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 weather related issues in North Dakota in the first and second quarters of the year as well as a backlog of completions in the Williston Basin. Due to stronger oil prices in 2011 our average net realized price for the year was $69.98, which is over $10 per barrel higher than our average net realized price compared with the same period in 2010. I would also like to point out that over half of our Williston Basin wells have been producing for more than a year now so we are seeing the benefit of stabilized long-term production mixed with 5 additional high interest wells anticipated to come online from our 2 programs in the basin in the first half of 2012. At December 31, 2011 our proved reserves totaled 3.1 million BOE replacing 280% of 2011 production. The total was comprised of 2.7 million barrels of oil, which was 86% of our total reserves, 2.7 Bcf of natural gas and 1,688 barrels of natural gas liquid. At year end, 56% of our estimated proved reserves were producing, 13% were proved developed non-producing and 31% were proved undeveloped, with oil accounting for approximately 86% of this total. Based on proved reserves our total estimated PV10 value at year end was $72.5 million, these numbers represent a 63% increase to the reserves and a 39% increase in PV10 value over December 31, 2010. On January 25, 2012 we sold an undivided 75% of our undeveloped acreage in the SE HR and Yellowstone Prospects. If applied retrospectively to our December 31, 2011 reserves, this sale reduced our proved developed reserves by 41,000 BOE due to acceleration of a reversionary interest at payout related to the producing wells. It also reduced our proved undeveloped reserves by 509,000 BOE, reduced our estimated future development costs by $21.4 million and increased our PV10 by approximately $468,000. Now moving on and looking ahead to the balance of 2012. At year end 2011 our Board of Directors approved a capital expenditures budget of approximately $48.1 million for our 2012 oil & gas drilling programs. The CapEx budget is comprised of an estimated $18.4 million to be spent in the Williston Basin of North Dakota in the Rough Rider and Yellowstone/SEHR programs with Brigham and Zavanna, respectively. $24.9 million in capital expenditures is budgeted to be spent on exploration initiatives in the Eagle Ford drilling program with Crimson. And the remaining $4.8 million originally budgeted for the San Joaquin Basin prospect research will be redirected towards other programs over the course of the year. Amounts budgeted for each regional drilling program is contingent upon timing, well cost and success and could be subject to further adjustments based on timing, weather and other factors. Moving on to our 2 drilling programs in the Williston Basin, I will start with Brigham exploration who most of our audience knows was acquired by Statoil of Norway in December of 2011. Since the transaction has taken place we have seen very little change in terms of who we work with on their operational team and we expect to continue to have a great working relationship with the group going forward. I'd like to congratulate the entire staff at Brigham for the success of their merger with Statoil and Bud and Dave Brigham in particular for a job well done. With Brigham Statoil we participate in 15 1,280 acre drilling units in the Rough Rider prospect near Williston, North Dakota. Since inception of our program with Brigham, which began in August of 2009, we have drilled and completed 19 gross Bakken wells and one gross Three Forks well. On Wednesday we announced the early 24 hour pull back for initial production rates in the Lloyd 34-3 #2H well, which was 4,300 BOE per day and accounts to our highest initial production rate reported in a company participated well under the program of critical [ph] . During the calendar year 2011 the company drilled 3 gross wells 0.6 net, completed an inventory of 5 gross wells 1.62 net, and have completed an additional 2 gross wells 0.28 net subsequent to year end. Brigham has notified the company of 3 infield wells scheduled to be drilled in Rough Rider acreage going forward. We are currently scheduled to drill a Bakken infield well in the State 36-1 unit this month, a Bakken infield well in the Sedlacek Trust 33-4 unit in April, and an additional Three Forks infield well in the State 36-1 unit in August of this year. On December 15, 2011 the company also sold an undivided 75% of undeveloped acreage in the Rough Rider prospect to Brigham for $13.7 million. Under the terms of the agreement the company retained the remaining 25% of its interest in the undeveloped acreage and its original working interest in its 20 developed wells in the Rough Rider prospect. After the sale our working interest in the undeveloped acreage and the Rough Rider prospect ranges from 3.4% to 9.9%. Although our interest in the undeveloped acreage with Brigham and Zavanna has decreased, we feel that this was a prudent move in order to maintain a strong balance sheet in light of the cost stream by [indiscernible] basin and as well as completion timing uncertainties that risk moving the company toward its borrowing limits late last year. In our second drilling program in the Williston Basin with Zavanna we participate in 2 parcels, Yellowstone Prospect and the SEHR prospect. We expect this program will ultimately result in 27 gross 1,280 acre spacing units with various working interest of up to 35% for our first 10 months [ph] . Our drilling program with Zavanna commenced early in 2011 and we drilled 8 gross wells 2.18 net during the year, 3 gross wells 0.9 net were completed in 2011 and the remaining 5 gross wells 1.27 net are expected to be completed in the first and second quarters of 2012. Currently we are nearing the completion of drilling out the plugs on the Wang well, which was fracture stimulated with 35 stages. We have an 18% working interest and 14% NRI in this well. Also the Crescent Farms well has been recently fracture stimulated with 35 stages and we expect to drill the plugs out of that well in late March or early April. We have a 27% working interest and a 21% NRI in the Crescent Farms well. Additionally we have an inventory of 5 wells build to a target depth of 20,000 feet currently scheduled to be fracture stimulated between now and June 2012 under the program with Zavanna. The completion schedule in our interest are as follows: the Skorpil 11-2 31H well is scheduled to begin completion initiatives in April and we have a 23% working interest and an 18% NRI in the well. The CDK 15-22 #1H well is scheduled to begin completion initiatives late in April. We have a 32% working interest and a 25% net revenue interest in the well. The Larsen 29-32 #1H well is scheduled to begin completion initiatives in May, we have a 28% working interest and a 21% NRI in this well. As these wells are completed they are expected to add meaningful production and subsequent revenues in 2012. Additionally the Skogen 17-20 31H well is scheduled to begin completion initiatives in June and we have a 6.6% working interest and a 5% NRI in this well. Lastly in the inventory, the Kepner 9-4 #1H well reached a total depth of 20,700 feet this week and completion initiatives are scheduled for June. We have a 4.6% working interest and a 3.6% NRI in this well. Looking forward, it is anticipated that by mid summer of 2012 that we will have an initial well drilled in all of our participated units [indiscernible] and will therefore pulled [ph] all of that acreage by production as we though. Zavanna has also indicated that they are working towards adding neighbors rig to continue to drill remaining undrilled units in the SEHR acreage block through May of 2013. In January 2012 we sold an undivided 75% of our undeveloped acreage in the SEHR prospect and the Yellowstone prospect to GeoResources, Inc. and Yuma Exploration and Production Company for $16.7 million. Our working interest in the remaining locations will be approximately 8.75%, the net revenue interest in new wells after the sale are expected to be in the range of 6.7% to 7%, proportionately reduced depending on Zavanna's actual working interest percentages. This divestiture was done in order to maintain a strong financial balance sheet and to demonstrate our participated value in the programs to the markets as well as our shareholders. Pertinent to this sale we did not sell any interest in 2 wells which we previously drilled with Brigham [ph] or 8 high interest wells that are already been drilled are completed with Zavanna. In addition to our core acreage in North Dakota, the company has disclosed on our 10-K filing that during the course of 2010 and 2011 we acquired 100% working interest and approximately 25,000 gross 18,700 net mineral acres of leases in Northeast Montana. At this time we are seeking departure with an industry peer to test the acreage in 2012 and implement a development program if initial drilling results are successful. I would now like to move on to our drilling program in the oil [indiscernible] of the Eagle Ford Shale. In 2011 we entered into 2 participation agreements with Crimson Exploration acquiring interest in two oil prospects in Zavala and Dimmit Counties located in Texas. Under the 2 participation agreements we participate as a 30% working interest, 22.5% net revenue interest partner in 13,785 gross, 4,136 net acres and 2 acreage bought [ph] . The Leona River prospect and associated leases are located in Zavala County Texas and the Booth-Tortuga leases are located in Zavala and Dimmit Counties. The leases in the Booth-Tortuga prospect are currently held by production and produce approximately 115 gross BOE per day, 20 net BOE per day from the Austin Chalk formation. The initial well on the Leona River prospect the KM Ranch #1 well was drilled during the second and the third quarters of 2011 and is now producing approximately 119 gross BOE per day. Well is still producing at natural pressure and it has not yet been put on pump. We have also drilled a second well on the acreage block [ph] , the KM Ranch #2 well. This well has been drilled to a total major depth of 12,875 feet, including a 6,100 foot lateral and is currently awaiting completion. The completion of the well is currently on hold until flowback of the Beeler #1 well results can be further evaluated in order to help determine best practices for the potential development of the 2 programs. Crimson is also monitoring the results from a large operator that has a significant drilling program in close proximity to our activity, which is multiple well completion results [indiscernible] . The initial well at the Booth-Tortuga prospect, the Beeler #1H well, commenced production in mid-February and gross 24-hour initial production rate of 370 BOE per day or 337 barrels of oil from 195,000 cubic foot of natural gas on an 18/64th choke. The well was drilled to a total measured depth of 14,428 feet, including a 7,200 foot lateral, and was completed using 20 stages of fracture stimulation. At this time we continue to monitor the initial flowback results of the well. In addition to our Williston Basin assets, the company participates with several different operators in the U.S. onshore Gulf Coast region. At December 31, 2011 we had 5 gross 0.12 net producing wells in the region. 2 of our wells with PetroQuest Energy have been very strong producers for the last several years averaging approximately 300 BOE per day during this period. These wells were anticipated to produce for an approximate 5 year well life and are now entering the end of their economic production cycle. To counter this loss of production from the region we drilled 4 gross wells in 2011 and have one gross well in progress at year end. The L.L. Bean well, which the company has an approximately 17% working interest and an approximate 13% net revenue interest is operated by PetroQuest Energy and again producing in the second quarter 2011. The company is currently realizing an average of 75 net BOE per day from the well, which is primarily gas. The Bayou Bend well, which was operated by southern resources and was in progress at year end is currently been tied in production this month after minor delay due to permitting. Turning to the other areas of our business, our 9 building, 216 unit multifamily apartment complex averaged 87% occupancy during 2011 and realized average monthly revenues of approximately $174,000 during the period. The property is collateralized with a $10 million conventional note and an impairment of $3.1 million recorded to reflect the difference between the cost of the property, and the lower range of the estimated fair market value at December 31, 2011. Although the property produces positive cash flow from its operations, the returns from our oil and gas investments are expected to yield a higher return and therefore it is our goal to sell this property in 2012 and redirect the sales proceeds to our growing oil & gas portfolio. I would now like to discuss the status of our Mount Emmons molybdenum project which is located in Gunnison County, Colorado. The Mount Emmons project is a primary molybdenum deposit, which includes a total of 163 acres, 25 patented and approximately 1,353 unpatented mining and mill site claims [ph] which together approximate 9,920 acres more [ph] over 15 square miles of holdings. In late December 2010, we received the $1 million option payment from Thompson Creek metals for 2011. In April 2011 Thompson Creek then notified the company and terminated its option agreement with U.S. Energy to develop the project. In notifying the company Thompson Creek cited more immediate development priorities in its portfolio. While we were disappointed with Thompson Creek's departure from the project, we are very pleased to have had the opportunity to work with Thompson Creek on this project. They were a first class partner and we appreciate the work that they've completed to advance the project. Looking forward, we are now utilizing the numerous technical engineering sighting and cost studies that were completed during their involvement with the project to draft our mine plan of operations, which we expect to submit to the U.S. Forest Service in the first or second quarter of 2013. We remain committed to moving the project forward on our own behalf as well as reaching out to other potential partners in due course as the mine plan of operation nears completion. I would now like to turn the call over to Bryon Mowry, the company's Principal Accounting Officer to review the financial portion of the call.

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 price of $69.98 per BOE was an increase of $10.83 per BOE during 2011 when compared to the realized price of $59.15 from 2010. Additionally during the year ended December 31, 2011 we made the decision to sell our multifamily complex in Gillette, Wyoming, Remington Village. As a result of this decision the operations of Remington Village were moved to discontinued operations and an impairment of $3.1 million was recorded against the book value of Remington Village during the year ended December 31, 2011. The operations at Remington Village for 2011 recorded a net income of $434,000 net of taxes compared to a net income of $226,000 for the year ended December 31, 2010. The primary reason for the increase in net income for 2011 was the non-reporting of any depreciation charges for the year ended December 31, 2011 due to Remington Village being recorded on our balance sheet as an asset held for sale. Primarily as a result of the activities described above we recorded a net loss of $4.8 million or $0.18 per share during 2011 as compared to a net loss of $772,000 or $0.03 per share for 2010. Moving over the balance sheet on December 31, 2011 our total assets were $162.4 million, cash and cash equivalents were $12.9 million and we had a debt balance of $12.4 million on the balance sheet and an additional $9.9 million in debt was recorded as a part of the liabilities held for sale. Our total debt at December 31, 2011 was $22.3 million, which was comprised of $12 million on our credit facility, $9.9 million related to Remington Village and $400,000 related to our land at our mining operations in Colorado. In January 2012, we paid the $12 million outstanding balance on our oil & gas facility down to 0. The $9.9 million debt related to Remington Village will be paid when Remington Village is sold. In summary, our balance sheet remained strong December 31, 2011 with working capital of $16.2 million, we had a cash balance of $12.9 million, plus marketable securities of $166,000 at December 31, 2011. Looking into 2012, we have our working capital positions, the full amount of our $28 million in credit facility and our cash flow from operations available to continue our funding and our continued growth and investment in our oil & gas portfolio. I would now like to turn the call back over to Keith.

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.