News Column

US ENERGY CORP - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

August 11, 2014

The following is Management's Discussion and Analysis of significant factors that have affected liquidity, capital resources and results of operations during the six months ended June 30, 2014 and 2013. The following also updates information as to our financial condition provided in our Annual Report on Form 10-K for the year ended December 31, 2013 (the "2013 10-K"). Statements in the following discussion may be forward-looking and involve risk and uncertainty (see "Forward Looking Statements"). The following discussion should also be read in conjunction with our condensed consolidated financial statements and the notes thereto.



General Overview

We are an independent energy company focused on the acquisition and development of oil and gas producing properties in the continental United States. Our business is currently focused in South Texas and the Williston Basin in North Dakota. However, we do not intend to limit our focus to these geographic areas. We continue to focus on increasing production, reserves, revenues and cash flow from operations while managing our level of debt. We currently explore for and produce oil and gas through a non-operator business model; however, we may operate oil and gas properties for our own account and may expand our operations to other geographic areas. As a non-operator, we rely on our operating partners to propose, permit and manage wells. Before a well is drilled, the operator is required to provide all oil and gas interest owners in the designated well the opportunity to participate in the drilling costs and revenues of the well on a pro-rata basis. After the well is completed, our operating partners also transport, market and account for all production.



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

Our current capitalized amounts in the oil and gas and mining areas at June 30, 2014 and December 31, 2013 were as follows:

(In thousands) June 30, December 31, 2014 2013



Unproved oil and gas properties $ 13,852$ 7,478

Proved oil and gas properties 71,972 79,444 Undeveloped mining properties 21,942 20,739 $ 107,766$ 107,661 Oil and Gas Activities We have active agreements with several oil and gas exploration and production companies. Our working interest varies by project (and may vary over time depending on the terms of the relevant agreement), but typically ranges from approximately 1% to 62%. These projects may result in numerous wells being drilled over the next three to five years. We are also actively pursuing the potential acquisition of additional exploration, development or production stage oil and gas properties or companies. The following table details our interests in producing wells as of June 30, 2014 and 2013. -27- --------------------------------------------------------------------------------

June 30, 2014 2013 Gross Net (1) Gross Net (1) Williston Basin: Productive wells 87.00 10.10 74.00 11.02 Wells being drilled or awaiting completion 8.00 0.09 10.00 0.18 South Texas: Productive wells 27.00 7.48 15.00 4.18 Wells being drilled or awaiting completion 4.00 1.04 -- -- Gulf Coast: Productive wells 3.00 0.56 3.00 0.56 Wells being drilled or awaiting completion -- -- 1.00 0.20 Total: Productive wells 117.00 18.14 92.00 15.76



Wells being drilled or awaiting completion 12.00 1.13 11.00 0.38

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

contracts. Williston Basin, North Dakota Rough Rider Prospect. We participate in fifteen 1,280 acre drilling units in the Rough Rider prospect with Statoil Oil & Gas, L.P. ("Statoil"). From August 24, 2009 to June 30, 2014, we have drilled and completed 21 gross (6.25 net) Bakken formation wells and two gross (0.22 net) Three Forks formation wells under our Drilling Participation Agreement with Statoil.



Three gross (0.07 net) wells were in progress at June 30, 2014. Our net investment in the Rough Rider prospect wells was $239,000 for the six months ended June 30, 2014. Statoil operates all of the wells.

Yellowstone and SEHR Prospects. We participate in twenty-seven gross 1,280 acre spacing units in the Yellowstone and SEHR prospects with Zavanna, LLC ("Zavanna"). Through June 30, 2014, we have drilled and completed 36 gross (3.07 net) Bakken formation wells and seven gross (0.32 net) Three Forks formation wells in these prospects. The wells are operated by Zavanna (18 gross, 2.91 net), Emerald Oil, Inc. (20 gross, 0.31 net), Murex Petroleum (2 gross, 0.13 net), Kodiak Oil & Gas Corp. (2 gross, 0.04 net) and Slawson Exploration Company, Inc. (1 gross, 0.01 net). During the first six months of 2014, we completed six gross (0.08 net) wells in the Yellowstone and SEHR prospects. At June 30, 2014, three additional gross (0.01 net) wells had been spud and were in progress.



Our net investment in the Yellowstone and SEHR prospect wells was $1.5 million during the six months ended June 30, 2014.

-28- -------------------------------------------------------------------------------- Bakken/Three Forks Asset Package. In 2012, we acquired approximately 400 net acres in 23 drilling units in McKenzie, Williams and Mountrail Counties of North Dakota. In June 2014, we sold our interest in eight of these 23 drilling units (approximately 285.7 net acres) for $12.2 million. At June 30, 2014, there were 21 gross (0.24 net) producing wells in the remaining 15 drilling units. During the six months ended June 30, 2014, our net investment in wells under the remaining drilling units in this program was $41,000. Two gross (0.04 net) wells were in progress at June 30, 2014.



South Texas (Eagle Ford Shale and Buda Limestone)

Booth-Tortuga and Leona River Prospects. We participate in the Booth-Tortuga and Leona River prospects with Contango Oil & Gas Company ("Contango"). At June 30, 2014, we have 25 gross (7.18 net) producing wells in these prospects comprised of 11 gross (3.30 net) Buda limestone wells, three gross (0.90 net) Eagle Ford Shale wells and 11 gross (2.98 net) Austin Chalk wells. During the six months ended June 30, 2014, we drilled and completed seven gross (2.10 net) Buda limestone wells in the Booth-Tortuga prospect. Two additional Buda limestone wells (0.38 net) were spud in the six months ended June 30, 2014. Our net investment in these wells during the first six months of 2014, including lease acquisition costs in the prospects, was $8.9 million. Big Wells Prospect. We participate in the Big Wells prospect with U.S. Enercorp. At June 30, 2014, we have two gross (0.30 net) producing Buda limestone wells in this prospect. During the six months ended June 30, 2014, we drilled and completed one gross (0.15 net) well in the Big Wells prospect. Our net investment in this well during the six months ended June 30, 2014 was $795,000. Q2 2014 Acquisition. In May 2014, the Company acquired 33% of a private South Texas based oil and gas company's (the "Seller") interest in approximately 12,100 gross (3,384 net) acres in Dimmit County, Texas. The acreage consists of 4,020 gross (1,181 net) acres of primary leasehold acreage and 8,080 gross (2,203 net) acres of farm-in acreage, to be earned through a continuous drilling program. The farm-in acreage has an initial two well commitment and a 12.5% working interest carry for the leaseholder (the "Farmor") in the first 10 wells. After 100% payout of all costs for the first 10 wells that are drilled under the farm-in program, the Farmor will back in for its 12.5% retained working interest in the prospect. The Seller also retained a 25% working interest back-in after 115% of project payout has been received by the Company. The Company paid $3.9 million to enter into the transaction, which included leasehold and farm-in acquisition costs as well as our proportionate share of drilling costs for the initial test well in the prospect. A minimum of three Buda formation wells are scheduled to be drilled in 2014.



Two gross (0.67 net) wells were in progress at June 30, 2014. Our net investment in this acreage and wells through June 30, 2014 was $5.6 million.

U.S. Gulf Coast (Onshore)

We participate with three different operators in the U.S. Gulf Coast (onshore). At June 30, 2014, we had three gross producing (0.56 net) wells in this region. Our net investment in Gulf Coast wells and properties was $26,000 during the six months ended June 30, 2014. -29- --------------------------------------------------------------------------------



2014 Production Results

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

Williston Basin South Texas Gulf Coast Total First Six Months of 2014 Production Oil (Bbl) 108,678 57,624 475 166,777 Gas (Mcf) 60,323 109,286 85,733 255,342 NGLs (Bbl) 2,415 9,825 18 12,258 Equivalent (BOE) 121,147 85,663 14,782 221,592 Avg. Daily Equivalent (BOE/d) 669 473 82 1,224 Relative percentage 54.7% 38.6% 6.7% 100%



Mount Emmons Molybdenum Project

With respect to the Mount Emmons project, the Company expects to continue scoping analysis of the Mine Plan of Operations with the U.S. Forest Service through the balance of 2014.

Additional Comparative Data The following table provides information regarding selected production and financial information for the quarter ended June 30, 2014 and the immediately preceding three quarters. For the Three Months Ended June 30, March 31, December 31, September 30, 2014 2014 2013 2013 (in Thousands, except for production data) Production (BOE) 116,499 105,093 123,246 101,987



Oil, gas and NGL production revenue $ 9,128$ 8,256 $

9,271 $ 8,582 Unrealized and realized derivative gain (loss) $ (612 )$ (331 ) $ 255 $ (1,075 ) Lease operating expense $ 1,807$ 1,250$ 1,393 $ 2,006 Production taxes $ 779$ 722 $ 835 $ 871 DD&A $ 3,583$ 3,294$ 3,744 $ 3,205 General and administrative $ 1,533$ 1,606$ 1,710 $ 1,337 Mineral holding costs $ 205$ 300 $ 294 $ 410 Water treatment plant $ 452$ 457 $ 603 $ 394



Income (loss) from continuing operations $ 56$ 250 $

(1,217 ) $ (706 ) Results of Operations



Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

During the three months ended June 30, 2014, we recorded net income after taxes of $56,000, or $0.00 per share basic and diluted, as compared to net income after taxes of $573,000, or $0.02 per share basic and diluted, during the same period of 2013. Significant components of the changes in results of operations for the three months ended June 30, 2014 as compared to the three months ended June 30, 2013 are as follows: -30-

-------------------------------------------------------------------------------- Oil and Gas Operations. Oil and gas operations generated operating income of $3.0 million during the quarter ended June 30, 2014 as compared to operating income of $2.1 million during the quarter ended June 30, 2013. The following table summarizes production volumes, average sales prices and operating revenues for the three months ended June 30, 2014 and 2013: Three Months Ended June 30, Increase 2014 2013 (Decrease) Production volumes Oil (Bbls) 83,212 84,412 (1,200 ) Natural gas (Mcf) 156,535 88,296 68,239 Natural gas liquids (Bbls) 7,198 1,898 5,300 Equivalent (BOE) 116,499 101,026 15,473 Avg. Daily Equivalent (BOE/d) 1,280 1,110 170 Average sales prices Oil (per Bbl) $ 95.53$ 88.38 7.15 Natural gas (per Mcf) 5.57 4.28 1.29 Natural gas liquids (per Bbl) 42.65 40.67 1.98 Equivalent (BOE) 78.35 78.35 -- Operating revenues (in thousands) Oil $ 7,949$ 7,460$ 489 Natural gas 872 378 494 Natural gas liquids 307 77 230 Total operating revenue 9,128 7,915 1,213 Oil and gas production expense (1,807 ) (1,765 ) (42 ) Production taxes (779 ) (800 ) 21 Income before depreciation, depletion and amortization 6,542 5,350 1,192 Depreciation, depletion and amortization (3,583 ) (3,213 ) (370 ) Income $ 2,959$ 2,137$ 822 During the three months ended June 30, 2014, we produced 116,499 BOE, or an average of 1,280 BOE/day. In our South Texas region, production increased 270%, from 13,230 BOE to 48,939 BOE, between the two periods as a result of drilling in our Buda limestone program. Production in our Bakken region decreased 24%, from 78,782 BOE to 60,052 BOE, between the two periods as a result of normal production declines and lower working interests in wells drilled in this region. We expect these regional production trends to continue. 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 is classified as oil and gas production expense. -31-

-------------------------------------------------------------------------------- We recognized $9.1 million in revenues during the three months ended June 30, 2014 as compared to $7.9 million during the same period in 2013. The $1.2 million increase in revenue is primarily due to higher oil and gas prices and higher gas sales volumes in the second quarter of 2014 as compared to the second quarter of 2013. Our average net realized price (operating revenue per BOE) for the three months ended June 30, 2014 was $78.35 per BOE compared with $78.35 for the same period in 2013. Due to takeaway constraints, the discount to West Texas Intermediate ("WTI") quoted prices, or differential, for oil prices in the Williston Basin has ranged from $13.00 to $17.00 per barrel during the three months ended June 30, 2014. Until additional takeaway capacity is available, we expect this differential to continue (with the amount of the differential varying over time) and that our oil sales revenue will be affected by lower realized prices from this region. Oil and gas production expense of $1.8 million for the three months ended June 30, 2014 was comprised of $1.8 million in lease operating expense and $27,000 in workover expense. Our depletion, depreciation and amortization (DD&A) rate for the three months ended June 30, 2014 was $30.76 per BOE compared to $31.80 per BOE for the same period in 2013. Our DD&A rate can fluctuate as a result of changes in drilling and completion costs, impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves. Mt. Emmons and Water Treatment Plant Operations. We recorded $452,000 in costs and expenses for the water treatment plant and $205,000 for holding costs for the Mt. Emmons molybdenum property during the three months ended June 30, 2014. During the three months ended June 30, 2013, we recorded $403,000 in operating costs related to the water treatment plant and $297,000 in holding costs. General and Administrative Expenses. General and administrative expenses increased by $247,000 during the three months ended June 30, 2014 compared to general and administrative expenses for the three months ended June 30, 2013. The increase in general and administrative costs in 2014 is primarily a result of increases of $201,000 in professional services, $30,000 in director's fees and related options expense, and $20,000 in compensation expense. Other Income and Expenses. We recognized an unrealized and realized derivative loss of $612,000 in the second quarter of 2014 compared to a gain of $347,000 for the same period in 2013. The 2014 amount includes a loss on unrealized changes in the fair value of our commodity derivative contracts of $238,000 and realized cash settlement losses on derivatives of $374,000. During the three months ended June 30, 2014, we recorded no gains or losses from the sale of assets. During the three months ended June 30, 2013, we recorded a gain on the sale of assets of $14,000.



During the three months ended June 30, 2013, we recorded an equity loss of $26,000 from our unconsolidated investment in SST. At December 31, 2013, we fully impaired the investment in SST. Subsequently, we no longer record our share of equity in earnings or losses of SST.

Interest income was $1,000 during each of the quarters ended June 30, 2014 and 2013.

As a result of higher average debt balances, interest expense increased to $149,000 during the quarter ended June 30, 2014 from $111,000 during the quarter ended June 30, 2013.

-32- --------------------------------------------------------------------------------



Discontinued Operations. During the three months ended June 30, 2013, we recorded income of $206,000, net of taxes, from Remington Village. We sold this property in the third quarter of 2013 and have no income or losses from discontinued operations during the three months ended June 30, 2014.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

During the six months ended June 30, 2014, we recorded net income after taxes of $306,000, or $0.01 per share basic and diluted, as compared to a net loss after taxes of $5.3 million, or $0.19 per share basic and diluted during the same period of 2013. Significant components of the changes in results of operations for the six months ended June 30, 2014 as compared to the six months ended June 30, 2013 are as follows: Oil and Gas Operations. Oil and gas operations generated operating income of $5.9 million during the six months ended June 30, 2014 as compared to operating income of $3.8 million during the six months ended June 30, 2013, excluding a $5.8 million non-cash impairment charge taken on our oil and gas properties during the six months ended June 30, 2013. The following table summarizes production volumes, average sales prices and operating revenues for the six months ended June 30, 2014 and 2013: Six Months Ended June 30, Increase 2014 2013 (Decrease) Production volumes Oil (Bbls) 166,777 165,785 992 Natural gas (Mcf) 255,342 176,394 78,948 Natural gas liquids (Bbls) 12,258 4,516 7,742 Equivalent (BOE) 221,592 199,700 21,892 Avg. Daily Equivalent (BOE/d) 1,224 1,103 121 Average sales prices Oil (per Bbl) $ 93.08$ 89.28$ 3.80 Natural gas (per Mcf) 5.30 4.53 $ 0.77 Natural gas liquids (per Bbl) 41.44 42.78 $ (1.34 ) Equivalent (BOE) 78.45 79.09 $ (0.64 ) Operating revenues (in thousands) Oil $ 15,523$ 14,802$ 721 Natural gas 1,353 799 554 Natural gas liquids 508 193 315 Total operating revenue 17,384 15,794 1,590 Oil and gas production expense (3,057 ) (3,731 ) 674 Production taxes (1,501 ) (1,633 ) 132 Impairment -



(5,828 ) 5,828 Income before depreciation, depletion and amortization 12,826 4,602

8,224 Depreciation, depletion and amortization (6,877 ) (6,674 ) (203 ) Income $ 5,949$ (2,072 )$ 8,021 -33-

-------------------------------------------------------------------------------- During the six months ended June 30, 2014, we produced 221,592 BOE, or an average of 1,224 BOE/day. In our South Texas region, production increased 334%, from 19,734 BOE to 85,663 BOE, between the two periods as a result of drilling in our Buda limestone program. Production in our Bakken region decreased 25%, from 162,554 BOE to 121,147 BOE, between the two periods as a result of normal production declines and lower working interests in wells drilled in this region. We expect these regional production trends to continue. 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 is classified as oil and gas production expense. We recognized $17.4 million in revenues during the six months ended June 30, 2014 as compared to $15.8 million during the same period in 2013. The $1.6 million increase in revenue is primarily due to higher oil and gas sales volumes and higher oil and gas prices in the first six months of 2014 as compared to the first six months of 2013. Our average net realized price (operating revenue per BOE) for the six months ended June 30, 2014 was $78.45 per BOE compared with $79.09 for the same period in 2013. Due to takeaway constraints, the discount to West Texas Intermediate ("WTI") quoted prices, or differential, for oil prices in the Williston Basin has ranged from $13.00 to $21.00 per barrel during the first six months of 2014. Until additional takeaway capacity is available, we expect this differential to continue (with the amount of the differential varying over time) and that our oil sales revenue will be affected by lower realized prices from this region. Oil and gas production expense of $3.1 million for the six months ended June 30, 2014 was comprised of $2.9 million in lease operating expense and $153,000 in workover expense. The $674,000 decrease in total oil and gas production expense in the six months ended June 30, 2014 as compared to the same period in 2013 is comprised of reductions in lease operating expense of $250,000 and workover expense of $424,000. Our depletion, depreciation and amortization (DD&A) rate for the six months ended June 30, 2014 was $31.03 per BOE compared to $33.42 per BOE for the same period in 2013. Our DD&A rate can fluctuate as a result of changes in drilling and completion costs, impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves. Mt. Emmons and Water Treatment Plant Operations. We recorded $909,000 in costs and expenses for the water treatment plant and $505,000 for holding costs for the Mt. Emmons molybdenum property during the six months ended June 30, 2014. During the six months ended June 30, 2013, we recorded $820,000 in operating costs related to the water treatment plant and $524,000 in holding costs. General and Administrative Expenses. General and administrative expenses increased by $581,000 during the six months ended June 30, 2014 compared to general and administrative expenses for the six months ended June 30, 2013. The increase in general and administrative costs in 2014 is primarily a result of increases of $349,000 in professional services, $176,000 in compensation expense and $35,000 in director fees and related options expense. -34- -------------------------------------------------------------------------------- Other Income and Expenses. We recognized an unrealized and realized derivative loss of $943,000 in the first six months of 2014 compared to a loss of $255,000 for the same period in 2013. The 2014 amount includes a loss on unrealized changes in the fair value of our commodity derivative contracts of $411,000 and realized cash settlement losses on derivatives of $532,000. During the six months ended June 30, 2014, we recorded a gain on the sale of assets of $28,000 from the sale of a piece of equipment. During the six months ended June 30, 2013, we recorded a gain on the sale of assets of $710,000, primarily related to the sale of our corporate aircraft and related facilities. During the six months ended June 30, 2013, we recorded an equity loss of $51,000 from our unconsolidated investment in SST. At December 31, 2013, we fully impaired the investment in SST. Subsequently, we no longer record our share of equity in earnings or losses of SST.



Interest income was $2,000 and $3,000 during the six months ended June 30, 2014 and 2013, respectively.

As a result of higher average debt balances, interest expense increased to $245,000 during the six months ended June 30, 2014 from $226,000 during the six months ended June 30, 2013.

Discontinued Operations. During the six months ended June 30, 2013, we recorded income of $438,000, net of taxes, from Remington Village. We sold this property in the third quarter of 2013 and have no income or losses from discontinued operations during the six months ended June 30, 2014.



Overview of Liquidity and Capital Resources

At June 30, 2014, we had $4.3 million in cash and cash equivalents. Our working capital (current assets minus current liabilities) was $5.4 million. As discussed below in "Capital Resources and Capital Requirements", we project that our capital resources at June 30, 2014 will be sufficient to fund our operations and capital projects through the balance of 2014. Given the size of our potential commitments related to our existing inventory of drilling projects, however, our requirements for capital could increase significantly during the remainder of 2014 if, among other things, we make acquisitions or elect to participate in any currently unanticipated drilling of additional wells. As a result, we may consider borrowing more than currently anticipated on our revolving 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 oil and gas. Significant price swings can have adverse or positive effects on our business of exploring for, developing and producing oil and gas. 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.



Capital Resources

Primary potential sources of future liquidity include the following:

Oil and Gas Production. At June 30, 2014, we had 117 gross (18.14 net) producing wells. During the six months ended June 30, 2014, we received an average of $2.9 million per month from these producing wells with an average operating cost of $510,000 per month (including workover costs) and production taxes of $250,000, for average net cash flows of $2.1 million per month from oil and gas -35- -------------------------------------------------------------------------------- production before non-cash depletion expense. We anticipate that cash flows from oil and gas operations will increase through the balance of 2014 as additional wells being drilled with Contango 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 reduce these average monthly cash flow amounts. Normal production declines and the back-in after payout provisions granted to certain of our counterparties will eventually decrease the amount of cash flow we receive from the relevant wells. We anticipate drilling more Buda limestone wells with Contango, U.S. Enercorp and others and additional Bakken and Three Forks wells with Statoil, Zavanna and others in the future and will continue to search for additional drilling opportunities to replace these oil reserves and cash flows.



Cash on Hand. At June 30, 2014, we had $4.3 million in cash and cash equivalents.

Wells Fargo Revolving Credit Facility. On July 30, 2010, we established a senior credit facility through our wholly owned subsidiary, Energy One to borrow up to $75 million (since increased to $100 million as described below) from a syndicate of banks, financial institutions and other entities, including Wells Fargo Bank, National Association, which acquired the North American reserve-based and related diversified energy lending business of our initial lending institution, 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, 2017), 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. As of the date of this report, the commitment amount is $100 million and the borrowing base is $24.5 million. As of June 30, 2014, Energy One was in compliance with all the covenants under the revolving credit facility.



As of the date of this report, we have outstanding borrowings of $8.0 million under the credit facility.

Capital Requirements Our direct capital requirements during the balance of 2014 relate to the funding of our drilling programs, the potential acquisition of prospective oil and gas properties and/or existing production, payment of debt obligations, operating and capital improvement costs relating to the water treatment plant at Mt. Emmons, ongoing permitting activities for the Mt. Emmons project and general and administrative costs. We intend to finance our 2014 capital expenditure plan primarily from the sources described above under "Capital Resources". We may be required to reduce or defer part of our 2014 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. Through June 30, 2014, we have spent approximately $17.3 million of our $30.2 million 2014 oil and gas capital expenditure budget. The remaining $12.9 million is currently budgeted to be spent on exploration and acquisition initiatives in South Texas and in the Williston Basin of North Dakota. Actual capital expenditures for each regional drilling program is -36-

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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 that program may be allocated to other 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. Operating costs for the water treatment plant during the remainder of 2014 are expected to be approximately $144,000 per month and holding costs related to the mine are expected to average $91,000 per month. Additionally, we anticipate expenditures of approximately $120,000 for water treatment plant improvements that are expected to improve the plant's efficiency and reduce costs and $200,000 for advancement of the Mine Plan of Operations. Insurance. We have liability insurance coverage in amounts we deem sufficient and in line with industry standards for the location, stage of development, and type of assets we operate. 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 $778,000 related to our oil and gas wells and $181,000 related to the Mt. Emmons molybdenum property. No reclamation is expected to be performed during the year ended December 31, 2014 unless a well, or wells, are abandoned due to unexpected operational challenges or if a well becomes uneconomical. As the Mt. Emmons project is developed, the reclamation liability is expected to increase. 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 Six Months Ended June 30, 2014

The following table presents changes in cash flows between the six month periods ended June 30, 2014 and 2013. 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. (In thousands) For the six months ended June 30, 2014 2013 Change



Net cash provided by operating activities $ 8,725$ 6,254$ 2,471 Net cash (used in) investing activities

(9,271 ) (5,052 ) (4,219 ) Net cash (used in) financing activities (1,055 ) (151 ) (904 ) Net cash provided by discontinued operations -- 265 (265 ) Operating Activities. Cash provided by operations for the six month period ended June 30, 2014 increased to $8.7 million as compared to cash provided by operations of $6.3 million for the same period of 2013. This $2.4 million year over year increase in cash from operating activities is primarily due to higher oil and gas revenue and lower oil and gas operating expenses during the six months ended June 30, 2014 as compared to the six months ended June 30, 2013. For further discussion related to cash provided by operations, please refer to "Results of Operations" above. -37- -------------------------------------------------------------------------------- Investing Activities. During the six months ended June 30, 2014, investing activities consumed cash through the acquisition and development of oil and gas properties in the amount of $19.5 million, the acquisition of property in the amount of $1.2 million and a net change of $61,000 in restricted investments. During this period, investing activities provided cash through $11.5 million from the sale of oil and gas properties and $28,000 in proceeds from the sale of used equipment. The $4.2 million change in investing activities during the six months ended June 30, 2014 as compared to the same period of 2013 is primarily a result of: (a) an $11.9 million increase in acquisitions and development of oil and gas properties in the six months ended June 30, 2014 as compared to the same period in 2013, (b) $11.5 million in proceeds from the sale of oil and gas properties as compared to no oil and gas property sales in 2013, (c) $2.6 million in proceeds from the sale of property and equipment in 2013 as compared to $28,000 during the six months ended June 30, 2014, and (d) $1.2 million purchase of property during 2014 with no property and equipment acquisitions during the same period in 2013. Financing Activities. Financing activities consumed $1.1 million during the six months ended June 30, 2014 from the repayment of borrowings under our credit facility, and $55,000 from the exercise of stock options. During the six months ended June 30, 2013, financing activities consumed $151,000 from the repayment of debt.



Critical Accounting Policies and Estimates

For detailed descriptions of our critical accounting policies and estimates, we refer you to the corresponding section of Part II, Item 7 of our 2013 10-K (please see pages 68 to 71).

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 related to 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 June 30, 2014, 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 for 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, 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 -38- -------------------------------------------------------------------------------- statements contain these identifying words. Forward-looking statements in this Form 10-Q include statements regarding our expected future revenue, income, production, liquidity, cash flows, reclamation and other liabilities, expenses and capital projects, future capital expenditures and projects, future transactions and takeaway capacity. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements due to a variety of factors, including those associated with our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil, NGL and natural gas prices, declines in the values of our properties that have resulted in and may in the future result in additional ceiling test write downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for our participation in oil and gas properties and for future acquisitions, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters and the operating hazards attendant to the oil and gas and minerals businesses. In particular, careful consideration should be given to cautionary statements made in the "Risk Factors" section of our 2013 10-K and other quarterly reports on Form 10-Q filed with the SEC, all of which are incorporated herein by reference. The Company undertakes no duty to update or revise any forward-looking statements. Forward-looking statements also include those relating to the permitting and approval process for the Mount Emmons molybdenum project (the "Project"). There can be no assurance that U.S. Energy will receive the permits and approvals necessary to pursue the Project. In addition, such permits and approvals, if received, could be unreasonably or unexpectedly delayed or made subject to conditions that reduce the benefits of the Project or render it uneconomic. The process under NEPA may be longer than the Company expects, may involve substantial costs, and may require substantial management attention. The mine, if constructed, could be substantially different in nature, productivity and economic potential than the mine as contemplated by the Mine Plan of Operations. In addition, if constructed, the operation of the mine will be subject to a wide variety of operating, commodity-price related and financial risks.



Off-Balance Sheet Arrangements

None

Contractual Obligations

We had three principal categories of contractual obligations at June 30, 2014: Debt to third parties of $8.0 million, executive retirement obligations of $841,000 and asset retirement obligations of $959,000.

The debt to third parties consists of $8.0 million in debt under our revolving credit facility. Each borrowing under the revolving credit facility has a term of six months but can be continued at our election through July 2017 if we remain in compliance with the covenants under the facility. The executive retirement liability will be paid out over varying periods starting after the actual retirement dates of the covered executives. The asset retirement obligations are expected to be retired during the next 33 years.


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Source: Edgar Glimpses


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