Good morning. My name is Karen and I will be your conference operator for today. At this time I would like to welcome everyone to the U.S. Energy Corp 2011 year end selected highlights financial results and operations update. [Operator Instructions] I would now like to turn the conference over to Mr. Mark Larsen, President and Chief Operation Officer of U.S. Energy Corp. Sir, you may begin your conference.

Thank you, Karen. Good morning ladies and gentlemen and thank you for joining us today. Joining me this morning is Keith Larsen, Chief Executive Officer of the company, who will be conducting the main portion of today's call and Bryon Mowry, our Principal Accounting Officer who will be reviewing the financial section of today's call. In terms of an agenda for today's call we will provide you with an update of our operating initiatives for the year ended December 31, 2011 as well as the period subsequent to year end and conduct a financial review before taking your questions in the Q&A portion of the call. Before getting started 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-K for the year ended December 31, 2011, which we filed Wednesday March 14, 2012 and other filings with the SEC. I will now turn the call over to Keith.

Thanks Mark and good morning ladies and gentlemen. Thank you for joining us. 2011 was another year of growth in the energy [ph] sector for U.S. Energy Corp. We continued to increase revenue from our oil & gas portfolio witnessed significant initial production rates as well as stabilized production from both of our participated Bakken drilling programs and expanded our strategic partnerships to include the Eagle Ford oil play. Also at year end we monetized undeveloped acreage in the Williston Basin in order to demonstrate value to our shareholders as well as maintain a strong balance sheet going into 2012. Results of this progress were demonstrated by another year of reserve growth including a 474% increase in the proved undeveloped category. Based on these year-over-year reserve increases our credit lender BNP Paribas has recently informed us that they intend to increase the commitment amount of our credit facility to $100 million from $75 million and increase our borrowing base to $30 million. This progress has allowed us to budget for a $8.1 million drilling program in 2012, which is anticipated to be funded from cash flow from operations as well as our credit facility with BNP Paribas. Turning to an overview of our 2011 operational highlights for the year ended December 31, 2011 we drilled 20 gross 4.1 net wells during the year in all of our programs and we once again realized a 100% success rate in our drilling initiatives in the Williston Basin. As a result of our growth we recognized record revenues from oil and natural gas production of $31 million. During the year we produced 442,000 BOE or 1,212 BOE per day, which is a slight decrease from our 2010 average daily production primarily due to the impacts to our programs as a result of unprecedented…

Thank you, Keith. Looking at the year end of December 31, 2011 our operating revenues increased by $5.4 million to $30.1 million when compared to revenues of $24.7 million in 2010. The operating revenues increased primarily due to higher commodity prices and a net decrease of $1 million in the loss per quarter from our hedging activities from $1.9 million in 2010 down to $900,000 in 2011. Operating revenues for 2011 reflected 22% improvement from operating revenues related to 2010. Oil & gas operations produced operating income of $4.6 million during 2011 as compared to $8 million during 2010. The decrease in earnings from our oil & gas operations was primarily due to a $5.4 million increase in operating expenses mainly caused by a $3.1 million work over on one well and an increase of $3.4 million in depletion costs. These increases were, these increases in costs were partially offset by an increase in revenues of $4.4 million and a $1 million decrease in unrealized and realized gains and losses on risk management activities when comparing the year ended December 31, 2011 to the year ended December 31, 2010. Our fourth quarter production revenues were $8.8 million an increase of $400,000 over the third quarter of 2011. Due to the recorded $3.3 million loss from our hedging activities during the quarter ended December 31, 2011, operating revenues decreased by $2.9 million to $7.1 million during the quarter ended December 31, 2011 as compared to revenues of $10 million during the quarter ended September 30, 2011. The decrease was partially offset by an increase of $400,000 of production revenue. Our production volumes for the year ended December 31, 2011 averaged slightly over 1,212 BOE per day, which is a small decrease from 1,230 BOE per day in 2010. Our average realized…

Thanks Bryon. In closing I would like to point out that 2011 was a successful year for U.S. Energy in terms of advancing our strategic, our strategy and achieving meaningful growth in the energy [ph] sector. We realized significant revenue from stabilized production in the Bakken and we grew our reserves significantly by adding proven undeveloped [indiscernible] locations in our reserve [indiscernible] . We had outlying acreage in the Williston Basin at reasonable cost, at the same time we monetized acreage in the basin in order to maintain our strong balance sheet as well as demonstrate value to our shareholders. We also expanded our initiative again to the oil window of the Eagle Ford play with Crimson, which could have significant development potential if our initial 3 well testing program performs as we anticipated. As demonstrated in our recent sales we will continue to prudently manage our balance sheet to maintain our flexibility in acquiring additional assets and to drive growth for our shareholders. 2012 promises to be another great year for the company. We appreciate your support through 2011 and look forward to reporting results as they are achieved throughout the balance of the year. That concludes our prepared remarks for today. Operator, would you begin the Q&A session now please?

[Operator Instructions] Our first question comes from the line of Noel Parks from Ladenburg Thalmann.

Just a couple of things. Sorry if I missed it. Did you talk about what the dry hole cost was for that Oakville well?

We did not. Which well was it?

At Oakville it was.

I think it was in the neighborhood of $300,000 to $400,000 Noel. I can check that for you though.

Okay, so not a particularly large number.

No.

Great. And also just in the Eagle Ford can you talk a little bit more about what's going on there as far as the fracing? It sounds like maybe there is a study going on as far as the technique or the [indiscernible]

Yes Noel, what we have been talking with Crimson about is, obviously we want to maximize the potential of the field. We know we've got oil there, which is a positive and there are different fracing techniques that are being applied by different operators in the area. Chesapeake is one of the big ones that is literally dried up against some of our acreage and we were anticipating in completing those wells in the near future, possibly over the next quarter. And would like to see the results of those as well as determine if their fracing technique is similar to ours or different than ours. If they are similar and they are getting good results then we will continue where we are at, if they've changed it somewhat then we would like to change it if they are getting better results than we are.

Got you. And just the last one I had is any sense going into this year what the G&A expense trends will look like?

I think that included in the last year we did see a decrease in some of the G&A and we are working every day to cut costs wherever we can. So I would hope that the trend will continue and we can reduce our G&A again similarly like we did in 2011.

And we also have a question from the line of Jeff Hayden from Rodman & Renshaw.

This is actually Adam Fackler. I was hoping you might share with us from a strategic standpoint how you were thinking about M&A and a little more specifically is there a specific portion of the budget you are looking to reallocate? Are there areas you would be particularly interested in and finally along the same line assuming a transaction would you ideally like to take an operating role or enter as a none [ph]?

Adam we've discussed all of those options we attempted Napier a couple of weeks ago as well as have investigated numerous companies as well as numerous projects and to answer your question directly well obviously we are looking for oil, not necessarily gas. You would probably see much less exploration for gas in our portfolio we are looking for oil. We saw several prospects we have taken a look at several prospects of bolster [ph] that are being redeveloped with laterals. We've actually looked at companies as possible acquisitions as well. So if we do go into operations it would probably be from acquisition of a smaller company possibly private, possibly public that has operations and has the potential properties out there. And specifically, obviously we probably will not spend the $25 million we have budgeted for the Eagle Ford this year and so we are looking for ways to take that portion of our budget and reallocate it into the many prospects that we've been looking at.

And our next question comes from the line of Jeff Conley [ph] from Sidoti.

I was just wondering if you could comment on the market for services and take away capacity in the Williston Basin and your expectations for the price differentials in 2012?

Well my understanding right now is we are seeing between $15 and $20 differential and again what I've been reading is there is a refinery in the mid-west that went down that added capacity of some 110,000 barrels per day and then conversely they had a tar sand facility in Canada that also tipped away that capacity. But in any play like this that is remold like the Williston Basin it's going to have some growing pains and the take away capacity going to have to be added. The last I heard that VOG is trying to add another 50,000 barrel a day unit train to go down to Cushing [ph] . The good thing for us is we are seeing $105 so at least we are realizing some $85 to $90 a barrel but I think that you are going to see additional and then there will be additions in capacity and then as the play grows and if again, to answer your other question that service cost don't escalate too much. Because we have seen them we are seeing AFPs as high as $11 million and again maybe the anticipation of others when you get EURS initially in remote areas like we have in the SEHR and the Yellowstone areas. Our engineers are giving us lower EURS and then as the wells perform, they become better. So the economics looks better even on $11 million. That's part of a reason why you saw an increase in our PV10 although we sold our proven undeveloped locations, it's because of the escalating costs. The drilling costs are staying fairly reasonable, the completion costs and the fracing costs we have seen a significant escalation. Now in relation to the same thing I talked to the folks at Brigham and they are starting to see some of the competition, get more competitive up there and in fact a couple of the recent AFPs we've seen from them we have seen a slight decrease. So it's one of those burn [ph] place, that services get out of hand and then as prices come down and competition gets more competitive. So that's kind of where I see it.

Okay. And then can you also comment on the time line of the Eagle Ford program?

Well again, it's -- the oil is not going any place obviously it's not going to get out again until it gets fraced and we just wanted to be sure with Crimson that we are using the very best techniques to maximize the potential. So I would say that we won't frac the KM Ranch probably for another month. We continue to monitor the flowback from the Beeler well and so obviously that program will be slowed down to give you a definite numbers right now I can't tell you, because we still have to see the performance of these other wells and then judge how we are going to move forward.

[Operator Instructions] We also have a question from the line of Joel Musante from CK Cooper & Company.

Most of my questions were answered but I still got a few more of them. What's your current production right now or the latest that you can give me?

Joel you know as Steve Richmond [ph] talked about this morning they are skewed numbers because we just completed a high 2 wells. So it would be skewed currently, but probably somewhere in the 1,600 to 1,800 barrel if those come down strong Joel, so I want to caution you.

Right, right, so like before you brought on those wells you are still in the same 1,100 to 1,200 barrel the day range or?

That's true. It was similar to year end and similar to what we saw last year, 1,200 barrels.

Okay and you brought on one of those wells in January -- is that correct and one in later?

Yes the Kalil came on in January and then we just brought on the Lloyd and then we are just drilling out the Wang.

Just drilling out the final plug on the Wang here Joel.

Okay alright and then the how long was the Beeler well -- about a month or?

Now the Beeler well has been on since clear back in February.

No the dealer was clear back in November margin [ph] .

Okay, alright and you had a tax benefit of $3 million was that from the write-down of Remington?

That was definitely part of it but there is also some benefit based on the excess completion cost that we can get for 2011 versus carrying it out into the future.

Okay alright and then lastly I was just looking at your -- some of the reserve information in your 10-K and it indicated you had $36 million in future development costs. But then there was a $42 million of development costs, future development costs in the standardized measure. What was the difference there? Is that proved developed producing dollars?

I think one of them is a PV10 and one of them is actual dollars. Joel, if you want to give me a call we can get Steve at the call and I can maybe give you some clarification on that.

And our next question comes from the line of George Gaspar [ph], a private investor.

First question on Eagle Ford. Just a little questioning the conclusions to date that there is a need to still try to figure out the fracing procedures. Considering the number of wells that Crimson has been involved in, in the Eagle Ford already I would think that they would have had the fracing procedures figured out for this particular area that you're joint with them on. Is there an explanation of what's different about that particular area you are in versus maybe other areas they are in because also the flowback rates don't seem to be that high where you are involved currently.

Yes George, the other areas they are in [indiscernible] are deeper and they are more over the wet gas. The rock is different down there obviously with the deeper depths, they have different deposition. So this is Crimson to my understanding this is their first shower if you will, 6,000 foot depth and so they are working on different fracing techniques and trying to get the best bang for the buck.

I see and what about -- is there something unusual about the flowback procedures involving what has been done to date. I know you seem like you ran into this problem on that very first well that you drilled in the Eagle Ford before you started these other 2 wells. Is there something unusual about the structure that allows -- requires a larger flow back at that period.

I don't think so George. I think that this area in Northern Dimmit County has not had the development like it has in Southern. And I think what we are seeing there is the fracing techniques are being tested. Obviously Chesapeake is spending a whole bunch of money not only to round us but all over the entire region. And when we would sure like to see it. The good thing is its similar to Brigham. It's having these bigger company spend the money to figure it out and then everyone kind of follows Brigham's lead and we think that if we are going to see similar situations like that in the Eagle Ford.

Okay, alright. And then -- just a overview question looking back since just post the announcement and the sale of the Uranium properties, the stock is selling at about 50% less than it was at that time and yet there has been a lot of activity commitment into the real estate and into drilling. And you've made some nice progress in North Dakota, marginal progress [indiscernible] to date. So that there is data [ph] about at least three or four years, you can correct me if I'm wrong but it seems like it's that long now. And what is it going to take to get U.S. Energy back up track to at least area of market price that was existed before even started into the IO patch and the real estate.

I think it's going to be performance George. I think that as we grow our reserves and our production that we will be recognized high in the industry as well as advanced imaging [ph] project, which is probably one of the reasons why our stock has not done as I would have expected it to. There were so many unknowns in the mining. There is not a lot of E&T companies that have a mine out there. And we are working on various ways to realize value there, just keep our shoulder to the grind stone and keep increasing the reserves and growing like we did last year. I think that eventually we will be seen by the market and we will be rewarded -- our shareholders will be rewarded for the efforts that we are putting forth.

Okay alright. And then one last one your flow rate there was a question prior to mine here on your current flow rates and you got to probably a positive plus flow rate right now because of an initial flowback. If you look at this 12,000 [ph] barrel a day range considering what you've done now in the sales of interest. Can you give us an idea where you would see that 1,200 barrels a day being let's say without moving the exploration program forward from where it is now it's completion. In other words I guess what I'm driving at is what's the loss of production that in the side that text of the sale of you have made firstly and secondly what do you see in the decline curve against that 1,200 barrels a day.

Well in the first sense George we didn't sell any of our production. All of our production as well as the time can high interest wells going forward of which we have completed now as I [indiscernible] . So those wells keep our original ownership now as well as Brigham wells. And to get into the crux of the question, understand that our first well we drilled with Brigham was in '09 and that was the Raddles #1 well which we are seeing and those wells are coming down somewhere between 100 barrels to 200 barrels a day. And I think the published numbers out there is the decline rate of some 3% to 5% after that. The numbers seem to me to be working that out. So, most of our base production, most of that 1,200 barrels I see is being stabilized and will not be declining, if at all. Complimenting that with the new wells that we are bringing on, even the smaller interest wells both with Brigham and Zavanna -- the 3 that we've got with Brigham that are planned and I would also feel confident they are going to give us more than the 3 this year. As well as additional wells with Zavanna so we don't give direction George, but certainly I could see us increasing our daily average production this year.

Okay and one last one on real estate. What's the value that you are carrying the project at now you took a $3 million charge -- so what is it valued at $20 million, $21 million range or less.

It was less [ph] prior George and we are down around it's right at $18 million.

$18 million. Okay and the original cost on that was what around $23 million, $24 million.

$24 million, $25 million.

$24 million, $25 million. Okay.

Thank you and we also have a question from the line of William Marcellus [ph], another private investor.

My question relates to Mount Emmons and if the project plan is accepted say later in 2012, how long would it take to actually get the project underway and what is the company's annual cost before actual development starts to carry the project?

William, this is Mark and to begin with our annual cost including the water treatment plants and our projected cost for the year is about $2 million and of that $1.8 million is roughly for the water treatment plant, the other $200,000 is working on the mine plant of operations. All of the technical data that we will receive from Thompson Creek was basically completed in the formative pre-feasability study and we are moving that forward to draft the plan of operations and we expect to file that -- submit the plan of operations to the Forest Service by April of 2013 at the latest. From there permitting timeline there are a lot of uncertainties there but we believe it's going to be a minimum of 4 years is likely what we are projecting to take us through the [indiscernible] process.

And so then during that 4 years you will still be expending about the $2 million a year.

That is correct. It maybe a little higher with other work and public outreach and so forth possibly up to $1 million to be conservative.

Thank you, sir. And I see no further questions from the phone.

Alright, well ladies and gentlemen thank you for joining the call. Thank you for all the support from our shareholders and investors out there and for keeping an eye on us and we do look forward to an exciting 2012 and we look forward to updating you after our next quarter.

Thank you, sir. This concludes today's conference call. Everyone may now disconnect.