Reggie Larsen – Director of Investor Relations Keith G. Larsen – Chairman and Chief Executive Officer Steven D. Richmond – Chief Financial Officer Mark J. Larsen – President and Chief Operating Officer

Jeffrey R. Connolly – Brean Capital, LLC Noel A. Parks – Ladenburg Thalmann Securities Curtis R. Trimble – Global Hunter Securities LLC

Good day ladies and gentlemen and welcome to the U.S. Energy Corp. Second Quarter 2013 highlights and financial results conference call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this conference call is being recorded. I would now like to introduce your host for today’s conference, Reg Larsen, Director of Investor Relations. Please begin.

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, and Steve Richmond, the company’s Chief Financial Officer. In terms of the agenda, Keith will provide you with an overview of the highlights and operating initiatives for the three and six months ended June 30, 2013. Steve will then conduct the financial review portion of the call, and we will finish up 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 maybe 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, 2013, which we filed yesterday and our other filings with the SEC, all of which are incorporated herein by reference. I’d now like to turn the call over to Keith Larsen. Keith G. Larsen: Thanks Reg, good morning everybody. To begin today’s call, I would like to first thank the audience for attending our conference call and for following the company’s progress at midyear point of 2013. I am pleased to report that the company recorded a net income after taxes of $573,000 or $0.02 per share during the quarter-end at June 30. During the quarter, the company produced 101,026 barrels of oil equivalents, which is an average of 1,110 barrels of oil equivalent per day nets of the company. This production comes from 92 gross, 15.76 net producing wells, primarily located in the Williston Basin of North Dakota. The company recognized revenues from oil and gas production of $15.8 million during the first six months of 2013 and had working capital of $12.8 million at quarter’s end. Moving on to our oil and gas initiatives, as many of you may know, we have recently moved the focus of our South Texas drilling program with Crimson Exploration from developing the Eagle Ford shale, to testing and developing the Buda Limestone formation. The company currently participates in approximately 10,140 gross acres in the Booth Tortuga acreage block in Dimmit County, which are perspective for the Buda Limestone formation. In addition, the company also participates in 3,443 gross acres in the Leona River acreage block in Zavala County. Both areas are also perspective for the Eagle Ford shale, Austin Chalk and, Pearsall and Georgetown formations. The company has an approximate 30% working interest and a 22.8% net revenue interest in each acreage position. Early in 2013, favorable production results were obtained from operators adjacent to the Booth-Tortuga acreage block. These results prompted the operator to propose and drill our first Buda Limestone test well, the Beeler #2H well, which is a spud in April 2013 and begin producing in May 2013. Well was drilled to a total measured depth of 11,013 feet, including an 3,700 foot lateral. Well was completed open hole without fracture stimulation and has an initial production rate of 859 gross barrels of oil equivalent per day. The well has since produced approximately 57,500 gross BOE during the first 83 days of production which is the last reported data, or an average of 693 gross BOE per day. During July, the well averaged approximately 597 gross BOE per day. The well has clearly demonstrated a superior economic return today based on a $3.75 million AFE. Based upon the results from Beeler #2H well, the operators now contract as a drilling rig and has notified the company that they anticipate utilizing rig to drill the Buda Limestone wells throughout 2013. In this regard, the Beeler #2H well was start on August 3, and is currently being drilled at a depth of 3,300 feet. The well is anticipated to be completed nearly September, on completion the rig will mobilize for the next well site and begin drilling the Beeler #4H well. We are very pleased with this development, but caution the listeners that future drilling results are hard to predict. At this point mean time we’ll remain cautiously optimistic about this drilling program in Texas and look forward to providing further updates as more wells are drilled. We expect to report our drilling results from the 3H well in the mid to late September. Now I’ll move on to the Williston Basin, in North Dakota, we participate in 65 1280 acre drilling units in the Basin under three active programs. At June 30, 2013, we have 74 gross, a 11.02 net producing wells and 10 gross 0.18 net wells being drilled or waiting completion. At the quarter’s end, we are producing approximately 932 net BOE per day from the second of our business, which is the majority of our production profile and is primarily oil. We continue to participate in the drilling and completion of new wells in the basin on a smaller lower risk basis in order to maintain our stabilized base production from this region. I will now turn to Mount Emmons Molybdenum Project located in Gunnison County, Colorado. During this quarter, on April 22, 2013, the Company received a letter from the U.S. Forest Service notifying the Company that it had completed a review of the Mine Plan of Operations for the Mount Emmons Molybdenum Project in Colorado and that it has determined that the Mine Plan of Operations does contain sufficient information and clarity to form the basis for a proposed action to initiate scoping and analysis under the National Environmental Policy Act, NEPA. The letter also states, U.S. Energy has met the requirements of the Reality Check provision granting conditional water rights for the Mount Emmons Molybdenum Project by filing the plan for the Mount Emmons mine with the Forest Service. No other special use permits or rights-of-way for the water facilities are required because they are addressed in the plan. The MPO provides an in-depth description of the proposed construction, mining, processing, and reclamation operations for the project. The Company recently initiated a scoping analysis of the MPO with the U.S. Forest Service and anticipates that such work will continue through the balance of 2013 while we continue to work towards our goal of monetizing the project outright such that we can focus solely on oil and gas development. I’d like to now turn the call over to Steve Richmond, the company’s Chief Financial Officer to review the financial portion of the call. Steven D. Richmond: Thank you, Keith. During the quarter ended June 30, 2013, we recorded net income of $573,000 after taxes, or $0.02 per share as compared to a loss after taxes of $990,000, or $0.04 per share for the quarter ended June 30, 2012. Operating revenues for the quarter decreased by $607,000 to $7.9 million as compared to revenues of $8.5 million during the quarter ended June 30, 2012. The decrease in operating revenue was primarily due to lower oil and gas sales volumes in 2013 as compared to 2012. Our average realized price for the quarter ended June 30, 2013 improved to $78.35 per BOE from $71.74 per BOE during the second quarter of 2012. Lease operating expense per BOE including work over cost was $17.47 per BOE for the quarter ended June 30, 2013. This rate compares to $13.72 per BOE for the same period in 2012. Our DD&A rate was approximately $31.80 per BOE for the quarter ended June 30, 2013 compared to $33.92 per BOE in 2012. Looking at the six months ended June 30, 2013, we’ve reported a net loss of $5.9 million after taxes or $0.19 per share as compared to a net loss after taxes of $1.4 million or $0.05 per share for the six months ended June 30, 2012. Our 2013 earnings were negatively impacted by a $5.8 million non-cash ceiling test write down on our oil and gas assets that we took in the first quarter of 2013. During the six months ended June 30, 2013, operating revenues decreased by $1.1 million to $15.8 million as compared to revenues of $16.9 million during the six months ended June 30, 2012. The decrease in operating revenue was primarily due to lower oil and natural gas sales volumes in 2013 as compared to 2012. Our average realized price for the six months ended June 30, 2013 improved to $79.09 per BOE from $73.03 per BOE during the same period in 2012. Lease operating expense per BOE including work over cost was $18.68 per BOE for the six months ended June 30, 2013. This rate compares to $15.77 per BOE for the same period of 2012. Our DD&A rate was approximately $33.42 per BOE for the six months ended June 30, 2013 compared to $33.23 per BOE in the first six months of 2012. We continue to focus on cutting our costs and as a result general and administrative costs were $441,000 lower during the three months ended June 30, 2013 as compared to the same period in 2012. G&A costs were $1 million lower in the six months ended June 30, 2013 as compared to the first six months of 2012. In the financial and operational release that went out yesterday we presented a modified EBIDTAX table showing earnings before interest, income taxes, 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. We use this non-GAAP measure internally to manage our business and believe it is a valuable tool in measuring operating performance. Earnings before modified EBITDAX was $8 million for the six months ended June 30, 2013, which is a 33% increase over the modified EBITDAX of $7.1 million for the same period in 2012. Through our hedging program, we have hedged 600 barrels of oil per day through June 30, 2014 using costless collars. Our weighted average core price for July 1, 2013 through June 30, 2014 is $90.42 per barrel and a weighted average ceiling price is $98.40 per barrel. On March 5, 2013, the Company entered into a purchase and sale agreement with an undisclosed buyer to sell its Remington Village apartment complex located in Gillette, Wyoming for $15 million. The transaction is now anticipated to close on or before September 20, 2013 subject to due diligence and the purchaser’s ability to obtain an acceptable loan commitment for the proposed acquisition of the property. Finally, at June 30, 2013, we remain in good position to fund our forward drilling programs with $4.1 million in cash and cash equivalents, working capital of $12.8 million and $15 million in borrowing capacity remaining under our $25 million line of credit with Wells Fargo. I’d now like to turn the call back over to Keith Larsen for the Q&A session. Keith G. Larsen: That concludes our prepared remarks for today. Operator, would you begin the Q&A please?

(Operator Instructions) Our first question comes from Jeffrey Connolly of Brean Capital. Your line is now open. Jeffrey R. Connolly – Brean Capital, LLC: Hey, good afternoon guys. Keith G. Larsen: Hey Jeff. Steven D. Richmond: Hi Jeff. Jeffrey R. Connolly – Brean Capital, LLC: First question is, does the success of the Buda change your view on Bakken acquisitions when it comes to CapEx this year? Keith G. Larsen: Jeff, we are still looking at some acquisitions, some small acquisitions and we are looking at spending somewhere in the neighborhood of 35,000 to 50,000 flowing barrels and if we can see those type of opportunities in the Williston Basin and we will go after those, but other than that, the economics down on the Buda look much, much better than the Bakken or quite frankly anything that we have participated in so far. Jeffrey R. Connolly – Brean Capital, LLC: Okay, great. And can you just give us or just tell us how the spud to spud and spud to first production times work down in the Buda? Keith G. Larsen: Yes, we’d like to get at least 15, maybe 30 days of production just so we have a good handle, but spud to spud, it looks like it’s going to be about three weeks to four weeks. So we start the well on the 3 and I would expect we will be operating the well by the first of September and onto the next one. Jeffrey R. Connolly – Brean Capital, LLC: So we are looking at about four or five wells down the Buda for the remainder of the year? Keith G. Larsen: That’s what it looks like right now, barring any mechanical or unseen problem, but we are expecting at least four or maybe five. Jeffrey R. Connolly – Brean Capital, LLC: All right. That’s it from me. Thanks guys. Keith G. Larsen: Thanks Jeff.

Thank you. Our next question comes from Noel Parks of Ladenburg Thalmann. Your line is now open. Noel A. Parks – Ladenburg Thalmann Securities: Good morning. Keith G. Larsen: Good morning, Noel. Noel A. Parks – Ladenburg Thalmann Securities: I am just curious, in the Buda, I am not that aware of what other folks are doing around there. Are there any other flow through opportunities that are getting similar results or that will further around in drilling that you have been able to get a look at the data from? Keith G. Larsen: There have Noel, in fact I am going to present at Enercom next Wednesday and we will put up a slide that shows some of the cumulative production from offsetting wells, but pretty much they started late last year, Dan Hughes company, a private company and Sage, another private company have been drilling mainly to the east service and somewhat to the south of it. And for instance, a couple of the wells have tuned like in six months a 150,000 barrels, so that was really the reason we started this program, was the offsetting wells and either offline or you can take a look at our presentation, and I will show you some of those results from of those wells. Noel A. Parks – Ladenburg Thalmann Securities: Great, I will look forward to it. And to the degree that the area is now getting more attention. You’ve talked about Leona River having Eagle Ford and some of the other packets as well. It’s been interesting. I think of Swift Energy, for example, which is in to Central Louisiana, East Texas region. Baird announced on their call that they were actually planning to get rid of a couple of big Austin Chalk deals that were doing pretty well, but I guess with some new developments, but pretty costly. So I was wondering do you see, other than the flow, do you see other people getting busy near Leona River same thing in the other formation? Keith G. Larsen: We don’t. We do see some activity in the (inaudible) nat area and it looks like it’s coming to water. So we’re encouraged by some of those results, but we haven’t seen a lot of good activity up that part north? Noel A. Parks – Ladenburg Thalmann Securities: Okay. With Chesapeake? Keith G. Larsen: Yeah, mainly up there, Noel, it’s Chesapeake has got a large acreage position and they have been developing in a lot of the Eagle Ford wells in that area. Noel A. Parks – Ladenburg Thalmann Securities: Okay, great. I think that’s it for me. Thanks. Keith G. Larsen: Okay. Thanks Noel.

Thank you. Our next question comes from Curtis Trimble of Global Hunter. Your line is now open. Curtis R. Trimble – Global Hunter Securities LLC: Good morning, everyone. Keith G. Larsen: Good morning. Curtis R. Trimble – Global Hunter Securities LLC: Just kind of pursuing this Buda a little bit and with a mapping play more ratably if you will. Keith you’ve talked about potential number of locations inside the one room you might have. Keith G. Larsen: It looks like on a 320 acre spacing we’ve got room for 25, 30 wells. Curtis R. Trimble – Global Hunter Securities LLC: And any idea how many of those maybe offset by some of the induced activity and maybe you got a little bit more confidence that one of those locations or handful of locations work a little bit more than the other locations. Keith G. Larsen: Probably the less we gave us four spuds before we drill the first well, and they gave us a PV10 of $3.5 million on all four of those PUDs and they are in close vicinity to the eastern border of our acreage position. And of course that’s where we’re starting our drilling program. Curtis R. Trimble – Global Hunter Securities LLC: And then, in terms of ASC flow out of the Bakken, have you seen much in the way of changes that have been fairly steady as those kind of work to layout from the wet May-June weather? Keith G. Larsen: Too steady and disappointing as well. In fact, it’s my opinion some of our lower EUR units are going to wait to be drilled until those prices come down substantially, but we’re seeing our operators focusing on now is on our largest EURs, the $500,000 plus EUR locations. The costs are I think they’re staying consistent somewhere in $10.5 million to $11.5 million. Curtis R. Trimble – Global Hunter Securities LLC: Great. Appreciate it. Keith G. Larsen: Okay. Thank you.

Thank you. Our next question comes from [George Gasper], a private investor. Your line is now open.

Yes, good morning. Keith G. Larsen: Good morning, George.

First thing, could you give us a benchmark on what substantial Buda revenue stream was in that $7.9 million for the second quarter? Steven D. Richmond: Do we have an idea? It’s Steve. We had only production of a little bit in May and then all of the month of June.

Great. To Keith, can you come up with a number on it? Keith G. Larsen: About 800,000 to 900,000 in those two months.

800,000 to 900,000, okay. And the current drilling that’s going on in the 3H, is that from the same location that you drill the H2 well and where might you be looking to go on the next well after? Keith G. Larsen: It is, George, from the same location. We actually drilled to the Southwest and again that was offsetting a couple of wells, the (inaudible) well, and it is from the same locations that it will be drilling to the northwest, directly to the southeast? Mark J. Larsen: Yeah, southeast. Keith G. Larsen: The first one was to the southeast and all of these wells that we have seen are oriented from the northwest to the southeast. So in that location, we will go up and again it’s about 3800 foot lateral and then we will move over two locations to the west and we will drill another one to the northwest and we believe that if we are successful in that well as well as one we’re drilling now that we will pickup additional spud locations.

I see. So basically then the rig will move to initiate the next well? Keith G. Larsen: That is correct.

Okay. And can you give us some reference on what you’re seeing in the area from the other companies that private otherwise that have been particularly for drilling into the east (inaudible), is there anything going on in and around the acreage that you have? Keith G. Larsen: Yes. I will just name a few. The cumulative production from the Heitz 303 #2H which is east of it is 180,000, the Heitz 302 #3H as cumulative and which is right adjacent to it is 215,000. The Heitz 302 #5 125,000, Heitz #1H is a $144,000. Keith G. Larsen: All of those George are immediately to the east of us. One I mentioned, 215,000 actually adjoins write-up against the acreage position in the eastern boundary of our acreage.

Thank you. Okay, and in terms of lifting, so your strategy would be to look south and west somewhere you’re located now to engage just following on with your comment made about the possibility of drilling through your four wells by the end of the year, would that be the South Texas going west and south? Steven D. Richmond: West and south, that’s correct.

I see, okay, all right. Based on the cost structure assuming and tell me if I’m wrong, assuming that this open hole process is in less than $3.5 million, and it would seem that and if that’s correct, your return on investment is potentially close at hand on the first well. Can you make any comments on that? Keith G. Larsen: We expect that during the fourth month of production, we will get all our money back for drilling completion.

Oh, okay, all right. Okay, thank you. Keith G. Larsen: Okay, thanks George.

Thank you. (Operator Instructions) And we do have a follow-up from [George Gaspar], a Private Investor.

Okay, thank you. Keith, the comments that you made on the moly project across the deal. The process is elongated obviously to get this up and running in terms of some type of actual development. Can you scope us some kind of roundabout target date that you might be looking at to conclude this environmental impact totally and exclude that for somebody to really initiate a serious interest about going forward what’s from an operational point of view on the development? Keith G. Larsen: Well, first of all I think we have progressed the two appoints where we do have serious people looking on it. But to answer your other question, George the Forest Service that we’re working was down there. They don’t have a specialist that has done a large mining project like this one. And so what we are doing, what we asking them to do, is to consider hiring somebody that has done one, that has worked down one. So they are familiar with all of the twists and turns that come with one of these environmental impact statements.

All right. Keith G. Larsen: Our next meeting is scheduled in October with them. It’s the government saying when the sequester is something they don’t do anything from about June until October and we plan on meeting with them in October and discussing, finalizing, bringing somebody and of course we are going to pay that person salary when they work on our project. Bring that person in and the next step would be a scoping analysis that we’ll do with public comments and then to answer your question wholly, I’m looking at three-year to four-year timeframe to get this thing wholly permitted.

All right. And then I got one technical question on North Dakota. Just kind of running the talk about declining curves, you’ve had some experience and therefore went a good three years possibly. Keith G. Larsen: Four years now.

Four years now. If you look that your [curvy] engagements on what’s drilled with the original agreement with Brigham and ongoing, could you just inside the decline curve (inaudible) let’s say an average initial well, and what you might be doing today versus, let’s say, if you looked at it nine months after the initial IP, and now you would have potentially as much as maybe two years of experience beyond that. What are the flow rates looking right now, versus to the point of the initial declining curve and then off of the IP rates? Keith G. Larsen: Well, I think there is a lot of industry data out there, George and I’m not an engineer, but what we’ve seen, in my experience is about a 90% decline in the first year, but you got a 2,000 barrel IP at the end of the year. It’s probably going to be doing somewhere in the neighborhood of 150 barrels to 200 barrels, and surprisingly most of our (inaudible) wells today are doing 100 to 150 barrels a day. So the decline after the first year, call it two years seems to be very, very small. Now there is a lot of factors that play into that, work overs and replacement of pumps and water jobs. We flush some fresh water down into the wells, because they have salt problems. We try to dilute that salt because of scaling on some of the tubing and most type of things. But basically most of our wells that I’ve looked at recently of that have the advantage of two year spuds are doing somewhere between 100,000 and 150,000 barrels a day.

Okay. All right. And does that historical stock prices that you’ve got some good experience I know, does that get to be a real challenge looking at the, you mentioned like 9 million or 9.5 million or 10 million, 11 million a well. Is that becoming more of an obstacle? Mark J. Larsen: It certainly is. I think George, and I’ve talked about this before. The first well we drilled was Brigham in October of 2009. It was a 28 stage, 10,000 foot lateral and again it was a good well, with that also number one, but it cost us $6.25 million, that was the AFP and it came it at the AFP, but same may be a few more stages up to 35 or things what we’re doing now. As I mentioned they’re running $10 million or $11 million.

Okay. Keith G. Larsen: Some of the areas that we drilled and have the lower EUR say 250,000 the economics look pretty scanty and I think it’s evidenced by our operators and they are going to our higher EUR which basically is to the south and east of the Missouri river.

Okay, all right, and well that’s interesting data and any thoughts on your Montana improving at this point in time. Keith G. Larsen: Well, right now they have to drill a well before the end of 2015, the people we saw the least. Apache has been active up, there all over it’s been very quite. I’ve had our PR team will call them and I said they are very tight lipped about the area and they don’t have any future drilling plans. So if that means that they are acquiring more leases and are holding the information clause or that they didn’t get good results I don’t know.

Okay. Well, it’s a good idea. I appreciate the data and I can understand it with your relating as the enthusiasm that you all have on Buda and hopefully it will continue to transpire on the positive as you moving forward, because it looks like the economics, just assuming that production rates can hold at a reasonable level relative to the cost structure. This could look like a real interesting place for you to be. Thank you. Keith G. Larsen: Thank you, George. And just kind of further in addition we’re looking for additional opportunities in this entire area. We think there is additional potential opportunities in the Buda. Although, we’d like to see some additional results like we’ve got in the first well.

Thank you. At this time I am not showing any further question. So I’d like to turn the call back to Mr. Keith Larsen for closing comments. Keith G. Larsen: Yeah, I would like to once again thank our audience for joining us today. We look forward to providing next update in the coming weeks. In particular we are looking forward to obtaining and evaluating the results from our next dealer well in South Texas and continuing to draw through the balance of the year. The success of the next well could be a turning point for this program and has the potentially to greatly impact our daily production revenue and opportunities for growth in the oil and gas segment of our business. Thank you operator.

Thank you. Ladies and gentlemen, thank you for participating in today’s conference. This does conclude today’s programs. You may all disconnect. Everyone have a wonderful day.