Good day, ladies and gentlemen and welcome to the first quarter 2010 Brigham Exploration Company Earnings Call. My name is Josh and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions). I would now like to turn the presentation over to our host for today's call, the Chairman, President and Chief Executive Officer, Ben Brigham. You may proceed, sir.

Thank you, Josh. Thanks to each of you for participating in Brigham Exploration Company's first quarter 2010 conference call. With me today we have Gene Shepherd, our Chief Financial Officer and Executive Vice President; Lance Langford, Executive Vice President of Operations; Jeff Larson, our Executive Vice President of Exploration; and Rob Roosa, our Finance Manager. Importantly, before we get started, I'd like to encourage you to be prepared such that during the course of this call you can view our conference call presentation, which can be accessed via our website at www.bexp3d.com. It includes very helpful information regarding our first quarter results, as well as our plans for the remainder of the year. We'll be referring to the slides in the presentation during our discussion. During the call, we're going to make some forward-looking statements to help you understand our company's results. In our company's SEC filings and the press releases that were issued yesterday, there are some risk factors that should be noted that might cause our actual results to differ from what we talk about today or from our projections. I encourage you to review our filings with the SEC. In addition, in this call we may use the terms probable and possible reserves that we do not include in our SEC filings. We may also discuss locations, which include proved reserves as disclosed in our SEC filings. Please refer to page two of our corporate presentation for a cautionary note to U.S. investors regarding the use of the terms probable and possible reserves and locations. Finally, a copy of our company's press releases, as well as other financial and statistical information about the periods to be presented in the conference call will be available on the company's website, under the section entitled Investor Relations at www.bexp3d.com. So…

Thanks Bud. Before we get into our discussion of our first quarter results, I would like to update you on the company’s current liquidity position. What a difference a year makes? Over the last 12 months, we have executed on a number of liquidity enhancing initiatives that have allowed us to accelerate our drilling activity to five operated rigs beginning next week and over the next 12 months should take our drilling activity to eight operated rigs, which is the much better match with our huge inventory of unreal development location that we have in front of us on our 305,000 net acres in the Williston Basin. Briefly, the liquidity enhancing initiatives that have set the stage for the dramatic forecasted growth in our production in proved reserve volumes are as follows. Number one in June of 2009, we closed on our new credit facility that has pushed out the maturity of the facility to July 2012. At the present time, we have no outstanding balance under the credit facility. Item number two, as we bring on new wells in the Williston Basin, we continue to actively hedge our oil volumes via costless collars in order to mitigate oil price risks over the next two critical years that we are ramping up our drilling activity. Slides 26 and 27 depict our current oil and natural gas hedge portfolios. Item number three, next week we expected to close on the sale of what is essentially the proved developed producing portion of our West Texas assets totaling 510,000 barrels of oil equivalents for $14 million. Although not a huge transaction, its significance is that it is the first step in our plant monetization of our conventional asset. Item number four, over the last 12 months we completed three equity offerings raising a…

Thanks, Gene. That really concludes our call. Josh, we would like to turn it over for the question-and-answer session.

(Operator Instructions). And our first question comes from the line of Michael Jacobs of Tudor, Pickering & Holt. Michael, you may proceed. Michael Jacobs - Tudor, Pickering & Holt: So, I heard you reference planned monetization of conventional assets you’re drilling from South Texas as well as -- perhaps I am jumping to conclusions, but I’m hearing you say that you are planning on booking some reserves in order to pull the trigger and bring more capital in. Do you have a rough estimate as to when you could sell down conventional gas or is it more a function of price?

We hadn’t drilled a well there in the Vicksburg in over a year and we got some great projects and the majority of the value or more than 50% of the value there is the liquid. So looks economically attractive, so we've got two wells teed up and that will really juice up the production there and there is a lot of value there with 52 locations in inventory. It’s a real attractive asset, so it is something we could potentially develop. Michael Jacobs - Tudor, Pickering & Holt: And would a divestiture drive you to accelerate rig adds or is the current pace that you have outlined more connected to ensuring kind of operational efficiencies?

It's just another bucket of liquidity, Mike, so it's available to us, and we feel like we need to access additional capital. Certainly we are very active in the basin, particularly west of the Nesson looking at some acreage acquisition opportunity. So, depending upon how those play out that could certainly impact our thinking about selling conventional assets, but there is no defined time line for any further monetization beyond just the West Texas assets that will close next week Michael Jacobs - Tudor, Pickering & Holt: And a question for Bud or for Lance, directionally we have seen some operators move towards your method that you have innovated, and specifically longer lateral site order completions and even in the areas with better porosity. However one of the areas where there is still little bit or lack of consensus is the specific method of completion, as it relates to plug and perf versus sliding sleeves. And I know that ball size when its total stage is, but is there an instance where you would use sleeves if you were doing less stages, kind of, 24 or lower?

Right now, we think that it cost us extra money to do the perf and plug method. And it also cost us additional capital to use ceramics and we are doing that because we believe it's improving our productivity in the near term and in the long term, both. So I see this now, unless we get some evidence that redirects us that we will continue to use perf and plug and ceramics. Michael Jacobs - Tudor, Pickering & Holt: Right, so it's more function of a conductivity and productivity.

That’s correct. Michael Jacobs - Tudor, Pickering & Holt: Final question on the Mortenson well, you did 23 stages there and it's pretty nice to 2300 barrel equivalent rate there. Any reason why that was 23 stages versus 30 plus?

Mike, again, this is Lance and I think if you saw in the presentation, we are going to start breaking out certain areas and start varying one variable in each of those areas and you are going to see us do some different things here and there and of course varying the stage in a smaller geologic and geographical area, so that we got more continuity of the productivity of the rock. So that we can really determine what's the optimum number of stages and then we are also going to start looking at size of stages and maybe even try some new fluid. So, I think you will see over the next year, you are going to see us tweaking our completions across the basin, but it's going to take some time.

You next question comes from the line of Ron Mills of Johnson Rice.

Hey, guys, a little bit of a follow-up to Mike's last question and what Lance was saying. When you are looking to break the acreage position into several different areas, obviously the portion to the North West from at least production productivity standpoint, little lower rates than what you have seen down in the southern portion and central portion of Rough Rider. How do those results or how should those eventually affect your capital allocation as you look across the Rough Rider block?

Well, Ron, this is Lance. Even though we are seeing lower productivity up there in the area, we are still seeing really good economics. So, even on the low side of what we have been seeing is really economics. So, I think it’s really about ensuring that we get all of our acreage HPP-d and held and we’ll make decisions based on that and when its not a situation of HPP-ing or holding acreage in the near-term, we will be focusing or drilling in the more prolific areas.

Okay. And as you go from the four rigs to five, next week to eight next May, depending on success in the Three Forks and Rough Rider, how would you all view the allocation of rigs we offered Three Forks versus Bakken and then throw the wrinkle there of follow-on potential success in Montana, which are alluded to probably accelerating further at some point in that success case or how would you allocated those eight rigs?

Yeah, Ron, I’ll take first shot and these guys can add to what I had to say. But, importantly with the number of rigs we are operating we are well ahead of any exploration issues and it does give us flexibility to adjust the program, balancing out all the different opportunities and challenges out there. We are going to drill an increased density in Rough Rider, such as the course at Three Forks which is going to (inaudible). We have already drilled the Bakken well. And then, of course, as you point out with success in Montana, it would add to our inventory of locations. I do think the potential divestitures, west Texas is the first one, but potentially more of them that will provide us more powder to further accelerate. We do think that with the offerings we did over the last year, it positions us with a critical math in terms of our capital structure to accelerate hopefully beyond the eight rigs and because given the debt of the inventory particularly if it grows will meet to. So we balance in a lot of different things and the opportunities. We do want to delineate Three Forks and Rough Rider, we are excited about that, and hopefully we will be delineating the Bakken and potentially the Three Forks in Montana. So it's kind of a continuum of data that's flowing in, and suggesting our scheduled real time depth. Does that answer your question somehow?

Yeah, it does. And then two real quick ones for Gene, just in terms of reporting production versus sales, obviously some of that is timing related, as you have oil in storage before it gets trucked away, what is your outlook in terms of on a quarterly basis is kind of 5,000 barrels a quarter or something a pretty good number that we should expect for going into inventory? Or will that move quite a bit? How do you all look at the production versus sales and then on the LOE basis, the guidance of 650 to 675, a pretty strong number I assume, that excludes any workovers, and that can even continue to improve as on a unit basis as you add a bunch of volumes in the Bakken. Is that the right way to look at LOE?

Well, ultimately, I mean, we were spending the $38 million on the facilities, and decentralized some of the collection, so ultimately I think that issue will get mitigated in terms of the inventory issue. You saw a big growth in the fourth quarter of last year; some growth, not as much in the first quarter and probably as our activity ramps up, you will continue to see growth until we get those facilities hooked up. In terms of the LOE, we had some very extraordinary workover expense in the fourth quarter of last year and in the first quarter of this year which skewed our per barrel EOE figures and so going forward, we are not forecasting certainly the same period of workover expense. Those workovers that we did late last year and early this year were known and, but as in this case, when you get out there and working over a well sometime you have some cost over runs, but we are not expecting those types of workovers in the current quarter and going forward at least they are not planned and then over time obviously we will be growing our production volumes very significantly this year. So, on a per barrel basis certainly we expect that those LOE costs from the first quarter to decline significantly and that’s reflected in the guidance we've issued for LOE for the second quarter.

If you just look at the Bakken alone, what‘s the typical LOE per barrel of a Bakken well?

Well, that’s a hard question to answer. Per well, per month basis I think what is it, Lance? $10,000 per well, per month is that about right, Lance? $10,000?

Yes, it’s about $10,000 and then it did depends also on how much salt water is being made and then the infrastructure is going to help us reduce that number for salt water trucking and disposal as we go forward. So, that’s going to be reduced and one thing I wanted to add also, on the oil storage rigs we are adding four wells a month right now. When we get five rigs running, we will be adding five new wells produced in a month. So, that tankage, so you will see storage go up in the near-term until we get our infrastructure build out. One of the things that Gene and I have been looking at is how do you get our field people to focus on trying to minimize that number. So I don’t know if its going to continue to go up at the rate its going because hopefully we can operationally focus on trying to reduce what we have in [tank gauge] at the end of the month for our wells.

But if you think about it Ron, I mean $10,000 per well per month that’s $120,000 and to divide that by lands to 120,000 barrels that we expect to see in the first year, so that’s a buck a barrel. So you can see that despite these properties being oil, which you normally expect to have higher LOE cost because of the prolific nature certainly early on in the lives of these wells, as we bring those wells on and bringing those Williston basin wells on that that should bring our corporate LOE per barrel down. Just bringing in an incremental well on will have a positive impact on per barrel LOE.

That’s fair. And but from a life the well standpoint if that productivity comes down that you cost on that well goes up. So I guess when you look at, when you and your economics to get to your $9.5 million PV 10% over the life of the well, are you expecting plus or minus $5 or $6 per barrel LOE or?

You can’t and we’ve had to go back and look is it so dramatically from a buck obviously to will see to a much higher number and that number is going to positively impact as Lance referenced by the central gathering facilities not only on the crude oil side and reducing the differential, which won’t impact the LOE but certainly on the waste water gathering side we are occurring very significant cost there on a per barrel basis.

Electricity go down and all the other things the wear and tear on equipment because you are producing much lower rates later in the line.

Right

I would expected to be driving down as not only we adding down a lot of these high rise wells but we are adding down more rigs too and we are adding no more high rates wells, so that should help us driving it down at least over to next year.

I mean there is no question, we are in this ramp up mode in drilling activity that acceleration and activity is going to, positively impact our per barrel LOE. So about ten years from now. its hard to say that will be a mix of how many wells we drilled, and, but certainly, I'll be happy to talk some more with you about that topic, if you want to?

Our next question comes from the line of a John Freeman of Raymond James.

Just want to focus a little bit more on the cost again. So, I believe like the original CapEx was based on just over $628 million, but I think on the last call may be Gene you had mentioned it or kind of assumed about a 5% kind of cushion, if you will above that in case, I guess, cost kind of creep up, I guess first, is that right?

Well that’s for Lance, because Lance is going to answer this question, but we had 6.825% but we had 7 .1/2 % average build-in to protect the company against operational issues that we've not account all day, we haven't had a lot of those types of issues and certainly any cost (cream ). So but ,that of, that takes you up to 7.3% but that's not, we are not saying that, when we put those figures out there, 6.825% was the AFE at that time and then the average was with the average.

Oaky , and then on the $6.8 million, just kind of roughly, how, like your (last) five wells lets say, kind of compare to that number?

Well, the last four wells, added an average AFE cost of about $6.5 million and our field estimates are below that. So we feel like our costs are coming in below our AFE. So, that’s the last four wells.

If you want to look at all the, and I’m just only, Lance…

That’s not all though. These are the last four, but they are not on that. So, these are the most recent. So, let us go with those numbers because we have seen some costs creek. So, our actual costs today are about 6.5 on the wells that we just completed.

Okay, and then if we are trying to get a sense of just, mainly just focused on this year at the moment on the cost components potentially could creek versus the ones you have got maybe locked in to a little bit longer term contracts. So, if I’m just thinking about either your rig rates or your proppant or your pressure pumping the pipe like, of those which ones do you have locked up a little bit longer term opposed to well-by-well?

This is Lance again. We have most of the large equipment locked in. They do have some variability based on market conditions or actual cost going up. So, we have got basically simulation locked up and that does not include the proppants, but is how the pumping charge which is the majority of the cost. We have got rig crews locked up and both of those have some kind of variability. We have got directional, perfs, mud, our plugs, our swell packers, our perforating ramps. I think we got over 65% in some termed agreements. Our casing, we have got all of our casings bought for all wells to about mid-2011. So, we are in pretty good shape there and we will later path on as we get closer. So we are in pretty good shape, but we have seen some additional cost creek. We still think the wells that we are drilling right now that are going to complete or going to complete for less than $7 million.

Then towards of your presentation like slide 36, you have a slide there on differentials that sort have been kind of declining. Based on everything I have been hearing that the differentials there look like they are going to go up a decent bit here in the next month or so as some of the other refineries that are down longer than expected. Just kind of what you all are expecting on differentials on the Bakken?

Right. What’s happened out there is that there is the shore up plans, the Mandan plans doing a turn around I think the three month periods of those displaced barrels and I think it was 60,000 barrels or 70,000 barrels a day are being forced in to the Enbridge pipelines and other pass. So it's kind of tightening the markets but we are seeing differentials in the eight range even with that extra or that reduction in capacity there.

Then last question on the eastern Montana which I used to refer to Ghost Rider, I guess your guys are calling it Pale Rider now, the [sweep-in-well] like what’s the status I mean that one was supposed to have been completed, at least commenced the completion back in March, what’s kind of a update there?

Yeah, this is Jeff, yeah, the Sweetman well, we do have a small percentage working interest in Sweetman well but that was currently completing and that’s all we can share with you today. Then to give you a little bit more guidance on the name changes Ghost Rider is actually the 70 square mile shoot that is a sub set of Pale Rider. So we apologize, we call it Pale Rider Eastern Montana and then again Ghost Rider in sub set of that.

Our next question comes from the line of Subhash Chandra of Jefferies. Subhash, you may proceed.

Some questions about some third party activity, in the Pale Rider area that FH well is been producing, I think for a little bit. Any sort of insights there and then in the Three Forks Rough Rider any other key wells, that you are watching and now that all Obert is known I think there was a new field well or etcetera, are you seeing a pick up in Three Fourth activity in Rough Rider.

Yes, this may be, I will start and Jeff probably can add, Subhash. So what I have to say, that on that FH well unfortunately we don’t have an interest in that well and we haven't been able to get the party to share information with us. So we really don’t have anything that we can provide on that. Jeff may want to talk about there is more Three Fork activity out there.

Yeah, we have the Rough Rider there is definitely the Three Fork activity, we are keeping a close eye on, as you know, the industry is aware of the kind of Obert well, kind of also has two other rigs running, the [Gary] well, the [Gary] and [Ricky Rig] in the west side, those are truly not declared as Bakken or Three Forks wells and we are definitely actively watching those. Some other important data points to the north east of Rough Rider, the new field [High well] is a Three Forks well currently listed and completing and in a well, that is recently just popped up. I think you are aware of the depends on Panther Wil E. Coyote well. They're truly being off set by the Henderson Well direct offset to the west and we believe that's probably also a Three Forks [task]?

Well that was, so that another Panther well?

Its actually operated by [Dynergy].

Okay, got it

One section to the west of Bakken

Okay, okay, and any on the Henderson well may not too, you cannot dismiss a 1,000 barrel a day producer but any idea whether anything special going on between 1,000 barrel a day in a 30 stage frac?

Subhash, it could be Arnson well?

Arnson, yes. Did I misspeak?

Well, we thought we are heard Anderson, but we just couldn’t hear you well.

I’m sorry.

Subhash, this is Lance here. We are looking at that and that’s one of the reasons to try and break these things down in to smaller geologic and geographical areas. So, that we can really try and start to understand what's happening in the smaller area. You got to remember, we have those 21 wells spread out over 160,000 acres of just our acreage, but if you look in the geographic area, it’s a huge area. And so, we have been pretty consistent on what we have done on our wells. So, I don’t think its anything that we have done mechanically different, but we are analyzed and all that. We really don’t have anything to say expect it is just performing differently right now and as we get more wells we will be have some statistic to be able to say if there is a reason, if we have reason.

Yes, that’s make sense.

Does that answer your question?

Yes, absolutely. On the spacing, in 1280 unit, 6 Bakken, 6 Three Forks, but not with the well board sitting on the top of each other like it has, but side to side. When do you think you will actually do a pilot and do you have to file specifically for a pilot or can you go ahead and drill this test unit?

This is Lance again. So, it's not 6 Bakken, 6 Three Forks. Right now, we are planning on 3 Bakken, 3 Three Forks per unit.

Okay.

So, we are going to start doing some increase density this year. We’ve done a little bit, but as far as doing the six wells hopefully by the end of this year at least in one area we’ll have some increased density in one zone and we’ll have one study at least. Bud you want to add something?

Yes, in Rough Rider, of course at mid year we are going to spud, what is about its early third quarter, Jeff or third quarter.

Yes its early third quarter and see us put some more science too. We will probably run microseismic and things like that to really understand what we’re seeing.

Yes, it will be interesting because that you know we’ll drilled the first increased density well and then come back I think its 60 days later and drill the third well in that unit for the Bakken and as Jeff is saying we are planning right now and working on like out microseismic so its going to be interesting. We are comfortable right now that we can drill three well in these areas for each units but it will be interesting to see as we've increased the number of frac stages. It’s smaller frac per stage so we are still and more efficiently breaking up the rod, but how much penetration have already fraced extending the drain. So it’s going to be really, I think very beneficial for us to acquire some microseismic they can and we learned a lot from drilling these wells.

Okay. Two more for me just further on that part, any reason why industry might be sort of circling 4-27 spacing? Is that just kind of what’s practical at this point, good starting point or do you think there is additional depth to it a lot of I think about the talking about 4-27 spacing that unit. Then secondly, I guess question for Gene and final question on guidance on the effective tax rate going forward if you said it I miss it, I apologize?

Well, I’ll answer some of the space and I am not sure I fully understood your question on space but I’ll tell you kind of our thought on spacing, if you look at down [Coley],which was the original middle Bakken field, its been drilled two to three sections overall almost all of the whole area, and from our view point, those wells were much higher permeability in the rock than in our areas, which would lead to make you believe that, it will be at least three or more wells per unit. So that’s kept one of the basis of what we have done, there also been other people that have been drilling this increased density wells and I think there was a Kodiak that put out our report yesterday…

I didn’t see it, Lance I don’t know.

It was Kodiak, they said, they did a simultaneous frac on 1400 feet apart, and they felt like that there was going to be a greater than three well density. I think, it was a broad count.

Yes, they fraced four wells.

Yes, that would be four wells spacing was rod spacing, and that may have been down and done by anybody. In any case it’s a bit [tighter] area, are obviously going to need more wells per unit, and just let me add one other thing, we have seen, if you look at our well, as we have increased a number of frac jobs, or stages, we have actually been shortening, the frac links, because we have been using the same pounds of propane for lateral foot of hole. So as we increase the number of frac, out along from total yield, those frac veins are getting shorter and shorter, and our EURs are getting higher and higher. What that tells me is that, we have shortened our drainage radius but we have done a lot more efficient draining of the rock between the frac veins always toed at yield. Ultimately our achieving is wanted to do. So there'll four wells per unit, but I think it may even be, even in the tide areas, we have it may be had some variability, may be through summer three, may be summer four, maybe summer five.

It will be interesting, once we have drilled out of three wells in Rough Rider and we had required a microseismic, it could provide us an opportunity for a test case to come in and potentially drill two wells between each of those three laterals and see if there is more opportunity there.

You asked about the tax, ordinarily you would expect this to being seeing deferred taxes generated, but at the end of the year, last year, we had a deferred tax asset on the books of roughly $77 million and at the end of the first quarter, that’s per deck tax asset was $73 million. Now it’s not on the balance sheet because we’ve got a valuation allowance that offsets it, but so I would expect them for the remainder of this year that we would not see any deferred tax assets or deferred taxes as a result of the deferred tax asset that we have got. So, we are going to sell the West Texas asset. It's not a big transaction. There will be a gain. We have got big and well position to offset the gain associated with West Texas, but there could be some AMT taxes associated with that gain, but they won't be big numbers.

Our next question comes from the line of Scott Hanold of RBC Capital.

I got just a couple of quick ones here. First on the Sweetman, I know you are not talking about right now, but how many frac stages is going into that well and how long is that lateral? Could you at least talk about that?

Yes, Scott, this is Jeff. It’s a two section lateral, section 24, 25 and if memory serves it was 22 fracs. We can get you back on that, Scott.

Okay, and then, as far as (inaudible) new well, is there anything you could see as far as drilling the well, what you are seeing there? Any kind of indications on the well, really on?

Again Jeff here. Sorry, we can’t share anything with you on that right now. We are currently analyzing the core.

Yeah, again a lot of science there and so we just need to wait until we compile some meaning full data there and then we’ll put that out to the market.

Okay. And that will be late June or early July. Is that right?

Correct. And that’s what we are anticipating. That’s correct.

And our next question comes from the line of Michael Scialla of Thomas Weisel. Michael, you may proceed.

Let me talk just in general about, you mentioned the sweet spots. What do you think controlling those, is it primarily thickness or rock quality or and how does that vary as you look from the Ross area across the west, through the Rough Rider area?

This is Jeff, just real quick. We’ve got good geologic control from a vertical standpoint from historic wells and what occurred out here is from the vertical wells, you can tell thickness and also proximity, but you can’t tell the permeability. So we think permeability could be a significant driver and which enhances some of these sweet spots and that’s why you’ll see us continue in core wells where we think its efficient because once we get the rock core we can really can dial in on the porosity and the perm and things like that but it really help us to understand the sweet spot better.

And do you know yet how you are going to change the completion techniques where to find the better perm?

Yeah, we’re. This is Bud. I’ll take first shot. Lance might want to add but really its different for different areas I mean in some areas we’re like for example, the Ross area, we went from, our Anderson well is a terrific well with 24 stages in the Sorenson with 27 was the record well for the Basin. So that’s got us really excited about the Jack Cvancara with 36 stages, so there was still increase in number of stages. In some other areas we feel like kind of appears that we didn't see dramatic improvement going from sight 28 to 30 or 32 stages, So in those areas were varying other things. And so Lance if you want to add something about the different things we are varying in the different areas?

Right, I think, I alluded to them earlier, one of the other things is, even though we've increased the number of stages we haven’t, we have been short in our frac link. So one of the things that we are going to look at is look at optimal, try and figure out optimum, number of stages and once you know that, then you look and say, hey, what is the optimum frac length. If we do bigger jobs, are we going to be adding in EUR's and rate of return and so will be increasing the amount of profit we are pumping. Some of the other things we might look at, some different propane in an area, we might use an area where we use different propanes or may be different fluids that (type of things)

Okay. Then in terms of your guidance I appreciate the second quarter guidance. Now that you have got this very large inventory and it has been pretty well de-risked. Anything on your back from given longer term guidance’s, infrastructure a still primary concern that would hold you back from doing that?

We got guidance, I think you're talking about production guidance?

Yeah, I am sorry to,

Yeah, we have got production guidance for this year, for our oil volumes, and gas volumes and we have got guidance out there for next year, for just our oil volumes. So, right now, though we don’t really have much, we don’t have anything in the budget currently, other than Williston Basin, wells in the budget for 2011, so we expect our gas volumes after we get these two Vicksburg wells, and bring them on, and then we start to resume on the conventional side, on the gas side, start at the decline rates, the normal decline rates, and offsetting that, will be the growth in our Williston Basin lines, for in 2011.

Okay, I apologize , that is my mistake. Just lastly to with this huge inventory that since the beginning bigger all the time, you've obviously developed a lot of expertise here. Any thought of, hear there is a lot of new plays that are being chased oil specifically resource plays. Any thought and try to take this technology and transfer it in other areas? Or are you worry about taking your eye of the ball here?

We are keenly focused on this opportunity here. That being said, this company has a history, as the Bakken is the great example, that of being able to analyze plays around the country and get up to speed on them. So Jeff does have and he might want to add to it, he has some teams that look at the other plays, but over the near-term our real opportunity is to create value is in this play, but clearly that technology is transferable and there are a lot of it is and our expertise with those plays but we are monitoring them. We don’t have any plans to pickup any positions in those plays at this time, but it make sense for us to map them out and monitor them and catch the real opportunity to compliment what we are doing but no plans there.

Obviously, in the year 2020 after we've drilled out the current acreage, we will have something to replace that inventory.

I will be dead by then, but I wish you take that plays.

Our next question comes from line of Derrick Whitfield of Canaccord Adams.

Just want to build on million Mike’s first question there, specifically focused on completion testing in 2010. It sounds like your first variable that you are going to start to play with will be the amount of stages. It sounded like from Lance, that you may even change whether it’s the type of propping that you’re going to use. Are there specific parts that you guys would consider sand over ceramics?

Yes, Derrick, this is Lance. Well, what we have been doing and let me start back from the beginning. What we have been doing from the beginning is using the science and the engineering and design in this wells where we know that there is a benefit for running ceramics. So we are running ceramics. We determine perf and plug fairly early on over the sleeves and so those variables have always been constant and what we didn’t doing from the beginning almost is at least since EOG brought in swell packers in to the basin we've just the increasing number of stages used in ceramics, perf and plug and the same consistent pounds of PUD or ceramics per lateral. So that’s been pretty consistent. So we’ve got a pretty good feel, overall, what the right number of stages are but there is too much variability in a 160,000 acres. So we are going to break it in to five areas. We’re going to couple those areas. We may still continue to change the number of stages because the rock is a long ways from the two groups from one another. So there may be one in Rough Rider and one in the Easy Rider so that we can optimize in the smaller geographic area what’s the optimum number of stages. One of the other things we may do is increase the amount of sand that we pump per lateral foot that will extend and that that will be ceramic. That will extend the fraclings and see what that does to our recovery in our economics. One of the other things we may do in an area is increase the profit concentration. So a lot of the people only pump four pounds per gallon. We are going to ramp it. We have been ramping six to eight and just change that one variable in an area and see what the benefit is by trying it on higher concentrations. Then in other area we may try pumping other propane I doubt it will ever be white sand. Right now we think that’s the wrong thing to do. We might try resin coated sand which has higher strength, It should be okay for this application but there is some other negative benefits to that and we might also try some other propanes. They are not ceramics but there are not sand and we might try fluids, different fluids technology

Thanks Lance that was really helpful and really we are very early on that Mortenson well but did you guys learn anything with that well and going between three stages and well what’s the cost of that well, if you don’t mind?

The Mortenson well was around it was about 62.

No I think, this Bud., I think what’s you are saying is that in some areas we were trying maybe in the cases pull back on the number of stages and see how benefit analyst of the incremental stage is there, but that’s of course [Ross] area we got 24 and 27 at Sorenson. We got the record well so in the Cont Chert we want to plan 36 stages and I think some others operator have done with a substantial numbers stages like that and seen some strong results, certainly we have at this point. So I can’t bigger a different rates for the different areas.

Got it great. and you guys also mentioned some micro seismic, do you have any specific plans in any given quarter to run those test other than your Rough Rider or Ross areas?

Yes I would be in Rough Rider area, what we are currently planning to do is in a Rough Rider area and also we were doing the increase spending which should be early third quarter looking at currently on the timing.

At this time showing no further audio questions available. Ben Brigham, you may proceed.

Right, this is Bud. I do want to thank everybody for their participation in the call and we look forward to reporting on what should be a really exciting second quarter. Thank you.