US Energy Corp (USEG) 2010 Q2 法說會逐字稿

Good morning. My name is Hughie, and I will be your conference operator today. At this time I would like to welcome everyone to the U.S. Energy Corporation second-quarter financial results and operations update. (Operator Instructions).

Thank you. I would now like to turn the conference over to Mr. Mark Larsen, President of U.S. Energy. Sir, you may begin your conference.

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, we will review our operational highlights for the second quarter of 2010, as well as the period subsequent to quarter-end and provide you with an update on our various strategic operating initiatives. We will also conduct a brief financial review before taking your questions.

On August 9, 2010, we filed our 10-Q for the second quarter ended June 30, 2010, and I would refer you to that document for the Company's most recent financial statements.

Before I turn the call over to Keith Larsen, I would like to read you the following forward-looking statement. In this conference call, officers of U.S. Energy Corporation will be making forward-looking statements within the meaning of Section 21E of the Securities & Exchange Act of 1934. All statements, other than the statements of historical fact, are forward-looking statements, including without limitation the statements under Management's Discussion and Analysis of Financial Conditions and Results of Operations, as well as disclosures about possible exploration, development and operational of our oil, gas and mineral properties; production potential of wells scheduled for drilling or completion; the Company's year-end production goal; 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 affect the reported amounts of assets, liabilities, revenues and expenses. Actual results could differ from our estimates. You should consider 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 June 30, 2010, including the cautionary statements regarding forward-looking statements.

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

Thank you, Mark, and good morning, ladies and gentlemen. At the end of the second quarter, the Company had 13 producing wells, up by one from the first quarter and average daily production during the quarter of 1098 net BOE per day versus an average daily production of 248 BOE per day for the quarter ended June 30, 2009. The combination of only a single new well and declining production from existing producing wells impacted our results, which were down from the strong showing we posted in the first quarter of this year.

Based on new wells added so far in the third quarter and our drilling schedule for the balance of 2010, we expect our production and, therefore, our financial results to improve over the next few quarters. Our drilling participation agreement with Brigham continues to drive much of our year-over-year improvement in production, cash flow from operations and revenue growth.

Just recently we announced the completion and initial production for the 10th and 11th of the 15 initial wells contemplated under the agreement. It is our expectation that the remaining initial wells will be drilled during the balance of 2010. Upon drilling and completing the 15th well in the program, we will have earned the right to particularly drill up to 30 additional wells in the Bakken formation and up to 45 wells in the Three Forks formation for a total of 75 additional wells. If spacing is ultimately increased to four wells per unit per formation, the potential number of additional wells could increase to 105.

At the start of the second quarter, we announced initial production from the Jack Erickson well, the ninth under the DPA with Brigham. It produced approximately 2323 barrels of oil and 1.9 million cubic foot of natural gas per day or 2652 BOE per day during an initial 24-hour pullback period. The well was completed with 12 Packers and 30 fracture stimulation stages. U.S. Energy's initial working interest in this well is approximately 21% with a net revenue interest of 17%.

Just last week we announced initial production from the Sedlacek Trust 33-4 well, the 10th well to be completed with Brigham. It produced approximately 2413 barrels of oil and 1.7 million cubic foot of natural gas per day or 2695 BOE per day during an early 24-hour flow back period. The well was completed with 12 packers in 30 fracture stimulation stages. U.S. Energy's initial working interest in this well is approximately 47% or 37% net revenue interest.

Announced this morning, initial production from our 11th well with Brigham, the Sukut 28-33 well, produced approximately 1752 barrels of oil and 1.2 million cubic foot of natural gas per day or 1959 BOE per day during an early 24-hour flow back period. The well, again, was completed with 12 packers in 32 fracture stimulation stages. U.S. Energy's initial working interest in this well is approximately 42%, 33% net revenue interest.

Oil sales have commenced from both the Sedlacek and Sukut wells. Gas is being sold currently from the Sukut well, while gas sales from the Sedlacek trust wells are expected to commence within 30 or 45 days.

In terms of some of the remaining initial test wells to be drilled under the agreement, we expect the Kalil Farms well to be the 12th drilled under the DPA with Brigham. We have an initial working interest of approximately 20% representing 16% net revenue interest in this well, which we believe will be spud late in the third quarter. The 13th initial test well should be the Hovde 33-4 well, in which we have an initial working interest of approximately 23% which translates into 18% net revenue interest.

We expect this well to spud early in the fourth quarter of this year. The two remaining initial test wells to be drilled under the DPA will also spud in the fourth quarter.

We understandably remain very pleased with our arrangement with Brigham, enjoying 100% success rate to this point. As we move toward the completion of the 15 initial test wells, we are increasingly focusing on the longer-term potential for this agreement. In June the North Dakota Industrial Commission granted us two down spacing or infill drilling permits for the Brad Olson unit in Williams County. The Brad Olson 916 #1 well, which as a reminder was completed in October of 2009, with an IP rate of 2112 BOE per day, was the first well drilled in this unit. The first infill well, the Brad Olson 916 #2, has been drilled to depth and completion initiatives are pending.

The second infill well, Brad Olson 916 #3, is now scheduled to spud by mid-August rather than late October as originally anticipated with completion initiatives expected to be wrapped up approximately 90 days subsequent to the completion of the Brad Olson #2 well. By drilling the two wells back to back, we will capture the drilling cost savings and then produce and evaluate micro-seismic data on the Brad Olson #2 well, along with well performance and any additional spacing data that can be attained. The Company has an approximate 32% working interest and 25% net revenue interest in both the #2 and #3 wells. It is anticipated that a similar working interest will apply to all future wells in the unit under the terms of the DPA.

In June we decided to drill a Three Forks test well in an existing partnered unit. The State 36-1 #2 spudded in mid-July and is currently drilling in the horizontal portion of the well bore. The original well drilled in this unit was the State 36-1 well, which had an additional production rate of 3807 BOE per day in the Bakken formation. The Company has an approximate 13% initial working interest and 11% net revenue interest in this first Three Forks well, and it is anticipated that a similar working interest will apply to all future wells in the unit under the terms of the DPA. This well is also planned to be a long lateral well, 10,000 feet, and is expected to be completed in 30 fracture stimulation stages.

We have cored the Bakken and the Three Forks zone of this well in order to obtain further geologic information pertaining to the target zones. The results from these early infill and Three Forks wells are important to the overall size and longevity of our agreement with Brigham. If they prove successful, this could ultimately translate in up to 90 wells being drilled under the DPA, depending on the ultimate spacing within the units to be allowed by the state of North Dakota. At present we believe we could have as many as 18 producing wells with Brigham by the end of the year.

In addition to our Williston Basin drilling program, we are involved in the Gulf Coast onshore and West Texas regions with three separate oil and gas partners. During the quarter ended June 30, 2010, the Company was producing approximate 311 net BOE per day from four previously announced wells in the Gulf Coast region. Each of these wells has held relatively stable production rates since their completion dates.

Also, during the second quarter, we acquired a 10% after casing point working interest in up to five prospect areas in the Permian basin in West Texas. The Aspen well is currently drilling forward at approximately 9400 feet, and the well is expected to take another 30 to 45 days to drill and complete, assuming we have success. The Wolf prospect is scheduled to spud in late August and is anticipated to take approximately 45 to 60 days to drill and complete. The Aspen and Wolf prospects are 13,500 foot targets that are estimated to have a gross unrisk reserve potential of 1.1 million BOE and 800,000 BOE respectively.

Subsequent to quarter-end, we were pleased to announce successful drilling and completion of one of our largest wells to date, in which we enjoy significant working interest. The ALMI #8 well located in the South Chauvin field in Terrebonne Parish, Louisiana, reached contract depth of 12,624 feet total vertical depth in late July. The well encountered approximately 64 feet of net pay in two zones. We encountered 14 feet of net pay in the lower target zone. The lower zone is expected to have an initial production rate of approximately 4 million to 5 million cubic feet per day.

In addition, approximately 50 feet of net pay was encountered in the upper target zone, which is expected to be completed upon depletion of the lower zone. We expect initial production rate from the upper zone to be approximately 10 million to 12 million cubic feet per day. U.S. Energy participated for 53.3% of the drilling costs, 50% after casing point, in order to earn a 36% net revenue interest interest in prospect. The well is currently being completed and is expected to begin producing gas and condensate for sale by next week. We expect this well to make a significant contribution to our third-quarter production numbers.

For the quarter ended June 30, 2010, we produced 72,601 barrels of oil and condensate and 164 million cubic foot of natural gas or a total of 99,934 barrel of oil equivalent for the quarter. The production had an average realized sale price of $71.98 and $6.05 respectively, which was substantially higher than what we realized in the second quarter of 2009. This translates into operating revenue from our oil and gas business of $6.2 million in the quarter.

Looking ahead, we have an active drilling program planned for the second half of 2010. In the Williston Basin, we expect to drill and complete four remaining initial test wells envisioned under the DPA, two infill wells and one Three Forks test well. The projected net cost to the Company for all remaining wells is expected to be approximately $13.2 million, which is subject to change based on Brigham's ownership in the individual wells and participation from other working interest owners.

The Company committed to spending $1.1 million on completing the ALMI #8 well in the third quarter. We continued to evaluate our area of mutual interest for drilling prospects, and we may elect to drill additional wells onshore in the Gulf Coast region in 2010. We have also allocated $1.5 million to drill up to five inland oil and gas wells in the Permian basin of West Texas and an additional $1.5 million to drill up to four more wells in central Louisiana.

Additionally we continued to evaluate other opportunities to grow production so we can leverage our strong balance sheet in the face of improved commodity pricing. We have budgeted $8 million for our Louisiana and Texas endeavors through the end of 2010.

Overall, based on our continued success in the Bakken, our recent success in the Gulf Coast and our planned drilling schedule for the balance of the year, and potential joint ventures or acquisitions, we anticipate that the Company will meet its goal of 2500 BOE per day at December 31, 2010, based on our trailing 30-day average production.

Turning to our Mount Emmons molybdenum project in Colorado, Mount Emmons Moly Company, a wholly owned subsidiary of Thompson Creek Metals Co. USA, continues to advance this project through the early planning and evaluation stages. Mount Emmons moly continues to meet their spending commitments and has budgeted approximately $7 million to $9 million for the project this year. The ongoing work being done by Mount Emmons moly is focused on extensive pre-feasibility, engineering and environmental studies, along with continued permitting activities. The culmination of this preliminary work, including an anticipated underground infill drilling program, will then be compiled into a full feasibility study for the project.

We continue to work hand-in-hand with an industry-leading partner to ensure the environmental plan keeps pace with the need to drive economic growth in the region and are confident that we can develop a project that meets the needs for all groups.

Moving on to geothermal initiatives, at June 30, 2010, U.S. Energy's total investment in Standard Steam Trust LLC, a Denver, Colorado-based private geothermal resource acquisition and development company, stood at $3 million, reflecting a 22.8% interest in the Company. U.S. Energy's stake in the Company dropped from 23.8% at December 31, 2009, as the company did not elect to participate in funding a cash call. In April 2010, the Company received a cash distribution from Standard Steam Trust in the amount of $1.1 million. This distribution is the Company's share of proceeds from the sale of two of SST's geothermal prospects to an undisclosed third-party. With the ongoing industry and utility interest in the renewable energy sector, we believe SST remains a tremendous opportunity to create further value for our shareholders in the future.

Turning now to our financial results, the Company recognized $6.8 million in revenues during the quarter ended June 30, 2010, compared with revenues of $1.5 million during the prior year period, a 355 increase over the second quarter of 2009. Cash flows from operations improved to $7.5 million for the six months ending June 30, 2010, as compared to catch consumed by operations of $2 million for the same period during 2009.

In addition, the Company added approximately 510,000 BOE and reserves from wells completed thus far in 2010. These increases are the result of our drilling activity in the Williston Basin since December 31, 2009. The Company recorded net income of $1.4 million for the six months ended June 30, 2010, or $0.05 per share and a net loss of $130,000 or less than $0.01 per share for the three months ended June 30, 2010. That is compared to a net loss of $2.9 million or a loss of $0.13 per share during the quarter ended June 30, 2009.

Looking at the balance sheet, the Company had cash and cash equivalents of $6.1 million, plus $34.4 million in US treasuries at June 30, 2010. Working capital at the end of the second quarter was $43.1 million, down from 53.4 million at the end of 2009. The decrease in cash and working capital was primarily due to the investments made in our oil and gas portfolio.

Subsequent to quarter-end, 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 of up to $75 million with initial borrowing base of $12 million. It 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 corporate purposes. The facility provides us with a non-dilutive cost competitive source of capital that we can use to advance our overall drill strategy. This facility, combined with our $10 million unsecured line of credit at a regional bank, gives us current access to $22 million in available credit. As of today, we have no borrowings under either facility.

We continue to execute operationally in the second quarter with our results affected by the timing of the completion of new wells, some of which came on production in the third quarter. We believe we will continue to drive growth over the near, medium and long-term. We also believe our strong balance sheet and improved access to non-dilutive capital provides us with the flexibility to act on a range of opportunities in the execution of our growth strategy.

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

(Operator Instructions). Marco Rodriguez, Stonegate Securities.

I was wondering if you could talk a little bit about your production volumes in Q2? Did they meet the expectations that you had going into the quarter?

Good morning. They did not. We thought that we would have drilling and completion of additional wells in the second quarter with our partnership with Brigham. We have seen some delays in the completion initiatives up in the Bakken. There are currently a record number of drill rigs working up there, and quite frankly, they are having a bit of a difficult time getting tracking crews. So there were some delays that are going to be pushed into the third and fourth quarters on the completion.

Okay. What was the oil price differential in Q2?

The oil price for Q2?

The differential.

The differential has been running about -- I think it averaged about $6.00 or $7.00.

Okay. And then the update that you provided in regard to your overall reserves adding about a little over $0.5 million, do you have the exact number as far as where your reserves are currently, including the production you have already done and kind of a breakdown of what is oil versus gas?

You know, that will probably come out with our year-end reserve, but the 510,000 barrels was a result of the Bakken wells that were completed in the first six months. And we did not publish the exact amount of the total in our 10-Q or our 10-K.

Right, okay. And then some curiosity here in regards to the real estate. In your -Q you would talk about the occupancy rate had a pretty significant uptake quarter over quarter. I'm just wondering what might have been a driver behind that.

Well, we dropped some of the rates to increase the occupancy up there and stay competitive. I think that may have had as well as the overall recovery from this recession, which we are feeling now in Wyoming because of the higher commodity prices, oil and gas prices.

No per se projects that came on that you saw an influx of individuals? Just more of a pricing aspect?

You know, if you go to Gillette, Wyoming, which is where this facility is located, they always have projects going. They are building a $2 billion approximately electric power plant up there. They are doing an $80 million addition to their hospital. It is always quite active. But to point my finger at one particular project, I don't think I could do that.

Joel Musante, C.K. Cooper & Co.

I just had a few questions. First, on the production numbers, I'm just trying to get -- an idea of when you expect all these -- the most recent wells -- sometimes they are tested, and they don't go online right away. So just the last couple of wells and then the ones that you have in the future that you know about. Can you give me a good idea of when you expect them to come online? Because, as you know, your production base is not that great at this point, and with these big production rates coming on, it could really move the needle a lot depending on the time frame. So I just wanted to see if I can nail that down a little better.

I think you listened in on Brigham's conference call. They are expecting to get another half of a fracing crew during the third and fourth quarter, and hopefully two full crews by January. I don't mean to hedge a little bit, but we are probably looking at a completion of the #2 well in the Brad Olson unit somewhere around the 1st of October, and probably similar for the Sukut. We have not been -- I have not seen the numbers yet for the Three Forks test, but I'm sure that Brigham is going to be anxious as we are to do completion on it and see what type of results we get.

Under our agreement, all 15 of the original have to be drilled by the end of the year, and they have indicated, as we mentioned, we are going to have the to infill and the Three Forks. The timing for the completion on the frac jobs is a bit up in the air because of Brigham's other activity. I'm hopeful by the end of the year we will have all 18 wells completed.

Okay. So what was your exit rate at the end of the second quarter for production?

It was 1097 barrels BOE per day.

Was that the average rate or the --?

No, that was the average for the quarter. It was probably a bit lower for the exit because we did not complete those wells, the other three wells. So I don't have it in front of me, but I can look it up if you want to give me a call afterwards.

Sure. Okay. And then can you just give us an update on what you are seeing in the M&A market and if you're close to any new deals?

We are looking at three deals seriously as we speak, and I'm confident before the end of the third quarter we will announce at least one of those. We are looking at initiatives throughout Texas. We are looking at some stuff up in Montana. We are looking at some things in Colorado, here in Wyoming in the Niobrara, as well as some stuff in California. And I'm confident before the end of this quarter that we will have one of those deals done.

What is your objective or criteria for just what you're looking at?

We are looking mainly at oil. We are seeing some opportunities in gas, but predominantly our focus is on oil. We are looking at sizable acreage packages, so that if we are successful in a test, that we have a lot of running room, multiple well potential. That is our criteria.

Okay. Well, that is all I had. I appreciate it.

Bob Carlson, Janney Montgomery Scott.

Congratulations, guys. On the deals that you are looking at, are these leases that we would pick up?

It is leases that we pick up and joint ventures.

And secondly, where do we stand now that our production is ramping up in the establishment of a hedging program?

We are currently working on that, and I would expect that we will have some hedges in place before the end of the third quarter.

Thank you. Again, well done.

Sandy Wyman, Guilford Securities.

Just one quick question here. With a $75 million line of credit that you put in place, plus the $10 million, of which you have got $22 million immediately available and it looks to me like you got $40 million plus in cash or equivalents, does that not cost you something? Is that really long-term thinking, or would that be sort of earmarked for some of these deals that you are talking about?

Well, it is really both. We don't know how many wells Brigham will propose, but we certainly don't want to be out drilled by them because under our agreement we are either in or out and the same with them. So we thought it prudent to be looking for debt when we don't need it. But certainly we see it as complementing any acquisition that we may make, as well as providing capital for drilling money if that becomes the case, and I believe that it will be.

George Whiteside, SWS Financial Services.

Congratulations on a good quarter. My question is to some degree I realize it may be difficult, but looking at your balance sheet, it appears as though you've essentially invested $15 million of your cash in the first half of the year. And then you are ramping up rather strongly on the production side. Do you foresee a time when in effect you will be at least at equilibrium or cash flow positive in terms of investment versus revenue coming out of your various projects?

Well, it is kind of hard to project that depending on how much activity we have got and, of course, the timing of these completions. I mentioned earlier, specifically in the Bakken, that's a major driver, which is why we missed our mark in the second quarter. We thought we would have more completions. And that is -- (multiple speakers)

That is not under your control?

Exactly. It is not under our control. So if we had full control, I could give you a more definitive answer. But, again, what our goal is is to drive up production, I mentioned earlier to hedge a portion of our production just in case there are some weaknesses in the prices, and grow our cash flow and revenues through the drill bit.

And that is certainly understandable. It sounds as though you have got a strategy at the moment with so many projects coming on and prospects of acquisitions, etc. that essentially you have got if you want to call it a policy of being opportunistic and driving forward as rapidly as you possibly can if the projects make sense. Is that a good summation of the overall game plan?

That is definitely an indication of what our plans are, and we've had a lot of patience, and we have looked at a lot of deals. I would say so far this year we have seriously looked at 10 deals, and we have screened at least 50 different deals in different areas. We are opportunistic. We believe that if we keep our patients that another Brigham-like deal will come along in one of the shale plays or one of these basins, and I'm confident that we will be able to attain them.

Well, and you have certainly positioned yourself well financially, not only in terms of current cash balances, but taking advantage of the situation where credit is available and, as you say, borrowing money when you literally don't need it. Based on some recent past experience, that looks like a very wise move.

Well, it does cost us money to have the facilities in place, but we think that we are well positioned when that next opportunity comes along. As I mentioned earlier, it is a good time to look for money when you don't need it. The terms are much better I should say.

Yes. Thank you.

(Operator Instructions). There are no further questions at this time. Do you have any closing remarks? I take that back. We just have three participants that just queued up. [Charles Manson], who is a private investor. Please go ahead.

Thank you for the presentation. I have a couple of questions on the production. I think you mentioned just a minute ago that the average exit production for the last month was 1097 barrels of oil equivalent per day. I added up the wells in the Williston Basin that you drilled since November through 1st the April, the average is probably a little less than six months of total production time, and the initial production for those wells was 17,119, and you're running at approximately -- well, you said this number was a little high. Actually the last day would have been lower. Are you, in fact, getting about 5% of initial production on those wells?

Well, the wells are at various stages of timing, if you will, since their completion. The wells are performing pretty much as we had predicted, and again, the prediction was a hyperbolic curve where they come down extremely fast from that very high initial production rate. And then we expect that they will level off somewhere in the 8% to 14% range after one year --

Yes, you are already -- the numbers you just gave are already about 5% of initial production on wells that have had less than six months on average.

Well, remember those IPs are gross. They are not our net interest in the wells.

Okay. That is correct. I probably have an --

So that, again, I think you're probably up better than 15% or 20% of that initial production --

Right. No, that would drive it up. That probably explains the discrepancy. I'm just grabbing.

Then one other question that I had it, and in the past I guess I had talked with you and you mentioned that you were -- or that Brigham was using ceramic [profits], and that it cost about $1 million per well to use the ceramic profits. And I was asking the question and the basis as I understood it was that the crush strength of the ceramic is greater than the formation pressure, and that for sand, which is the other alternative, the crush strength is theoretically below the formation pressure. And I had asked a question -- I don't know if you have an answer for it yet or not -- but is the crush strength of the sand greater than the crush or deformation strength of the shale, and if so, why would it matter if you use ceramic or sand?

I must tell you I don't know the answer to that. The way that it has been explained to me, as I think I told you before, was white sand has a crush of about 8000 psi. Now how that is interpreted in the Bakken formation in the deformities, I don't have that answer. The way it was explained to me is from Brigham and their operations is they use the ceramic, which has a 12,000 psi crush strength near well bore to ensure that the well bore is kept open and keep those frac wings open. But, on the technical side, I really don't have the answer.

Okay. Thank you very much.

[Jack Nimby], private investor.

I appreciate your time for taking my call, and congratulations on your recent reporting. I noticed that there has been some state auctions in North Dakota, and I just wondered if USEG has participated in that auction. I guess it has been reported that your Brigham partner was able to acquire some leases at some relatively inexpensive costs of about $1500 or less. Did USEG participate in that auction?

We did not participate in that auction nor did we participate with Brigham, and I think that reported number was closer to $1000 an acre --

Okay. I was just curious why is that area an area that you're looking to get away from, or do you find opportunities greater in other areas?

No, we have a noncompete with Brigham in that area. We have been an AMI where if we acquire leases we have to offer it to them. So we have not focused on that area. Our focus has been in Montana where we believe there are some opportunities there, and the price per acre is much less than it is over in that Fairway area, if you will.

Terrific. And is part of the -- you're hiring of the investment banker and looking at deals, is part of that -- is part of the new deals you are looking at, would that include shale plays? And, again, it is pretty much part of a two-part question because I have actually posed the same question in a prior conference call. I know there has been a huge difficulty in terms of hiring and securing the fracing crews. In general, can you comment on if you're looking at shale investments, and what is the industry doing in terms of handling the shortage of all of these fracing crews that obviously are affecting not only your production levels but also many other companies, O&G companies in the same industry?

Well, I can give you kind of an overview. The first part of your question is yes. We are looking at some things in the Eagle Ford. Not so engrossed with the Fayetteville myself. We are not in the Marcellus. I think that the big boys are going to have to figure that play out, and there are going to be some environmental concerns. We still like the Permian, and there is some possibility that there are some shales and some tight sands down in that area, predominately, though, the Bakken, and we are also looking at some things in California.

The second part of your question, I can answer you on a personal note. My son in January was hired by BJ. They took him down to Denver as part of about 25 different individuals, he was one of them. Paid him $18 an hour to go through six weeks of training where he got his hazmat and he also got a CDL, commercial driver's license, and they put him right to work over in Dickinson, North Dakota. He is working mainly for EOG on frac jobs. He came home about two weeks ago and told me another 25 folks signed up in Denver.

So the industry, the way I explain it to people, is that, if you build it, they will come, but there is going to be a lag before they come. Certainly Halliburton and BJ and the other service companies want to wrap up as quickly as they can because that's how they make their money, but some time there is a lag, especially with the record number of rigs that are working up in the Bakken. Recently I believe it's up to about 140 rigs that are working. So we are confident that they will come, but the prices are probably going to move up, and there are going to be some delays.

Right. It has been reported that the cost of some of these wells has reached almost $8 million, and I would hope -- again, it's not only USEG and Brigham, but there are many other companies that they are able to complete their verticals, but the laterals have been delayed again just due to shortages of the fracing crews. So that's been a concern. Obviously it affects production, but it appears that Brigham is going to hire another half crew, and maybe -- are they going to have two full crews committed then effective January, or is it two additional crews?

I believe it is two total crews is what they announced on their conference call.

Okay. Also, in the next series of questions, there has been quite a bit of message board discussion on a number of issues, and obviously, as an investor or whether retail or an institutional investor, we have all got the same concerns in terms of what USEG is doing in the involvement in some of their investments as it relates to the book value or I should say the price per share versus the book value of USEG. And obviously we are all disappointed in that regard. And I know you have limited ability to be able to talk and discuss on where the price of USEG should be at this point.

But in terms of the actual real estate at this point, I know that the rentals or the occupancy rates have gone up. Are you actively trying to monetize or put the property up for sale? I understand that in this environment it is probably not the best thing to do. But has there been thought and discussion on that?

There has been thought and discussion on it. But the one thing about that is, we are getting about a 7% return on our money, which beats the heck out of what we are getting in treasuries. So to monetize and put the money back into treasuries is a bit of a difficult situation, but our board has discussed those matters. We have not made a definitive decision to actively go out and market the property.

Okay. I appreciate the response on that. Also, again, a big part of the concern of many of the investors has been the G&A expenses. I know that where you are currently located, that obviously the cost of the plane and the cost of hiring out a pilot and all those concerns. Have you looked at the feasibility studies of hiring out a private plane when the opportunity calls for travel, that versus the cost of the plane and all the overhead that comes along with it?

Because of our location, to charter an airplane to come up here, you are paying a couple of hours of dead add time. Let me just speak about the airplane a little bit.

It is just another one of the tools. I think it was one of the key instrumental tools that helped us get the Brigham deal, as well as several other deals. We have used the airplane sparingly. We generally, if we don't have less than five people going, we take commercial. I travel commercial a lot myself.

Okay. So you do still fly in commercial, and again, so there have been studies at least performed in terms of seeing if it makes sense to keep the plane and the cost of the pilot and then all the other associate expenses versus hiring out specific contracted flying? (multiple speakers) So has that feasibility study been done?

We have looked into those numbers as I mentioned, and right now the board and the management has decided that that is the best practical way to handle some of our travel.

Okay. And one last final question is, on some of the -- I have not had the chance of going through quite a bit of the stock options offered to employees. I know, again, it is a big item that has been discussed on the board. And again, obviously we all want everybody to do well from a stock performance standpoint and all the key employees and all the key members obviously to do well in terms of stock pricing. But my concern has been that it seems to have been pretty excessive, especially from where we are right now currently trading under book value. Are some of these options tied to performance of the stock, and it revolves around price per share?

Well, over the past two years, there have been no options issued, except for 10,000 options were issued to our new board member, Stephen Conrad, that just came on. But management has not received them. We are cognizant of the fact that they are accounted for under Black Scholes, and they do hit our earnings. And so we have not issued any options.

Anything recently. Terrific. Keith, I do appreciate your time, and good luck on our next few deals. Hopefully they will come through, and again, I appreciate your time and good luck.

Jack, thank you for the questions and answers. I appreciate it.

[John Creasing], [Mailer & Emerson].

Nice going on your progress. I have two quick questions. One is, do you have any development locations next to that major gas well in Louisiana?

No, it is a one-shot deal.

Okay. Number two, what is the pipeline outlook up in the Bakken? I know at one time there was -- and maybe there still exists -- I'm sure there does in some places -- the differential for trucking to get to the nearest pipeline. What is the outlook for improving the economics up there with better gathering system?

Actually it has been -- has improved over a year ago. The differential got as high as $19 or $20. They did have some bottlenecks up there. EOG has put a 50,000 barrel a day train, an actual unit train that goes down to Cushing. There have been several reversals of portals. It appears to me that they are increasing their takeaway capacity by some 300,000 barrels, and they are actively working on that. We have been pleasantly surprised at the differentials down in the $6.00 to $7.00 range. When we got into this deal, we modeled it at $70 oil and a $10 differential. And, as we have mentioned, we have been able to enjoy much higher prices on that. And, again, we are looking at hedging a portion of our production to ensure that those type of hits will not affect us as much.

At this time I'm showing no additional questioners in the queue. I will turn the program back over to Mr. Larsen for any closing remarks.

Well, guys, just keep an eye on us. I appreciate everybody listening into the call. We are making progress, as I mentioned. I'm confident we are going to have another deal lined up before the end of the quarter. I'm very pleased with the production and the advancements we are making with Brigham. We see at least the next three to four years a lot of run room up there. As I mentioned, 90 to 120 additional wells. We think we're going to have some success in the Permian with Houston Energy down there. We will know within the next 30 to 45 days, and we are just going to continue to grow our production, continue to grow our revenue, cash flows, and just become a serious oil and gas company.

So thanks, everybody, for joining us. Thank you for the questions. We appreciate it, and I look forward to the next quarterly update.

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