Keith G. Larsen - CEO and Chairman Steven Daniel Richmond - CFO Mark J. Larsen - President and COO Reggie Larsen - Director, Investor Relations

Curtis Trimble - Global Hunter Securities Jeffrey Connolly - Brean Capital, LLC George Gaspar - Robert W. Baird & Co.

Good morning. My name is Huey and I will be your conference operator today. At this time, I’d like to welcome everyone to the U.S. Energy Corporation’s Third Quarter 2012 Highlights, Operations, and Financial Results Conference Call. (Operator Instructions) I’d now like to turn the conference over to Mr. Reg Larsen, Director of Investor Relations of U.S. Energy Corporation. Sir, you may begin your conference.

Thank you. Good morning ladies and gentlemen, and thank you for being with us today. Joining me this morning is Keith Larsen, Chief Executive Officer of the Company, who will be providing an overview of the quarter and an operations update; and Steve Richmond, the Company’s recently appointed Chief Financial Officer, who will be providing a financial review for today’s call as well as Mark Larsen, President of the Company, who will be joining us for the Q&A. In terms of the agenda, we will provide you with an update on our operating initiatives for the quarter ended September 30, 2012 as well as the period subsequent to quarter end. We will also conduct a financial review of the quarter and finish with question-and-answer portion of the call. As a preliminary matter, I’d 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 assumption of U.S. Energy’s management. These and all statements other than statements of historical fact are forward-looking statements within meaning of Section 21-E of the Securities and Exchange Act of 1934 and Section 27-A of the Securities Act of 1933. The forward-looking statements are subject to numerous risk and uncertainties including those described in the Form 10-Q for the quarter ended September 30, 2012, which we filed on Friday November 09, 2012. Our Form 10-K for the year ended December 31, 2011 and other filings with the SEC, all of which are incorporated herein by reference. I’d now like to turn the call over to Keith Larsen. Keith G. Larsen: Thanks, Reg and good morning ladies and gentlemen. I will begin the call with an overview of the quarter and nine months ended September 30, 2012 operational highlights. At September 30, 2012, the Company had participation in 79 gross or 14.88 net producing Wells, which include 62 gross Williston Basin Wells, three Gulf Coast Wells, 11 gross Austin Chalk Wells, and three gross Eagle Ford Wells. The Company produced 106,060 BOE during the three months ended September 30, 2012 with average daily net production during the quarter of 1,153 BOE per-day. During the nine months ended September 30, 2012 production totaled 336,880 barrels of oil equivalent, which is an average of 1,229 BOE per-day. The Company recognized $24.5 million in revenues during the nine months ended as compared to $22.1 million during the same period of the prior-year. The $2.4 million increase in revenue was primarily due to higher oil sales volumes in 2012 when compared to 2011. We continue to focus on increasing production, reserves, revenue and cash flow from operations while managing our level of debt and seeking out additional growth opportunities in the segment of our business. In that regard, we announced on September 21, 2012 that the Company entered into a purchase and sale agreement with an undisclosed seller to prior interest in producing Bakken and Three Forks formation wells and related acreage in McKenzie, Williams and Mountrail Counties, North Dakota. Under the terms of the agreement, the Company acquired working interests in 23 drilling units with an estimated 294,000 BOE in proved reserves for $2.3 million after adjusting for related revenue and operating expenses from the effective date through September 21, 2012. USEG’s working interest in the drilling units averages 1.45% and ranges from less than 1% to approximately 5%. There are currently 27 gross producing wells in the acreage. Of these wells, 25 are producing from the Bakken formation and two are producing from the Three Forks formation. All of the approximate 400 net acres are currently held by production and produces approximately 47 BOE per-day net to USEG. On a going forward basis, there is a potential for USEG to participate in an additional 135 gross wells from the Bakken and Three Forks formations combined and the Company will be heads up for its proportionate interests on all new wells drilled within the units. Since the closing of the purchase one of the operators, Oasis has drilled the Ash Federal 5300 11-18T well, which recently had an IP of 3,430 BOE. Oasis is also permitted four additional gross wells near this location, two targeting the Bakken formation and the remaining two targeting the Three Forks formation. In addition to the Oasis wells, Emerald Oil and Gas is also permitted three gross Bakken wells. We anticipate these wells to be drilled beginning in the first quarter of 2013. Under the Statoil program, the Williston based on North Dakota, the State 36-1 #4H well which is a Three Forks formation targeted well is scheduled to spud in December. The well is the fourth well in the State unit and the second Three Forks formation well in that unit. In addition to the State Three Forks infill well, Statoil has also permitted three gross additional infill wells in the Hovde unit with one of the wells targeting the Bakken formation and the remaining two targeting in Three Folks formation. We anticipate these wells to be drilled in the coming months. During the quarter, two gross 0.11 net wells were drilled in the SE HR acreage block under the Zavanna program. The Witt #1H well was completed in early November and had nearly 24-hour flow back rate of 1,564 BOE per-day. The Barker #1H well was drilled to its total depth in October and is scheduled to be completed in mid-November. Subsequent to the quarter end, the Bunning #1H well is in the final stage of drilling the horizontal portion of the wellbore and also is scheduled to be completed in late November. The Company has also elected to participate by proportionate share 8.75% approximate in salt water disposal facilities in each acreage block under the drilling program of Zavanna. The project is currently underway and is expected to be completed in the fourth quarter of 2012. These facilities consist of gathering lines and a salt water disposal well in each acreage block, which are expected to reduce the water disposal costs and to ultimately reduce our cost per barrel of oil produced from the program. As I previously stated, all of the units in the Yellowstone acreage block are held by production. Going forward, we believe the operator will continue to focus on drilling the remaining SE HR initial wells units through early summer of 2013 as well as begin to drill into the wells in 2013. The Company will gain a better insight into the 2013 Zavanna drilling program at a scheduled partners meeting later this week. On June 8, 2012 the Company sold an undivided 87.5% of our acreage in Daniels County, Montana to a third-party for $3.7 million cash. Under the terms of the agreement, we retained a 12.5% working interest and approximately 20,000 net acres and reserve overriding royalty interest in leases equal to the positive difference between existing burdens of record in 19%. The purchaser committed to drill a vertical test well to depths sufficient to core the Bakken and Three Forks formation on or before December 15, 2015 and to carry us for our 12.5% working interest on that well. Apache Corp recently announced that they had acquired in excess of 300,000 net acres in Daniels County. During the third quarter, Apache spudded two Bakken and two Three Folks wells approximately 15 miles North West of the Company’s acreage. We will be closely monitoring the Apache result as they become available. In addition to our active program in the Williston Basin, the Company also has a 30% working interest in two oil prospects in Zavalla and Dimmit Counties, in south Texas with Crimson exploration. The two prospects bring the Company’s participation in the region to 13,785 gross or 4,136 net acres. The KM Ranch #2 well in Zavalla County Texas, our second well in the Leona River acreage block, was drilled to a total measured depth of 12,875 feet, including a 5,250 foot perforated lateral, in the first quarter of 2012. We completed the well in August with 16 stages of fracture stimulation. The well had a peak 24-hour gross flow back rate of 511 BOE, which consisted of 457 barrels of oil and 326 MCF of natural gas. We plan to further analyze completion techniques being utilized by other area operators and believe that a longer lateral with additional fracture stimulation stages, maybe the key to unlocking this areas potential for development. In addition to the Eagle Ford formation drilling program, a private operator has tested the Buda formation immediately east of our Booth-Tortuga prospect, with the reportedly promising initial results. We have discussed the Buda formation test, well with Crimson in the near future and we have plan to announce our South Texas drilling program when our 2013 budget is finalized before year-end. In May 2012, we acquired a 26.5% initial working interest in approximately 6,700 gross acres in the Woodbine Sub-Clarksville 7 project area in Northeastern Texas with Mueller Exploration. The seven prospects were drilled in succession from June through August of 2012. Two of the gross wells .4 net are currently being evaluated for production potential and the remaining five 1.33 net were deemed to be non-productive. Before turning to the financial portion of the call, I’d like to provide an update on the Mount Emmons project. On October 10, 2012, the Company filed a preliminary Mine Plan of Operations with the U.S. Forest Service in Delta, Colorado. The preliminary plan is under review by the U.S. Forest Service. On Friday November 9th U.S. Forest Service notified the Company that additional time is needed to complete the review, but will not exceed 60 days. On acceptance by the U.S. Forest Service, the Mine Plan of Operations will be released to the public in its entirety. Regarding the federal land exchange effort, there has been no progress on this front since the effort was suspended in June 2012, primarily due to the uncertainty of the outcome of the federal elections and the unknown make up of progress. The Company’s primary focus for this time is the finalize and pursue the Mine Plan of Operations, particularly the initiation of the National Environmental Permitting Act, NEPA process, which is expected to follow the Mine Plan Operations acceptance by the U.S. Forest Service. Once the Mine Plan of Operations has been formally accepted by the U.S. Forrest Service, the Company plans to issue a press release outlining the components of the Mine Plan of Operations. In addition to the filing of the Mine Plan of Operations, the Company has also installed the plumbing system, which allows for the capture and control of the water flowing from behind the bulkhead in the mountain. The intent of this system is to reduce the influent metals loading by not allowing oxidation while the water travels from within the mine to the surface. Capturing the water be at the plumbing system, the Company has reduced the influent metals loading by 33% to as much as 50% which was resulted in decreased chemical costs to treat the water as well. The Company has also installed and tested a new filtration system, which may allow for 24-hour operations in the future. Initial testing has indicated that the system could reduce our overall water recycle volumes by approximately 40% when converted to 24-hour operations. The overall goal of the combined projects is to reduce the annual water treatment plant operational costs by approximately 300,000 to 500,000 annually beginning next year. The Company has embarked on additional cost cutting measures company wide. Including sale of its corporate aircraft and related facilities and a reduction in our staff. We believe these measures will allow result in a reduction of G&A expense approaching $1 million in 2013. I’d like to now turn the call over to Steve Richmond, the Company’s CFO to review the financial portion of the call.

Thank you, Keith. During the three months ended September 30, 2012 we recorded a net loss of $1.9 million after taxes or $0.07 per share as compared to net income after taxes of $268,000 or $0.01 per share for the quarter ended September 30, 2011. During the nine months ended September 30, 2012 we recorded a net loss of $3.3 million after taxes or $0.12 per share as compared to a net loss after taxes of $2 million or $0.07 per share for the nine months ended September 30, 2011. Both the quarter ending September 30, 2012 and year-to-date earnings have been negatively impacted by onetime charges. During these nine months we have recorded approximately $4.2 million in non-cash impairments including $2 million impairment on Remington Village, $1.8 million impairment on our corporate aircraft and $523,000 ceiling test write-down on our oil and gas assets. In the financial and operational release that went out last Friday, we presented an EBITDAX table showing earnings before interest, income taxes, depreciation, depletion and amortization, accretion of discount on asset retirement obligations, non-cash impairments, unrealized derivative gains and losses, and non-cash stock compensation expense. We use this non-GAAP measure internally to manage our business and believe it is a valuable tool in measuring operating performance. EBITDAX was $9.8 million for the nine months ending September 30, 2012 an increase of 66% from $5.9 million for the same period of 2011. A reconciliation of EBITDAX to net income is presented in the earnings press release which was published on Friday, November 9 and is available on the Company’s website for review. Similar improvement is reflected in our cash flow from operations which increased from $2.4 million during the nine months ended September 30, 2011 to $9.3 million during the same period of 2012. As Keith noted, during the nine months ended September 30, 2012 our operating revenues increased to $24.5 million as compared to revenues of $22.1 million during the nine months ended September 30, 2011. This 11% increase was primarily due to higher oil sales volumes in 2012. Our average realized price for the nine months ended September 30, 2012 improved to $72.71 per BOE from $68.31 per BOE during the nine months ended September 30, 2011. Lease operating expense per BOE including work-over cost was $15.83 for the nine months ended September 30, 2012 compared to $20.07 per BOE for the nine months ended September 30, 2012 is down primarily due to lower work-over costs in 2012. Our DD&A rate was approximately $32.89 per BOE for the nine months ended September 30, 2012 compared to $30.17 per BOE for the first nine months of 2011. Moving to the three months ended September 30, 2012 our operating revenues decreased by $769,000 to $7.6 million as compared to revenues of $8.4 million during the three months ended September 30, 2011 primarily due to lower natural gas sales from Gulf Coast wells. Our average realized price for the three months ended September 30, 2012 improved to $72.03 per BOE from $69.95 per BOE during the same period in 2011. Lease operating expense per BOE including work-over cost was $15.95 for the three months ended September 30, 2012 this rate compares to $15.07 per BOE for the three months ended September 30, 2011. Our DD&A rate was approximately $32.15 per BOE for the three months ended September 30, 2012 compared to $32.13 per BOE for the same period of 2011. We continue to focus on cutting our costs and as a result general and administrative costs were down $170,000 and $1.1 million during the three and nine months ended September 30, 2012 respectively from the same period in 2011. Through our hedging program we have had 600 barrels of oil per day through 2013 using costless collars. Our weighted average floor price for October, 2012 through December, 2013 is $90.66 per barrel and our weighted average ceiling price is $104.76. Finally at September 30, 2012 we remain in good position to fund our forward drilling programs with $3.7 million in cash and cash equivalents, working capital of $13.9 million and $22 million in borrowing capacity remaining under our $30 million line of credit with Wells Fargo. I would now like to turn the call back over to Keith Larsen for the Q&A session. Keith G. Larsen: Thanks, Steve. That concludes the prepared remarks that we have today. Operator, would you please open up the Q&A session.

Yes, sir. (Operator Instructions) Our first question comes from Curtis Trimble with Global Hunter Securities. Please go ahead, your line is open. Curtis Trimble - Global Hunter Securities: Hi, good morning everyone. Looking at Daniels County, in Montana, kind of first off, has the partner permitted that initial well that they committed to drill yet? Keith G. Larsen: They have not. Curtis Trimble - Global Hunter Securities: And, I guess, looking at participation, uses of the capital for the fourth quarter; can you kind of benchmark maybe a range of capital expenditures expected and maybe number of wells that you would expect to participate in for the fourth quarter? Keith G. Larsen: Probably in the neighborhood of $5 million to $7 million is what what's been in the last two months. Curtis Trimble - Global Hunter Securities: And number of wells maybe on a gross or net basis or maybe just put a range on that one. Keith G. Larsen: Well, they’re predominantly probably going to be the Williston Basin wells, so probably 0.4 or 0.5. Curtis Trimble - Global Hunter Securities: Thank you very much. Keith G. Larsen: All right. Thanks, Curtis.

Thank you, sir. Our next question comes from Jeffrey Connolly with Brean Capital. Please go ahead, your line is open. Jeffrey Connolly - Brean Capital, LLC: Hi, good morning. Keith G. Larsen: Good morning, Jeff. Jeffrey Connolly - Brean Capital, LLC: You guys reached the pooled payout on the second group of Brigham wells in this recent quarter? Keith G. Larsen: We have not – we have not reached payout on the first group either. Jeffrey Connolly - Brean Capital, LLC: Okay. And then do you still expect the first group will be in the first quarter of 2013, or can you update us on when you expect the pooled payout to kind of hit? Keith G. Larsen: Mid-year of 2013 and probably because of a large work-over that we had in the first group, both groups will payout at about the same time. Jeffrey Connolly - Brean Capital, LLC: Okay. All right. Thank you. Keith G. Larsen: Thanks, Jeff.

Thank you, sir. Our next question in queue comes from the line of George Gaspar. Please go ahead, your line is open. George Gaspar - Robert W. Baird & Co.: Can you talk about the forward expenditures on a more detail? Could you outline what you’re projecting in terms of drilling expenditures for the fourth quarter and at this point what your drilling program expenditure target is for 2013, and could you talk a little bit about how you expect to finance it? Keith G. Larsen: Sure, George. First of all I think we’re going to spend somewhere in the neighborhood of $5 million to $7 million, the final part of November and December and that will predominantly and in fact all of it will be in the Williston Basin and that depends on weather and performance of the operators. So, probably 0.4 or 0.5 net wells. As far as our budget for next year, we're working on that currently with our partners and we will present that to our Board of Directors at our meeting in December for their approval. After that we will give guidance and put out what our budget is and what's been approved. George Gaspar - Robert W. Baird & Co.: Okay. Can you talk a little bit about what your assumptions are and where are you going to concentrate your effort next year relative to performance from the overview from this year? Keith G. Larsen: Well, obviously we’re going to continue our program up in the Williston Basin and in fact we’re seeing additional non-op packages that are coming to us. It depends on how we do on these two possible completions down in this Texas program that we did with Mueller. We haven’t produced the wells yet, but they’re looking promising and if we do get some success there, there will be some additional development down there, and it’s just too early to tell down there. But obviously through our cash flow and through our debt, we feel that we’re well funded going into next year and we’ll stick to that. George Gaspar - Robert W. Baird & Co.: Okay. And then -- and my second question was going to be, on the two wells that you made reference to in Texas. Can you explain a little bit about, if I remember originally there was apparently just one well that looked like it had some potential, and then now you got two wells here suggesting currently, so could you suggest -- could you tell us a little bit about the depth, what you’re trying to do actually and try to bring these wells to some type of production? Keith G. Larsen: Yeah, well we still have one Woodbine well, that we believe we’ve got some up dip if you well, that, that we plan on drilling that sometime in the future, maybe the first quarter. The other two were formations that were bit of a surprise when we were going after that down dip and we still have to do some testing, they’re both shallower, one is gassy and one is oily. George Gaspar - Robert W. Baird & Co.: Okay. And do you have any target on what you could maybe when you get a handle on what the potential might be there? Keith G. Larsen: It’s just too early George to tell. I could guess, but I’d prefer that we wait for the results and then once we do some infill drilling then we’ll define both formations better. George Gaspar - Robert W. Baird & Co.: In terms of speaking about infill drilling there, how much of the – in terms of the shallower formation that you’re attempting to get a completion on how extensive is that shallower formation and the acreage that you have at this point in time? Keith G. Larsen: That’s just too early to tell George, it’s not a seismic play and there are thin seams, they’re only 10 to 12 foot thick. So, we would just have to keep drilling it out until we find what the boundaries are on it. So, it’s just early to say. George Gaspar - Robert W. Baird & Co.: Okay. Thank you. Keith G. Larsen: Thanks, George.

Thank you, sir. (Operator Instructions) I guess we have a follow-up question from George. Please go ahead, your line is open. George Gaspar - Robert W. Baird & Co.: All right, thank you. Keith, about the Eagle Ford, you mentioned about this well structure that apparently the Buda that … Keith G. Larsen: Buda.

… Buda, excuse me – that’s apparently evident – potentially evident in acreage that you have under your control with your partners. Exactly how far – can you give us an idea how far are we – the indicated success in that formation is from where you might be able to drill? Keith G. Larsen: Sure. What they did is they’ve drilled five wells now, which is an indication to me that they’ve had some success. And they are within a half a mile east of our boundary in the Booth-Tortuga area. George Gaspar - Robert W. Baird & Co.: Okay. All right. And what's the depth on that formation well to what you’ve drilled up to in the first wells? Keith G. Larsen: It’s right below the Eagle Ford. George Gaspar - Robert W. Baird & Co.: I see. Keith G. Larsen: So, we’re talking about [6,500] feet, something like that. George Gaspar - Robert W. Baird & Co.: Okay. And then a question on the real estate project, can you bring us up to date on what's going on there as far as your utilization, your occupancy and what your thoughts are going forward on that; is there any interest showing up and do you actually have it on the market yet, and could you talk a little bit about what your thoughts are in there? Mark J. Larsen: Yeah, George this is, Mark. We have relisted the property. George Gaspar - Robert W. Baird & Co.: Okay. Mark J. Larsen: We're focusing primarily right now on reduction of expenses associated with the property. I think we’ll have -- we will have some success there. The marketing effort again is early stage, but we’re going to put it out there, we see it as a non-core asset, and we will like to sell it. So, we’re moving in that direction, both on the sales side as well as cost reduction -- expense reduction. George Gaspar - Robert W. Baird & Co.: Okay, all right. And one question generally about, with the pressure on the stock here and to its current price level; is there any entertaining of the possibility of buying stock back, I know that, that’s different than drilling wells, but at this price level relative to your book, is that not a reasonable approach or is it just that the financial situation wouldn’t allow it to happen? Mark J. Larsen: Well, George anything that we did right now, we would have to take that out of our debt facility. George Gaspar - Robert W. Baird & Co.: I see. Mark J. Larsen: And I don’t think that we will be taking debt down to buyback our stock. We need that money to generate additional revenues in the drilling of the wells. George Gaspar - Robert W. Baird & Co.: Okay, all right. And can you just relate a little bit about, you talked about average pricing on a per barrel basis nine months a quarter, in this was it $72 range. How are prices, I know the market’s pulled back in WTI. How would you be looking at your average price today in the fourth quarter relative to third quarter, what kind of a dip would you have in there? Mark J. Larsen: Of all things George, and you and I’ve talked about this before, we got hit in that third quarter with the differential from the Bakken prices to WTI. They got a size $20 plus for sometime in there and recently we’ve seen that narrow down and to even less than $5 a barrel. And so, if those prices hold and I think probably everybody is aware the unit trains that they put in and they’ve build a lot of capacity up there. They’re also putting in additional pipelines and they’re going to need it. They’re up to 700,000 barrels a day at Bakken wide. So those are the factors that are going to affect us as well as the price moving up and down, but I think we got down some time in July, August when we were only getting $65, $70 a barrel. That was even with us at $85 or $90 and additionally that’s why we and I believe others have had 600 barrels a day and an average price of about $90 on the floor and about $105 on the ceiling. So, we think we’re protecting our cash flow in that regard. George Gaspar - Robert W. Baird & Co.: I see. Okay, and as far as the view on forward pricing differential, do you think that it’s going to be narrower because of the ability to evacuate more oil out of the area by tanker, and it seems like it’s going that way. Does that influence the differential? Mark J. Larsen: Sure it does. That’s all takeaway capacity influences and probably George, what we’re going to see is some areas of that spreads going to get bigger and then that’ll overbuild and it will narrow down because of the stories I’ve heard they’re going to take it up to over a million barrels a day and until that transportation constrainments taken care of once and for all, you’re probably going to see some volatility there. George Gaspar - Robert W. Baird & Co.: Okay. And then your production per day was of course in 1100 plus range. Was that impacted at all in the third quarter by work-over and what are you experiencing this quarter in terms of work-over that would tend to slow production. Give us some thoughts on that. Mark J. Larsen: Well, now that we’re involved with the number of wells what we are seeing additional workovers as well as just the age of the wells. And in my opinion just looking back at it, I haven’t looked at it statistically, but we didn’t do a lot of workovers in the third quarter. Currently we don’t have a lot of workovers going on, but we’re bringing on – just putting on pump – some wells with Zavanna and of course your downtime there to install the pumps and so forth and you’re not going to have any oil until they get put on. So overall, I think we’re starting to get stable production. We are involved in enough wells where we can start building from here. These wells are going to be 20-year plus wells up in the Bakken and they’re going to have some workovers. But the LOEs on these – on the barrel per oil, we think it’s real reasonable. As I mentioned, just about the payout, probably mid-year next year on that first set of 10 wells with Brigham. It took a bit longer and what we’ve had anticipated, but once we get to that point and that’s just generating additional cash flow. So we’re pleased with what we’ve got. George Gaspar - Robert W. Baird & Co.: Okay. Right. Thank you. Mark J. Larsen: Thanks, George.

Thank you, sir. And presenters, there appear to be no further questions at this time. Do you have any closing remarks? Keith G. Larsen: Yeah, I’d like to end the call by stating that our drilling programs have remained very active through 2012 and expect steady drilling in 2013. We are working with our partners to develop our 2013 budget and proposed drilling schedule in order to provide the market with a look at our growth potential as we move into the next full-year of drilling and completing wells. We also have a tremendous opportunity to create value for our shareholders with the Mount Emmons project. I look forward to updating you on the progress, certain milestones are met. We’ve made significant strides in reducing the Company’s overhead and it’s our ultimate goal to continue to grow our portfolio of producing assets and to create long-term value for the company shareholders. I like to thank everybody in the audience for joining us today and we look forward to the next call.

Thank you, sir. This concludes today’s conference call. You may now disconnect.