Mark Larsen - President and Chief Operating Officer Keith Larsen - Chief Executive Officer and Chairman Steven Richmond - Chief Financial Officer

Noel Parks - Ladenburg Thalmann Evan Richert - Sidoti & Company Curtis Trimble - Global Hunter

Good morning. My name is Danielle, and I will be your conference operator today. At this time, I would like to welcome everyone to the U.S. Energy Corp third quarter 2013 selected highlights, operations and financial results conference call. (Operator Instructions) I would now like to turn the conference over to Mr. Mark Larsen, President of U.S. Energy Corp. Sir, you may begin your conference.

Good morning, ladies and gentlemen, and thank you for joining us today. With me this morning is Keith Larsen, CEO; and Steve Richmond, the company's Chief Financial Officer. In terms of an agenda, Keith will provide you with an overview of the highlights and operating initiatives for the three and nine months ended September 30, 2013. Steve will then conduct the financial review portion of the call, and we'll finish up with a question-and-answer session. As a preliminary matter, I would like to note that during this call, we may make forward-looking statements which maybe identified by the words will, anticipate, expect, and similar words that are based on the beliefs and assumptions of U.S. Energy's management. These and all statements other than statements of historical fact are forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934 and Section 27A of the Securities Act of 1933. The forward-looking statements are subject to numerous risks and uncertainties, including those described in the Form 10-Q for the quarter ended September 30, 2013, which we filed on Friday, November 8, and our other filings with the SEC, all of which are incorporated herein by reference. I'd now like to turn the call over to Keith.

Thanks Mark, and good morning, ladies and gentlemen. To begin today's call, I'd first like to thank the audience for attending our conference call and for following the company's progress throughout 2013. During the quarter, the company produced 101,987 barrels of oil equivalent, which is an average of 1,109 barrels of oil equivalent per day, net to the company. This production comes from 101 gross, 15.1 net producing wells, primarily located in the Williston Basin of North Dakota. Production has remained stable during the first three quarters of 2013 at approximately 1,100 net barrels of oil per day to the company. As a result of our continued oil and gas development throughout 2013, the company recognized revenues of $24.4 million during the first nine months of 2013 and had working capital of $5.1 million at quarter's end. Moving on to our oil and gas initiatives. As many of you may know, we have recently moved our primary focus towards our South Texas drilling program with Contango Oil & Gas, specifically towards the development potential of the Buda Limestone formation. The company participates with Contango in approximately 10,140 gross, 3,042 net acres in the Booth-Tortuga acreage block in Dimmit County, Texas, which are prospective for the Buda Limestone, the Georgetown, the Pearsall and other formations. The company has an approximate 30% working interest and approximate 22.5% net revenue interest in the acreage. The first Buda Limestone formation test well for Beeler number 2H well, was drilled to a total measured depth of 11,013 feet, including a 3,700 foot lateral. The well was completed open hole without fracture stimulation. The well had an early 24-hour initial production rate of 859 BOE per day. The well has produced approximately 102,500 gross BOE through October 31, 2013. Once the well began producing, we receive payout in four months. In July 2013, the operator spud the Beeler number 3H. The well was drilled to a total measured depth of 10,800 feet, including a 3,215 foot lateral, was completed naturally without fracture stimulation, and commenced production in September at a peak 24-hour initial rate of 1,260 BOE per day, 92% oil, and have a thirty-day average production rate of 859 BOE per day. In September 2013, the operator spud the Beeler number 4H. The well was drilled to a total measured depth of 11,350 feet, including a 3,777 foot lateral. The well was completed naturally without fracture stimulation, and commenced production at a peak 24-hour initial production rate of 1,430 BOE per day, 84% oil, and a thirty-day average production rate of 1,190 BOE per day. Contango is now drilling the Beeler 5H. The well is currently drilling at a depth of 7,696 feet, with a planned 3,636 foot lateral. We and Contango currently expect this rig to remain active in the area for the remainder of this year and throughout 2014 to continue to delineate and evaluate the Buda potential over a larger area than has currently been drilled. On August 5, 2013, under an area of mutual interest election, the company also acquired a 15% working interest, approximately 11.25% net revenue interest, in an additional 4,243 gross, 636 net acres from a private oil and gas company based in San Antonio, Texas, bringing our total acreage in the play to 14,383 gross and approximately 33,700 net acres. The new leasehold is contiguous to the southwestern portion of the Booth-Tortuga acreage block held with Contango. The initial well on this acreage, the Willerson number 1H well, targeting the Buda formation, was recently completed at a total measured depth of 11,030 feet, including a 3,300 foot lateral. Initial flow rates has been very positive, and we will continue to monitor the well and observe performance before releasing results from this well. Now, I'll move on to the Williston Basin of North Dakota. We participated in 65 1,280 acre spacing units in the basin under three active programs. At September 30, 2013, we had 82 gross, 10.1 net producing wells and 9 gross, 0.18 net wells being drilled or waiting completion. During the nine months ended September 30, 2013, we averaged 878 net BOE per day from this segment of our business, which accounts approximately 80% of our net daily production profile. As you can see from our release published this morning we continue to actively participate in the drilling and completion of numerous new wells in the basin in order to maintain our stabilized base production from this region. I will now turn to Mount Emmons molybdenum project located in Gunnison County, Colorado. During the second quarter of 2013, the company received a letter from the U.S. Forest Service notifying the company that it had completed a review of the Mine Plan of Operations for the Mount Emmons molybdenum project in Colorado and that it has determined that the Mine Plan of Operations does contain sufficient information and clarity to form the basis for a proposed action to initiate scoping and analysis under the National Environmental Policy Act, NEPA. The letter also states, U.S. Energy has met the requirements of the Reality Check provision granting conditional water rights for the Mount Emmons molybdenum project by filing the plan for the Mount Emmons mine with the Forest Service. No other special use permits or rights-of-way for the water facilities are required because they are addressed in the plan. The MPO provides an in-depth description of the proposed construction, mining, processing, and reclamation operations for the project. During the third quarter the company initiated scoping analysis of the MPO with the U.S. Forest Service and anticipates that such work will continue through the balance of 2013 and into 2014. In addition to working towards advancing the mine plan, we also continue to work towards our goal of monetizing the project outright by continuing to implement efficiencies and cost reduction methods at the site in an effort to reduce overall holding cost with the project. I'd like to now turn the call over to Steve Richmond, the company's Chief Financial Officer to review the financial portion of the call.

Thank you, Keith. During the quarter ended September 30, 2013, we recorded a net loss of $134,000 after taxes, or $0.03 per share as compared to a net loss of $1.9 million, or $0.07 per share for the quarter ended September 30, 2012. Operating revenues for the quarter increased by $943,000 to $8.6 million as compared to revenues of $7.6 million during the quarter ended September 30, 2012. The increase in operating revenue was primarily due to higher realized oil prices in the third quarter of 2013 as compared to same quarter in 2012. Our average realized price for the quarter ended September 30, 2013 improved to $84.15 per barrel of oil equivalent from $72.03 per BOE during the third quarter of 2012. Lease operating expense per BOE including work over costs was $19.67 per BOE for the quarter ended September 30, 2013. This rate compares to $15.95 per BOE for the same period in 2012. Our DD&A rate was approximately $31.43 per BOE for the quarter ended September 30, 2013 compared to $32.15 per BOE in the same period in 2012. During the nine months ended September 30, 2013, we reported a net loss of $6.2 million after taxes or $0.22 per share as compared to a net loss after taxes of $3.3 million or $0.12 per share for the nine months ended September 30, 2012. Our 2013 earnings were negatively impacted by a $5.8 million non-cash ceiling test write-down on our oil and gas assets that we took in the first quarter of 2013. During the nine months ended September 30, 2013, operating revenues were $24.4 million as compared to revenues of $24.5 million during the nine months ended September 30, 2012. The decrease in operating revenue was primarily due to lower oil and sales volumes in 2013 as compared to 2012, which was partially offset by higher realized oil prices in the nine months ended September 30, 2013 as compared to the same period in 2012. Our average realized price for the nine months ended September 30, 2013, improved to $80.80 per BOE from $72.71 per BOE during the same period in 2012. Lease operating expense per BOE including work over cost was $19.02 per BOE for the nine months ended September 30, 2013. This rate compares to $15.83 per BOE for the nine months ended September 30, 2012. Our DD&A rate was approximately $32.75 per BOE for the nine months ended September 30, 2013 compared to $32.89 per BOE in the same period in 2012. We continue to focus on cutting our costs and as a result general and administrative costs were $322,000 lower during the three months ended September 30, 2013 as compared to the same period in 2012, and $1.4 million lower in the nine months ended September 30, 2013 as compared to the first nine months of 2012. In the financial and operational release that went out earlier today, we presented a modified EBIDTAX table showing earnings before interest, income taxes, depreciation, depletion and amortization, accretion of discount on asset retirement obligations, non-cash impairments, unrealized derivative gains and losses and non-cash stock compensation expense. We use this non-GAAP measure internally to manage our business and believe it is a valuable tool in measuring operating performance. Earnings before modified EBITDAX was $11.5 million for the nine months ended September 30, 2013, which is a 16% increase over the modified EBITDAX of $9.9 million for the same period in 2012. Through our hedging program, we have hedged 600 barrels of oil per day through June 30, 2014 and 300 barrels of oil per day from July 1, 2014 through December 31, 2014 using costless collars. Our weighted average core price for October 1, 2013 through December 31, 2014 is $90 per barrel and our weighted average ceiling price is $97.05 per barrel. On September 11, 2013, the company completed the sale of the Remington Village Apartment Complex located in Gillette, Wyoming to an affiliate of the Miller Frishman Group, LLC for $15 million. The related commercial note in the amount of $9.5 million was paid in full at closing and net proceeds to the company were approximately $5 million as a result of the sale. Finally, at September 30, 2013, we remain in good position to fund our forward drilling programs with strong cash flow from operation, $5.5 million in cash and cash equivalents, working capital of $5.1 million and $18 million in borrowing capacity under our $25 million line of credit with Wells Fargo. I'd now like to turn the call back over to Keith for the Q&A session.

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

(Operator Instructions) And your first question comes from the line of Noel Parks from Ladenburg Thalmann. Noel Parks - Ladenburg Thalmann: With the results that you have of the two additional Buda wells, could you just talk a little bit more about sort of your current understanding of the play and your acreage, with these solid results ramping the other, are you now thinking that there is a pretty good chance that most of the acreage will work?

Noel, certainly on the eastern portion of the acreage, we've got three wells and the fourth one being drilled now, and also that at least on the eastern ports we have higher confidence that that could turn into more development, but we really haven't drilled out to the outer edges on the western portion. So we're cautiously optimistic and continue to de-risk additional acreage as we go and that's why we're going to keep the rig working throughout next year. Noel Parks - Ladenburg Thalmann: In the financials, you were talking about the G&A trend. Now, that you know that you've got the rig definitely active for next year and then you also have molybdenum scoping, is it the low point and do you think G&A will keep up going forward or do you accept that might even head down from here in the next few quarters?

I will expect the G&A will probably creep minimally upward and we're probably at the low point at this time, Noel. Noel Parks - Ladenburg Thalmann: And I guess, just my last thing is back to the Buda, is the thinking still that completions are going to be essentially open hole going forward or any thoughts of trying to do something more aggressive in stimulation or is that even needed?

Noel, I think that after these wells deplete, and probably have some time on them, aren't producing as well as they are now, but probably they will be looking at some additional stimulation, but I guess the way it is now when you have a good thing, don't mess with it.

And your next question comes from Evan Richert from Sidoti & Company. Evan Richert - Sidoti & Company: I hopped on the call bit late, so apologize for any redundancy. What are the drilling times on these dealer wells? Is that being consistent or any variation there?

With any drilling you do have some mechanical problem sometime. I think the shortest time that we had on one of the wells was around 25 days and we've been up over 35 days on others. And I think, Evan, as we go both operators are going to learn more and more and they're going to be using the same rig hopefully, so that those crews will understand what we're trying to do and both the drilling time and the costs or the cost associated we expect to come down. Evan Richert - Sidoti & Company: And what's the average cost on those right now?

The AFPs right now $3.8 million. Evan Richert - Sidoti & Company: And what kind of spacing are you using on those?

They are 320s, and probably you like other folks -- we've heard that Dan Hughes had a hearing in downsize to 160s, so there is a potential to go down to 160s, but currently we have on 320s, 30 to 40 locations if the entire acreage pans out, and of course, that's a big if. And if they go down further to 160s, you can do the math, so we have a lot of running room for a company of our size, a three or four year inventory potentially. Evan Richert - Sidoti & Company: And then any communication you had with the operator about anything they've seen leading to different results to one part of the acreage or the other, obviously there's has only been a couple of wells so far, but as far as decline rates are, any differences in IP?

We saw that at number 4 well, which has been the best one we've had today, and it came on at some 1,430 BOE and basically oily. So we're kind of pleasantly surprised, as we continue to program and we just hope that continues. We probably are going to hit some areas where they're not as good, but we're hoping that as we continue to go, we continue to have success we're having. And yes, we do talk to the operators frequently and they keep us updated on whether we see the geo-steering and so forth. So we're in at least weekly contact with both operators. Evan Richert - Sidoti & Company: And any CapEx plans for 2014 here?

We're just working on our budget as we speak, to be approved in December, and we'll announce our budget after that approval. Evan Richert - Sidoti & Company: And then, as you're communicating with the operators, any expectation that at some point in '14, if the results keep being strong that you'll look to bring in another rig?

Certainly, that has been discussed even initially. But I think that we need to have more success before we make that decision. And U.S. Energy would be prepared to add a second rig if that's the decision. Evan Richert - Sidoti & Company: And then, obviously the Budas where you're looking now, any plans for whatever your CapEx is for '14 to go anywhere else in the Bakken or Williston, or is it pretty much all go into the South Texas?

So South and East Texas both, we're looking at prospects in both. And some stuff in Kansas and Nebraska. But pretty much we want to get a real good feel for how much success we're going to have here in the Buda first. But we continue to look at prospects across the west.

And your next question comes from Curtis Trimble from Global Hunter. Curtis Trimble - Global Hunter: So looking at a little bit further on the transom from the Buda well, and kind of get an idea of your appetite for picking up some additional working interest maybe in some other plays or other things that are you're getting it right on stream now, outside of what you got on the docket right now?

Well, pretty much we've been focused in South Texas looking at other areas for potential for the Georgetown, the Buda and the Pearsall. There is some good buying stuff in East Texas that we've looked at, but pretty much we've been focusing on South Texas. Curtis Trimble - Global Hunter: And how much you think maybe even with the down-spacing, do you think some other acreage shake or loose there or there are some land that are associated maybe can't fund the well and are looking to monetize things in the near-term?

Well, pretty much in this neck of the woods, everything is leased up, mainly for the Eagle Ford. So if we do find additional acreage, it would probably have to be with an additional operator down there somewhere, at least in the meetings area that we're in, in the Booth-Tortuga area.

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

I'd just like to thank everybody for your support and being patient on this Buda. Certainly hope that we continue to have success down there and we fully expect to have additional success down there. Thanks to everybody for joining the call. And we look forward to updating you after the yearend results.

This concludes today's conference. You may now disconnect. Everyone have a great day.