US Energy Corp (USEG) 2010 Q4 法說會逐字稿

Good morning, my name is Javon and I will be your conference operator today. At this time I would like to welcome everyone to the U.S. Energy Corp. 2010 year-end selected highlights financial results and operations update. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator Instructions). Thank you. I would now like to turn the conference over to Mr. Mark Larsen, President and Chief Operations Officer of U.S. Energy Corp. Sir, you may begin your conference.

Thank you, Javon, and good morning, ladies and gentlemen. Before we get started I'd like to point out there is a slide presentation to accompany this call which can be accessed via the home page of our website at www.USNRG.com. The slide presentation is located in the upper left-hand corner of the page.

With me this morning are Keith Larsen, Chief Executive Officer and Board Chairman, and Scott Lorimer, our Chief Financial Officer. In terms of an agenda for today's call, please see slide 1 for an outline of the topics we will discuss during the call today. We will review our operational highlights for the year as well as the period subsequent to year end, provide you with an update on our various operating initiatives and we'll conduct a brief financial review before taking your questions.

Before I turn the call over to Keith, I would like to draw your attention to the Safe Harbor disclosure slide which is slide 2 in the presentation. Please take a look at that for a moment.

During the call and the review of our slides we may make forward-looking statements which may be identified by the words could, anticipate, expect and similar words that are based on the beliefs and assumptions of U.S. Energy's management and on information available to the Company within the meaning of Section 21e of the Securities and Exchange Act of 1934.

You should consider the information provided by officers in the context of the disclosures provided in the Form 10-K for the year ended December 31, 2010 which we filed yesterday, including the cautionary statement regarding forward-looking statements. I'd now like to turn the call over to Keith Larsen, CEO of U.S. Energy Corp.

Thank you, Mark, and good morning, ladies and gentlemen. 2010 was another banner year of growth in the E&P sector for U.S. Energy Corp. We expanded our strategic partnerships for the benefit of shareholders, continued to increase our production across the portfolio, witnessed significant initial production rates from our Bakken oil wells and added acreage in several core areas.

From a strategic standpoint, in 2010 we continued to expand our E&P portfolio on multiple fronts with a diverse range of operating partners. Moving on to slide 3 of the presentation -- we believe this strategy is the prudent way to gain exposure in a number of attractive oil and gas regions, including the Williston Basin of North Dakota, the Permian and Eagle Ford plays in Texas, on shore Gulf Coast and the San Joaquin basin in California.

Looking at the map you can see that we now have multiple prospects with geographic and regional diversity. Of the prospects highlighted, six of them involve partnerships with experienced operators that have active or soon to be active drilling programs. Concurrent to these non-operated initiatives we're also in the process of transitioning to operations on our own behalf in Southeastern Colorado through a promising new acquisition as we recognize that a company our size needs to grow into the role of operator ship and we're taking steps to do so.

Turning to an overview of our 2010 operational highlights for the year ended December 31, 2010, we drilled 13 gross and 3.33 net wells and realized 100% success rate in our drilling initiatives in the Williston Basin. As a result we recognized record revenues from oil and natural gas production of $26.5 million. During the year we produced 448,000 barrels of oil or 1,230 barrels of oil per day which was an increase of 173% from our 2009 production.

Now turning to slide 4. At December 31, 2010, and as verified by our two independent third-party reserve engineers, Ryder Scott and Cawley, Gillespie, our proved reserves totaled 1,955,000 barrels of oil replacing 193% of 2010 production. The total is comprised of 1,550,000 barrels of oil, 2.1 Bcf of natural gas and 52,000 barrels of natural gas liquids. At the year end 70% of our estimated proved reserves for producing 19% were proved developing non-producing and 11% were proved undeveloped with oil accounting for approximately 79% of this total.

Based on proved reserves our total estimated PV-10 value at year end was 52.1 million. These numbers represent an 80% increase in reserves and a 102% an increase in PV-10 value over December 31, 2009. Mark, I'd now like to turn it over to you. Could you continue, please?

Sure. We realized an average oil price in 2010 of $72.11 per barrel excluding the impact of our hedges or $5.89 per barrel higher than in 2009. Our average natural gas price realized during the year was $4.96 per Mcf or $0.66 per Mcf higher than 2009 price of $4.30 per Mcf.

Now moving on to slide 5 and looking ahead to the balance of the year, we anticipate spudding approximately 40 gross or 13 net wells with capital expenditures of approximately $45.7 million in our 2011 oil and gas drilling programs. The CapEx budget is comprised of approximately $33.2 million to be spent in the Williston Basin of North Dakota and the Rough Rider in Yellowstone and Southeast HR programs with Brigham Exploration and Zavanna respectively.

The remaining $12.5 million in capital expenditures is budgeted to be spent on exploration initiatives in California, Texas, Louisiana and for our Southeastern Colorado drilling program which we will operate. Amounts budgeted for each regional drilling program is contingent upon timing, well cost, availability of equipment and services and success of each program.

If our non-Bakken drilling initiatives in California and Colorado are not initially successful then funds allocated for those drilling programs will be allocated to other drilling initiatives in due course. The actual number of gross and net wells could vary in each of these cases and are also subject to change due to non-consents by other working interest partners.

Now I'd like to review our strategic partnerships in the Williston Basin and North Dakota. As we have been discussing over the past year, the partnership with Brigham Exploration has been very beneficial to the Company and our shareholders in that we have been able to leverage Brigham's operational expertise in the Bakken oil play to deliver consistently strong well results.

To date the Company has participated with Brigham in 18 wells. This figure is inclusive of 15 initial wells, one in each 1,280 acre spacing unit, which earned U.S. Energy its participated interest in each of the units. Of the 18 wells drilled in 2009 and 2010, 17 targeted the Bakken formation and one was a Three Forks test. 14 of these wells are producing including the Three Forks well and four are currently awaiting completion. It is anticipated that of the four wells awaiting completion one well will be completed in each month beginning in March of this year.

As it you can see on slide 6, all 14 wells have been completed with long laterals and a high number of fracture stimulation stages averaging an initial peak production, initial peak rate of production of approximately 2,500 BOE per day. I'm sure that most people on this call are aware that these wells have a steep initial decline once put on production which flattens to stabilize production within the first year.

Slide 7 of the presentation shows U.S. Energy Corp.'s production chart through December 30, 2010 since inception of the program. Now let's talk for a moment about our inventory and our future development drilling opportunities within the partnered acreage with Brigham.

Upon drilling and completing the 15th well in the Brigham program we will have earned the right to drill infill wells in both the Bakken and Three Forks formations in each unit. In 2010 Brigham drilled two infill development wells in the Brad Olson unit in which the Company participated. During the fracking of the Brad Olson 916 No. 2 well, Brigham conducted a micro seismic survey to interpret frac wing performance.

According to Brigham the subsequent data indicates that the frac wings appeared to extend laterally approximately 500 foot on either side of the well bore, or 1,000 foot in total per well. Based on one mile wide spacing unit and results from the micro seismic monitoring, Brigham recently announced that their findings appear to support development of at least four wells producing horizon per 1,280 acre spacing unit or approximately four each Bakken and Three Forks wells per spacing unit.

If this theory proves to be correct the spacing could allow U.S. Energy Corp. to participate in an additional 43 infill Bakken wells and 59 Three Forks wells within the 15 Brigham units. Overall this would suggest a total of 120 potential gross drilling locations in the Brigham program representing a multi-year drilling inventory. We are pleased with the initial results from the Brigham drilling program and we anticipate our 2011 program with Brigham will consist of four to six additional gross wells.

Continuing on, the success of our drilling program with Brigham led us to enter into two additional partnership agreements with Zavanna LLC in December 2010 with the acquisition of an additional 6,200 net acres in McKenzie County, North Dakota.

Now turning to slide 8 of the presentation you will see the participated acreage with Zavanna is outlined in blue and orange and is also in the core area of the Bakken play. That Yellowstone acreage block is located between two of our stronger producing wells, the Sedlacek Trust and the Papineau Trust wells. These two wells averaged an early initial peak rate of production of 2,870 BOE per day. The SE HR acreage block is located a bit further south of our participated acreage with Brigham.

Under the agreement we anticipate participating in 31 gross drill spacing units with Zavanna who will operate the program. In early 2011 Zavanna contracted the drilling rig for an initial three well program. Zavanna has drilled the first well, the Cheryl 14-23, to total depth. U.S. Energy Corp. has an approximate 34% working interest, 27% NRI in this well.

The second well, the Olson 8-15, is currently drilling in the horizontal portion of the well bore and is nearing TD. U.S. Energy Corp. has an approximate 30% working interest 23% NRI in this well. The third well, the Koufax 3-10, is planned to spud in early April in the SE HR leasehold. The Company has an approximate 13.1% working interest in 10.1% NRI in this well.

Zavanna plans to fracture stimulate the well using the slick water completion application and approximately 35 frac stages for these first three wells starting in July 2011. Subsequent to contracting the rig for the initial three wells in the program, in late February Zavanna contracted a precision drilling rig for a 12-month period starting April 1, 2011 through March 31, 2012. With this rig we plan to drill approximately one well per month from April 2011 through March 2012.

It is estimated that six of the new wells will be drilled into Yellowstone acreage block and four will be drilled in the SE HR acreage block during this timeframe. We have included our estimated working interest and estimated NRI interest in the red blocks on the map on slide 8 for your review. The average interest in all of the wells in the currently planned Zavanna drilling program, including the three wells previously mentioned, is approximately 22.5% working interest and 17.3% NRI.

Additionally, we recently signed an AFE to precipitate in the drilling of a Bakken well with Murex Petroleum Corporation in the Yellowstone AMI. This well is the result of an acreage trade within the Yellowstone leasehold between Zavanna and Murex whereby Murex will operate the well. Our interest in this well is approximately 9% with a 7% NRI. With the addition of the Murex well we are now drilling two Bakken wells in the Yellowstone acreage block. We also anticipate that Murex will drill an additional Bakken well on the Yellowstone leasehold in 2011.

The Company believes that the overall program with Zavanna could provide for the potential of up to 93 gross Bakken and 93 gross Three Forks wells under the three wells per formation per unit scenario. If you supply the most recent spacing estimation announced by Brigham the estimated well count could increase to 248 gross Bakken and Three Forks wells combined into 31 units.

U.S. Energy Corp. now participates in approximately 13,470 net acres in the heart of the Williston basin -- excuse me -- in the heart of the Williston Basin, Bakken and Three Forks play in North Dakota. This acreage position represents a chance to participate in approximately 276 to 368 gross drilling locations depending on ultimate spacing and the continued economic viability of the Bakken and Three Forks formations.

Also please note that on slide eight on the smaller map of the three states that in addition to our core acreage in North Dakota the Company disclosed in our 10-K filing that during the course of 2010 we acquired a 100% working interest in approximately 16,500 gross 11,600 net mineral acres of leases in Northeast Montana. This leasing effort is ongoing and we anticipate leasing up to 25,000 net acres total in this area.

At this time we are continuing to lease our target acreage at reasonable lease costs with the intent to develop acreage for our own right or to partner with an industry peer to test and develop the acreage. If initial if initial drilling results are successful. In addition to our Williston Basin assets, the Company realized stabilized production in the Gulf Coast region for four producing wells.

Turning to slide 9 of the presentation you will see that the Company has realized income from base production from two wells with our partner PetroQuest Energy and also from two wells with our partner Houston Energy. The CL&F No. 1 well began production in late 2008 in the ALMI number eight well has been producing since July of 2010. There are additional pay zones in both wells which are anticipated to be targeted once the initial producing formations are depleted.

Turning to slide 10 of the presentation, you will see we have developed a mix of additional drilling opportunities with proven regional operators and look forward to continuing to work with each to develop the targeted resources in the various prospects in which we participate.

I will now provide an overview on slide 11 of the Moose Prospect in Kern County California with Cirque Resources. In October 2010 we entered into an acquisition, exploration and development agreement with Cirque to acquire a 40% working interest in the prospect in the prolific San Joaquin basin of California.

Under the terms of the agreement USE is committed to pay approximately $2.5 million to earn a 40% working interest in approximately 6,120 gross 2,450 net acres and to carry Cirque for a component of its drilling cost casing point in a commitment well. If successful additional wells drilled will be on a heads up basis with each party participating for its proportionate share of the well cost.

Cirque is the operator of the project and the commitment well is tentatively planned to be spudded next month. The Moose Prospect is a Miocene target in the San Joaquin basin with an expected total drilling depth of approximately 13,000 feet. The commitment well is targeting up to 300 feet of layered Stevens sands in a stratigraphic trap on the flank of a prolific oil producing field in the basin.

Based on the results of the commitment well additional seismic analysis may be applied to further delineate the overall prospect and prospective drilling program. Geologic evaluation and current spacing suggest potential for up to 40 additional drilling locations.

Now moving on to slide 12 of the presentation and to our entree into operatorship in our Apache prospect located in Southeastern Colorado. The Company is participating in the prospect with an 80% working interest in approximately 3,000 net acres with a private group based in Denver, Colorado who will retain the remaining 20% interest in the prospect.

We anticipate spudding the initial test well in the prospect in June of this year targeting the Mississippian formation. The well is planned to be drilled to approximately 6,500 feet and is a conventional vertical well. If the initial test well is successful we believe that there is potential for an additional 40 wells on the acreage based on 80-acre spacing. We see this expansion into operatorship as an opportunity to drive our growth internally and to control our own pace of development.

Leasing on the prospect was recently completed and in the near future we will be applying for three well permits with the state of Colorado. The estimated dry hole cost for each well is approximately $250,000, so we view this project as one that represents a low-risk high potential return profile and we look forward to reporting results of the program in the coming months.

Now moving on to slides 13 and 14, I'd like to talk about our most recent announced entree into the oil window of the Eagle Ford shale. Slide 13 provides an overview of the prospect features which I will cover, and slide 14 provides detail about the location of the prospect, a type log from a nearby control well and star symbols representing recently drilled Eagle Ford wells in the area.

On February 18, 2011 we entered into a participation agreement with Crimson Exploration to acquire a 30% working interest in an oil prospect in Zavala County, Texas. Our initial target formation is the Eagle Ford shale. Under the terms of the agreement we will earn a 30% working interest, 22.5% NRI and approximately 4,700 gross 1,400 net contiguous acres through a combination of a cash payment and a commitment well carry.

Crimson will be the operator of the prospect and all future drilling and leasing will be on a heads up basis. We plan to spud the first well during the second quarter of 2011. The well is planned to be drilled to a total measured depth of approximately 12,500 feet which is 6,000 foot vertical and 6,500 foot horizontal and to be completed with approximately 14 fracture stimulation stages.

If successful the initial well is planned to be put on production for several months to evaluate well performance. And also if successful we anticipate that Crimson will propose an aggressive drilling program of up to 12 Eagle Ford wells in 2012. It is estimated that under current spacing in the area that there is potential for up to 26 gross, 7.8 net drilling locations on the acreage.

U.S. Energy and Crimson will also identify and plan to jointly seek additional opportunities in the Eagle Ford oil window with the intent of expanding our inventory for future development in the play. I want to make note to the audience that there is exploration risk in each of the above mentioned prospects.

We are excited about each of these new drilling opportunities as they each represent ongoing resource development potential which is our ultimate goal if the initial well tests are successful. If drilling success is achieved each one of these prospects could provide a significant drilling inventory and growth opportunities for the Company.

Turning to the other areas of our business, our nine building, 216 unit multi-family apartment complex averaged 90% occupancy during 2010. The property generated positive cash flow from operations of $1.2 million during the year and is wholly owned by the Company. However, based on the anticipated ramp of drilling activity in 2011 and beyond, the Company has decided to finance the project in the short term as well as list the property for sale.

In order to access our equity in the project an appraisal was ordered late in 2010. The results of the appraisal reflected a value of $21 million which resulted in a $1.5 million impairment at December 31, 2010. The Company has no future plans for real estate development as it is clearly focused on development of its oil and gas initiatives. It is our goal to sell this property in 2011.

I'd now like to briefly discuss the status of our Mount Emmons molybdenum project. Moving on to slide 15 you will see an artist's rendition of the deposit within Mount Emmons. Our partner is Thompson Creek Metals which operates the project. Thompson Creek is currently drawing up an anticipated underground drilling program which is evolving as engineering work continues to be refined. We don't yet know when the drilling program will be finalized and initiated.

In late December we received our $1 million option payment for 2011. f For 2011 and looking forward Thompson Creek is still determining the annual budget amount taking into account the ongoing engineering and drilling plan analysis.

In closing on this subject, I think what investors should continue to bear in mind regarding this project is that it remains a long lead time project. However, we are delighted with the work that Thompson Creek has done to date, both professionally and particularly in the Gunnison County Colorado community and we look forward to writing future progress reports as warranted.

I'd now like to turn the call over to Scott Lorimer, the Company's CFO, to review the financial portion of the call.

Thank you, Mark. As Keith mentioned, 2010 was a year of significant growth for the Company. As compared to 2009 revenues increased by 163% to $27.2 million, cash flow from operations increased 385% to $12.4 million. Our oil production increased 173% to approximately 449,000 barrels of oil equivalent for the year and reserves increased 80% to nearly 2 million barrels of oil equivalent at year end.

Primarily due to the increased oil production from our Williston Basin drilling program and improved oil and gas prices, oil and gas revenues increased from $7.6 million in 2009 to $26.5 million in 2010. Oil and gas operating expenses increased $1.1 million in 2009 to $6.1 million in 2010. And DD&A increased from $3.6 million in 2009 to $10.6 million at 2010. As a result net operating income from oil and gas segment increased nearly 450% from $1.5 million in 2009 to $8 million in 2010.

Through our wholly-owned subsidiary, Energy One LLC, we also enhanced our financial flexibility through the establishment of a $75 million senior credit facility with BNP Paribas. The current borrowing base under the facility is $18.5 million. We expect, based on our year-end reserves that this could be adjusted upward at the next determination date.

At year end we had not drawn any funds on the facility; however, we did borrow $3 million in February of 2011 to fund a portion of our participation in the Eagle Ford shale project in Texas with Crimson Exploration. Additionally, during 2010 we established a hedging program which consists of a WTI oil costless collar or 200 barrels per day at a floor of $[75] and a ceiling of $83.25 and 2 WTU swaps for 200 barrels per day each at $79.05 and $89.60.

As a result of the increasing oil prices we recorded a realized loss of $156,000 and an unrealized loss on these hedges at December 31, 2010 of $1.7 million. Revenues for our real estate operations for the year were $2.5 million and the property casual approximately $1.2 million in 2010.

In addition, at December 31, 2010 management determined that an impairment in the amount of $1.5 million existed on the long-term assets as of December 31, 2010 appraised -- as the December 31, 2010 appraised by you was less than net book value of the asset. In 2011 we decided to sell this property and we used the funds to finance our oil and gas programs.

Additionally, as a result of the sale of its geothermal properties we recorded a $1 million gain on our investment in Standard Steam Trust. During the year ended December 31, 2010 we reported a net loss after taxes of $772,000 or $0.03 per share as compared to a loss of $8.2 million or $0.38 per share during the prior year. Contributing to this loss amount were the non-cash charges of $1.5 million impairment on Remington and $1.7 million -- $1.9 million on the hedges at year end.

Moving to the balance sheet, the Company had cash and cash equivalents of $6 million plus marketable securities of $19.2 million, $17.8 million of which were US treasuries at December 31, 2010. Working capital at year end was $11.1 million, down from the prior year due to the funding of our ongoing oil and gas initiatives.

In summary, during the year we continued to advance our oil and gas operations and ended 2010 with improving trends in revenues, production and cash flow. Our year-over-year improvement in these areas demonstrates the progression of our programs as we advance them through the drill bit.

We look forward to reporting the results of our 2011 initiatives and their impact on the Company's bottom line as we continue to grow into the E&P sector. I'd now like to turn the call back over to Keith Larsen.

Thank you both, Mark and Scott. In closing, I'd like to point out that 2010 was a successful year for U.S. Energy in terms of financing our strategy and achieving meaningful growth in the E&P sector. As Scott mentioned, we grew our production reserve significantly. We added core and outlying acreage in the Williston Basin at reasonable cost in order to increase our development inventory and overall footprint in this prolific play.

We increase our total exposure to oil, expanded our existing partnerships, established new partnerships and took our first deliberate steps toward operatorship in negotiating the purchase of 3,000 net acres in Southern Colorado. We're expanding our development opportunities through our program with Cirque in California as well as entering into the Eagle Ford play through a partnership with Crimson Exploration which was formed in early 2011. We continue to drill ahead in the Bakken, Three Forks, Gulf Coast and in Texas and Louisiana.

We have taken a more proactive approach in terms of investor outreach by presenting at more conferences and visiting with institutions on the road more frequently. In this regard, I believe that we continue to deliver growth when the market gains greater exposure to an understanding of the U.S. Energy story. We begin to see greater market recognition for our efforts.

We will continue to prudently manage the balance sheet to maintain our flexibility to drive growth and we are all very excited about moving towards operations in Colorado. 2011 promises to be another great year for the Company. We appreciate your support through 2010 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). Joel Musante, CK Cooper & Co.

Hey, Mark; hey, Keith. How are you doing? I just had a couple questions. First, just to expand on your closing remarks there. As you -- with your focus on E&P now we've seen a lot of the pieces coming together. But can you just talk about how you envision that -- your move as a non-operator to become more of an operator, the time line there and where you're going in terms of staffing needs and divesting properties and the whole picture there?

Sure, Joel. We thought that our entree into operatorship in Colorado would be a fairly simple transformation because it's not very complex. They're vertical wells and they're fairly shallow at 6,500 feet. Completions are not technical. Certainly we're not staffed up at this time to do a 10,000 foot lateral drill, but we are staffing up. We are currently looking out to hire a reserve engineer and also a land man.

We do have a professional geologist on staff now that's been with us for about the past nine months. And we'd like to grow into operation slowly. I would envision that if we're successful in Colorado that we would expand and add more personnel, probably a drilling engineer and some more technical people and of course probably some contract pumpers.

Okay. And given the big acreage position you're assembling in Montana, I mean, when do you think you would potentially drill a first well there?

We're still evaluating it and, as we mentioned, we're still accumulating the acreage to firm up our position there. I would envision possibly late this year we'd contemplate trilling a well -- that initial well in that area.

Okay, all right. And you said that you would, based on your conventional drilling prospects in Colorado and based on the success in Colorado, Gulf Coast and California in the event that you might want to move forward and into other areas, how would you allocate that capital and what areas might you go to?

Right now we're pretty well focused on the Bakken and the Eagle Ford, that's where we're looking for opportunities. As far as the operatorship, we're keeping our options open there, Joel. We're seeing opportunities. Since we announced that we did the deal with Crimson we've had many, many opportunities that we've looked at.

Again, we think there are huge opportunities in the conventional sense because a lot of people are overlooking them and going to the resource plays, the Bakken and so forth. So we're seeing all kinds of opportunities. At this time I can't tell you exactly where it's going to be, but we're looking at areas that other people I don't think are looking at at this time.

And did you get a sense -- with Brigham's call they ramped up their activity levels. You're going to participate with them with four to six wells this year and clearly their objective is to prove up the concept of infill drilling there. Going forward with all the locations you can potentially have, have they discussed the drilling pace going forward in that area?

They have not, Joel. As you're aware, they've got a large acreage position and the good thing is all of the research and development that's being done up there on how many infill wells they're going to need and they're still evolving in the fracking technique, that the oil that we have in place isn't going anywhere. And we have not discussed with Brigham what the plans are for 2012 or going forward.

But eventually, I think everyone understands, those wells will be drilled and, of course, would like to be a little more aggressive especially with oil prices in the $100 range.

Okay. And I don't know if you have these numbers handy, but I was trying to get a reserve replacement cost for your Bakken development. So that would basically be the development cost that you spent during the year over the reserve adds from that area.

Joel, in fact I got that question this morning and I'm working on that. The difference is we have to take out some of the expenses that we put into Zavanna. So I'm still working on that.

Okay, all right. Great, that's all I have. Thanks.

Thank you, Joel.

[Duff Gordon], [Aberdeen Investment].

Hello, gentlemen. I'm an old-fashioned guy, I'm interested in earnings. And I'm trying to put together a model -- I think, Mr. Larsen, that you were quoted in one of those executive interviews, that you see 5,000 barrels a day within five years. What I'm trying to get a handle on is what -- if there's any kind of band of cost that you can tell me that you expect for that oil? Is it $50, $60, $70 a barrel? If that's a fair question that way I can try to figure out my own earnings projections.

Well, of course there are lots of variables that go into that number and I was kind of put on the spot to say where would like to be in five years and that was kind of a flippant remark because that takes a lot of planning and developing your plans as you go forward.

But I could see that we could get to that with the growth that we have and the tremendous amount of locations we have up in North Dakota. As far as a per barrel cost across the board, I think our F&D costs are somewhere in the $25 range. But if you look into the financials and separate it out, then you'd be able to see what that number is. Probably $25 to $30. Does that answer your question?

So if we're selling at $100 are you saying that the spread is $70 on a cash basis?

No, there's -- I don't know what the spread would be, $100 compared to $25 or $30, that would just be our F&D costs, or our finding and development costs. But there are certainly other costs that are associated with it. So I'm not prepared today to give you those estimates.

It's $50 or $60 I would say -- all in.

Scott, do you -- could you --?

We've not, I don't have that number right here.

We don't have that number. But probably all-in costs, as Mark mentioned, would be closer to $50 or $60, but those are just estimates.

Yes, that's what I've heard from other companies too. The land package that you currently have, is that sufficient to fund your growth for the next five years?

Well, as we mentioned, we've got 200 plus locations in the Bakken alone if the spacing (multiple speakers) --

Works out.

-- to be what it is. So those are lots of locations that we have just in that area alone. And depending on our success in California and Colorado that could add significantly to the locations that we have. So I think that we have the land position that significantly will achieve those goals although we're still looking at additional land packages.

Okay. Is there anything left on the fourth quarter -- wells that were drilled where the money hasn't or the funds haven't really flowed that we can expect in the first quarter? Does that make sense? Like a -- like a lag?

Are you asking for completion of wells?

Yes, just increased revenues.

As we mentioned, those Bakken wells have not been completed. We expect to begin the completion this week in fact on one of them and then finish the other four with Brigham one a month for the next four months.

Okay. What is your hedging strategy, is it 20%? Or I heard there was a number there that didn't seem that high.

40% is our strategy.

How much?

40%.

40%?

Up to 40%.

So you are going to implement the same strategy, that is a collar strategy?

We're discussing that with our Board currently about how going, forward, but I think probably that would -- collars would certainly be in the mix.

I would encourage you as a former options trader just to look at the straight out far out of the money puts rather than sell the upside. And I think investors are looking for that too, but that's my opinion. I appreciate your time.

Thank you.

All right.

Marco Rodriguez, Stonegate Securities.

Good afternoon, guys, thanks for taking my questions here. I was wondering if you could maybe provide your thoughts on expectation for production levels in 2011 and how you might expect it to trend given that you've got a good year under your belt on the wells that are currently producing in the Bakken.

We don't at this time give guidance, Marco. But I think if you see the wells that we have planned then you can make some assumptions about the Bakken wells as well as our ownership. That flush production is going to help significantly.

But what we're really trying to do is build a base which goes back to one of the slides we showed to where once these wells level off after a year they're going to be several long term recurring revenues for us. But the answer to that is you kind of have to make your own assumptions looking at our drilling program and our net and gross wells and throwing in there some success ratio in Colorado and California.

Okay. And then can you talk then about your expectations in the LOE per BOE? You had a pretty big spike here in Q4.

Yes, well, what we found there is there are workovers, it is traditional oil well -- oilfield activity. There's salt associated with some of the wells, there's workover, there are sucker (inaudible). And so some of the costs on the workovers have added to the LOE.

As far as the expectations going forward, I think we'll see probably after this year, after the workovers and then the frequency of the workovers during this year, if those were initial and not recurring then hopefully the LOE's will go down. If not then you could expect the LOE's to be similar to this year.

So you're expecting 2011 LOE to be similar to 2010 LOE? I'm not sure I followed you.

No, I don't expect them -- it depends on the operator and how many workovers they do on these various wells. And what I understand is the salt content is higher with the initial flush production and there are some water issues and some other issues and we're hopeful that the workovers go down and so I just don't know what this year is going to bring us.

Are you guys modeling for a down or an up type number?

I think we've modeled it to be about the same as it was last year.

And then in regard to your CapEx plan for O&G, you've got $45.7 million out there. Assuming everything goes to your expectations can you kind of outline how you're going to spend that money in regard to timing? And then if you can kind of quantify that as well?

You know, we have an internal budget, but we don't publish that. It has been approved by our Board. But I think that you can pretty much split it up evenly over the year.

I'll add to that, Marco. You're going to see obviously the bulk of our work done with Zavanna this year and it equates to approximately 60% roughly of that budget amount and the other amount -- but other 40% would be geared towards Brigham with completion of wells this month and then resuming some drilling of wells as we move through the year with some additional completions near the end of the year. So about 60/40 Zavanna/Brigham respectively.

Of the $33 million.

Yes, of the Williston Basin component of the budget.

Okay. And then can you kind of outline how -- your expectations on funding that CapEx?

Well, cash flow, certainly our borrowing base and the proceeds from the building.

So then in terms of the building what are your expectations there as far as timing?

Well, it appraised at $21 million and the timing, we don't -- we're not going to fire sale if we're not forced to. So I would say within the next six months.

Have you entered an any discussions with anybody else or it's just kind of up for listing for sale?

We're still in the listing process.

Okay. And then I was just kind of wondering what sort of -- have you guys thought about an optimal capital structure, what that might be?

In which regard, Marco?

In regard to debt versus equity.

Yes, debt to equity, we also have discussed that with our Board and we will not go above 40% debt to equity either.

Okay. Okay, great, thanks a lot, guys.

Thanks, Marco.

[George Gaspar], private investor.

Yes, good afternoon -- good morning, good afternoon I guess, depending upon where you are. A question on the deep -- the wells drilling with Zavanna currently. Can you identify specifically your turning point and depth relative to the wells that you've drilled with Brigham?

They are very similar, George. Most of these wells are between -- they turn the corner between 10,000 and 11,000 and all of them are doing a 10,000 foot lateral with Zavanna as well as Brigham.

so there isn't any deeper drilling going on with the Zavanna project in terms are of the Bakken location relative to the Brigham depths?

No, what we've seen so far is it's very similar between -- like I said, the Bakken zone is between 10,000 feet and 11,000 feet.

Okay, and you're near -- if I recall what you indicated earlier, you're near the end of your drilling of well 2. You've got any color for us as to what you're actually seeing in terms of the depth of the Bakken sand relative to the Brigham locations you've drilled?

Very, very similar characteristics. All these wells have gas shows and oil shows by drilling. I think it's a given they're all going to make an oil well, it just depends on if they're economic and of production rates.

Okay.

Very similar sand characteristics to the -- it appears to me the whole Rough Rider area including the southern portion which we are involved with with Zavanna.

Okay. And if I recall now, this is a three well program so you -- in terms of what you're doing currently you'll start a third well I assume at the end of this horizontal run on the second well. Will that begin immediately? And what happens beyond the third well with Zavanna?

Well, as Mark mentioned, the three well program we agreed with, they will move right to the next location with that same drilling rig. And then we have a separate drilling rig that we've contracted with Zavanna starting April 1 to drill one well a month for 12 months.

Okay, all right. And so the rig that you -- the current rig, does that terminate after the third well and then you're picking up this rig that will work for a year? Do I understand that right?

That is correct.

Okay, all right. And then as you're going forward in the next 90 days, can you kind of list out the actual drilling markers that we should be looking for in terms of well drilling activity? You've already explained that you're going to try to do a completion one a month going forward in the Bakken.

But if we're to look at just the overview of Texas, Louisiana, California -- if you set up these wells on a sheet of paper what are we looking at in terms of dates that you have that we should be looking at for a start up of the drilling process?

George, this is Mark. We're currently drilling two wells in the Bakken, one with Zavanna, one with a Murex. We expect to continue to drill one well a month with Zavanna roughly and maybe four to five weeks per well. But one well a month through March 2012. So we see that drilling pace continuing.

We feel that will also be supplemented after midyear to midyear -- after midyear with Brigham one well a month in the third- and fourth-quarter time frame is what we're estimating. And then that will be further supplemented by drilling a well with Crimson which we expect in may which will be our test well in the Eagle Ford.

And then typically from our schedule one to two wells a month with our other partners depending upon success and prospects that we're anticipating. So significant drilling activity, consistent drilling activity, of course they're all subject to weather, timing, availability of services and so forth. But we expect a busy year overall on the drilling front and completion.

Okay. And then on Louisiana, what's the marker date in terms of drilling going forward?

We're expecting to spud --.

We've spud.

Yes, we've spudded that well.

Spud with -- it's the LLP prospect and it spud -- they've said conductor, so they're going to be drilling forward right away. The other one that you may be mentioning is the Texas well with Southern Resources.

Right.

And we expect within the next week or two to spud that well as well.

Okay. All right, now, one last question and that's to do with the original outline and procedural drilling procedural situation with Brigham. If I recall, all partners have the right to cough after 12 months the infill in the areas that you've drilled successfully well by well.

Any one of the partners can call -- can prepare to drill and call for the other partners to conclude an agreement to go ahead. I'm probably not saying this right, but what are the expectations that U.S. Energy would try to initiate a call against that post 12-month agreement well by well?

What it's called George is a proposal. We couldn't propose a well until after the first of this year.

Right.

And part of the reason we are staffing up and getting into operations is so we will have the confidence if we wish to do that that we would go ahead and propose a well to them. As far as the expectations for the remainder of the year, I don't think that we would propose a well unless we brought in another partner that had the expertise and the experience and the confidence to complete one of these 20,000 foot wells.

I see. Okay, thank you.

Thank you, George.

Josh Young, Young Capital.

A couple quick questions. First off, can you walk through what the sources of financing are for the $45.7 million you plan to spend this year on CapEx?

Sure, just what I mentioned, Josh, is we're going to take it out of cash flow, our debt facility, which right now is $28 million, and then the sale of our property in Gillette.

And then of that $28 million, how much is currently available and how much is drawn?

We drew down the $3 million as part of the payment to Crimson.

Okay, so you have $25 million available. And then is that tied to the real estate or is that purely a reserve based loan?

$10 million of it is tied to the real estate and the other is tied to the oil.

Got it. And then -- so it sounds like you're relying on about $10 million or so of cash flow to fund operations in addition to the financing?

Approximately, right.

And then just I guess stepping back, I mean it struck me -- you guys now have over 25,000 net acres in the Bakken, you're trading at a substantial discount to your peers. I mean, how do you think about this and how do you think about getting recognition in the market or sort of realizing value for the phenomenal set of assets that you guys have put together?

Well, as you know, Josh, we've attended significantly more conferences, we're trying to meet with new people, new institutions, I agree that we're undervalued. In fact I'd add to the conversation with you that a lot of those companies are being valued at $10,000 an acre. And if that was our valuation up there it would be significantly higher. So we're making a concerted effort to get out to these conferences, to get our name out there, to get our story told to as many people as we can.

And then how do you think about the mining asset that you have? I mean, as we've discussed before, I think it's possible that people look at you and they say, okay, you guys have these great oil and gas assets and then you have this real estate which it sounds like you're going to be divesting over the next year or so and then you have a mining asset and they scratch their heads over the mining asset and they look on at other companies. I mean how do you think about that?

Some people may do that, Josh, and what we've decided to do is add more by you by bringing in an exceptional partner and advancing it. We understand it's long-term and if we elected to sell it at this time it would be pennies on the dollar. It gets more valuable as time goes by and we get closer to a permit.

And so we see it as kind of a passive thing because we've laid off the operations to a major significant molybdenum mining company that has the wherewithal to get the job done and we believe that they will be successful.

Great. And then to clarify, you guys don't have any funding obligations on that mine for a while, right? If they pursue --?

Only the operation of the water treatment plant, that is our responsibility. All of the other responsibilities are Thompson Creek's.

Great. Well congratulations on putting together some great deals. I'm excited to see additional production going forward.

Thanks, Josh, look forward to seeing you in the future.

Okay, great. Take care.

Marco Rodriguez, Stonegate securities.

Really quick, I was wondering if you could address the payables up at the $15 million level at December. Where are we now?

The payables at December 31 primarily consisted of amounts that were due to Brigham relating to wells that have been drilled. And much of that has accrued because they had not billed us as of December 31 but we had to accrue it. We are paying those bills as they come in. I don't have the number for you today what the accrued payables are, that will be coming out in the first-quarter Q. But they have been paid down.

Have they been paid down significantly or do you think it will --

Yes.

-- probably bleed into Q2?

They've been paid down significantly. Now, of course, when we get more activity again it goes back up again. But the minute that the invoices -- the jibs are in issued by the operators we do pay them.

Okay, great. Thanks, guys.

Thank you.

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

Thank you, Javon. I would like to thank everyone for joining us today and I look forward to updating you on our progress in the next quarter.

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