Reggie Larsen - Director of Investor Relations Keith Larsen - Chief Executive Officer Steve Richmond - Chief Financial Officer

Noel Parks - Ladenburg Thalmann Evan Richert - Sidoti & Company

Operator: Good morning. My name is Kate, and I will be your conference operator today. At this time, I would like to welcome everyone to the U.S. Energy Corp’s Second Quarter 2014 Selected Highlights, Financial Results and Operations Update Conference Call. All lines have been placed on mute to prevent any background noise. I would now like to turn the conference over to Mr. Reggie Larsen, Director of Investor Relations of U.S. Energy Corp. Sir, you may begin your conference.

Thank you. Good morning, ladies and gentlemen, and thank you for joining us today. With me this morning is Keith Larsen, Chief Executive Officer of the Company; Steve Richmond, the Company's Chief Financial Officer, as well as members of the Company’s management team. In terms of agenda for the call, Keith will provide you with an overview of our highlights, financial results and operating initiatives for the quarter ended June 30, 2014 as well as the period subsequent to quarter end, and we’ll finish the call with a question-and-answer session. As a preliminary matter, I would like to note that during this call, we may make forward-looking statements which may be identified by the words will, anticipate, expect, and similar words that are based on the beliefs and assumptions of U.S. Energy's management. These and all statements other than statements of historical fact are forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934 and Section 27A of the Securities Act of 1933. The forward-looking statements are subject to numerous risks and uncertainties, including those described in the Form 10-Q for the quarter ended June 30, 2014, which we filed yesterday and our other filings with the SEC, all of which are incorporated herein by reference. Relevant non-GAAP reconciliations are available on the Company’s Web site which is located at www.usnrg.com. I'd now like to turn the call over to Keith.

Thanks, Reg, and welcome everybody. I first like to thank the audience for attending today’s call and for following the Company's progress through the mid-year point of 2014. To begin, I am pleased to announce that the Company has recorded net income after taxes of $56,000 during the quarter ended June 30, 2014. During the six months ended June 30th, the Company recorded net income after taxes of $306,000 or $0.01 per share. During the three months ended June 30th, the Company produced 116,499 barrels of oil equivalent, which is a 15.3% increase over the same period of 2013 and a 10.9% increase over the first quarter of 2014. Average net daily production was 1,280 barrels of oil equivalent during the quarter ended June 30th and I would like to note June’s monthly average daily production was up to 1,352 net barrels of oil equivalent per day. The uptick in production comes primarily as a result of the Beeler number 16 and 17 wells in South Texas which began producing mid June. Overall, our production and revenues come from 117 gross 18.1 net wells primarily located in the Williston Basin of North Dakota and in South Texas. As a result of our production growth, the Company recognized $9.1 million in revenues during the second quarter of 2014 which is a 15.3% increase as compared to $7.9 million during the same period of the prior year. For the six months ended June 30th, the Company recognized $17.4 million revenues which is a 10.1% increase in revenues as compared to $15.8 million in revenues during the same period in 2013. Both increases are primarily due to higher oil and gas prices and higher oil and gas sales volumes when compared to the same period of the prior year. Looking ahead, we remain in a good position to fund our forward drilling programs. At June 30th, we had $4.3 million in cash and cash equivalents and an additional $16.5 million in borrowing capacity under our $24.5 million line of credit with Wells Fargo. During the quarter, our borrowing base was reduced from $26.5 million to $24.5 million due to the divestiture of certain assets and associated reserves in the Williston Basin of North Dakota for $12.2 million. Subsequent to the sale, $9 million of the proceeds were used to pay down the credit facility resulting in a remaining balance of $8 million. During the six months ended June 30th, we received an average of $2.9 million per month from our producing wells with an average operating cost of $510,000 per month including workover cost and production taxes of $250,000, for average net cash flows of $2.1 million per month from oil and gas production before non-cash depletion expense. In the financial and operational release that was published yesterday which is available on our Web site, we presented an EBITDAX table showing earnings before interest, income tax, depreciation, depletion and amortization, accretion of discount on asset retirement obligations, non-cash impairments, unrealized derivative gains and losses, and non-cash stock compensation expense which we refer to as modified EBITDAX, and a reconciliation of modified EBITDAX to net income. Modified EBITDAX was $4.2 million for the three months ended June 30th, an increase of 12.5% when compared to a modified EBITDAX of $3.8 million for the same period of 2013. Modified EBITDAX was $8.3 million for the six months ended June 30th, an increase of 2.4% compared to a modified EBITDAX of $8.1 million for the same period of 2013. Now moving on to our oil and gas operations, our primary focus remains on our active drilling programs in South Texas targeting the development of the Buda Limestone formation in Zavala and Dimmit counties and on our drilling programs with several operators in the Williston Basin of North Dakota. In South Texas, the Company currently participates in approximately 35,000 gross, 9,100 net acres in Zavala and Dimmit counties. During the quarter the Company expanded its footprint in South Texas through an acquisition of an additional 12,100 gross, 3,300 net acres in Dimmit County, Texas. The acreage is prospective for the Escondido, Olmos, San Miguel, Austin Chalk, Eagle Ford Shale, Buda Limestone, Del Rio, Georgetown and the Edwards formations. Our current focus on this newly acquired acreage is the Buda Limestone formation in which we have drilled two test wells to-date. In the Booth Tortuga acreage block which is operated by Contango Oil and Gas and is located in both Zavala and Dimmit counties the Company has an approximate 30% working interest and approximate 22.5% net revenue interest in approximately 13,100 gross 3,500 net acres. The Beeler number 5 well began producing in late April; well was completed naturally without fracture stimulation and had a peak early 24 hour flow back rate of 241 BOE per day and a 30 day average production rate of 122 barrels of oil equivalent per day. The Beeler number 9 well was also completed naturally without fracture stimulation and commenced production in late April. The well had a peak early 24 hour flow back rate of 883 barrels of oil equivalent per day and a 30 day average production rate of 326 barrels of oil equivalent per day. The Beeler number 16 well was spud on April 18th. The well has drilled to a vertical depth of approximately 7,000 foot with dual laterals of approximately 4,000 foot each. Well was completed naturally, again without fracture stimulation, and commenced production in the second week of June. The well had a peak early 24 hour flow back rate of 1,083 barrels of oil equivalent per day, and a 30 day average production of 723 barrels of oil equivalent per day. The Beeler number 17 well was spud on May 13th. The well was completed naturally again without fracture stimulation and also commenced production in the second week of June. The well had a peak early 24 hour flow back rate of 1,326 barrels of oil equivalent per day and a 30 day average production rate of 1,109 barrels of oil equivalent per day. Beeler number 19 well was spud on June 10th. The well was completed naturally again without stimulation and commenced production in the second week of July. The well had a peak 24 hour flow back rate of 1,458 barrels of oil equivalent per day. And during the first 28 days of production, the well had an average production rate of 1,204 barrels of oil equivalent per day. The Beeler number 8 well was fracture stimulated with 12 stages during the third week in June. Production increase was not realized as a result of stimulation and it is theorized that the nearby fractured zones were depleted by an offsetting well. The well is still producing however, and we continue to monitor the well's performance. Beeler number 20 well was spud on July 3rd. The well was drilled to a total depth of 16,574 foot, which included a 9,474 foot lateral, the longest lateral to date in our program. We continue to monitor the early production data from the well, which so far is comparable to the early flow back results of the Beeler number 17 well. Beeler number 17, Beeler number 19 and the Beeler number 20 well costs have been approximately 2.6 million gross per well. Going forward we are currently scheduled to drill an additional four gross Buda wells with Contango during the balance of the year. The drilling rig utilized in our program with Contango is currently drilling a well at another site in which we do not participate. We anticipate that the rig will return to drill our next participated well in the Booth Tortuga acreage block in early September. All four wells are proposed to be drilled with lateral lengths of over 9,000 foot. Under an Area of Mutual Interest Election, the Company also acquired a 7.5% working interest in an additional 800 gross 60 net acres in the Booth Tortuga prospect. This acreage is operated by a private Texas based company which is now rigging up for a second well in the acreage block. The acreage block lies between the Beeler number 16 and the Beeler number 9 well locations. The first well drilled, the Bruce Weaver number 2 was spud on June 6. The well was drilled to a total depth of 13,290 foot which included an approximate 6,665 lateral. The well was completed naturally without fracture stimulation and had an initial production rate of 894 barrels of oil. During the first 10 days of production the well averaged approximately 760 gross barrels of oil. During the early flow back the operator has flared the associated gas from the well, which is not included in the initial production rate. The well is currently being tied into a sales line to capture the gas sales, which has averaged approximately 1,000 MCF per day or approximately 167 gross additional barrels of oil equivalent during the first 10 days of production. The second well proposed in this acreage block the Bruce Weaver number 1 well will also target the Buda formations and Austin Chalk re-entry resulting in an anticipated overall reduction in the drilling cost of this well. The drill rig has been moved on site the well will be spud this week as a re-entry into an existing Austin Chalk wellbore which has substantially reduced the AFE per well. I’ll now move on to our Dimmit County acquisition. On May 7th, the Company entered into a Participation Agreement with a private South Texas based oil and gas company to acquire 33% of the seller's interest in approximately 12,100 gross, 3,384 net acres in Dimmit County, Texas. The Company paid $3.9 million to enter into the transaction which included acquisition costs as well as our proportionate share of drilling cost for the initial test well in the prospect. The initial test well was spud on May 5th and was drilled to a measured depth of approximately 11,297 feet, including an approximate 5,000 foot lateral. The well was fracture stimulated during the first week of August with 17 stages. We are currently monitoring the flow back of the fracture stimulation and hydrocarbon fluids from the well. The second well in the program was spud on June 23rd. The well was drilled to a measured depth of approximately 11,000 foot including an approximate 4,600 foot lateral. This well is scheduled to be fracture stimulated during the third week of August. A third well in the program is also scheduled to spud in mid September. In summary we continue to test to refine our focus (inaudible) South Texas due to the potential of the Buda Formation as well as the additional multiple stack hydrocarbon-bearing formation. This summer we have participated in a dual lateral on the Buda, we have extended the lateral length of over 9,000 feet and we have fracture stimulated an existing wellbore. In our newly acquired acreage block in Dimmit County, we have built two test wells and fracture stimulated the first well late in July. The second well in that program is scheduled to be fracture stimulated later this month and we are looking forward to evaluating the results. We have also recently purchased the 3D geomagnetic data package covering just under 4,000 line miles of data in Zavala and Dimmit County, Texas. The delineation of the data is currently underway by the Company and consultants with the intent to identify the potential for additional acreage acquisition. During the quarter ended June 30, the Company realized 538 net barrels of oil equivalent per day of production from this region which represents an approximate 32% increase over average net daily production from the area during the first quarter of 2014. We will continue to evaluate the results from this region with the intent to enhance our own gas reserve potential and to increase our net daily production as we continue to develop these assets. Now I will move on to the Williston basin of North Dakota. We participated in 74,280 gross, 2,939 net acres in Williams, McKenzie and Montreal counties, North Dakota. At the quarter’s end we had 87 gross, 10.1 net producing wells and eight gross, 0.09 net wells being drilled or awaiting completion. During the three months ended June 30, we averaged approximately 660 net barrels of oil equivalent per day from this area which represents a slight decrease over the first quarter of 2014 average daily production of 679 net barrels of oil. This decrease is primarily due to the divestiture of certain Williston Basin assets. As discussed earlier divestiture (net of the company) (ph) 12.2 million for the sale of approximately 286 net acres and 16 gross, 0.62 net producing wells in Williams and McKenzie counties North Dakota. The sold assets averaged approximately 52 net barrels of oil equivalent per day during 2013. We intend to continue to actively participate in the drilling and completion of our inventory of wells in the basin in order to maintain our base production from this region as well as seek out additional acquisition opportunities in the area that have accretive value to our portfolio of assets. Before moving on to the question-and-answer portion of today’s call, I’d also like to highlight that our combined activity in North Dakota and South Texas have produced two successive profitable quarters during 2014. And that we have entered the third quarter with additional flush productions from our most recently completed Buda wells. We are currently evaluating the fracture stimulation completion in our newly acquired acreage with an additional fracture stimulation coming later this month with an additional drill in mid September. We have been very active in South Texas this year and thus far we are seeing positive results while continuing to delineate and develop our position in the region. We will continue to manage our balance sheet and drilling commitments with a goal of increasing production, reserves, revenue and cash flow from operations with the ultimate goal of driving continued growth and profitability for the Company’s shareholders. That concludes our prepared remarks for today. Operator, would you please begin the Q&A session.

Yes, sir. [Operator Instructions] Our first question comes from the line of Noel Parks with Ladenburg Thalmann. Your line is open. Noel Parks - Ladenburg Thalmann: Good morning.

Good morning Noel. Noel Parks - Ladenburg Thalmann: I was just wondering, with this string of very solid results from the Buda, compared to some of the early results that were a little bit more variable, can you give us a sense of - is there a pattern that you guys and the operators kind of crack the code of what’s going to make successful well there and what might be a less successful well?

Well, Noel I think as you know, these wells are controlled by natural fractures. And I think now that we’ve gone to the 9,000 foot lateral, our chances of hitting those natural fractures has increased as well as the excellent performance by Contango knocking cost down below $3 million. It still remains a statistical play. We have had some lesser wells, but it appears right now that the wells that are performing exceptionally not only carry themselves and offer an excellent rate of return but they’ll carry some of the lesser wells as well. Noel Parks - Ladenburg Thalmann: And the question of the frac stimulation. It’s sounding like a number of the wells are performing just fine without it and I think you only mentioned one well, it might have been the Beeler 8 maybe the reserves have been depleted by an adjacent well. So essentially is there - (inaudible) expect that most of the wells will be un-stimulated going forward or will it just vary from location to location?

I think it’s going to vary from location to location and depend on results. We are early on in the flow back for this additional test that we did fracture stimulation on. And we think we explained the reason that (the 8) (ph) was offsetting that (inaudible) well, it was the 300,000 barrel well. So we kind of explained the depletion but it’s still going to be some experimentation as we go forward much like we did early on in the Bakken. So I think the verdict is still out there. Noel Parks - Ladenburg Thalmann: Great, and just one last one. Any thoughts on what DD&A might look like going forward as you have - had a lot of production coming on, (you’re on) (ph) as unit basis or aggregate?

Well, it’s been running about 30, Noel, with the cost here and the performance of these wells it may come down a bit but we’ve been using $30 a barrel. Noel Parks - Ladenburg Thalmann: Okay, great. That’s all from me. Thanks.

Thanks, Noel.

Our next question comes from the line of Evan Richert with Sidoti. Your line is open. Evan Richert – Sidoti: Good morning guys.

Good morning, Evan. Evan Richert – Sidoti: Obviously some good results in the last couple of wells you’ve drilled; I noticed in the press release you talked about Contango drilling outside your AMI right now. What’s your sense for their plans? I don’t know how much you communicate but beyond the end of 2014 how much they plan on drilling in your shared acreage?

We haven’t talked to them about 2015 but obviously with these types of results they like them as well as we do. And I would anticipate that we would keep that rig throughout the remainder of 2015 as well. Evan Richert – Sidoti: Okay. And then being that you have a lot of production coming on but you also have no wells being drilled with Contango at the moment, Is it your sense that 2013 or third quarter production would be sequentially down from the second quarter or do you think wells being added mid quarter of Q2 will be enough to offset the natural decline?

I anticipate we’re going to have a slight increase for the third quarter production mainly because that number 20 well didn’t come on until late in the quarter. And it appears to have very similar results to that number 17 well which was very strong - it has been and is a very strong well for us. Evan Richert – Sidoti: And then as far as the asset sales go, is there any other acreage you’re open to kind of spinning off right now or what are your thoughts on that?

We anticipate keeping all the acreage that we have currently, we had that opportunity to sell the small acreage position, we just felt like the value was there and we went ahead and pulled the trigger on it, but we’re not looking to sell additional acreage at this time. Evan Richert – Sidoti: Okay, fair enough. And then last question from me and I’ll hop back in the queue. What are your thoughts on possibly taking an operating role at some point in 2015, is that something you’re considering or you’re happy with the role you’re in now?

No, we are looking at acquiring acreage both in Texas and North Dakota for our own account and operating it at some point. Evan Richert – Sidoti: Okay, that’s it. Thanks guys.

Thanks, Evan.

[Operator Instructions] Our next question comes from the line of George Gaspar, private investor. Your line is open.

Yes, thank you. Keith, looking at the net number for the June exit point and what you did for the second quarter in total, this sale of the assets in Williston now, will there be a drawdown in the third quarter from that sale or was that executed in such a manner that the deduct was done totally in the second quarter, for the sale?

It’s done. Those averages were after the sale, George, especially for the June production.

Okay, so effectively would there have been production in there from that sale in April and May?

Yes, there would have been.

So we get - just looking at trying to come up with a number there, there would have to be a deduct in the third quarter before adding the add-ons that are coming your way overall in particularly the Buda?

That’s correct.

Okay, all right. And then you should have some pretty good uplift in the third quarter from the Buda because you got one well that’s not included with pretty good flow and you got a well previously that was included in your June period but that was only for a couple of weeks. So, that didn’t really get related on a quarterly total basis. So I assume that there is some, potentially, some pretty decent momentum here. Am I judging that correctly?

I think that you are. We anticipate an uptick. I can’t tell you exactly what it’s going to be but in my opinion it’s going to be better than the second quarter.

Okay. And then in the drilling in the Buda going on now, are you continuing to do just open hole? I know you’re doing lat growth and you’re going out longer periods. Are you actually piping on the lateral to any extent in any of these most recent wells? Can you identify that?

In the Booth Tortuga area we have only done one, we’ve only run the pipe in one and that was the number 8. All the rest have been open hole stimulations.

I see, okay, and that’s the continuing process and actually you’re still continuing - so you’re going out further on your laterals and there is still consistency in completing on a open hole basis and getting those flows coming back?

That’s correct. And again as I mentioned earlier George the 9,000 foot lateral, so we have more of a chance that these natural factures in it, it’s bearing out that we apparently are because the well’s performance are bearing testimony to that.

I see, okay, all right. And then in terms of the going forward process in the wells that you have yet this year with Contango and the partnership, where are you looking at those being positioned more to the west or south of the configuration of where you’ve been drilling through the number 20?

Actually the number 20 was quite a bit west. The additional wells that I’ve seen now are in between that number 6 well which is an outstanding well and the number 20, so we are kind of infilling if you will.

I got you, okay, so that’s your target for the remainder of the year in terms of that partnership then.

That’s correct. There could be some changes that need to be made because a lot of things - the dealer ranch has hunting restrictions that’s start in about a month. And they have to move some locations because of that.

I see, okay, all right, and then one question on shares outstanding; I noticed that in the release that you did the number shares out for the three months ended June on a year-to-year basis is up 555,000. Can you identify where all those shares went in terms of the increase in share count?

Those were option exercises.

So totally option exercises?

Predominantly, yes.

Okay, all right, thank you.

Okay, thank you George. Operator: There are no further questions at this time. This concludes today’s conference call. You may now all disconnect.