Reggie Larsen - Director of Investor Relations Keith Larsen - Chief Executive Officer Steve Richmond - Chief Financial Officer Mark Larsen - President and COO

Noel Parks - Ladenburg Thalmann Evan Richert - Sidoti & Company Mike Jacobson - Oak Ridge Financial Patrick Rigamer - Global Hunter Securities

Good morning. My name is Danielle, and I will be your conference operator today. At this time, I would like to welcome everyone to the U.S. Energy Corp First 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 an agenda for the call, Keith will provide you with an overview of our highlights, financial results and operating initiatives for quarter ended March 31, 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 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 March 31, 2014, which we filed on Friday, May 9, 2014, 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 website which is located at www.usnrg.com. I'd now like to turn the call over to Keith.

Thank you Reggie. To begin today's call, I'd first like to thank the audience for attending our conference call and for following the company's progress during the first three months of 2014, which have been active on several fronts. During the three months ended March 31, 2014 the company produced 105,093 barrels of oil equivalent which is an average of 1,168 net BOE per day. This production comes from 123 gross or 17.5 net wells primarily located in the Williston Basin of North Dakota and South Texas. As a result the company recognized 8.3 million in revenues during the quarter as compared to 7.9 million during the same period of prior year. The $377,000 increase is primarily due to higher oil and gas sales volumes when compared to the same period of the prior year. During the quarter we recorded net income after taxes of $250,000 or $0.01 per share basic and diluted. Looking ahead we remain in a good position to fund our forward drilling programs on March 31, 2014 we had $2.5 million in cash and cash equivalents and additional $14 million in borrowing capacity under our $25 million line of credit with Wells Fargo. Subsequent to the quarter end we have drawn an additional $6 million to fund an 800 gross, 60 net acre AMI election and acreage immediately adjoining the Booth-Tortuga acreage block as well as our recently announced 12,100 gross acreage Dimmit County acquisition. This [draw] leaves our remaining borrowing capacity at $8 million currently we anticipate adding an additional $1.5 million of capacity based on our year end reserve report during our semi-annual redetermination which is anticipated to be finalized this week. During the quarter we received an average of $2.8 million per month from our producing wells with an average operating cost of $417,000 per month including work over cost and production taxes of $241,000 for average net cash flows of $2.1 million per month from oil and gas production before net non-cash depletion expense. From the financial and operational release that was published on Friday May 9, which is available on our website, we presented and 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 $4.1 million for the quarter ending March 31, 2014. 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 County and our drilling programs with several operators in the Williston Basin. In South Texas, the company now participates in approximately 34,500 gross, 9,000 net acres in Zavala and Dimmit Counties, a 58% increase in net acreage as compared to year end 2013. As previously mentioned, the increased figures come through an AMI election of an additional 800 gross r 60 net acres, immediately joining the Booth-Tortuga acreage block as well as our recently announced 12,100 gross 3,384 net acre Dimmit County acquisition. In the Booth-Tortuga acreage block located in both Zavala and Dimmit County, Texas, the company has an approximate 30% working interest and approximate 22.5% net revenue interest and approximately 13,114 gross or 35,61 net acres. Full time rig is contracted is to drill wells in succession during the balance of 2014, contingent upon continued success of the program. During the quarter, we completed the drilling of the number 6, number 7 and number 8 wells. Beeler number 6 well has an initial production rate of 1,185 gross BOE per day that was 91% oil and the 30 day average production rate of 778 gross BOE per day. Beeler number 7 well had an initial production rate of 440 gross BOE per day, 90% oil and a 30 day average production rate of 187 gross BOE per day. Beeler number 8 well had an initial production rate of 886 gross BOE per day, again 91% oil and a 30 day average production rate of 347 gross BOE per day. Subsequent to the quarter’s end Contango completed the Beeler number 5 and the Beeler number 9 wells. Both wells commenced production in late April; initial flow rates are currently being monitored. As this program is now matured from the initial testing stage with 9 gross wells drill to-date, we have made an election to only published production rates once 30 days of data has been evaluated. We believe this is more accurate measure of an individual wells production profile and has a more meaningful data point for investors. The Beeler number 16 well was spud on April 18, 2014. The well was drilled to the vertical depth of approximately 7,000 feet at an approximate 4,000 foot lateral. Upon the completion of the drilling of the first lateral, the operator elected to come back to the heel of the well and sidetrack and drill an additional approximate 4,000 foot lateral. Both laterals are currently being completed naturally without fracture stimulation. Beeler number 17 well, which is located directly to the south of the Beeler number 16 well scheduled to spud this rig. Beeler number 10 and Beeler number 20 wells are anticipated to be spud in early June and late June, respectively. On May 7, 2014, under an Area of Mutual Interest Election, the company acquired a 7.5% working interest in an additional 800 gross, 60 net acres in the Booth-Tortuga prospect. This acreage is offered through and is operated by a private Texas-based company. The first well to be drilled on the acreage, the Bruce Weaver number 2 well, will target the Buda formation and is scheduled to spud in late May. The acreage block lies between the Beeler number 16 and the Beeler number 9 well locations. Now moving on to our Big Wells prospect which is contiguous to the Southwestern portion of the Booth-Tortuga acreage block. The company has a 15% working interest, 11.25% NRI and 4,243 gross or 636 net acres from U.S. Intercorp, a private oil and gas company based in San Antonio, Texas. The second Buda formation well on this acreage, the Willerson number 2 well was spud in early February 2014. The well was completed open hole without fracture stimulation and commenced production in the first week of March. The well had initial production rate of 634 gross BOE per day and that was 72% oil and had a 30-day average production rate of 179 gross barrels of oil equivalent per day. The operator plans to monitor the production from both wells in the acreage block before additional development plans are made. I'll now move onto our Dimmit County acquisition, which was announced via press release on Thursday May 8th. Under the agreement, the company acquired 33% of the seller's interest in approximately 12,100 gross or 3,384 net acres. The acreage consists of primary lease hole to acreage and farm-in acreage to be earned through a continuous drilling program. The farm-in acreage initial two well commitments and a 12.5% working interest carry for 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 to its 12.5% retained working interest in the prospect. The seller also retained a 25% working interest backed in after 115% of project payout has been received by the company. The company paid $3.9 million to enter into the transaction, which includes leasehold and farm-in acquisition costs, as well as our proportionate share of drilling costs for the initial test wells in the prospect. A minimum of three Buda formation wells are scheduled to be drilled during the balance of 2014. The first well in the program spud the week of May 5th and is currently drilling in the vertical portion of the wellbore. As additional leasing in farm-in opportunities are still being pursued, we do not plan to identify the location of the prospect or the wells by name until drawing results and additional leasing results won’t further disclose you. In summary, we continue to refine our focus on this [regime] of South Texas due to the potential of the Buda formation, as well as the additional multiple stack hydrocarbon-bearing formations that are present. In addition, down spacing and fracture stimulation of the Buda formation and other formation development in each prospect may enhance the oil and gas reserve potential. Now I’ll move on to the Williston Basin of North Dakota. We participate in 65 1,280 acre spacing units in the basin with numerous operators. And at the quarter’s end we had 97 drills 10.6 net producing wells and 13 drills 0.22 net wells being drilled or awaiting completion. Subsequent to the quarter’s end, four of the gross wells were pending completion at quarter’s end are now producing and three gross wells are currently being completed to be turned over to production. During the three months ended March 31, 2014, we averaged approximately 679 net BOE per day from this segment of our business which was negatively impacted by winter weather-related issues in the basin during the quarter. We’re now beginning to see improvement in this area as we enter into the spring months and things begin to full better from an operational standpoint. We 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. To close out the operation’s portion of the call, I’d also like to mention that the company deploys the risk management strategy covering our oil and gas production through its hedging program. Currently, we’ve had 600 barrels of oil per day through 2014 using costless collars. Our weighted average core price for the second through fourth quarters of 2014 is $90 per barrel and our weighted average ceiling price is $97.31. Before moving on to the question-and-answer portion of today’s call, I’d also like to highlight a few additional points of progress which have been made early in 2014. While we continue to develop our portfolio of assets in North Dakota with our partners, we have also refined our focus on acquiring and developing oil and gas assets in South Texas and we believe that this area will continue to be a growth catalyst for the company and shareholders in both the short and long-term. We continue to evaluate our production in field data and we are learning more from a regional perspective on a daily basis. With this information in hand, we elected into an additional partial through an AMI election last week and also announced our Dimmit County acquisition, which we believe has a probability of success based upon our technical evaluation of the acreage. With these recent developments, we expect to have three rigs drilling by late May targeting the Buda formation. I would also emphasize the multiple stack pay nature of this area as we believe that there is a potential for additional development on a going forward basis. Additionally we recently hired a full time lineman with eight years of experience in leasing in South Texas. He has spent the last four years actively leasing and developing both industry and private relationships in our target areas in and around Zavala and Dimmit Counties. We plan to fully utilize his understanding of this area to continue to grow our acreage and development portfolio. That being said, we will continue to manage our balance sheet and drilling commitments with a goal increasing production, reserves, revenue and cash flow from operations with the ultimate goal of driving growth and profitability for the company’s shareholders. And finally I would like to mention that we have identified the top 20 producing counties in the U.S. which account for 52% of our oil production and 20% of our gas production. U.S. Energy has significantly involved in the number five ranked county, McKenzie and North Dakota, the number six ranked county Mountrail and North Dakota, the number 12 ranked country Williams and North Dakota and finally the number 14 ranked and that’s Dimmit and Texas. We believe we can expand our presence in these areas and our focus will be geared towards these areas as we strive to add to our production profile of reserves. That concludes our prepared remarks for today. Operator, would you begin the Q&A session now please.

Yes sir. (Operator Instructions) And your first question comes from the line of Noel Parks of Ladenburg Thalmann. Please go ahead. Noel Parks - Ladenburg Thalmann: Good morning. Can you hear me?

Yes. Good morning, Noel. Noel Parks - Ladenburg Thalmann: Hey, I was just curious, what are you thinking out in as far as alternate or deeper formations in East Texas at this point, that’s only been expanding the drilling inventories, so I was just wondering if it’s going to be essentially just Buda from here on or you are thinking about in the near-term that is targeted some other formation?

Noel as you could imagine, we are getting lots of several formations as we are going down for the Buda. And as well the Georgetown sits directly below the Buda and we got the Eagle Ford potential, the Austin Chalk, the Edwards and all of those are being analyzed and look like looked at as we are drilling the Buda. We are getting some gas kicks and getting some interesting data I suppose would be the best way to put it right now. But in the immediate short-term it’s basically the Buda. And then if we get interesting looks then our operators have indicated that they are open to going out and testing some of these other formations. Noel Parks - Ladenburg Thalmann: Okay. And you described one of the wells where one laterals is drilled and then the operator went back and I guess just kicked up in the opposite direction and did an additional lateral. Is that a practical way to look at development going forward or is that just a situation that you have a particular reason to accommodate that?

Well, my understanding is that was pretty common talk practice in the Austin Chalk and they have pretty good results. Of course if we get very well performing well -- very highly profitable, we are (inaudible) a two lateral in the future. And by the way Noel, it's not in the opposite direction; it's parallel to the first well. Noel Parks - Ladenburg Thalmann: Same direction, but just deeper in the formation or…?

It's not the same depth. Other operator is contained along on this particularly well, believes they know the gamma signature and that's what they follow and basically it's about 20 foot off the bottom of the Buda. Noel Parks - Ladenburg Thalmann: I see, great. And just at this point with various timing agreement and so forth you're looking at, do you have a sense on a net basis looking ahead the next year to roughly where the budget might head. Are we looking at maybe 50% higher going forward if you continue on this track or…?

Certainly those are the goal that we’re shooting for Noel. We don't give guidance on what our production is because of the nature being a non-operator, as well as the early nature of being in the Buda. But certainly our goal here on the company is to increase our production by 50% for the year and to leave the year significantly higher than that on a daily basis. Noel Parks - Ladenburg Thalmann: Great, that's helpful.

Okay. Thank you, Noel. Noel Parks - Ladenburg Thalmann: Thank you.

Thank you. And your next question comes from the line of Evan Richert from Sidoti & Company. Please go ahead. Evan Richert - Sidoti & Company: Good morning, guys.

Good morning, Evan. Evan Richert - Sidoti & Company: Noel asked a couple of my questions, so I was just wondering, I guess to start off your thoughts on production rate so far, I mean I know you bring off [downgrading] Texas now. But would you have expected any more contribution on the Booth-Tortuga and Buda or is this kind of in line with what you were hoping for?

Not quite in line, we thought that we would have some more of our better performing wells, although the wells we have, the numbers speak for themselves. It’s just going to be I believe the statistical pay down there. We’re going to have some better wells and some that are kind of mediocre if you will, as well as we’re a bit disappointed but not that surprised with the slowdown up in North Dakota and the Bakken wells because of the weather up there and the nature of North Dakota in the winter time. Evan Richert - Sidoti & Company: Sure. On that note, what kind of drilling times were you seeing up there during the quarter in the Bakken?

I think they’ve got it down to about 21 to 25 days. Evan Richert - Sidoti & Company: So that wasn’t -- I guess I am just trying to assess the weather impact.

Yes, the drilling wasn’t impacted as much as the completion. Evan Richert - Sidoti & Company: Okay.

As well as they shut several wells then because of flooding. And as you’re probably aware of and they also have road closures in the spring. Evan Richert - Sidoti & Company: Sure.

The roads and those types of things. I think you’ve pretty much seen it across the board with most Bakken players out there; they’ve had a decrease of some 15% to 30% decrease in their production. Evan Richert - Sidoti & Company: Okay. And then just to clarify one thing that left on, I think it was the [16H] that you had the other sidetrack on. That was because you were the operator was pleased with the results not because of the mechanical issue?

It was because they were pleased with the results and because of the speed in which we drilled the first lateral; they are getting better at it, if you will. Evan Richert - Sidoti & Company: Okay.

I would anticipate in the future that we probably will continue this practice especially if we have the type of level we think we have. Evan Richert - Sidoti & Company: Okay. That’s helpful. And then another, you bring on a third rig, I know you have the CapEx budget to that. Do you have a kind of a number in mind on how much you’d expect you go to drilling versus acquisitions in the year?

Pretty much I think that most of our money is going to go towards the drilling now. Evan Richert - Sidoti & Company: Okay. So, now that the recent acquisitions and you just focus on drilling the remainder of the budget?

Pretty much for this year we’re just focused on the drilling. Evan Richert - Sidoti & Company: Okay. And then the AMI you talked on and I think you said hit last week, did any cash changes in that?

Yes. There was about $300,000. Evan Richert - Sidoti & Company: Just 300,000. Okay. That’s it for me. I’ll hope back in the queue.

Okay, thanks Evan.

Thank you. And your next question comes from the line of George Gasper, private investor. Please go ahead.

Yes, good morning.

Good morning George.

First question is regarding again the Buda drilling process. Could you highlight the drilling cost on a per well basis that you’re encountering currently versus where you were initially? And can you highlight also the -- when a lateral is drilled, what’s the additional cost to do that lateral versus the initial penetration horizontal?

Sure. Well your first question was how are the costs looking and we’re very pleased with Contango especially. The first initial costs were around $4 million to $4.5 million, they’ve got to down closer to around $3 million for the completing drilling. And I think it’s split about evenly. Steve, do you get -- about $1.5 million to drill and about $1.5 million to drill the lateral.

So what you’re saying is $1.5 million to drill the vertical portion and then $1.5 million to drill the lateral?

And complete.

And complete, okay. Then the question is ongoing when you drill a second lateral, what kind of cost does that incur in terms of the well costs since you’re already down vertical and just moving over and drilling second horizontal.

George, I don’t want to give you a number that I don’t know. I will have to look into that and if you want, you can call afterwards, I can talk, but I don’t know right now.

Okay. And I know that you answered this in part earlier to a question regarding lateral drilling, you implied that laterals are near parallel, so you are not getting out very far broadening the end point. How close can you get together between laterals and the initial drilling, so that it doesn’t cause pressurization changes in the structure because you are drilling open hole?

Again I don’t have the complete answer to that, but my recollection is the end points or where they land that second lateral is about 1,500 foot away from the first lateral. Of course in the beginning, it’s going to be very close to the first lateral.

Okay. So it would be up to something like 1,500 feet away at the end point?

That’s my recollection.

Got it, okay. Alright. And can you, Keith, regarding the whole area that you are in out there in Dimmit particularly and you have been able to correlate additional acquisitions or the opportunity there; what’s happening in terms of other [companies] in the area, can you identify that is this area becoming more attracted to other drillers and how close in or can you continue to expand your area of opportunity?

Well, I believe that we can’t expand it but to answer to your question, I think there is more interest not only because of us but others that have had success in the Buda and that’s why we were being a little bit close to the rest of this acquisition, we believe there are additional opportunities and we certainly don’t want talk the prices up.

Okay, all right. And one if I could one question on North Dakota, this feeling off in the first quarter, I assume was because of get backs and well were near their total cost outlays and get back was incurred or the decline curves. Now, you have got a lot of small interests in a lot of wells that are drilling, do you think that you can stabilize your current production by the type of drilling you are doing now or potentially even increase the production per day, what’s your thought on that?

Our thoughts are initially and internally is that we plan on maintaining our base production not drilling it, but the additional drilling because of the smaller nature will stabilize that production, a lot of wells we have interested in now are older wells and so the declined profile is much lower than the initial wells, but of course we rely on the flush production from the smaller interest wells to maintain that production base as well. So the answer of the question is to maintain that production of around 700, 800 barrels per day.

Okay, all right, thank you.

Thanks, George.

Thank you. (Operator Instructions). And your next question comes from the line of Mike Jacobson from Oak Ridge Financial. Please go ahead. Mike Jacobson - Oak Ridge Financial: Good morning, gentlemen.

Good morning, Mike. Mike Jacobson - Oak Ridge Financial: Wonder if you could give us an update maybe including time tables regarding the Mount Emmons project?

Sure.

This was Mark Larsen, Michael. Mike Jacobson - Oak Ridge Financial: Hey.

We have continued forward lift with our permitting, we are evaluating our next steps there and of course protecting our water rights along the way. We have also looked at ways to reduce the cost to the holding cost of the water treatments plan (inaudible) water that we treat from the Keystone mine and at the same time we have kept the open discussions or the opportunity for discussions with the town parties for various alternatives on how to monetize that asset. So we are keeping those three activities active and ongoing. Mike Jacobson - Oak Ridge Financial: Okay. What is the next step in the permitting process or is that all set ready to go now?

The next step is to go out and do a water background study and to do that study we have to enter into an EIS and it appears we are still negotiating them with the Forest Service and the time it will take regarding the scope of work that will be entailed in that process that type of decision is going to be made in the next I would say 90 days and that work to begin within that timeframe, as well as continuing the permitting process itself and other items there, it’s a several facetted project as you can imagine so we are monitoring each of the moving parts literally on a daily and weekly basis and we are contacted with Forest Service, our consultants and various agencies frequently. Mike Jacobson - Oak Ridge Financial: Thank you.

Mike, to answer your question the bulk of the work on the permitting will not start until next year because of the EIS on the scope Mark mentioned. Mike Jacobson - Oak Ridge Financial: Got it. So that’s a year or two away?

It is. Mike Jacobson - Oak Ridge Financial: Thanks.

Okay. Thank you, Mike.

Thank you. And your next question comes from the line of Patrick Rigamer from Global Hunter Securities. Please go ahead. Patrick Rigamer - Global Hunter Securities: Hi, good morning guys.

Good morning. Patrick Rigamer - Global Hunter Securities: With the shifting focus to the Buda, just curious if you have kind of an ultimate acreage goal or year-end target on how many acreage you'd like to have there?

I think pretty much what we've got right now, we need to drill and get results of that and see what we have. Patrick Rigamer - Global Hunter Securities: Okay. And then in your presentation show there is the [green press] of economics for the Buda and that's the $4 million well costs. Just curious if you’ve run that analysis at some of these lower costs that we've been seeing in the $3 million range?

We haven't, but before our next presentation we'll have those numbers included and probably some averages that will be add more history now as we know exactly what the EURs and the production profile are for a group of wells and we could be more accurate in our economics. Patrick Rigamer - Global Hunter Securities: Okay. Thank you very much.

Thank you, Patrick.

Thank you. And your next question comes from George Gasper, Private Investor. Please go ahead, sir.

Thank you. Keith, relative to what you targeted for drilling cost for 2014, can you share with us where you might see that total number being for the year now relative to your accomplishment of some additional acreage plays involved that you’ve taken down?

I think we have $12 million budgeted for the Texas acreage and that probably will be bump up somewhere closer to $15 million, $16 million for the year in total.

Okay, all right. And so then for the year in total, if it gets to 15 in the Buda area, what do you envision for the year is that in total?

In total somewhere around $35 million.

35, okay. And are you -- so are you generating -- do you have the capacity right now to generate about $2 [million] a month in terms of the cash flow that’s going back into the drilling?

That’s what we generated for the first three months George, it was little over $2 million I think it was $2.1 million.

On a per month basis?

Per month and as we increased our production profile with the success, the success of what we’re doing down there, we expect that to increase and we’ll exit the year at somewhat higher than that.

I see, okay. Well that’s good. And then on -- you mentioned, you made reference to being interested going forward in some potentially deeper levels below the Buda; is there any -- been able to track any other exploration companies in the general vicinity of the Buda and drilling projects that are going deeper that maybe have taken place more current than in past years, do you have any fix on that at all?

Well the lower formation that I’ve seen people targeting down there is the Pearsall and it’s quite significantly deeper, somewhere around 10,000 foot and there is [no actually] folks there. But we’re more interested in possibly the Georgetown which is directly beneath the Buda in the [efforts] which is significantly above the Austin Chalk.

Okay, all right. Thank you.

Thank you George.

Thank you. And there are no further questions at this time. This concludes today’s conference call. You may now disconnect.