US Energy Corp (USEG) 2011 Q3 法說會逐字稿

Good morning, my name is Karen and I will be your conference operator today. At this time, I would like to welcome everyone to the US Energy Corp third quarter 2011 operational and financial results conference call. All lines have been placed on mute to prevent any background noise. Thank you.

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

Good morning, ladies and gentlemen; and thank you for joining us today. Joining me this morning is Keith Larsen, Chief Executive Officer of US Energy; and Bryon Mowry, Principal Accounting Officer for the Company, who will be reviewing the financial section of today's call.

In terms of an agenda for today's call, we will provide you with an update on our operating initiatives for the quarter ended September 30, 2011, as well as the period subsequent to the quarter-end; and conduct a brief financial review for before taking your questions in the Q&A portion of the call.

Before getting started, I would like to note that during this call, we may make forward-looking statements, which may be identified by the words will, anticipate, expect, and similar words that are based on the beliefs and assumptions of US Energy's management team. These and all statements, other than statements of historical fact, are forward-looking statements within the meaning of Section 21e of the Securities and Exchange Act of 1934 and Section 27a of the Securities Act of 1933. Forward-looking statements are subject to numerous risks and uncertainties, including those described in Form 10-Q for the quarter ended September 30, 2011, which we filed yesterday, on November 7th; and our Form 10-K for the year ended December 31, 2010 and our other filings with the SEC, all of which are incorporated herein by reference.

Now I'd like to turn the call over to Keith.

Thank you, Mark; and good morning, ladies and gentlemen.

I will now begin the call this morning with an overview of our third quarter 2011 operational highlights. At September 30, 2011, the Company had 37 gross producing wells, which include 19 Williston Basin wells, 6 Gulf Coast wells, 11 Austin Chalk wells; and our Booth Tortuga prospect and one Eagle Ford well, with average daily net production during the quarter of 1,306 BOE per day. This is an increase in 16% BOE per day sequentially from second quarter of 2011. The increase in production is primarily due to wells coming back on production in early July, subsequent to the weather-related issues encountered during Winter and Spring months in the Williston Basin of North Dakota. During the quarter, in the Williston Basin under the Brigham program, we spudded the Kalil #2H well in mid-September, and reached TD last week.

We have a 27% working interest in this well, and we anticipate completing this well in the fourth quarter of 2011. The well is an infill Bakken formation well, and the original well in the unit had a gross initial production rate of 1,586 BOE per day. The final scheduled well to be drilled this year by Brigham is the Lloyd #2H well, which is expected to this week spud this week, with completion initiatives also anticipated to take place in the fourth quarter of 2011. We have an 8% working interest in the well, and original well in the unit had the highest initial production rate of all wells thus far under our program with Brigham, which was 4,030 gross BOE per day. So, we have high expectations for the infill wells in this unit. Additionally, drilling continued under the Zavanna Bakken program during the quarter, and is scheduled to continue as contracted until the end of May 2012.

We are currently drilling the seventh gross well in the program. Competition for services has delayed completions beyond the original projections; however, in order to better control the outcome of our drilling program and, more importantly, the completions another partner in the Zavanna-operated program, Liberty Resources, had ordered a full frac array of equipment, and is currently training their crews to run it upon its delivery to the Williston Basin in late November. These crews will be dedicated to our participative program, as well as another program that Zavanna and Liberty are partnered in.

As the frac crews begin to complete the wells in succession, we anticipate catching up to the inventory of drilled wells awaiting completion by Spring 2012, and then being able to keep pace with the completions between the two programs. In this regard, we're pleased to have recently announced the initial production rate from the Cheryl #1H well, which came in at 1,503 gross BOE per day on a restricted show. The well was fracture-stimulated with 35 stages, and is the first well completed by Zavanna under our program. The Company has a 39% working interest in the well.

Additionally, the Koufax #1H well has been fracture-stimulated with 35 stages, and the plugs are currently being drilled out in order to bring the well onto production. We have a 20% working interest in this well, and we look forward to announcing the results of this well in the coming weeks. The Olson #1H well is also currently being fracture-stimulated with 35 frac stages, and we expect results from this well towards the end of November or the first week in December. We have 30% working interest in the Olson well. During the quarter, we participated in the drilling of one additional Bakken well with Murex Petroleum Corporation and the Yellowstone AMI. This is the second unit that we participated in that is operated by Murex, in which we will have opportunity to participate in infill wells within the units going forward. The David Roger #1H well has been drilled to total depth, and completion initiatives are scheduled to begin mid-November 2011. We have a 3% working interest in that well. Based on our four Bakken and four Three Forks wells per unit, we believe we have the potential to participate in approximately 336 gross drilling locations in the Brigham and Zavanna programs.

Our 31,000 total net acres in the Williston Basin is comprised of approximately 12,000 net acres with Brigham and Zavanna, and now approximately 19,000 net acres in the Wolverine prospect in Daniels County, Montana. In addition to our success in the Williston Basin, the Company announced earlier this year, that it had entered into a participation agreement with Crimson Exploration to acquire a 30% working interest in two oil prospects in Zavala and Dimmit Counties in South Texas. The prospects target the oil window of the Eagle Ford Shale play. The two prospects bring the Company's participation in the region to 13,785 gross, 4,136 net acres.

It is estimated at under current spacing, that there is a potential for the Company to participate in a 114 gross, 34 net, wells in both prospects combined. During the third quarter, the first well in the Leona River Prospect, the KM Ranch #1, was completed with 20 frac stages. The well was drilled to a total measured depth of 12,627 feet, including a 5,800 foot lateral. Initial flow-back data indicate that the well was in communication with the extraneous source of water, not coming from the Eagle Ford formation. Diagnostic production logs identified the source of the water entering the well bore near the toe of the well, and in late August, the water source was mechanically isolated with the setting of a plug, and the casing between frac stages nine and 10. The well was then placed back on production at an initial gross rate of 418 BOE per day. The initial production rates from the 11 contributing frac stages are the equivalent of 3,200-foot lateral. Crimson and the Company are very encouraged by the latest results, showing excellent oil flow potential from essentially half the lateral, which is indicative of good reservoir parameters, along with the relatively high gas rates seen in the flow-back period. The KM Ranch well averaged 200 BOE per day gross during the month of September.

The initial well on the Booth Tortuga Prospect, the Beeler #1H, is expected to spud next week. After the Beeler #1H is drilled, this rig will mobilize back to the Leona River acreage block and drill the KM Ranch #2H and the KM Ranch #3H in succession. These two additional wells in the acreage block are planned to be drilled in locations chosen to further test the boundaries and productivity of the acreage and its overall development potential. The Beeler well is scheduled to be fracked in late December, and the two new KM Ranch wells in the first quarter 2012.

Moving on to the San Joaquin Basin of California. The first well in the Moose Prospect with Cirque resources is scheduled to spud in the fourth quarter of this year. The well site is permitted, and preliminary site work began this week. The Prospect is a Miocene target with an expected total drilling depth of approximately 13,000 feet. The commitment well is targeting up to 300 feet of layered Stevens sands and the stratigraphic trap on the flank of the 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 of current spacing suggests potential for up to 40 additional drilling locations.

In the Gulf Coast region, the Bayou Bend well, a liquids-rich natural gas target, was drilled in Southeastern Texas by the operator, Southern Resources. The well was drilled to a depth of 11,265 feet, and three prospective pay zones were encountered. Production casing has been run on the wells, and completion initiatives are scheduled to commence this week, with initial production expected to commence by the end of the month. We have a 13% working interest in this well. If initial production test are satisfactory, additional development wells are possible. All future wells will be drilled heads up.

On October 27, 2011, the Company entered into agreement with Yuma Exploration to sell its interest in the Livingston Prospect in Louisiana for $1 million in cash. The closing has taken place, and the Company has received the funds from this transaction. The Company owned a 4.79% working interest in the prospect, which included one gross producing well that netted USEG approximately 5 BOE per day, and one additional gross development well that was being completed at the time of the sale.

During the third quarter, we recognized revenues from oil and natural gas production of $10 million. We produced 120,198 BOE, or 1,306 BOE per day, which is up sequentially from the second quarter of 2011. Looking ahead, we expect that oil volumes will increase very meaningfully in the fourth quarter, as we are scheduled to complete 6 additional gross wells before year-end. This figure represents two wells with Brigham, one well with Murex, two wells with Zavanna, and one Gulf Coast well. We realized an average oil price in the third quarter of $84.38 per barrel, excluding the impact of our hedges; or $17.24 per barrel higher than the third quarter of 2010. Our average natural gas price realized during the quarter was $5.59 per Mcf, $0.77 per Mcf lower than the third quarter of 2010.

Moving on to our non-E&P assets, at the Mount Emmons molybdenum project, we continue to make steady progress on several initiatives, which include the initial drafting of our mine plan of operation. We remain committed to advancing the project, and look forward to providing an update on these initiatives in the coming months. I'd also like to touch briefly on the Remington Village apartment complex, located in Gillette, Wyoming. In May, the Company listed the complex for sale with a commercial realtor, and we obtained $10 million long-term loan from a commercial bank on the asset. Our goal remains to monetize this asset in order to maintain our focus on oil and gas and deploy the remaining capital into those programs.

I'd now like to turn the call over to Bryon Mowry, the Company's Principal Accounting Officer, to review the financial portion of the call.

Thank you, Keith.

Our third quarter operating revenues increased by $4.25 million, to $10 million, during the quarter ended September 30, 2011; as compared to revenues of $5.7 million during the quarter ended September 30, 2010. This operating revenue increase is primarily due to higher oil sales volumes, higher commodity prices, and a $1.6 million gain from our risk management activities. Operating revenues from the third quarter of 2011 reflect a 22% improvement from operating revenue realized during the second quarter of 2011. Oil and gas operations produced operating income of $3.5 million during the quarter ended September 30, 2011; as compared to a direct operating income of $1.3 million from our oil and gas operations during the quarter ended September 30, 2010.

The increase in earnings from oil and gas operations is primarily due to, A, a $2.1 million increase in revenues due to higher production and commodity prices during 2011 compared to 2010; and B, a net gain of $1.6 million in unrealized and realized gains and losses on our risk management activities in 2011. The increase in oil and gas revenue are partially offset by $1.2 million higher lease operating expenses, and $900,000 higher depletion expenses in 2011. Direct operating income from oil and gas operations increased by approximately 13% from the three months ended June 30, 2011. Production volumes for the three months ended September 30, 2011, averaged just over 1,300 BOE per day; up 5% from oil and gas volumes from the same quarter of 2010, and 16% from oil and gas volumes from the quarter ended June 30, 2011. The realized oil price of $84.38 per barrel was $17.24 per barrel higher during the third quarter of 2011 than the realized prices from the third quarter of 2010, but down approximately $15.39 per barrel from realized oil prices in the second quarter of 2011. At September 30, 2011, we had a total debt balance of $21.6 million.

In September, our borrowing base under our senior credit facility with BNP Paribas, was increased to $28 million as a result of the redetermination based on the June 30, 2011 financial statements, production reports, and reserve reports. During the quarter ended September 30, 2011, we borrowed an additional $8 million from our senior credit facility, and subsequent to the end of the third quarter we borrowed an additional $12 million, bringing our total drawn to date under the senior credit facility to $23 million. The proceeds of the loan are being used to fund our oil and gas programs and overhead expenses.

During the quarter ended September 30, 2011, we recorded a net income of $268,000 after taxes; or $0.01 per share, as compared to a net loss after taxes of $235,000, or $0.01 share for the quarter ended September 30, 2010. Our balance sheet remains strong as of September 30, 2011, with working capital of $13 million. We have cash of $4.8 million, plus marketable securities of $295,000 at September 30, 2011.

I'd now like to turn the call back over to Keith.

Thank you, Bryon.

Before moving on to the Q&A portion of the call, I'd like to congratulate our partners of Brigham Exploration for the recent announcement regarding their merger with Statoil of Norway. The management team and entire staff of Brigham have done a fantastic job operating the programs in which we participate in, and have continued to set the bar high in the Williston Basin as far as technological advancement and leading the way to unlocking Bakken and Three Forks potential. Statoil's entry into the Williston Basin provides a good indication of potential of the Basin and its ability to attract investors from all parts of the globe. At this point, we look forward to seeing how Statoil's growth plans fit into our participated program, and we see this transaction is a good metric to show the value of our production and acreage in the basin. We will be very busy during the fourth quarter completing our 2011 drilling programs; we are pleased with the initial results from the Cheryl well under the program with Zavanna, and look forward to reporting our additional completion results that are currently under way.

Under our Eagle Ford program with Crimson, we look forward to testing the Booth Tortuga acreage block in the coming weeks, as well as drilling the planned additional wells in the Leona River acreage block to further delineate the prospective area. Based on these initial results, we will plan our drilling programs for 2012. Also, we are excited to get under way in California with Cirque, and we look forward to the upcoming drill and subsequent results in this prolific producing region in California. If successful, this program could add significant development potential for the Company.

Given our sizable inventory of drilling projects and the potential to add to that inventory with our test wells in the Eagle Ford, as well as California, our requirement for working capital to participate in these programs in 2012 looks to be considerable. As a result, we are currently considering selling or joint-venturing some of our oil and gas tests, as demonstrated by the recent Yuma transaction. We will present our 2012 operating budget to our Board of Directors at the December Board meeting for approval, and will look to provide further guidance for 2012 to the shareholders, subsequent to the approval by the board.

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

(Operator Instructions)

Jeff Hayden, Rodman & Renshaw.

I guess, a couple of questions. I think you just touched on this one a little bit. But any color or do you guys kind of have any idea of what the program on the Brigham AMI acreage could look like next year?

Jeff, I've called them up and by the way it's the indication that there's three of the top executives are the only guys that are going to leave. The rest of the operational team is going to be replaced. It's my understanding they plan on keeping the office in Austin as well as expanding additional employees down there. We ask the question, I believe they also budget in November for approval in December. And pretty much the answer they got is they're looking at the bigger picture of how much money they are going to put into it rather than individual.

The other thing they indicated to us is they have now completed two, three spots, one with us in the Bakken formation, our battles (inaudible) number one and another three spot. They are in the process of doing two, four spots, and they are doing a five spot. They said before they announce or give us their development schedule for next year they'd like to be sure of the spacing for the Bakken formation. Which just makes sense, Jeff, if you do a three spot you can't down space it to a five spot. You have to start out planning for a five spot.

They are still doing additional testing up there. They recognize our concerns and our wants, of course we'd like to see what their plan is for next year. They indicated that they'll work with us and they're going to attempt to get us the numbers before our December meeting.

Then jumping over to the Zavanna AMI. Any discussions with them or any idea as to whether or not they'll stay active after the current contract expires in May?

Yes, Jeff, this is Mark. We believe they will but what they have on the slate now is just through May which is another four or five wells that will be drilled between now and that timeframe. Just back-to-back drilling. That will take us into about midyear and by then we should have planning for the balance of the year.

All right, and then jumping across the border, any updates or any plans for the Montana Bakken acreage?

Jeff, this is Mark again. We are looking -- actively looking for a partner in that acreage. And at the same time we're actively continuing to lease. There is competition up in that area but we're still getting some good, relative leaps, bonus payments and so forth. And we're confident that we are going to bring in a partner in due course.

Okay and where does your position currently stand at right now?

It is right at about 19,000 acres net.

Okay guys, I appreciate it.

Noel Parks, Ladenburg Thalmann.

Just a few things I wanted to run by you. Talking about the KM Ranch well. How much of the production there is oil and how much is gas or other liquids?

It's still in about 120 barrels and about 500 Mcf.

Okay great. The current plan for California looks like you are hoping to get out there fourth quarter 2011, first quarter '12. How is that looking right now? I know the water was an issue for the longest time.

Noel, that's a good question. The water is still there and Cirque actually went to the state as well as the current water bank and requested that we could move the pad location because of the water issues. That has been approved. They've started the site work but they also had to do some special species trapping which should be concluded today. If they catch either the Kangaroo Rat or a Spotted Lizard, they will have to request a relocation of those animals and that takes about two weeks.

Thus far as we've learned that they have not trapped anything. And if they do not trap anything through the period then we will be able to go ahead and drill the location. We have the rig contracted and ready to go. So as soon as we get through this trapping procedure and perhaps a subsequent relocation of those species then we will be able to start drilling. We're hopeful that we will be able to start drilling by the end of this month. Until we get these results we will not know.

When we were ready to drill earlier this year we did the trapping and we found nothing so that was encouraging.

I just wanted to check on one number you guys mentioned earlier. Was it -- oh yes, with Cirque in the Moose Prospect that [myosin] target. Did you say that you anticipate up to four or 40, additional drilling locations?

Possibly under current spacing, up to four-zero, 40 additional locations.

Oh, great.

Joel Musante, C.K. Cooper & Company.

First, it looked like you're natural gas volumes fell off a little bit last quarter. What was the reason for that?

We've got some of the wells with PetroQuest are getting older and we're starting to see some of the production fall off on those wells. In the past we'd seen that offset by the Bakken wells, but some of these wells are getting a little bit older and they will be coming off.

All right, so, do you have an exit rate, end of the quarter? Because I know that you came back from the weather delays in the Bakken and then you've got a lot going on. Is there some -- I don't know if it's end of quarter or whatever you can give me.

Joel, with these Bakken wells, depending on what their IP comes up, but every well we've participated in has been a strong producer. Even the 1,500 barrels, that turned out to be a good well for us with Brigham. Depending on, again weather delays up there, but I think we could easily see somewhere between 1,500 and 2,000 barrels for the end of the month of December.

And what about the other two months in the quarter, for the fourth quarter?

All in all I'm comfortable we're going to see an increase because again of these high productions. Let's just say we're hoping for 1,500 for the quarter anyway.

And that will probably be on the oilier side because your gas seems to be dropping off? I guess you had that one Eagle Ford well but that seems a little gassier.

It is and we did do that LL Bean with PetroQuest and it'll probably be a three or four year well and it' holding steady at about 4 million cubic foot a day and very little that puts an (inaudible) Joel. But right now I believe we are 70% liquids and about 30% gas.

Okay and with the $12 million that you spent at the end of the quarter. Where you at with well paying for all of the wells With the Zavanna wells, you've five more that have been drilled. Are they all paid up or is there still some left on that? And then the same with the two Brigham wells?

We don't pay for the completion until they call for completion costs. So we have paid all the drilling costs on those. We have advanced, of course, on the three wells, the completion costs. We don't have to take any more debt according to our budget between now and the end of the year. But we have enough money to service all of the programs that we have in place.

All right that's helpful.

Josh Young, Young Capital.

Can you walk through the choice of -- it sounds like you're going to joint venture or sell down some non-producing acreage in the Bakken. Prior at conferences and possibly other conference calls you had mentioned that you might consider selling production. I guess given the transactions that have happened recently in the Bakken and the high value that people are placing on existing production, how do you think about that choice and that trade-off?

Right now, of course as we've announced, we'd like to keep all of our production and our reserves. Now, if somebody came with some very realistic numbers, that had made sense we would consider that. But our goal right now is to keep our reserves and production and just sell the opportunity going forward.

It looks like if you if you look at the Brigham transaction, Brigham was bought for what look like over $200,000 per flowing barrel. Which would obviously be well, well in excess of what your whole Company is valued at. And if you sold production at a metric, not necessarily even at that, but at half of that, you could potentially finance all of your other capital programs into the foreseeable future.

That is true.

Then on the Eagle Ford front, how do you think about well costs going forward and what your drilling program there might look like?

What I have read and seen down there, Josh, the competition is not as (inaudible) because it's Texas. You still have a lot of people that are doing work both conventional and horizontal down there. I would expect the announced cost of about $6.7 million to $7 million is along the lines of the first well we did with them to be in line. We just won't really know the final numbers until we drill these next three wells.

How do you plan to finance your 2012 capital program?

Part of it is going in, we will have a redetermination. I'm confident we'll have an increase in our reserves, so we will have some room there. As well as [slowing] down some of our assets and the cash flow. We'll give more guidance for that after we have our budget approved later in December.

Okay, great.

George Gaspar, Private Investor.

Follow-up question on the first Brigham well that you reviewed in your release, the #2H. I notice that you indicated as well was spudded mid-September. And reached total depth in first week of November. That looks to me like that was a 50-day the stretch. Was there something unusual about this? This seems like a long drilling time for the average well that you've been drilling with Brigham and Zavanna. Can you explain that?

Yes, George, this is Mark. We did have a few issues in drilling the curb. We actually had to come back and re-kick off curb. That expended some additional time. They tried to work through those issues, but unfortunately it took additional time. But unfortunately they got it figured out and kicked it off. But it has reached TD without any further complications.

On the first Zavanna well, the Cheryl, the #1H. Was there something different in terms of your completion approach to initialize a slower initial flow to get more stability of the flow? Or can you explain that at all?

What Zavanna and Liberty's theory is, is that if they reduce the flow that they will preserve the fractures in the rock from the fracking process. Some companies use a reduced flow and some companies just open-throttle or open-choke, if you will, such as Brigham. And Brigham isn't under the thinking that it will damage the (inaudible) but time will tell. Nonetheless, Zavanna has shown us decline curves from the days they have completed on even six 40s, where they've gotten similar URs to some of the other open flow wells up in the basin.

Again, their theory is if they reduce the flow, they keep the pressure in the whole, that ultimately we're going to see similar results in the first month. To say what Brigham well would perform at and then similar EURs on these high producing Brigham wells and possibly preserving the fracture in the overall well bore integrity throughout time. So time will tell on that, George, and it's just a different method of completing the well and establishing an initial production rate.

I might add, George, we've taken a look at our first seven day average on all of our Brigham wells and we've currently produced about 10,000 barrels in that Cheryl well. That's in line with a lot of the wells that we completed with Brigham as well. It will be interesting to see at the end of 30 days how it compares and again it's right in the ballpark.

The numbers on your answer to a previous caller about your possible target for the fourth quarter. If you just look at the #1H, no I realize that you're not going to stay at 1,000 barrels per day. With your 30% net revenue interest, that well could conceivably get you above that 1,500 barrel a day range by the end of this month, correct? From where you are at the end of the quarter.

George, as I'm sure you're aware they do flow for a certain amount of time and then they come off of production and you have to set them on pump which takes its time to work over a rig. Like I mentioned to Joel this could be 1,500, 2,000 depending on the performance and how long the performance last for they have to put them on pump. Their performance after they put them on pump. So, pretty confident in 1,500, if anything more than that I'm happy with.

One follow-on, on both the Brigham acreage and you're play and Zavanna. The recent announcement of a possible three-bench system in the Three Forks which apparently has proven to be successful in recent a well or two. Rather outstanding actually. You got any assessment of the possibility of this lower Three Forks opportunity on acreage that you have with both companies?

We've looked up the location of those two. I believe that Continental did a very large coring program and we are following their lead and watching their results. George, we did see that they had a Three Forks test that came on pretty strong, about 10 miles from our Lloyd. Then Whiting, you sent me the information on them, we looked up that 7,000 barrel well and it's about 12 to 14 miles to the east and north of us. Certainly when we see those type of numbers we're encouraged. If you listen to Mr. Hahn talk about the four benches in the Three Forks instead of only one, his number goes up exponentially. I think we're more inclined to let the big guys take a look at that and probably even Statoil will be wanting to do a little bit more research in that. But it just adds value to our play and our position is the way I see it.

Michael Bodino, Global Hunter Securities.

Has there been any preliminary reserve work done on the wells that have been drilled today? And then can you provide any guidance what you're seeing on the average EUR per Bakken wells?

Yes we have, Michael, our average right now in all of our NADEX spaces is about 475,000 BOE. I believe and I've talked to Clyde Gillespie that they've been a little bit conservative because the play is so young. Remember that we were some of the very first wells to come into production with Brigham up there. That's our average. We've seen an upper limit of about maybe 650 and a lower of around 350.

With some of the newer wells with more frac stages, and with the Zavanna program are you seeing any change? Is that migrating up? Are you getting a better well result from a EUR perspective? Or is it just too early to tell on that program?

I think it's too early and we'll get our reserve report now at the end of the year and it's going to be interesting not only from the viewpoint of existing wells but also PUDs. I think that with Brigham and Oasis and others up there that certainly there's an argument to be made that we're going to get at least one offset in each of those units and we haven't got any PUDs flows offsets until they've have been permitted. It would be interesting to see at the end of the year but I'm confident that we're going to have a significant increase in our reserves.

I'd certainly expect that. That was the next question about the PUD bookings and whether there has been any discussions with Clyde Gillespie on the topic. One other thing that I wanted to ask about is on the Eagle Ford. What is the ideal situation in terms of how you want to see that progress and what needs to be tested there? Do you want to see a lot of wells being drilled? And I have a follow-up question to that in a second.

Certainly we want to just see these next three drills and we want to get some production on those to see how they perform. Certainly don't want to see the water issue that we had to first one. If you look up there, if we get a 600, 800, 900 barrel well that's a different well then a Bakken 900 barrel well. We'd be pleased if we saw those type of numbers and would be inclined if we had the money to move forward and a little more aggressive manner. I think Crimson feels the same way.

I haven't talked to the guys at Crimson about this but any discussions about targeting anything beyond the Eagle Ford acreage.

Not yet. They have their engineers are looking at all of those different formations but certainly first of all we want to try and prove up the Eagle Ford and get some production off of it. We haven't had any serious discussions beyond any other formation though.

Thank you, sir andI show no further questions in queue at this time. Do you have any closing remarks?

I might have sounded a little dry, but we're pretty excited about all of these programs. The important thing right now is we are getting some plush production. We've got 19 wells on production up in the Bakken and so we're starting to see a flattening out if you will. Where the new wells are nice but we're getting a real good solid base of recurring revenues and the number I've seen are these are going to be 25 or 30 year wells. And that supplies recurring revenues and recurring cash-flows to the Company and that's what we started out when we started this program to get into.

Now, if we can duplicate that, certainly with Crimson and Eagle Ford that's got more hype and possibly is expiration in California to where we can just keep adding sequentially and keep those revenues coming month to month. Fortunately, we did have a profitable month this month and we hope to repeat that. And I think that we're well underway to that goal. So, appreciate every body sitting in and having patients with us. I appreciate all of the comments and questions and thanks for sitting in today.

Ladies and gentlemen this concludes today's conference call. You may now disconnect. Everyone have a good day.