs
    --       16  
 Option payment from Thompson Creek
    --       (354 )
 Costs at the end of the period
  $ 20,739     $ 20,739  
                 
 
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 March 31, 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.


 
 
-14-

 
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.


 
 
-15-

 
U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)



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.  At December 31, 2011 and 2010, we recorded a $3.1 million and $1.5 million, respectively, impairment to adjust the carrying value of the multifamily project to the approximate appraised value.  At March 31, 2012, management has determined that no further impairment is needed.  As of March 31, 2012, the accompanying condensed consolidated balance sheets present $18.1 million in book value of assets held for sale, net of accumulated depreciation, and $10.1 million in liabilities held for sale.  Because Remington Village has been classified as an asset held for sale, the scheduled depreciation of $224,000 for the first three months of 2012 or the $237,000 for the first three 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.

The following is a reconciliation of the total liability for asset retirement obligations:
 
   
(In thousands)
 
   
March 31,
   
December 31,
 
   
2012
   
2011
 
Beginning asset retirement obligation
  $ 510     $ 303  
Accretion of discount
    9       23  
Liabilities incurred
    45       187  
Liabilities sold
    --       (3 )
Ending asset retirement obligation
  $ 564     $ 510  
                 
Mining properties
  $ 153     $ 149  
Oil & Gas wells
    411       361  
Ending asset retirement obligation
  $ 564     $ 510  
                 


 
 
-16-

 
U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)



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.

Energy One's commodity derivative contracts as of March 31, 2012 are summarized below:
 
       
Quantity
         
Settlement Period
Counterparty
Basis
 
(Bbl/d)
 
Strike Price
 
                   
Crude Oil Costless Collar
                 
10/01/11 - 09/30/12
 BNP Parabis
 WTI
    400  
Put:
  $ 80.00  
             
Call:
  $ 99.00  
Crude Oil Costless Collar
                     
01/01/12 - 12/31/12
 BNP Parabis
 WTI
    200  
Put:
  $ 90.00  
             
Call:
  $ 106.50  
Crude Oil Costless Collar
                     
10/01/12 - 09/30/13
 BNP Parabis
 WTI
    200  
Put:
  $ 95.00  
             
Call:
  $ 116.60  

The following table details the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category:
 
 
(in thousands)
 
 
Derivative Assets
 
Derivative Liabilities
 
 
Balance Sheet
 
Fair
 
Balance Sheet
 
Fair
 
 
Classification
 
Value
 
Classification
 
Value
 
                 
Crude oil costless collars
Current Asset
  $ 101  
Current Liability
  $ 758  
                     
 
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.


 
 
-17-

 
U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)



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:

·  
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.  As of March 31, 2012, we held $179,000 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 $809,000 at March 31, 2012 as a result of payments of the liability.  The other accrued liabilities are the long term portion of the executive retirement program.

   
(In thousands)
 
         
Fair Value Measurements at March 31, 2012 Using
 
   
March 31
   
Quoted Prices in Active Markets for Identical Assets
   
Significant Other Observable Inputs
   
Significant Unobservable Inputs
 
Description
 
2012
   
(Level 1)
   
(Level 2)
   
(Level 3)
 
                         
Commodity risk management assets
  $ 101     $ --     $ 101     $ --  
Available for sale securities
    179       179       --       --  
                                 
Total assets
  $ 280     $ 179     $ 101     $ --  
                                 
Commodity risk management liability
  $ 758     $ --     $ 758     $ --  
Other accrued liabilities
    809       --       --       809  
                                 
Total
  $ 1,567     $ --     $ 758     $ 809  
                                 


 
 
-18-

 
U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)



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.

   
(In thousands)
 
March 31, 2012
                                   
   
Less Than 12 Months
   
12 Months or Greater
   
Total
 
         
Unrealized
         
Unrealized
         
Unrealized
 
Description of Securities
 
Fair Value
   
Gain
   
Fair Value
   
Gain
   
Fair Value
   
Gain
 
                                     
Available for sale securities
  $ 179     $ 150     $ --     $ --     $ 179     $ 150  
                                                 
Total
  $ 179     $ 150     $ --     $ --     $ 179     $ 150  
                                                 
 
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 $10.2 million as of March 31, 2012.

8)       Debt

At March 31, 2012, total debt in the amount of $10.2 million consists of debt on our multifamily housing project and the purchase of land near our Mt. Emmons molybdenum property.  The debt on our multifamily housing project has an interest rate of 5.50% and the land debt bears an interest rate of 6.0% per annum.

On May 5, 2011 we borrowed $10.0 million from a commercial bank against Remington Village.  At March 31, 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.

The land debt of $400,000 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 three months ended March 31, 2012, the Company issued 36,070 shares of common stock.  These shares consist of (a) 15,000 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 employees of the Company.
 
 
 
-19-

 
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 March 31, 2012:
 
(Amounts in thousands, except for share amounts)
 
               
Additional
 
   
Common Stock
   
Paid-In
 
   
Shares
   
Amount
   
Capital
 
                   
 Balance January 1, 2012
    27,409,908     $ 274     $ 122,523  
 2001 stock compensation plan
    15,000       --       48  
 Exercise of employee stock options
    1,070       --       --  
 Exercise of outside director options
    20,000       --       50  
 Expense of employee options vesting
    --       --       2  
 Expense of outside director warrants vesting
    --       --       22  
 Balance March 31, 2012
    27,445,978     $ 274     $ 122,645  
                         
Employee Stock Option Plans

All options outstanding at March 31, 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.

The Company recorded $2,000 and $251,000 of related compensation expense for the three months ended March 31, 2012 and 2011, respectively.  As of March 31, 2012, there was no unrecognized compensation expense related to 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 three months ended March 31, 2012.

Director Option Plans

From time to time we issue stock options to non-employee directors for services.  During the three months ended March 31, 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 months ended March 31, 2012, we recorded $23,000 in expense for options issued to non-employee directors.  We will recognize an additional $145,000 in expense over the vesting period of the outstanding options.  During the three months ended March 31, 2012, we issued 20,000 shares of common stock to directors of the Company as the result of the exercise of 20,000 outstanding options.


 
 
-20-

 
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 three months ended March 31, 2012:

   
March 31, 2012
 
   
Employee Stock Options
   
Director Stock Options
 
         
Weighted
         
Weighted
 
         
Average
         
Average
 
         
Exercise
         
Exercise
 
   
Options
   
Price
   
Options
   
Price
 
                         
Outstanding balance at December 31, 2011
    2,318,399     $ 3.94       210,000     $ 3.10  
Granted
    --     $ --       70,000     $ 2.85  
Forfeited
    --     $ --       --     $ --  
Expired
    (50,000   $ 4.97       --     $ --  
Exercised
    (4,167 )   $ 2.52       (20,000 )   $ 2.52  
Outstanding at March 31, 2012
    2,264,232     $ 3.92       260,000     $ 3.08  
Exercisable at March 31, 2012
    2,264,232     $ 3.92       173,334     $ 2.96  
                                 
Weighted Average Remaining Contractual Life - Years
      4.67               4.82  
                                 
Aggregate intrinsic value of options outstanding
          $ 558,000             $ 95,000  
                                 
 
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.


 
 
-21-

 
U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)



11)       Segment Information

As of March 31, 2012, we had two reportable segments: Oil and Gas and Maintenance of Mineral Properties.  A summary of results of operations for the three months ended March 31, 2012, and 2011, and total assets as of March 31, 2012 and December 31, 2011 by segment are as follows:
 
   
(In thousands)
 
   
For the three months ended
 
   
March 31,
 
   
2012
   
2011
 
Revenues:
           
Oil and gas
  $ 8,335     $ 6,679  
Total revenues:
    8,335       6,679  
                 
Operating expenses:
               
Oil and gas
    6,534       6,864  
Mineral properties
    619       472  
Total operating expenses:
    7,153       7,336  
                 
Interest expense
               
Oil and gas
    30       9  
Mineral properties
    6       9  
Total interest expense:
    36       18  
                 
Operating (loss) income
               
Oil and gas
  $ 1,771     $ (194 )
Mineral properties
    (625 )     (481 )
Operating income (loss)
               
from identified segments
    1,146       (675 )
                 
General and administrative expenses
    (1,894 )     (2,411 )
Add back interest expense
    36       18  
Other revenues and expenses:
    (121 )     (1,864 )
Loss before income taxes
               
and discontinued operations
  $ (833 )   $ (4,932 )
                 
Depreciation depletion and amortization expense:
         
Oil and gas
  $ 3,641     $ 2,785  
Mineral properties
    32       26  
Corporate
    125       126  
Total depreciation expense
  $ 3,798     $ 2,937  
                 
 
 
 
 
-22-

 
U.S. ENERGY CORP.

Notes to Condensed Consolidated Financial Statements (Unaudited)
(Continued)

 
 
 
   
(In thousands)
 
   
March 31,
   
December 31,
 
   
2012
   
2011
 
Assets by segment
           
Oil and Gas
  $ 94,507     $ 109,141  
Mineral
    20,755       20,755  
Corporate
    32,959       32,543  
Total assets
  $ 148,221     $ 162,439  
                 

 
12)       Equity Income in Unconsolidated Investment

We recorded an equity loss from our unconsolidated investment in Standard Steam, LLC (“SST”) during the three months ended March 31, 2012 and 2011, of $60,000 and $64,000, respectively.

13)       Subsequent Events

Montana Acreage Sale.  On May 9, 2012, the Company signed a Letter Agreement to sell an undivided 87.5% of its acreage in Daniels County, Montana to a third party for $3.68 million.  The agreement is conditioned upon execution of a mutually acceptable Purchase and Sale Agreement and will be effective on June 1, 2012.  Under the terms of the agreement, the Company will retain a 12.5% working interest in the acreage and reserved overriding royalty interests (“ORRI”) in excess of 81%.  The purchaser will also commit 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 will deliver an 80% NRI to the purchaser and 1% ORRI to a land broker.  The Company will also pay the land broker a 10% commission for the cash consideration paid by the purchaser.
 


 
 
-23-

 
 

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 months ended March 31, 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.  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 operated our 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 March 31, 2012 and December 31, 2011 were as follows:
 
   
(In thousands)
 
   
March 31,
   
December 31,
 
   
2012
   
2011
 
 Unproved oil and gas properites
  $ 17,462     $ 17,098  
 Proved oil and gas properties
    97,596       73,844  
 Undeveloped mining properties
    20,739       20,739  
    $ 135,797     $ 111,681  
                 
 
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 65%.  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 March 31, 2012 and 2011.
 
 
 
 
-24-

 
 
 
 
 
March 31,
 
2012
 
2011
 
Gross
 
Net
 
Gross
 
Net
Williston Basin:
             
Productive wells
     27.00
 
       8.95
 
     13.00
 
       4.40
Wells being drilled or awaiting completion
       7.00
 
       1.08
 
       8.00
 
       2.08
               
Gulf Coast/South Texas:
             
Productive wells
       5.00
 
       1.12
 
       5.00
 
       0.99
Wells being drilled or awaiting completion
       1.00
 
       0.13
 
       2.00
 
       0.27
               
Eagle Ford:
             
Productive wells
       2.00
 
       0.60
 
         --
 
         --
Wells being drilled or awaiting completion
       1.00
 
       0.30
 
         --
 
         --
               
Austin Chalk:
             
Productive wells
     11.00
 
       2.98
 
         --
 
         --
Wells being drilled or awaiting completion
         --
 
         --
 
         --
 
         --
               
Total:
             
Productive wells
     45.00
 
     13.65
 
     18.00
 
       5.39
Wells being drilled or awaiting completion
       9.00
 
       1.51
 
     10.00
 
       2.35
               


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 Brigham Exploration Company.  From August 24, 2009 to March 31, 2012, we have drilled and completed 19 gross Bakken Formation wells (7.30 net) and one gross Three Forks formation well (0.18 net) under the Drilling Participation Agreement with Brigham.   Three additional gross wells (0.15 net) are expected to be drilled during the balance of 2012.  Brigham operates all of the wells.

During the first three months of 2012, the Company completed two gross wells (0.41 net) in the Rough Rider prospect.   Our net investment in the Rough Rider prospect wells was $2.7 million for the three months ended March 31, 2012.

Yellowstone and SEHR Prospects.  We participate in 27 gross 1,280 acre spacing units in the Yellowstone and SEHR prospects with Zavanna, LLC (“Zavanna”).  Through March 31, 2012, we have drilled and completed seven gross Bakken formation wells (1.47 net) in these prospects, including two gross wells (0.12 net) operated by Murex Petroleum.   Zavanna operates the remaining wells.  At March 31, 2012, two additional gross wells (0.10 net) were being drilled five 5 gross wells (0.98 net) were awaiting completion.

During the first three months of 2012, we completed two gross wells (0.45 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 $6.5 million during the quarter ended March 31, 2012.
 
 
 
-25-

 
 
 
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.

U.S. Gulf Coast (Onshore) / South Texas

We participate with several different operators in the U.S. Gulf Coast (onshore).  At March 31, 2012, we had five gross producing wells (1.12 net) in this region.  During the three months ended March 31, 2012, we drilled one gross well (0.10 net) that was deemed to be nonproductive.  Our net costs for this well through March 31, 2012 were $174,000.  One gross well (0.13 net) was in progress at March 31, 2012 and commenced production in the second quarter of 2012.  Our net investment in Gulf Coast / South Texas wells was $220,000 during the three months ended March 31, 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 three months ended March 31, 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 second quarter of 2012.  Our net investment in these wells during the first quarter of 2012 was $2.7 million.

2012 Production Results

The following table provides a regional breakdown of our production during the first quarter of 2012:

 
Williston Basin
 
Gulf Coast / South Texas
Eagle Ford
 
Austin Chalk
 
Total
First Three Months of 2012 Production
               
Oil (Bbl)
          87,335
 
              996
 
            2,305
 
            1,946
 
          92,582
Gas (Mcf)
          33,730
 
          49,234
 
            5,582
 
            1,226
 
          89,772
NGLs (BBs)
            4,053
 
              335
 
               --
 
              104
 
            4,492
Equivalent (BOE)
          97,009
 
            9,537
 
            3,236
 
            2,254
 
        112,036
Avg. Daily Equivalent (BOE/d)
            1,066
 
              105
 
                36
 
                25
 
            1,231
Relative percentage
87%
 
9%
 
3%
 
2%
 
100%
 

 
 
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Additional Comparative Data

The following table provides information regarding selected production and financial information for the quarter ended March 31, 2012 and the immediately preceding three quarters.

   
For the Three Months Ended
 
   
March 31,
2012
   
December 31,
2011
   
September 30,
2011
   
June 30,
2011
 
   
(in Thousands, except for production data)
 
Production (BOE)
    112,036       118,663       120,198       102,413  
Oil, gas and NGL production revenue
  $ 8,335     $ 8,846     $ 8,408     $ 7,025  
Unrealized and realized derivative (loss) gain
  $ (202 )   $ (1,738 )   $ 1,564     $ 1,123  
Lease opeating expense
  $ 2,010     $ 1,954     $ 1,811     $ 1,289  
Production taxes
  $ 883     $ 921     $ 832     $ 667  
DD&A
  $ 3,641     $ 4,230     $ 3,862     $ 3,120  
General and administrative
  $ 1,894     $ 1,883     $ 1,829     $ 2,138  
Mineral holding costs
  $ 110     $ 140     $ 266     $ 37  
Water treatment plant
  $ 509     $ 454     $ 497     $ 498  
Income (loss) from continuing operations
  $ (445 )   $ 309     $ 130     $ (279 )
Results of Operations

Three Months Ended March 31, 2012 compared to Three Months Ended March 31, 2011

During the three months ended March 31, 2012, we recorded a net loss after taxes of $381,000 as compared to a net loss after taxes of $2.2 million during the same period of 2011.  Significant components of the change in operating revenues and results of operations for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011 are as follows:


 
 
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Oil and Gas Operations.   Oil and gas operations produced operating income of $1.8 million during the quarter ended March 31, 2012 as compared to an operating loss of $185,000 during the quarter ended March 31, 2011.  The increase in earnings from oil and gas operations is primarily due to (a) a $1.7 million increase in revenues due to higher oil sales volumes during 2012 compared to 2011 and (b) $1.4 million lower lease operating expenses in the three months ending March 31, 2012 as compared to the same period of the prior year.  This is partially offset by $856,000 higher depletion expense in 2012 and a $564,000 decrease in natural gas revenues.  The following table summarizes production volumes, average sales prices and operating revenues for the quarters ended March 31, 2012 and 2011:

   
Three Months Ended
       
   
March 31,
   
Increase
 
   
2012
   
2011
   
(Decrease)
 
Production volumes
                 
Oil (Bbls)
    92,582       67,350       25,232  
Natural gas (Mcf)
    89,772       173,755       (83,983 )
Natural gas liquids (Bbls)
    4,492       4,781       (289 )
Equivalent (BOE)
    112,036       101,090       10,946  
Avg. Daily Equivalent (BOE/d)
    1,231       1,123       108  
Average sales prices
                       
Oil (per Bbl)
  $ 84.43     $ 83.27     $ 1.16  
Natural gas (per Mcf)
    3.04       4.82       (1.78 )
Natural gas liquids (per Bbl)
    54.76       48.94       5.82  
Revenue (in thousands)
                       
Oil
  $ 7,817     $ 5,608     $ 2,209  
Natural gas
    273       837       (564 )
Natural gas liquids
    245       234       12  
Total revenue
    8,335       6,679       1,657  
Lease operating expense
    (2,010 )     (3,397 )     1,387  
Production taxes
    (883 )     (682 )     (201 )
Income before depreciation, depletion and amortization
    5,442       2,600       2,843  
Depreciation, depletion and amortization
    (3,641 )     (2,785 )     (856 )
Income
  $ 1,801     $ (185 )   $ 1,987  
                         
 
During the three months ended March 31, 2012, we produced approximately 112,036 barrels of oil equivalent (BOE), or an average of 1,231 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 $8.3 million in revenues during the three months ended March 31, 2012 as compared to $6.7 million during the same period of the prior year.  This $1.6 million increase in revenue is primarily due to higher oil sales volumes in 2012 when compared to 2011.  Revenue from gas sales is lower in the three months ended March 31, 2012 when compared to the same period in 2011, primarily due to production declines from wells in the Gulf Coast.
 
 
 
-28-

 
 
 
Our average net realized price for the three months ended March 31, 2012 was $74.40 per BOE compared with $66.07 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 2011 when compared with 2010.  Due to takeaway constraints, the discount, or differential, for oil prices in the Williston Basin has increased to $20 to $25 per barrel.  Until additional takeaway capacity is available, we expect this differential to continue and our oil sales revenue to be affected by the lower prices.

Lease operating expense of $2.0 million for the three months ended March 31, 2012 was comprised of $1.3 million in lease operating expense and $718,000 in workover expense.  The $1.4 million reduction in total lease operating expense in 2012 as compared to 2011 is primarily a result of $1.8 million lower workover expense.

Our depletion, depreciation and amortization (DD&A) rate for the three months ended March 31, 2012 was $32.50 per BOE compared to $27.75 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 last quarter of 2011 and the first quarter 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.  However, natural gas and natural gas liquids volumes are expected to continue to decrease as production declines from the Gulf Coast producing wells.  The anticipated net increase in production is projected to add additional cash flows from operations and improve net earnings from our oil and gas operations.  However, various factors, including extensive workover costs on existing wells, 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.

Mt. Emmons and Water Treatment Plant Operations.   We recorded $509,000 in costs and expenses for the water treatment plant and $110,000 for holding costs for the Mt. Emmons molybdenum property during the three months ended March 31, 2012.  During the three months ended March 31, 2011, we recorded $429,000 in operating costs related to the water treatment plant and $43,000 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 expected to be higher as we will bear the increased share of the costs for the full year.

General and Administrative.  General and administrative expenses decreased by $517,000 during the three months ended March 31, 2012 as compared to general and administrative expenses for the three months ended March 31, 2011.  Lower general and administrative costs in 2012 are primarily a result of $220,000 lower stock options expense, $159,000 lower stock compensation expense and $126,000 lower compensation expense.

Other income and expenses.  We recognized an unrealized and realized derivative loss of $202,000 in the first quarter of 2012 compared to a loss of $1.8 million for the same period in 2011.  The 2012 amount includes losses on unrealized changes in the fair value of our commodity derivative contracts of $59,000 and realized cash settlement losses on derivatives of $143,000.
 
 
 
-29-

 

 
We recorded equity losses of $60,000 and $64,000 from the investment in SST during the quarters ended March 31, 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.

Gain on the sale of marketable securities increased to $47,000 during the quarter ended March 31, 2012 from $0 during the quarter ended March 31, 2011 as a result of the sale of shares of Sutter Gold Mining.

Interest income decreased to $5,000 during the quarter ended March 31, 2012 from $20,000 during the quarter ended March 31, 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 $39,000 during the quarter ended March 31, 2011 from $23,000 during the quarter ended March 31, 2011.  The increase in interest expense was related primarily to the $10.0 million borrowed from a commercial bank in May 2011 and the $12.0 million borrowed under our senior credit facility with Wells Fargo.  We repaid the $12.0 million borrowed under our senior credit facility in January 2012.

Discontinued operations.  We recorded income of 64,000, net of taxes from the discontinued operations of Remington Village during the quarter ended March 31, 2012 and income of $129,000, net of taxes for the quarter ended March 31, 2011.  The decrease in income is primarily a result lower occupancy rates when comparing the quarter ended March 31, 2012 to the quarter ended March 31, 2011.

We therefore recorded a net loss after taxes of $381,000, or $0.01 per share basic and diluted, during the quarter ended March 31, 2012 as compared to a net loss after taxes of $2.2 million, or $0.08 per share basic and diluted, during the quarter ended March 31, 2011.

Overview of Liquidity and Capital Resources

At March 31, 2012, we had $7.8 million in cash and cash equivalents.  Our working capital (current assets minus current liabilities) was $11.8 million.  As discussed below in Capital Resources and Capital Requirements, we project that our capital resources at March 31, 2012 will be sufficient to fund operations and capital projects through the balance of 2012.  Given the size of our potential commitments related to our existing inventory of drilling projects, however, our requirements for additional capital could increase significantly during the remainder of 2012 if we elect to participate in any currently unanticipated drilling of additional wells.  As a result, we may consider drawing down additional debt on our senior credit facility, selling or joint venturing an interest in some of our oil and gas assets, or accessing the capital markets or other alternatives, as we determine how to best fund our capital program.

The principal recurring uncertainty which affects the Company is variable prices for commodities producible from our oil, gas and mineral properties. Significant price swings can have adverse or positive effects on our business of exploring for, developing and producing oil and gas or minerals.  Availability of drilling and completion equipment and crews fluctuates with the market prices for oil and natural gas and thereby affects the cost of drilling and completing wells.  When prices are low there is typically less exploration activity and the cost of drilling and completing wells is generally reduced.  Conversely, when prices are high there is generally more exploration activity and the cost of drilling and completing wells generally increases.


 
 
-30-

 


Capital Resources

Potential primary sources of future liquidity include the following:

Oil and Gas Production.  At March 31, 2012, we had forty-five gross producing wells (13.65 net).  During the three months ended March 31, 2012, we received an average of $2.8 million per month from these producing wells with an average operating cost of $431,000 per month (excluding workover costs) and production taxes of $294,000, for average cash flows of $2.1 million per month from oil and gas production before non-cash depletion expense.  We anticipate that cash flows from oil and gas operations will increase through the balance of 2012 as the wells being drilled with Zavanna, Brigham, Crimson and others begin to produce.  However, decreases in the price of oil and natural gas, increased operating costs and workover expenses, declines in production rates, and other factors could decrease these average monthly cash flow amounts.

Normal production declines and the back-in after payout provisions granted to Brigham and Zavanna will eventually decrease the amount of cash flow we receive from these wells.  We anticipate drilling more Bakken and Three Forks wells with Brigham and Zavanna in the future and will continue to search for additional drilling opportunities to replace these oil reserves and cash flows.

Cash on Hand.  At March 31, 2012, we had $7.8 million in cash and cash equivalents.

Wells Fargo Senior Credit Facility.  On July 30, 2010, we established a senior credit facility through our wholly owned subsidiary, Energy One, LLC (“Energy One”) to borrow up to $75 million from a syndicate of banks, financial institutions and other entities, including Wells Fargo Bank, National Association, which recently acquired the North American reserve-based and related diversified energy lending business of BNP Paribas.  The senior credit facility is being used to advance our short and mid-terms goals of increasing our investment in oil and gas.

From time to time until the expiration of the credit facility (July 30, 2014) if Energy One is in compliance with the facility documents, Energy One may borrow, pay, and re-borrow funds from the lenders, up to an amount equal to the borrowing base.  The borrowing base is redetermined semi-annually, taking into account updated reserve reports.  Any proposed increase in the borrowing base will require approval by all lenders in the syndicate, and any proposed borrowing base decrease will require approval by lenders holding not less than two-thirds of outstanding loans and loan commitments.  On April 10, 2012, the commitment amount increased to $100 million and the borrowing base increased to $30.0 million (from $28.0 million) as a result of a redetermination using our December 31, 2011 financial statements, production reports and reserve reports.  As of March 31, 2012, Energy One was in compliance with all the covenants under the senior credit facility.

At March 31, 2012, we did not have any borrowings under the senior credit facility.  On May 1, 2012, we borrowed $5.0 million to fund our drilling programs.

Equity Market.  We filed a registration statement with the Securities and Exchange Commission on October 20, 2009 which became effective on November 6, 2009.  The registration statement provides for the sale of up to $100 million of the Company’s common stock from time to time.  During the fourth quarter of 2009, we sold five million shares of our common stock for $5.25 per share or $26.3 million, $24.3 million net of offering costs.  Additional capital may be raised under the registration statement to fund future oil and gas acquisitions and development drilling and other general purposes.  Unless extended, the registration statement will expire on November 6, 2012.


 
 
-31-

 


Asset Held for Sale – Remington Village.  Until the property is sold, we will continue to receive rental receipts from the property.  The property had an average occupancy rate of 87% during 2011 and was 88% occupied as of March 31, 2012.  Occupancy is dependent on the regional economy, including local coal mining operations, which has been affected by the global recession.  The property generated average positive cash flow from operations of $84,000 per month during the first three months of 2012 and cash flow is projected to remain in that range during the balance of 2012.

On May 5, 2011, we borrowed $10.0 million from a commercial bank against Remington Village.  The note is amortized over 20 years with a balloon payment at the end of five years and has an interest rate of 5.50% per annum.  The proceeds of the note were used to fund our general business obligations.

Capital Requirements

Our direct capital requirements during the balance of 2012 relate to the funding of our drilling programs, additional oil and gas exploration and development projects, acquisition of prospective oil and gas properties and/or existing production, payment of debt obligations, operating and capital improvement costs of the water treatment plant at the Mt. Emmons project and ongoing permitting activities for the Mt. Emmons project, operations at Remington Village until it is sold and general and administrative costs.  We intend to finance our 2012 capital expenditure plan primarily from the sources described above under “Capital Resources”.  We may be required to reduce or defer part of our 2012 capital expenditures plan if we are unable to obtain sufficient financing from these sources.  We regularly review our capital expenditure budget to assess changes in current and projected cash flows, acquisition opportunities, debt requirements and other factors.

Oil and Gas Exploration and Development.  We continue to expect capital expenditures of approximately $43.3 million in our 2012 oil and gas drilling program (through March 31, 2012, we have spent approximately $12.4 million of this budgeted amount).  The remaining $30.9 million in capital expenditure is budgeted to be spent on exploration and acquisition initiatives in the Williston Basin of North Dakota, Texas and Louisiana (primarily onshore Gulf Coast) and our operated Montana prospect. Amounts budgeted for each regional drilling program is contingent upon timing, well costs and success.  If any of our drilling initiatives are not initially successful or progress more slowly than anticipated, funds allocated for each drilling program may be allocated to other drilling initiatives and/or acquisitions in due course.  The actual number of gross and net wells could vary in each of these cases.

Mt. Emmons Molybdenum Project.  We are responsible for all costs associated with the Mt. Emmons project, which includes operation of a water treatment plant.  Annual water treatment plant operating costs during the remainder of 2012 are expected to be approximately $153,000 per month.  Additionally, we have a remaining budget of $756,000 for mining claims fees, permitting and water treatment plant capital improvements which are expected to improve the plant’s efficiency and reduce costs.

In 2009, 160 acres of fee land in the vicinity of the mining claims was purchased by the Company and Thompson Creek Metals Company USA (“TCM”) for $4 million ($2 million in January 2009, $400,000 annually for five years thereafter).  On December 6, 2011, TCM notified the Company that it wishes to sell its interest in the property.  The Company has 18 months from that date to decide whether to purchase TCM’s interest in the property, at TCM’s cost, and close such purchase.

Real Estate.  Cash operating expenses at Remington Village are projected to be approximately $89,000 per month until Remington Village is sold.  Additionally, we have budgeted approximately $300,000 for capital improvements on the property.


 
 
-32-

 


Insurance.  We have liability insurance coverage in amounts we deem sufficient and in line with industry standards for the location, stage, and type of operations in oil and gas, mineral property development (the Mt. Emmons molybdenum project), and the Remington Village housing complex.  Payment of substantial liabilities in excess of coverage could require diversion of internal capital away from regular business, which could result in diminished operations.  We have property loss insurance on all major assets equal to the approximate replacement value of the assets.

Reclamation Costs.  We have reclamation obligations with an estimated present value of $411,000 related to our oil and gas wells and $153,000 related to the Mt. Emmons molybdenum property.  One depleted oil and gas well in Louisiana is expected to be plugged and abandoned in 2012 at a projected net cost to the Company of $46,000.  No additional reclamation is expected to be performed during the year ended December 31, 2012 unless a well, or wells, are abandoned due to unexpected operational challenges.  As the Mt. Emmons project is developed, the reclamation liability is expected to increase.  It is not anticipated that his reclamation work will occur in the near term.  Our objective, upon closure of the proposed mine at the Mt. Emmons project, is to eliminate long-term liabilities associated with the property.

Cash flows during the three months ended March 31, 2012:

The following table presents changes in cash flows between the three month periods ended March 31, 2012 and 2011.  The analysis following the table should be read in conjunction with our condensed consolidated statements of cash flows in Part I, Item 1 of this report.

   
For the Three Months Ended March 31,
       
   
2012
   
2011
   
Change
 
   
(in thousands)
 
Net cash provided by operating activities
  $ 764     $ 1,409     $ (645 )
Net cash (used in) provided by investing activities
  $ 6,069     $ (2,264 )   $ 8,333  
Net cash (used in) provided by financing activities
  $ (12,015 )   $ 2,814     $ (14,829 )
 
Operating Activities.  Cash provided by operations for the three month period ended March 31, 2012 decreased to $764,000 as compared to cash provided by operations of $1.4 million for the same period of the prior year.  This $645,000 decrease year over year in cash from operating activities is predominantly a result of $1.5 million reduction in accounts payable.  The remainder of the change in cash provided by operations is part of the complete discussion of cash provided by operations in the Results of Operations above.

Investing Activities.  Investing activities provided cash during the first three months of 2012 through $18.1 million in proceeds from the sale of oil and gas properties, $62,000 from the sale of shares of Sutter Gold Mining and $22,000 from the sale of property and equipment.

Investing activities consumed cash through the acquisition and development of oil and gas properties in the amount of $12.0 million during the first three months of 2012.  Other uses of cash for investing activities in the period were an $84,000 change in restricted investments and $3,000 for the purchase of equipment.

Financing Activities.  Financing activities consumed $12.0 million during the three months ended March 31, 2012 through $12.1 million in repayments of debt.  Financing activities provided $50,000 through the issuance of common stock.
 
 
 
-33-

 

 
Critical Accounting Policies

For detailed descriptions of our significant accounting policies, we refer you to the corresponding section of Part II, Item 7 of our Annual Report on Form 10K for the year ended December 31, 2011 (please see pages 69 to 72).

Future Operations

Management intends to continue the development of our oil and gas portfolio as well as seek additional investment opportunities in the oil and natural gas sector.  Long term, we intend to fund the holding and permitting costs associated with the Mt. Emmons property.

Effects of Changes in Prices

Natural resource operations are significantly affected by changes in commodity prices.  As prices for a particular commodity increase, values for prospects for that commodity typically also increase, making acquisitions of such properties more costly and sales potentially more valuable.  Conversely, a price decline could enhance acquisitions of properties containing that commodity, but could also make sales of such properties more difficult.  Operational impacts of changes in commodity prices are common in the oil and gas and mining industries.

At March 31, 2012, we are receiving revenues from our oil and gas business.  Our revenues, cash flows, future rate of growth, results of operations, financial condition and ability to finance projected acquisitions of oil and gas producing assets are dependent upon prevailing prices of oil and gas.

Forward Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements.  When used in this Form 10-Q, the words “will”, “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Forward-looking statements in this Form 10-Q include statements regarding our expected future revenue, income, production, liquidity, expenses and capital projects.  Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements due to a variety of factors, including those associated with our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices, declines in the values of our properties that have resulted in and may in the future result in additional ceiling test write downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for our participation in oil and gas properties and for future acquisitions, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters and the operating hazards attendant to the oil and gas and minerals businesses.  In particular, careful consideration should be given to cautionary statements made in the Company’s Risk Factors included in our Annual Report on Form 10-K and quarterly reports on Form 10-Q filed with the SEC, all of which are incorporated herein by reference.  The Company undertakes no duty to update or revise any forward-looking statements.
 
 
 
-34-

 
 

Off-Balance Sheet Arrangements

None.

Contractual Obligations

We had three principal categories of contractual obligations at March 31, 2012: Debt to third parties of $10.0 million, executive retirement obligations of $934,000 and asset retirement obligations of $564,000.  The debt consists of debt to a commercial bank secured by our multi-family property in Gillette, WY and the purchase of land near our Mt. Emmons molybdenum property.  The debt to the commercial bank bears an interest rate of 5.5% per annum and the land debt bears an interest rate of 6.0% per annum.  The debt to the commercial bank is amortized over 20 years with a balloon payment due at the end of five years on May 5, 2016.  The balloon payment at maturity is $8.8 million.  The $400,000 land debt is due in two equal annual payments of $200,000, plus accrued interest. The next payment is due on January 2, 2013.  The executive retirement liability will be paid out over varying periods starting after the actual projected retirement dates of the covered executives.  The asset retirement obligations will be retired during the next 34 years.  The following table shows the scheduled debt payment, projected executive retirement benefits and asset retirement obligations as of March 31, 2012.  This table reflects the debt obligation on the Remington Village apartment complex on terms of the note.  However, because the related property is reflected as a current asset held for sale, the note is also classified in the financial statements as a current liability held for sale.
 
   
(In thousands)
 
   
Payments due by period
 
         
Less
   
One to
   
Three to
   
More than
 
         
than one
   
Three
   
Five
   
Five
 
   
Total
   
Year
   
Years
   
Years
   
Years
 
      
  $ 9,958     $ 508     $ 9,450     $ --     $ --  
                                         
 Executive retirement
    934       125       327       163       319  
                                         
 Asset retirement obligation
    564       46       23       14       481  
                                         
 Totals
  $ 11,456     $ 679     $ 9,800     $ 177     $ 800  
                                         

ITEM 3.  Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas.  The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues.


 
 
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To mitigate some of our commodity risk, we use derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk underlying our oil and gas production.  We may also use puts, calls and basis swaps in the future.   We do not hold or issue derivative instruments for trading purposes.  The objective of utilizing the economic hedges is to reduce the effect of price changes on a portion of our future oil production, to 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.

Through Energy One, we have entered into commodity derivative contracts (“economic hedges”) with BNP Paribas, a costless collar and two fixed price swaps, as described below.  The derivative contracts are priced using West Texas Intermediate (“WTI”) quoted prices.  U.S. Energy is a guarantor of Energy One’s obligations under the economic hedges.

Energy One's commodity derivative contracts as of March 31, 2012 are summarized below:
 
 
       
Quantity
         
Settlement Period
Counterparty
Basis
 
(Bbl/d)
 
Strike Price
 
                   
Crude Oil Costless Collar
                 
10/01/11 - 09/30/12
 BNP Parabis
 WTI
    400  
Put:
  $ 80.00  
             
Call:
  $ 99.00  
Crude Oil Costless Collar
                     
01/01/12 - 12/31/12
 BNP Parabis
 WTI
    200  
Put:
  $ 90.00  
             
Call:
  $ 106.50  
Crude Oil Costless Collar
                     
10/01/12 - 09/30/13
 BNP Parabis
 WTI
    200  
Put:
  $ 95.00  
             
Call:
  $ 116.60  

The following table details the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category:
 
 
(in thousands)
 
 
Derivative Assets
 
Derivative Liabilities
 
 
Balance Sheet
 
Fair
 
Balance Sheet
 
Fair
 
 
Classification
 
Value
 
Classification
 
Value
 
                 
Crude oil costless collars
Current Asset
  $ 101  
Current Liability
  $ 758  
                     
 
 
 
These contracts are accounted for using the mark-to-market accounting method and accordingly, we recognize all unrealized and realized gains and losses related to these contracts currently in earnings and such gains and losses are classified as gain (loss) on derivative instruments, net in our consolidated statements of operations.


 
 
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ITEM 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of March 31, 2012, the Company’s management, including its Chief Executive Officer and Principal Accounting Officer, completed an evaluation of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”)).  Based on that evaluation the Chief Executive Officer and Principal Accounting Officer concluded:

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