US Energy Corp (USEG) 2010 Q3 法說會逐字稿

Good morning. My name Allison 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 results and operations update. All lines have been placed on mute to prevent background noise. After the speakers' remarks there will be a question and answer session. (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.

Thank you, Allison, and good morning, ladies and gentlemen, and thank you for joining us today. With me are Keith Larsen, Chief Executive Officer of U.S. Energy Corp., and Scott Lorimer, our Chief Financial Officer.

In terms of an agenda for today's call, Keith will review our operational highlights for third quarter 2010, as well as a period subsequent to quarter end, and provide with you an update on our various strategic operating initiatives. Scott Lorimer will then conduct a financial review before taking your questions. On November 8, 2010, we filed our 10-Q for the third quarter ended September 30, 2010, and I would refer to you that document for the Company's most-recent financial statements.

Before I turn the call over to Keith, I would like to read you the following forward-looking statements. In this conference call officers of U.S. Energy Corp. will be making forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934.

All statements other than the statements of historical fact are forward-looking statements, including without limitation the statements under management discussion and analysis, of financial conditions and results of operation, as well as disclosures about possible exploration, development and operation of our oil, gas, and mineral properties and future business plans. Words like expect, anticipate, believe, and similar words and expressions will indicate that forward-looking statements are being made. These statements are subject to risks and uncertainties. Actual results may vary from what is projected by the forward-looking statements.

The financial statements included in our SEC filings require management to make estimates and assumptions, which effect the reported amounts of assets and liabilities and revenues and expenses. Actual results could differ from our estimates. You should consider the information provided by officers in the context of disclosures provided in the Form 10-K for the year-ended December 31, 2009, and Form 10-Q for the quarter ended September 30, 2010, including the cautionary statements regarding forward-looking statements.

I would now like to turn the call over to Keith.

Thank you, Mark. Good morning, ladies and gentlemen and thank you for joining our call this morning. At September 30, 2010, the Company had 17 gross producing wells, up by three from the second quarter, and we exited the quarter with an average daily production rate of 1,246 net BOE per day, which was an increase of 954 BOE from an average daily production rate of 292 BOE for the quarter ended September 30, 2009. This was also an increase of 13% over the 1,098 BOE per day in the second quarter of 2010.

Production volumes for the first nine months of 2010 averaged 1,225 BOE per day, which was an increase of 956 BOE over the 269 BOE per day in the first nine months of 2009. The increases in production, as well as associated revenues and cash flow, are a direct result of our ongoing drilling initiatives in both the Williston Basin of North Dakota and the Gulf Coast region.

During the quarter ending September 30, 2010, we completed three Williston Basin wells with an average initial production rate of 2,337 BOE per day. These wells consist of two initial wells, the Sedlacek Trust and the Sukut, and our first Three Forks formation test well, which was drilled in the State unit. During the quarter two infill wells in the Brad Olson unit were drilled to depth and as recently announced, the Brad Olson #2 was completed with an initial rate of 2,717 BOE per day.

This first infill well in the unit was monitored with a microseismic array to evaluate the frac wing performance during completion. The resulting information will be used to determine optimal spacing for the remaining wells in the unit and could delineate the potential to drill an additional 28 to 73 gross Bakken formation wells in our 15-unit program. The 28 would represent three wells per units, and the 73 would represent six wells per unit.

The successful results for the State Three Forks test well represent an important milestone for U.S. Energy, as this demonstrates the viability of the Three Forks formation in the Rough Rider acreage area. Further testing and additional positive results could delineate the potential to drill up to 44 to 89 gross additional Three Forks wells once spacing is defined. To date we've completed 11 of 15 initial wells, one infill well, and one Three Forks formation well under the drilling participation agreement with Brigham, with an average initial production rate of 2,454 BOE per day.

To close out a very active 2010, well 12, Kalil Farms, and the second infill wells, the Brad Olson #3, have been drilled to depth and are currently awaiting completion. Wells 13 and 14, the MacMaster and the Lloyd, are currently drilling in the horizontal portion of the well bore, and well number 15, the Hovde, is expected to spud later this month. Also, as we recently announced, in early 2010 we began acquiring leases perspective for Bakken and Three Forks formation production in northeastern Montana with geological features believed to be similar to the Rough Rider area of North Dakota.

To date the Company has acquired or leased for its own rights approximately 13,920 gross and 11,160 net acres under this program. Due to ongoing leasing activities in the region, more information and future plans for the acreage will be provided at a later date. With the addition of this acreage the Company's current Williston Basin lease holdings now total approximately 33,120 gross and 16,200 net acres.

In our Gulf Coast operations, we successfully completed the ALMI #8 well, which is located in Louisiana. The well encountered approximately 64 feet of net pay in two zones. Production began in mid August on the lower zone of the well, with initial production rates in the range of 580 BOE per day. This production comes from approximately 14 feet of net pay in the lower zone. Production is expected to move to the upper zone in approximately nine-to-12 months where approximately 50 feet of net pay was encountered and initial daily production rates are expected to be in the 1650 BOE per day range. We have 50% working interest and 36% net revenue interest in this well. Our net investment in the well through the end of the quarter was $3.3 million. With the addition of this well production from our Gulf Coast wells is now approximately 500 BOE per day.

During the quarter we also drilled two non-productive wells with Houston Energy in the Permian Basin. Our working interest in these wells is 13.3% and net costs incurred were approximately $381,000. We are currently evaluating results from these two wells before committing to any other wells in the Permian Basin. We will spud our last well in Louisiana for 2010 with Houston Energy around December 1. This Delta Farms northeast well is near our successful Delta Farms discovery, which is current producing 150 BOE gross and 28 barrels net to U.S. Energy. We will have a 25% working interest in this new well.

As a result of our 2009 seismic program, we are currently completing an oil prospect in Louisiana and expect results in the near term. The first well, which we completed in this program, watered out and is no longer producing. The second well experienced well bore damage during completion and we sidetracked the well that we are currently completing. We expect to drill additional wells under this program next year. Our working interest in the wells is approximately 4.5%.

In summary, for the quarter ended September 30, 2010, we produced 114,669 BOE and generated operating revenue from our oil and gas business of $6.3 million. For the nine months ended September 30, 2010, we produced 334,669 BOE and generated $20.2 million in operating revenue from oil and gas and $1.9 million from real estate.

During the quarter we also implemented a hedging program. We entered into two commodity derivative contracts with BNP Paribas; a costless collar for 200 barrels per day with a strike price of between $75 and $83.25, and a fixed price swap on 200 barrels per day at a strike price of $79.05. Both contracts hedge WTI and expire on September 30, 2011. The objectives for using the hedges are to reduce the impact of price changes on a portion of our future oil production, achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk.

The use of these derivative instruments limits the down side risk of adverse price movements. However, there is a risk that the hedges may limit our ability to benefit from favorable price movements. We may elect from time to time to add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in an effort to maximize our cash flow and earnings. During the third quarter of 2010 we took an unrealized loss from our hedging contracts of $586,000. If we did not have to recognize the unrealized loss the Company would have been profitable for the quarter.

In November 2010 we entered into an acquisition, exploration and development agreement with Cirque Resources LP to acquire a 40% interest in a 6,000-acre oil and gas prospect located in Kern County, California. The prospect is a 13,000-foot deep Miocene target in the San Joaquin basin on the flank of a very prolific oil producing field. Cirque operates the project. The commitment well is planned to spud in the fourth quarter. We're excited about the potential of this project and look forward to announcing results in the near future.

Turning briefly to our Mount Emmons molybdenum project in Colorado, Mount Emmons Moly Company, a wholly-owned subsidiary of Thompson Creek Metals, continues to advance this project through the early planning and evaluation stages. Mount Emmons Moly continues to meet their spending commitment and expects to spend $7 million on the project during 2010 and has announced plans to spend $11 million to $12 million in 2011 for preparatory work in anticipation of exploration drilling, further engineering evaluations, ongoing pre-feasibility study and ongoing project maintenance activities.

Our real estate investment, a nine building, 216 unit multifamily apartment complex have a 96% occupancy rate at September 30, 2010, compared with 91% at September 30, 2009. For the quarter we realized revenue of $646,000, down from $686,000 in the year-ago period. The decrease is due to lower rental rates at the property, which were partially offset by higher occupancy rates. For the nine months ended September 30, 2010, we realized revenue of $1.9 million on this project.

I would now like to turn the call over to our Chief Financial Officer, Scott Lorimer, to review our financial results for the third quarter and nine months ending September 30. Scott?

Thank you, Keith. The Company recognized $6.4 million in revenues during the quarter ended September 30, 2010, as compared to revenues of $1.4 million during the quarter ended 2000 -- or September 30, 2009, for an increase of $5 million during the third quarter of 2010 over 2009. For the year-to-date period, revenues increased $17.2 million and $4.3 million in the first nine months of 2009 to $21.5 million in the same period for 2010. The increase for both the quarter and the year-to-date periods is primarily a result of oil and gas revenues as a result of our drilling activity in the Williston Basin and on-shore Gulf Coast.

Our operating expenses incurred in the third quarter of 2010 were $7.2 million as compared to $3.7 million for the third quarter of 2009. The $3.5 million increase is primarily, again, a result of a $3.9 million increase in the oil and gas operating expenses directly attributable to our increased production during that period.

For the nine months ended September 30, 2010, operating expenses totaled $21.4 million versus $12.2 million during the nine months ended September 30, 2009. Again, the $9.2 million increase is primarily a result of the $9.6 million increase in oil and gas operating expenses. The Company recorded a small net loss after taxes of $235,000, or $0.01 per share fully diluted for the quarter ended September 30, 2010, as compared to a net loss of $1.7 million, or $0.09 per share during the quarter ended September 30, 2009.

For the year-to-date period, we recorded net income after taxes of $1.2 million, or $0.04 per share, basic and diluted, during the nine months ended September 30, 2010, as compared to a net loss after taxes of $7 million, or $0.33 per share, basic and diluted, during the nine months ended September 30, 2009. Cash flow from operations for the first nine months of 2010 were up $9.4 million to $12.4 million as compared to the first nine months of 2009.

Looking at the balance sheet, the Company had cash and cash equivalents of $10.4 million plus $29.2 million in US treasuries at September 30, 2010. This translates into $1.47 per share outstanding at September 30, 2010. Working capital at the end of the third quarter was $38.8 million, which is down from the $53.4 million at the end of 2009. The decrease in cash and working capital was primarily due to the investments we made in our oil and gas portfolio.

As Keith mentioned in August we announced our wholly-owned subsidiary, Energy One LLC, had entered into a $75 million credit agreement with BNP Paribas. The credit facility provides for maximum borrowings up of to $75 million with an initial borrowing bates of $12 million, which has since been redetermined using our second-quarter results and the reserve report from our Bakken wells and now stands at $18.5 million. The credit facility may be used to provide working capital for lease acquisitions, exploration and production operations development, including the drilling and completion of wells and for general administrative corporate purposes.

The facility provides us with a non-dilutive, cost-competitive source of capital that we can utilize to advance our overall growth strategy. In addition to the credit facility we also have a $10 million line of credit with a regional bank. As of today, we have no borrowings under either of the facilities -- either the facility or the credit line.

Thank you, Scott. In summary, during the third quarter we advanced our partner drilling programs with a high-impact well in the Gulf Coast and 100% success in the Williston Basin, including four key milestones. A successful infill well, the successful Three Forks formation test, substantial acreage acquisition in the Williston Basin, and we entered into a new JV with a proven operator.

We believe our strong balance sheet and access to capital positions the Company to execute on our growth strategy as we continue to develop our existing prospects and evaluate additional growth opportunities, both in the fourth quarter and beyond.

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

Yes, sir. (Operator Instructions) Our first questions comes from Joel Musante of C.K. Cooper & Company. Please go ahead.

Good morning, Keith. Good morning, Mark. Yes, I just had a couple questions. Just looking at production it's hard -- it jumps around a lot because wells come on and you have big wells coming on. I'm just trying to -- you ended -- let me see, I wrote down what you ended the quarter. It was 1,246 BOE/D. How do you see that -- what do you think that's going to be like going forward? I can't remember exactly when those BakKen wells came on and what's going to contribute to the fourth-quarter production while you seeing decline from the existing wells, so how do you think that's going to shake out?

We've got five more wells, Joel. We've got that infill well, the number three in the Brad Olson. Then we've got four additional wells of our original 15, as I mentioned. I'm not sure that all of those will get fraced and completed this year. In fact, I would expect that one and possibly two of them will be pushed into January because of timing out there and Brigham's schedule. But the impact of those five additional wells, if they are, in fact, high-rate producers like the other ones we've experienced, will definitely have an impact, the timing of which we just don't know at this time until we get some direction from Brigham and when the actual fracs will happen.

Okay. So what has come on after the end of the quarter in addition to that 1,246 number?

The Three Forks came on and the infill came on.

Okay, all right.

And then we're also -- we had a little bit of production from that ALMI well, which is averaging about 560 in the third quarter, but it will see a bigger impact event on our fourth quarter, definitely.

Okay, all right. And then in your conversations with Brigham, did you get a sense for what the program might be like for next year? I know you were talk about trying to get 10 or 11 infill locations.

We've expressed our desires to Brigham and they haven't gotten back to us yet, but we expect in the near term that we will hear and hopefully we can announce what our plans are for next year. But to date we don't have the number of wells that we plan on infilling. I believe that Brigham is going to be receptive, because they have some pretty big plans of their own to increase their daily production and certainly drilling-proven infill PUDs would be on my agenda if I were in their shoes.

Okay, all right. And what was the net number on the acreage that you acquired in Montana?

11,160.

11,160. So it looks like you have a pretty high working interest/ownership position in the acreage because the gross number was 13,900, if I wrote it down correctly?

That is correct.

So how do you plan to go forward -- first of all, where exactly is the acreage? What county is it in?

This is Mark, Joel. How you doing?

Pretty good, Mark.

Good. We're not prepared to disclose the location at the time. We like the location due to what we're seeing on the resist tailings from the Bakken and Three Forks in this area. Again, we prefer not to disclose even the county because we're picking up leases on a very competitive basis.

Okay.

It's an anomaly, if you will, in our view, looks similar to Rough Rider. So our current plans are to continue leasing, pick up around, say, 20,000 acres is a goal at this time. In the meantime we're pleased with what we have, but we want to quietly go about and pick up additional acreage and then put it together and either operate on our own, do some tests, or bring in another operator once we're prepared to do so.

if you were bringing another operator, would you -- how might that look?

Well, we would look for an experienced operator that likes what we see or agrees with what we see with the project, and we have high-interest leases with high NRI so we've got some room to sell down a portion of it at that time appropriate time.

As well, Joel, it's contiguous so we've block it up fairly well, which makes it even that much more appealing.

Okay, all right. And then just lastly, in Kern County, California, what -- can you -- you didn't go over too much what you're looking at there and what kind of -- what the size of the targets are, or what your plans were going forward. Could you just elaborate a little more on that?

Should, Joel, this is Mark again. First of all, we've looked at this prospect with Cirque dating back to June, I believe. Of course, Kern County is a very prolific oil producing region -- basin, and the location of this was unique how they put this lease package together and took some time. We were patient and diligent, worked through it with them. It's on the flank of a very prolific oil producing field, which we can't disclose at this time because we may pick up additional leases. It's wildcat, however, Joel. It's a target that hasn't been proven. It's really been upheld by putting lease blocks together. Cirque has done a good job in doing that. So with all of that in mind, we're excited about drilling with them. Stevens Sands is a very prolific producing formation in the -- in that region, and we hope to spud the well by year end and see positive results. I would caution that it is a wildcat, but if it does hit and if it's near what we expect to find, it could be a very nice asset for us to be partnered with, particular with Cirque.

And --

Joel, in addition we were -- as I've mentioned on this call before, we're looking at getting a little bit away from these one-off wells to where we'll risk our exploration money but we want some running room, and if we're successful in this first well there's plenty of room to run in this play.

So what's the size of the target? Do you have a P-10 number for it?

Let's just put in the way. According to Cirque's and our calculation, if we find what we think we find they could be very prolific wells with nice IP and running rates, but that's speculation until we actually drill a well and see what we found. But it's essentially these are layered Stevens Sands at about 13,000 foot. We've seen a geophysical anomaly down there where we think we've got a high spot that covers this 6,000 acres, possibly a little larger. And as Keith mentioned, if it hits, if there's oil there it could be very nice wells and the prospect could have -- could provide a lot of running room on, say, 40-acre spacing.

So from what I'm hearing, it sounds like one well would not be sufficient to develop the whole play. If you drill one well, you might get some offset locations, based on that?

Absolutely, yes. If one well hits it's going to be very promising with, say, up to 60 locations on this -- on the acreage.

All right, and what's the well cost and the oil and gas mix that you expect?

Well cost is going to be -- I think the dry hole cost is $2.5 million. Yes, that's what it is, $2.5 million. We're paying a portion of Cirque's interest, 40%, in the drilling cost, and then if we complete the well, if it's a successful well we're heads up from there on out. Our cost to drill with the carry is $1.6 million.

Okay, all right. And the completed well cost, is there any additional cost? You said the dry hole.

it'll be another -- over $1 million to complete the well.

Say maybe $1.250 million.

Okay. And how do you structure the carry and then your buy-in to the acreage?

Basically our buy-in was a total of $900,000m which equated to $340 per acre to purchase the 40% of the roughly 6,200 acres, and then again, we carry them 40% of the $2.5 million well cost, just the dry hole cost, which is another $1.6 million. So our total outlay is approximately $2.5 million. If it's a successful well, we're heads up on a 40/60 basis going forward. We're 40% and they're 60% for any drilling or any work that's done going forward from that first well, including the completion cost of the well.

Okay, and just last question. What was the oil and gas mix again? I forgot what that was.

There could be gas, but it's heavily weighted towards oil.

Okay. All right, thanks a lot for all the help there.

You bet, Joel.

Thanks, Joel.

Our next question comes from Marco Rodriguez of Stonegate Securities. Please go ahead.

Good morning, guys, thanks for taking my questions here. I was wondering if could you help me understand a little something in regard to your production volumes for the quarter. Sequentially your natural gas moved up pretty nicely, but not as large of an increase sequentially from oil, and I'm just having trouble reconciling that with the fact that your wells are heavily skewed towards oil production, so can you kind of help me understand that?

Except -- Marco, except for the two wells that we have in Louisiana, and they're high-production wells, one of them is doing about 13 MMCFD and the other one's doing 3.5 million. They both have condensed gas liquids. Current we're 62% natural gas, 6% -- or, excuse me, Maco, 62% oil, 6% natural gas liquids and 32% natural gas. But the two wells, Marco, to answer your question, we had a high-working interest in that ALMI well so that added a lot of natural gas. We have a 36% NRI on that ALMI well, and about a 10% NRI on the Lakehorn well.

Okay. And t hen obviously noticed here that you're breaking out the natural gas liquids again. Can you help me understand what initially drove the decision to not breaking out and then now we're breaking it out again? And do you, by chance, have the data for Q1 and Q2 for the production volumes there?

We don't have those with us, Marco, but if you'd call me back I can get them for you.

Okay, perfect. And so why are we breaking it out now again?

Well, we've always broken out the natural gas liquid, haven't we, Scott?

Well, we had some comments on the last Q that we had not broken them out, and what that did was it inflated the price that we reflected for natural gas, and we disclosed that, and people said, well, why don't you break it out separate. And so we kicked it around, we did some research on it and what we finally concluded to do was report products that are sold off of our producing wells the way that they're reported to us from the purchaser.

Okay.

Because if you put that natural gas liquids into oil it inflates the price of oil. If you put it into gas it inflates the price of gas then there's questions as to why are your unit prices so high.

All right. Okay, that's helpful. Earlier this year you had provided guidance of roughly 2,500 BOE based on a 30-day trailing average for a year-end guidance, if you will. Can you provide an update on that?

Sure. It wasn't guidance, Marco, it was a goal that we had set. And quite frankly, we thought we were going to buy some production, but in these markets we haven't seen a bargain out there to buy. And in addition to that we did not know the timing of Brigham completing these wells. We thought that all 15 wells would be completed by now. We started out and completed six right off the bat, but as Brigham grew and spread out their talent, if you will, they were delayed. But contractually they didn't to have drill them before the end of the year so we're looking at five wells now coming on line by the end of the year. So I don't believe we're going make the 2,500 but I do believe we'll be approaching 2,000.

So that will also be based on a 30-day trailing average?

That's what our goal is. So I don't believe we're going to make the 2,500 for the month of December.

Okay, all right. And then last kind of a housekeeping item here. Looking at your -- if I did my math right here, your LOE per BOE was that roughly $12.40-some cents, a little bit down from $15 from last quarter but still up from what you had been doing the last few quarters? Can you provide some color there in how we should be thinking about that going forward?

Well, on these Bakken wells, you do to have go in and do some workover work on them and it's a bit higher than what we expected, Marco, but there's a lot of sand that you use in these fracs and so those wells, they have to be worked on, so that's directly attributable. How that's going to shake out in the future I think should be lower, because after they produce awhile it doesn't become as much of an issue. Another issue that we've had up there is salt. We're getting gummed-up with some salt and having to add some fresh water to the walls so that the pumps work better, and these are gas/oil and pumps don't work real good when the gas doesn't separate. So as with any oil field, you have some issues with production.

Okay. So with five additional wells potentially coming on here in the December quarter and perhaps possibly into Q1, would it be fair to say that that LOE per BOE would probably be similar to the last, say, second and third quarter kind of a mix?

I believe that it will be in that range, yes.

Okay, perfect. Thanks, guys.

Thank you, Marco.

Our next question comes from [John Pricing] of [Moller & Emerson]. Please go ahead.

Hi, gentlemen. What's the current outlook and timing on the molybdenum project?

Quite frankly, John, that's probably a five-to-ten year project because there's a lot of work that has to be done. The next think that we'll have to do, the next real milestone was when we go in and file a complete plan of operations. At that time there'll be an environmental impact study commissioned by the forest service, and that probably is going to take in the neighborhood of two years plus to go through that process. So there's an awful lot of work that needs to be done down there and it is not a near-term project. Probably five years would be a best case, and more like seven years would be a rougher case, if you will.

Okay, just one more question. What are your thoughts on the further stock listing?

Further stock listing --

Or going on in exchange, like the Amex?

we've been courted by the New York Stock Exchange and we've discussed it, but we've had pretty good results with NASDAQ. We never say never but we have been out to the Exchange, and, of course, it costs money to be listed there, as well.

Right. Okay, thank you.

Thank you.

Our next question comes from Sandy Wyman of Gilford Securities. Please go ahead.

Good morning.

Good morning, Sandy.

Actually it is morning your time. Just a follow on to the first question, if you will. I'm just playing around here and trying to come up with a little bit of an insight in terms of projections going forward, and I know it's very difficult, having not even sat down with Brigham yet to determine exactly where you're going and the end of the fourth quarter into the first quarter. But even using those minimums, if you will, on the infill and the Three Forks wells, the minimum of 28 and the minimum of 44, I was wondering what kind of timing those might have and what kind of impact they could have? I'm just trying to come up with some kind of a guesstimate model, if you will, going forward as to what the projections might look like on a quarterly basis knowing, of course, that they'll be uneven, but I'm just trying to look out a year to two years from here.

Sandy, remember, they did this microseismic work on this infill well, and if you go in and space a three every 1,500 feet, then you're going live by that because it's difficult to down space from there. And so this microseismic work that they've done on this well and the number three well is, I think, going to give us a lot of insight, although there's going to be, in my opinion, a lot of trial and error because we don't want to leave any oil in the ground. I'd listened recently to Budd Brigham's presentation where he showed up to six infills per unit and his belief that the methods they're using are extracting a greater percentage of the oil in place.

To answer, though, your question, I think that within the next three or four years those bigger numbers are going to -- that it's going to take that long to play it out. There's going to be not only Brigham and us doing some experimentation and downsizing that other players up there to finally figure out what the optimal spacing is and when to drill them. I think right now that's what Brigham is struggling with, not only on our 15 units but also additional units that they have as to how to schedule and how to investigate what the best way to get all the oil is. I recently saw that they are announced they're going do a four infill well unit up there to test that, and so I hate to --

Well the difference between the three and the six per unit, who do they actually have to make that application to? When you say you listened to a presentation, was that an investor presentation, or was that to one of the regulatory agencies, or who do they have to appeal to, if you will?

Where I saw it, Sandy, and all the other listeners, was they have a very large PowerPoint presentation on their website, and Budd Brigham and the rest of his crew gave a conference call last week, and they talked about all of these issues. The actual entity that they have to apply to the state, it's the state of North Dakota Oil and Gas Commission, and they have to make the argument that using the microseismic and other studies that they've done and others, that it warrants a down spacing to first three in the Brad Olsen unit, and that's who they had to apply to, is the state of North Dakota, and they were granted that. So that's the process that it goes through, but it takes a scientific approach and convincing the state that it requires the downsizing.

I understand. Well, do you have any internal models that you can share with us in terms of wishful thinking in terms of minimum and maximum where you're going on a quarterly basis? Obviously it depends upon others, but I presume you have some kind of model?

We're current working on our plan and budget for next year, Sandy, but we don't typically put out those prediction numbers. We have to make some assumptions because of how we're going to spend our money, and our board then will approve our budget in whatever form it is around the 11th of December at our next board meeting, but we don't that have completed as yet.

Okay, last question then. Is the cash flow that you're producing and so forth adequate to fund everything going forward, or do we look towards any kind of an offering in the future?

I don't see an offering in the future at this time unless there was some type of acquisition that would warrant that, but certainly sitting on approximately $40 million in cash and having $28 million in available debt gets us a long way down the road. It's a big --

Got it.

-- [target] there and the real answer to the question is how many wells are we going to drill with Brigham next year? And secondly, if we're successful on the Kern County acreage, how many additional infill wells will we do there and we just at this time don't know.

All right. Okay, well, thank you very much.

Thanks, Sandy.

Our next question comes from George Whiteside of SWS Financial Services. Please go ahead.

Good morning, guys, congratulations on an excellent quarter. Mine is sort of a follow-up question relative to cash flow. In terms of your relationship with Brigham, when will you be at positive cash flow considering oil and gas sales versus drilling costs, et cetera?

Well, we -- do you mean when will we pay out on the wells?

Well, right now I presume that you're in a period of cash burn. You're having to -- because of your drilling activities and participation there that you're spending more cash than you're deriving in income from the wells that have been put into production. Is that an accurate assumption, or are you positive cash flow on the project?

No, that is an accurate assumption. We are spending more than we're bringing in.

Do you foresee a point at which we'll be breakeven or better?

Haven't run those calculations. Again, George, we're working on our budget for next year, which we include cash receipts, as well as disbursements, so I'll know a better handle once we get that finalized. So I just don't have an answer for you right now.

Well, and I'm not asking that in terms of -- because everything is -- it's certainly positive that you're able to drill more than perhaps we would have expected, particular with the Three Forks now having proven out. You hoped it would be a good project or zone, and obviously it looks as though you are going to enjoy some success with that aspect of the project. Is that accurate?

Certainly we would like to encourage Brigham to explore more on our 15 units, because if you look at the map of the area, they used our money to cover all four quarters, and I think it would be complimentary to them to go out and test additional Three Forks. One Three Forks well in this area does not make a field, and there's additional people that are looking for the Three Forks, as well, so we just have to see. But I think that that would be certainly something that could be expected that we're going do additional Three Forks tests next year.

My second question relates to the number of shares and the escalation in outstanding or fully-diluted shares. Remind me what was the biggest contributor to the increase?

Positively the five million share offering last year, that was the biggest contributor. You mean year on year?

Yes.

That was the offering we done December of last year. We issued five million shares.

I needed to be reminded of that, thanks.

You bet, thank you, George.

Thanks, George.

Our next question comes from Michael Bodino of Global Hunter Securities. Please go ahead.

Good morning, guys.

Good morning, Michael.

I actually had a couple of follow-up calls -- questions, I'll be brief. You mentioned the reserve report that was used to help you get your bank facility. Have you released any of those numbers and what the engineers were giving you in terms of corporate reserves?

We done the second quarter.

I'll go back in the get it. You don't have to give me that information. I guess it's just probably between the cracks where I don't remember it. Relative to Montana and the acreage position that you've been assembling there, is this a -- do you have timeline in mind to finish your acreage of leasehold aggregation and your timing of either doing a JV or drilling a first well?

We would -- this is Mark, Michael, and we plan on continuing the leasing into next year. We're trying to pick up again. We've got a target of around 20,000 acres and some leases are a challenge, as you can imagine. But that will likely be ongoing through the next two quarters. We'll see where we're at then. We are working on our own internal work and pos -- we're debating the possibility of taking it to one of these -- a larger operator, including Brigham. We'd like to talk to them about it at that time appropriate time.

Are you using an external land service to help aggregate this, or are you all doing this in-house?

We're using the consulting service.

Sure. So a well on that new acreage next year maybe, but maybe beyond that?

Possibility of next year.

Okay. Last question -- I'm sorry, go ahead.

Michael, this is Keith. What we're seeing, and I think you've seen it, too, and maybe some other folks on the call is, the activity seems to be going north and away from the wells that were drilled just over from the border from the Rough Riders, so we'd like the see the activity move more towards where we've got our leases and see it heat up a little bit and I believe that it's going to.

It's certainly -- a lot of guys have been aggregating large chunks of acreage that way and I think the activity, in general, is going to continue to pick up, particularly in Montana, and maybe moving north away from Mount Cooley?

we're a little cautious because the prices we're seeing are nowhere near what you're seeing some of the averages up there, so we'd like to congregate our land position before we really talk about it.

That's understandable. Relative to your non-Cirque, non-Bakken drilling program what do you have left on your calendar with PetroQuest, Yuma or Houston Energy?

We've got one well with Houston Energy we're going to drill. As I mentioned, it's near our Delta Farms well. It's not an offset to that well but it's in the same field, and we have high hopes for that. That will spud around December 1st. On the Yuma-operated wells in Louisiana, as I mentioned, we're completing a well. In fact, around the 20th to the 25th we should have initial results on that well. It's a lower working interest, 4.5%. There are as many as -- depending, again, on the success of this well, but that I believe that we'll drill at least three and maybe five wells within next year. With Houston Energy, we have only one well slated for next year, I believe. Scott, is it just one?

No, we haven't finalized that stuff yet.

I think we've just got one that are firmed up, and that's probably going to be in the second quarter, and that's about a 20% working interest well. That's with PQ. And with Houston Energy, again, we're evaluating these results from these two Permian Basin wells that were not successful. We had originally planned to drill up to five in that basin, but we're rechecking the seismic data and we'll be talking to them through the end of the year and formulating plans for next year, but as of this time we don't have any firm commitments.

Very good. Thank you very much, guys.

Thank you, Michael.

Our next question comes from Charles Matson, an individual investor. Please go ahead.

Thank you, good morning. I wanted to ask a question. I guess back in November and December you completed four wells with Brigham -- the BCD Farm, the Lee, the Strand, and the Williston -- and I'm curious as to what percent of the drilling costs has been recovered on these wells?

I've got it.

Approximately.

Just -- if you'll give me just a second here to look at the figures . I would say it appears across the board in the range -- to be in the range of 60% to 70%. Would that be fair, Scott?

Yes, that's fair.

60% to 70%.

Okay. And now then, refresh my memory, there's kind of a ratio of what your revenue interest is before and after the 100% recovery.

Correct.

What is that ratio?

65% before payout, and then it reverts to 35% after payout.

And so approximately --

On the first six.

On the first --

Six.

Approximately half of the initial payout, once recovery is made.

Well, it's -- we'd like just to be sure. Brigham didn't own 100% working interest in these wells, so on the first six we've got 65% of the working interest, which varies greatly --

No, I noticed where your ownership percent was 45%, 60%, 40%, and 65% on the first four in your original press releases so that it does change. But the ratio, I assume, stays kind of like -- basically it goes to approximately half of the revenue interest following 100% recovery from the initial revenue interest?

Right. The ratios are 65% of their initial working interest in that first well, and 35% to them. So if it's 100% well, it was 65% U.S. Energy, 35% to them. If it's a 50% initial working interest to Brigham, then those numbers would be cut by 50%.

Okay. And then when do you expect 100% recovery on those wells? Once again, approximately.

Of course, it's tied to the price of oil, but we've looked at, say, 16 to 18 months, it looks like, for payout I think would be a fair --

When we ran the economic models we estimated 19 months, and it looks like we will potentially beat that on most of the wells.

Okay. Now, what is basically the cumulative production on those wells, and then I guess what is the current daily production?

Well, of course, it varies across the whole spectrum of it, Charles. You can go on to the North Dakota Oil and Gas Commission's website and they publish cumulative numbers. We don't publish those numbers, nor does Brigham. And as far as a day to day, we don't put those numbers out, either. I think it's more meaningful when you talk about what the net is on the entire package for us.

Okay. So if, once again, this is public data, so if we just said the Williston, it started out with an initial oil of 2,769 in the first 24 hours, what was it for the last month, or what is it today?

I don't have that right in front of me what the numbers are, Charles.

Okay. Once again, I guess we can go back to the North Dakota and retrieve most of that information.

They do -- I have seen it. I haven't looked it up recently, but I have seen that they put outcome and -- I think it's monthly production, though, not daily.

Right. And I guess if it takes 19 months by your projections to recover 100% of the well cost, of course, your percentage of the recovery will cut in half. How many months do you think it will be before you recover a second well cost?

Again, that 19 months is from the initial production and so all 13 units that we've got currently have different --

No, no, that's on a per well, I presume. 19 months is each well basically will on average. Once -- I realize it varies because some of them have higher initial production than others and very similar completion costs. But if on average it's about 19 months to recover, how many months past that do you think it will be that you make the second recovery and get your money back? The first 19 months you basically break even on your investment. How many months past that do you think it will be before will you recover your investment a second time, basically having now made 100% on your investment?

With the reversion of the working interest?

Right with the reversion of the work -- well, basically without that, if you just said when do you expect -- the barrels of oil after 19 months, how many months will it be before we have those same equivalent barrels of oil?

I think it's -- that's very hard to predict, Charles, at this point and, of course, it's very much tied to the price of oil, so it's --

Right. No, I'm not asking price. I'm just saying barrels of oil --

Barrels of oil?

-- equivalent?

You're likely aware there's a steep decline, particularly off of the --

Would five years be a reasonable guess?

Five years, it's hard to speculate.

Would ten years be a reasonable guess, after the first 19 months and another ten years?

Charles, we just haven't run those numbers so a guess would be all that it is, but we're looking forward and I can tell you this, when we ran the initial numbers in our initial model, we were looking at about a 45% internal rate of return and it looks like we're going to beat that.

Right. Okay, thank you very much.

Thank you, Charles.

Appreciate it.

Our next question comes from Robert Carlson of Janney Montgomery Scott. Please go ahead.

Hey, guys, congratulations on the recent activity. Just a couple of questions. When we are accumulating this acreage, do we have staff in-house where we could be the operator should we decide to do so?

We probably will have to add on a few people, Robert.

Okay. How about the geothermal aspect? What's going on there? We haven't heard any updates there.

Yes, what they've done is they continue to evaluate some properties, and possibly encourage some joint ventures, but right now there hasn't been a lot of activity to mention.

Other than field activity.

Field activity. We're still very encouraged. The sale that they made this spring is definitely encouraging, as well as the work that they continue to do, which we believe will enhance the properties to where someone may come in and joint venture, as I mentioned, or buy it outright, like we did this spring.

But with oil prices ratcheting higher, shouldn't that activity increase?

I would think so, yes.

Okay, thanks.

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

I'd just like to thank everybody for your support. Very pleased in the results. Would like to see it come a little quicker, like everybody would. A little disappointed that we didn't get the final five wells completed sooner, but that gives us something to look forward to in December. Of course, the holidays coming up that may even put some delays in it, but we're very encouraged, we're very pleased to have Brigham as our operator. We're pleased with Cirque and the folks that they have on board and the things that we're going do out in California and certainly, knock on wood, we hope that we're successful there. We continue to look at additional deals, guys. We've looked at lots and lots of deals and we pass -- obviously pass on most of them, but we're just here working it and looking at deals, and we're trying to grow our production, grow our revenues. So thanks to everybody for your support and listening in on the call this morning.

thank you, everybody.

This concludes today's conference call. You may now disconnect.