Good morning. My name is Shannon 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 2013 selected highlights, operations, and financial results 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. Reg 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, and Steve Richmond, the company’s Chief Financial Officer. In terms of the agenda, Keith will provide you with an overview of our operating initiatives for the quarter ended March 31, 2013 as well as the period subsequent to quarter end. Steve will then conduct the financial review portion of the call, and we will finish up with the 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 March 31, 2013, which we filed on Friday, May 10, 2013 and our other filings with the SEC, all of which are incorporated herein by reference. I would now like to turn the call over to Keith.

Thanks, Reg and good morning, ladies and gentlemen. At March 31, 2013, the company had participation in 87 gross, 15.3 net producing wells, which include 70 gross Williston Basin wells, 3 gross Gulf Coast wells, 11 gross Austin Chalk wells in our Booth Tortuga prospect, and 3 gross Eagle Ford wells. At March 31, 2013, there were 10 gross, 0.25 net wells being drilled or awaiting completion in the Williston Basin of North Dakota. During the quarter ended March 31, 2013, the company produced 98,674 barrels of oil equivalent, which is an average of 1,096 net barrels of oil equivalent per day. The company recognized revenues from oil and gas production of $7.9 million during the quarter and had working capital, current assets minus current liabilities of $10.4 million at quarter end. Under our $27 million capital expenditures budget for 2013, we’ve spent approximately $5.9 million to fund our oil and gas drilling programs. The remaining $21 million is budgeted to be spent on exploration and acquisition initiatives in the Williston Basin of North Dakota and in Texas on our Buda Limestone development program with Crimson if positive results from both of the first two wells are realized. Our second Buda well is currently scheduled to be drilled in July. Moving on to our oil and gas initiatives under the Statoil development program in the Williston Basin of North Dakota, two gross wells have been drilled and we are awaiting completion at March 31, 2013. Our net investment for this program was $1.1 million during the quarter. Three additional gross wells are scheduled to be drilled during the balance of 2013. During the first three months of 2013 under the Zavanna drilling program in the Williston Basin of North Dakota, we completed three gross wells and drilled five additional gross…

Thank you Keith, during the quarter ended March 31, 2013, we recorded a net loss of $5.9 million after taxes or $0.21 per share as compared to a net loss after taxes of $381,000 for $0.01 per share for the quarter ended March 31, 2012. Our 2013 earnings were negatively impacted by a $5.8 million non-cash ceiling test write down on our oil and gas assets. In the financial and operational release that was published on Friday of last week, 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 that it is a valuable tool in measuring operating performance. Modified EBIDTAX was $4.3 million for the quarter ended March 31, 2013, which is a 33% increase over modified EBIDTAX of $3.2 million for the same period of 2012. Please see our press release for the reconciliation of modified EBITDAX to net income. Similar improvement is reflected in our cash flow from operations which increased by $2.5 million from $764,000 in the first quarter of 2012 to $3.3 million in the first quarter of 2013. During the quarter ended March 31, 2013, our operating revenues decreased by $456,000 to $7.9 million as compared to revenues of $8.3 million during the quarter ended March 31, 2012. The decrease in operating revenue was primarily due to lower oil sales volumes in 2013 as compared to 2012. Our average realized price for the quarter ended March 31, 2013 improved to $79.85 per BOE from $74.40 per BOE during the same period in 2012. Lease operating expense per BOE including work over cost was $19.92 per BOE…

That concludes our prepared remarks for today. Operator, would you begin the Q&A session now please?

Yes sir. (Operator Instructions) Your first question comes from the line of Noel Parks of Ladenburg Thalmann. You may begin.

Good morning.

Good morning Noel.

Just want to ask you about the Buda with the Crimson, Contango deal happening, assuming that they do run the one rig full-time out there, do you have a sense of how much of capital commitment that might involve to the degree that you guys participated going forward?

Initially Noel it looks like these wells if they perform as the first one they are going to be between $3 million and $3.5 million. And I would anticipate that we would be drilling one and may be one and a half wells per day and you are probably aware – or a month I am sorry. And you are probably aware that with Contango’s financial position certainly that was probably a big consideration to have at Crimson. So, we are pleased that they are going to have to budgeting and the financial wherewithal to move it forward.

And just looking at the sort of combined portfolios of the two companies and knowing you have that long relationship with Crimson, are there other areas you think might be possible or interesting for partnering going forward?

Looking closely and monitoring the first [well] [ph] development in the area, several companies are around us drilling into the first [well] [ph], and you have probably heard the same news we have but they look encouraging to us, it’s about 10,000 to 11,000 foot under our acreage position and we are monitoring that as we speak.

Great, that’s it for me.

Okay. Thank you, Noel.

Thank you. Our next question is from Jeffrey Connolly of Brean Capital. You may begin.

Hey, good afternoon and thanks for taking the questions guys.

Hey, Jeff.

If the Buda program ends up ramping up, does the CapEx for that just get shifted from the acquisitions in the Bakken or do you increase CapEx?

I think we could do either depending again on the results. We are still looking for acquisitions but we do have the wherewithal to shift the money over. So, I guess we could do both Jeff.

And can you give us some detail on some of the things that you are seeing that has you very encouraged about the early flow back so far on the Beeler #2 well?

Well, I don’t think it will be fair to Crimson to give the actual numbers. And I also don’t think it would be fair to the shareholders. Once we get a week or two of production, I think it would be better to announce at that time, so I am a little hesitant to put numbers out at this at this point, Jeff.

Okay, good.

But I think it’s indicative that we are going to drill another well in July and we are talking about putting a rig on full time.

Okay. And can you tell us what kind of cost you expect for the NEPA process in Mount Emmons, and what are some of the milestones that we can look forward to, to kind of gauge the progress of the whole project?

First of all, we’ll do a scoping and we’ll do an MoU, Memorandum of Understanding with the Forest Service. And under that process, the Forest Service actually hires an independent contractor to do the environmental impact statement. And under the scoping process, we will be involved with negotiating how much our involvement is with that group, but actually they are working for the Forest Service, and they are an advocate for the Forest Service, and the Forest Service will be an advocate for the final Mine Plan of Operations. Some of the milestones will probably be happening next year. There will be some baseline studies that will be conducted this year again after the scoping is done with the Forest Service, but we will be able to give you more of milestones and activities as we progress and definite dates and estimates, but right now we are still preliminary, because we haven’t done the scoping.

Alright, thank you. I appreciate it. That’s it from me.

Thanks Jeff.

Thank you. Our next question is from Michael Epstein of Northeast Securities. You may begin.

Gentlemen, could you give me a little more background on this impairment charge that you took, so I can better understand it?

Each quarter – this is Steve Richmond. Each quarter, we are required to perform a ceiling test analysis, which compares the cost that we carry in our full cost pool to our PV10, and it excludes our un-evaluated costs. And as a result of that comparison, we recorded the $5.8 million impairment.

Have you done that in prior quarters also?

Yeah, we do it each quarter.

Each quarter? Okay, and it is just a non-cash charge?

It is a non-cash charge.

So, you are writing down your interest in the other wells, is that a fair statement?

Yeah, we are writing down our full cost pool, which we deplete over our reserves.

And what is the bank – how does the bank accept that and does it affect your borrowing power?

Steve you might explain the re-determination.

We see do a re-determination every six months for our line with Wells Fargo. And they run their own price decks through and do their own modeling to come up with their own calculations to determine that. So, they are somewhat related but not directly.

Was this a surprise to the marketplace or is this well-known in the marketplace?

Well, it’s subject to the SEC price of oil, which is certainly a component of the total impairment amount. And so as if as oil prices go down or as that SEC price goes down, one would expect to have an impairment, particularly since we have booked an impairment at 12/31/2012.

I think also just to comment that the price creep up in the Williston Basin, that when the prices get up and you don’t pickup the EURs as expected in some of our more favorable areas, then some of those PUDs will come off. And I think it’s fair to say that a lot of other companies that are up in the Bakken probably ran into the same test and impairment issue.

Thank you, gentlemen.

Thank you.

Thank you. Our next question is from [George Gasper] [ph], a Private Investor. You may begin.

Thank you. Good morning. Question regarding your average price again please for your BOE for the first quarter versus the fourth quarter, can you give me that?

For the first quarter, our average price per BOE was $79.85 and that compared to $74.40 last year.

$74.44?

$74.40 flat.

Okay. Okay, so can you give me an explanation of is the average price is up $5 and you have taken impairment charge in the first quarter generally, aren’t impairment charges associated with lower average pricing, I know that you just made an explanation to a gentlemen. Could you reiterate again with the price accrued up that much in the quarter what was the need to take the impairment charge on that kind of price increase?

The price that is used in the reserve report are the present value analysis, that’s actually the SEC price, which is the first day of month pricing for the prior 12 months, but that average price actually slipped from, I believe it was $94.71 at 12/31/2012 to $92.63 at 3/31/2013. So, we had roughly a $2.08 price drop during that period that’s used in that calculation. Even though during the quarter, our actual received prices were higher.

I see, okay. Alright, second question on the Anderson project, can you give us any particular color at all on what you are seeing in terms of a flow rate and how are you working to test this shallow formation, can you relate anymore color on that?

Sure. George, we’ve got it on a small project. We are flowing about, well, not flowing, we are pumping about 30 barrels a day, and we are flowing moderate to time we believe and we have heard that in the well cost, it takes some time for the oil to come to the wellbore, but we were encouraged by some coring that we did as well as the Shell is on the way down. Again as I mentioned it’s preliminary there, but if we do get the oil, they are fairly inexpensive wells to drill and we believe we have got multiple well locations and multiple sands as well.

Okay. The 30 barrels you are referring to, is that includes the water in the oil, is that it?

It does and it also includes the water that we lost while we were drilling the well. And so you do recover that as well before you expect your well cut to come up.

I see. Is there any way of measuring when you go through separation of the oil and water, what net barrels you are doing per day?

There is, there is, and we don’t have an initial results yet George.

Okay, alright. And in terms of the Buda project, you indicated this morning that they are into direct full flow back operations at this point in time with Crimson. And what are you figuring that it’s going to take before you can define? What relate to a steady rate of oil production?

We consult with Crimson and I think at least a week’s production and probably more like two.

Okay.

So that we can get a true feel for where the well levels op at. And I think it would be unfair to announce it this is not a Bakken well.

Right.

It’s a different formation. So, within the next week or two, I would expect the results to be announced, George.

Great, okay. And just a little further explanation, I know they are generally – you are pretty close to some of the other wells that have been drilled. I assume that these other wells that possibly have been drilled to the east of your location. And can you just again explain it? It appears as though the Eagle Ford and the Buda climb to a shallower level at your drilling site relative to the Eastern portion of the Eagle Ford and it looks to me like the Eagle Ford is the 9,000, 10,000 feet deep in the Eastern portion with the Buda under that. So, am I correct that this trend is moving to a shallower point and that you are now in this 6,500 to 7,000 foot range to the top of the Buda?

Well, if you go to our corporate presentation on the website, we have got a slide I am forgetting the number, Rich, do you remember the number of the slide?

10.

I think its 9 or 10.

Okay.

It shows us versus the Buda, but actually George, the Eagle Ford is shallower than that. The Eagle Ford is down around 6,000 foot and the Buda is right below the Eagle Ford at about 6,500.

Okay.

And it shows the contours on that slide as well of the depths and how that is, it kind of wraps around in our acreage position and starts moving south. But you are correct the wells that – the wells that we monitor are to the east and south of us. And I would just like to point out that included in our reserve report we got four PUD locations on our acreage with that offsetting and we got $3.5 million PV10 on those four locations.

Okay. And in terms of the going forward possibilities, the way you’ve structured now you’re looking at drilling a second well early July I assume or whatever and then depending upon the results of that well there would be a determination of an additional drilling rig or is it possible that a determination can be done for a drilling rig full-time based on what you see on the first – in the Beeler well there your flow testing now?

Again, we’re pretty encouraged and the reason it’s going to be in July because that’s next availability of the drill rig.

I see.

I think its no secrete, so everybody probably is aware if you are not. The key to the Buda is natural fracturing, we’re not fracture stimulating and the way we did hit some natural fractures we saw that in the mud logs. And we want to confirm that it’s contiguous through our acreage. So, the second well will be important and if it doesn’t perform then we’re going to have to take a look at why not and evaluate it. But we are very encouraged today by what we have seen and of course we are not going to be far away from that first well, because (indiscernible) results.

Okay, alright fine. Thank you.

Thanks George.

Thank you. (Operator Instructions) There are no further questions at this time. Do you have any closing remarks?

Yes, I would like to thank our audience for joining us today. At this point in time we remain optimistic about potential of developing the Buda formation in South Texas. And we look forward to releasing results of the Beeler #2 well in the coming weeks. This program did ultimately provide for a meaningful growth catalyst for the company on a going forward basis particularly if the decision to deploy a full-time rig is made by mid-summer. We also look forward to continuing the advancement of the Mount Emmons project and working with Forest Service to initiate and complete the NEPA process in due course. As always I appreciate your support and look forward to reporting our progress in our various programs as further operational results are achieved.

This concludes today’s conference call. You may now disconnect.