Ben Brigham - Chairman, President and CEO Gene Shepherd - EVP and CFO Jeff Larson - EVP, Exploration Lance Langford - EVP, Operations

Michael Jacobs - Tudor, Pickering & Holt Ron Mills - Johnson Rice John Freeman - Raymond James Subhash Chandra - Jefferies Scott Hanold - RBC Capital Michael Scialla - Thomas Weisel Derrick Whitfield - Canaccord Adams

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 let's get started. First if you'll go to slide 3, you can see our outline for the call today. I am going to provide you with an overview and a few high points, which will be followed by an update on our operational activity in the Williston Basin. After that, Gene will finish up with the financial update. After our updates, we would be happy to answer any of your questions. On slide 4 you can see a few summary points. First, at this point, we believe we have substantially de-risked about 164,000 net acres and that's out of the roughly 305,000 net acres we controlled in the play. We now had 21 consecutive high rate, long lateral, high frac stage wells come online with an average peak rate of over 2,500 barrels of oil equivalent per day. We are just getting started drilling this inventory, given that we have roughly 474 net undrilled development locations remaining to be drilled in our core substantially de-risked areas. We estimate that our wells are paying out in less than 1.5 years, with a 36 year economic life in an average rate of return of about 80% Our acceleration from four-day rigs which is underway is expected to reduce the time it will take us to drill our de-risked inventory down from around 20 years to about 11 years, a reduction of about 9 years. That brings forward over 200 net wells, which we believe add $10 to $11 per share in shareholder net asset value. Also at this pace, we will be holding bi-production or de-risked core acreage within about three years with our initial production unit wells. Again, shortening our core full development cycle by an estimated nine years from 20 to 11 years. So by getting that initial well drilled in roughly three years, we have the option preserved to potentially drill the five additional wells each spacing unit for full development. Looking at production, we expect our oil production to grow by 125% this year and to double again next year to approximately 10,400 barrels of oil per day. And as you saw in our press release issued yesterday, we are on track thus far to meet those objectives. Furthermore, over the next several months we anticipate moving more of our non-core acreage into the core category, thereby converting some of our potential locations into the de-risked development category. Other operators are already contributing to converting some of our potential locations into the de-risked inventory in the Three Forks in our Rough Rider area. And we should have our first operated Three Forks well done by late in the second quarter or early in the third quarter. We've also drilled our first Montana well and expect to have completed results for that well at about the same time period. With success in Montana, we had the potential to convert a meaningful amount of additional acreage into the core category. So these are meaningful catalysts, those two areas have the potential to double our development inventory in the play. Moving forward to slide five, you can see the oil commodity advantage that has persisted over the last several years. Nothing has changed here. We expect oil to be the favorite commodity domestically for at least the next three to five years, given the ample supply of natural gas provided by the numerous quality unconventional gas plays. The downward pressure on the gas rig count should help to keep the costs of drilling complete our oil wells down, thereby providing attractive margins in returns on our huge inventory at Bakken and Three Forks oil drilling projects In slide six is our well by well growth in the Bakken and Three Forks oil production through year end. Now if you move forward to slide seven, you can see how we progressed during the first quarter of 2010. Our first quarter 2010 Williston Basin production was up 29% sequentially, relative to the fourth quarter of 2009. As shown on the slide, we are currently fraccing one well, the 36 frac stage Jack Cvancara with three wells waiting on completion and four wells currently drilling. As noted in our press release, our fifth rig commences next week. So in the second quarter for the first time, we will have four rigs fully impacting the quarter with completion with our fifth rig bringing production into our third quarter. Slide eight simply illustrates the impact of Williston drilling is having on our complete total oil volumes and that's despite the fact that we are just getting started. We have quickly grown meaning oil volumes and transform to resource-driven oil company. Our first quarter oil production was up roughly 24% sequentially over the fourth quarter of 2009 and comprised approximately 66% of our 6:1 equivalent total production and 79% of our revenue in the first quarter of 2010. Slide nine illustrates our second quarter and full year 2010 production guidance. I should mention that our guidance for the second quarter is without the benefit of our fifth rig, which commences next week. The fifth rig will possibly impact our third quarter production. Given the accelerating production growth this drilling is generating including the strong wells that have come online thus far in the second quarter, we believe we are on pace to meet our targeted 125% growth in oil production during 2010. As shown on slide 10, oil continues to trade at substantial premium to natural gas. In the first quarter 2010, our oil volume is sold at 12.1 equivalency, as opposed to the 6:1 convention. That's expanded up late, given the prompt month NYMEX equivalent to today of about 21.1. As a result, our barrel of our oil today is generating about 3.6 times of revenue of a 6:1 equivalent Mcf of natural gas. Now briefly touching on operational enhancements and well performance, slide 11 shows the improvements our team has delivered in well performance as we have increased the number of frac stages. We haven't only elevated the initial rates, we have elevated the entire production curve and therefore, the ultimate reserve recoveries. And of course, that's driven down our finding costs in enhanced or economic returns. Moving forward to slide 12, you can see that our team has led by example in the play. Our early 24-hour peak rate have roughly doubled the average of our peers. It's really a combination of being an early mover in the play and therefore smartly acquiring acreage in the core of the best areas and also being smart in the application of ever improving drilling and completion technologies. At the bottom of the slide, you can see the key elements that our team has delineated as important for generating optimum economic returns in the play. And that brings me to slide 13, for the most part last year we have picked all the elements with the exception of the number of frac stages. That's one reason we had such success. We were varying one element the right one, so that we could see the impact it had on well performance. However, there are significant geological differences across the vast area. For example, in Rough Rider, some of our wells are over 30 miles apart. We are now accumulating baselines for well performance in six different areas as shown on slide 13, such that we can further refine to determine optimal drilling recipes in the various areas. This is one reason we expect to continue to deliver improved performance over time. Different formulas will be optimal in different areas and we are now beginning to delineate those formulas. Also on slide 13, you can see the pipeline gathering facilities we have, and are currently building on the ground. These facilities will help us reduce our costs, both to produce our wells, but also to get our oil and natural gas to the market. These facilities will also attract third party volumes to everyone’s benefit. So we are capitalizing on our dominant acreage positions in these areas in ways that will benefit our shareholders meaningfully over the long haul. Slide 14, is the type curve we discussed for our wells. The mid case estimated ultimate recovery of 600,000 barrels of oil equivalent pays out in less than 1.5 years with an estimated rate of return of roughly 80%. Of course that is an average EUR that we have been talking about for sometime now. Slide 15 lists our 21 consecutive long lateral high frac stage wells in order from the earliest at the bottom to the most recent at the top. Our 21 long lateral high frac stage wells have generated early peak 24-hour production rates, averaging about 2,500 barrels of oil equivalent today. As you can see highlighted in yellow more of our recent wells are outperforming. We believe that by year end given the number of wells we will have drilled in different areas that is likely, we can provide more definition, in particular, of some of other real sweet spots that are outperforming our expectations. Though it could be that by next year, we will have different type curves and different average reserve expectations for different areas. Moving to slide 17, you can see our acreage in the Williston Basin in red. We have been growing our acreage in our core areas such that our total acreage position in the basin is approximately 305,000 net acres. We expect our acreage to continue to grow further in our core Ross and Rough Rider areas, where we drilled our 21 consecutive successful long lateral wells. I will briefly discuss each of these areas, as well as our acreage in Eastern Montana, where we helped to successfully complete our Rogney well and thus grew our inventory of developmental projects. We have included our spacing unit development plan on slide 18. We are comfortable that we can drill three horizontals across each units for each objective, possible more in some areas. So in area such as Ross, where we believe we de-risked the Three Forks, we currently think we will drill at least six wells in each spacing units. Slide 19 illustrates our inventory in the basin. In the upper green box, we list the core acreage that we believe we de-risked to this point, providing us with an estimated 493 net development locations, which is about an 11-year inventory, with our ramp up to eight rigs. On slide 20, you can see how that inventory would grow with success in the Three Forks and Rough Rider, roughly 58% to approximately 781 net locations. The fact that Continental and others have drilled Three Forks discoveries immediately west and east of our acreage, coupled with our Three Forks core in Olson well, has already somewhat reduced the risk for the Three Forks and Rough Rider. Below that you can see the opportunity we have in Montana. Success in both the Three Forks and Rough Rider in the Bakken as well as potentially Three Forks in Montana could more than double our inventory of drilling locations. So with eight rigs running it would grow from an 11-year inventory to 22 plus year inventory. Now moving to our Rough Rider map on slide 21, you can see that activity in the area is exploding. As you can see, our discoveries are scattered all around our 123,000 net acres in the area. By next week we will have four rigs working here, but other operators are also picking up the pace with some recent encouraging results, both east and west of our acreage. One recent third party operated well is Continental's Obert Three Forks discovery, which is immediately west of our acreage and apparently produced at initial rate of approximately 900 barrels of oil equivalent per day. We are very excited about our upcoming Three Forks wells, which should commence later in the second quarter. We are also very excited about the potential of our Rogney well in Eastern Montana as shown on slide 22. We have successfully drilled the well and are doing quite a bit of science that will benefit us immensely if we get into developed mode here as we are. We have poured 120 foot interval, which includes the basal Lodgepole, Bakken and Upper Three Forks. We should have results from our Rogney well to talk about either late in the second quarter or early in the third quarter. Like Rough Rider, we are benefiting here from third party operated wells, which could also contribute to the de-risking of this area. Moving east to Mountrail County in North Dakota in our Ross area as shown on slide 23, we are proud to have drilled what today is a record well in the basin with our Sorenson well. The Sorenson had 27 frac stages and produced at a peak early rate of about 5,100 barrels of oil equivalent per day. As discussed in our press release yesterday, we continue to perform spectacularly. Given that we are very excited about our Jack Cvancara, which is currently fracing just one mile to the northwest. We are planning to frac 36 stages in this well, which will be a record for our company. We have high expectations for this well and of course, this area appears to be a real sweet spot for us. We have an approximate 83% working interest in the Jack Cvancara. Last, moving to South Texas in slide 24, we drilled and are preparing to complete the first of two Vicksburg wells, the Sullivan #16 in mid-May. We are currently drilling the second well, the Sullivan #17. These wells are in terrific fields. We have 52 proved probable and possible locations available to drill here. And given that over 50% of the value in these fields comes from liquids, these wells typically generate strong economic returns even with low natural gas process. We expect these wells to meaningfully impact our production from this area. So that concludes my remarks. Now I will hand the call over to the Gene to provide you with the financial update. Gene?

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 total of $541 million of net proceeds. A testimony to the very significant NAV creation opportunity that we have in front of us, we have obviously experienced very significant share price depreciation since we completed the first offering last May at $2.75 per share and our most recent offering completed earlier this month was priced at a premium to the pre-launch share price. Lastly and most importantly, after the completion of our first high rate, two section lateral Olson well in Rough Rider in January 2009, we have completed an additional 21 consecutive high rate, two section laterals significantly enhancing the company's liquidity and cash flow. We now have the capital on our balance sheet to fund the continued ramp up in our drilling activity to eight operated rigs by May 2011. Slide 28 depicts the incremental NAV of roughly $10 per share that is generated by accelerating our operating rig count from four to eight rigs. Furthermore, we feel in the current environment, our current liquidity position provides us with the capacities to sustain an even higher level of activity. We look forward to the day, when we can take our operated rig count beyond even the eight rigs that we are forecasting to reach next May. At April 28th, we had $378 million of cash and marketable securities on the balance sheet. As depicted on slide number 29, combining our cash position with the unused availability under our credit facility gives us $488 main dollars of total liquidity. Based on our current acreage position and our current inventory of drilling locations, we are forecasting that we will not have a need for external capital through the year-end 2011 and possibly beyond. However, we do have the option to access additional capital to fund other growth opportunities that we feel might materialize for us in the Williston Basin, some of which are outlined on slide 30. These additional sources of capital would be generated by the sale of all or some portion of our conventional assets and use of the unused capacity under our senior credit facility or some other form of debt financing. Moving on to a brief discussion of our financial results, our first quarter total production volumes averaged 5,420 Boe per day above the high-end of our Q1 production guidance and an increase of 7% sequentially and 1% from that in Q1 2009. More importantly, given our focus on drilling our Bakken and Three Forks predominantly oil wells, our first quarter oil volumes averaged 3,552 barrels of oil per day, an increase of 24% sequentially and 84% from that in Q1 2009. Our Q1 oil volumes represented 66% of our total production volumes. More importantly, because the substantial pricing disparity of oil versus natural gas, which we are fully able to capitalize on by focusing our drilling in the Williston Basin. Our oil volumes represented 79% of our total first quarter pre hedge revenues. Our first quarter total production volumes reflect an increase in our oil inventory of approximately 5,012 barrels held in our on-site tank batteries at March 31st. Adjusting our Q1 production volumes for the growth in our oil inventory results in average daily sales volumes for the first quarter of 5,364 Boe per day. Higher commodity price and higher oil production volumes more than offset the impact of lower hedge settlement gains and lower gas production volumes during the first quarter, resulting in a 38% increase in revenues, including hedge settlements of $29.5 million. First quarter 2010 revenues were positively impacted by $13.8 million due to a 109% increase in our pre-hedge commodity prices. This increase was partially offset by $6.9 million decrease in cash hedge settlement gains. On a per unit basis, we saw operating expense, which includes operating and maintenance expense, expensed workovers, and ad valorem taxes increased 13% to $9 per Boe in the first quarter 2010 from $7.98 per Boe in the first quarter 2009. A $220,000 decrease in our base operating and maintenance expense was offset by $795,000 increase in workover expense, primarily related to several of our conventional natural gas wells worked over during the first quarter. On a per unit basis production taxes increased to $5.19 per Boe in the first quarter 2010 from a $1.69 per Boe in the first quarter 2009. Due to the growth in our North Dakota oil volumes and the higher associated taxes, production taxes were 8.7% of pre-hedge revenue in the first quarter of 2010, compared to 5.9% of revenue in the first quarter 2009. In addition to the growth in our North Dakota oil volumes, higher commodity prices and the associated increase in revenue in the first quarter 2010 also contributed to the increase in production taxes over that for the comparable period last year. General and administrative expense for the first quarter increased to $3.1 million from $2.1 million in 2009, an increase in employee compensation expense primarily resulting from reinstating an employee bonus accrual in the first quarter of 2010 after it was discontinued in 2009 accounted for the bulk of the increase in G&A expense. The higher commodity prices and growth in oil volumes in the associated increases in our revenues contributed to a 39% increase in EBITDA during the first quarter 2010 to $21.4 million. Moving on to the balance sheet, at the end of the quarter we had a $107 million of cash in marketable securities, $160 million of senior notes and zero balance under our credit facility with $110 million bond base. Recapping capital spending activity for the first quarter, our exploration and development capital expenditures totaled $52.1 million of which $43.6 million went to drilling expenditures and $8.5 million went to land expenditures. Slide number 31 depicts our updated 2010 E&D capital expenditure budget of $294 million to drill 31 net horizontal Bakken and Three Forks wells and our initial 2011 E&D capital expenditure budget of $360 million to drill 45 net horizontal Bakken and Three Forks wells. In our earnings release yesterday, we provided production guidance for the second quarter. In terms of our expectations for the second quarter, we are forecasting for our total production volumes to average between 6,200 and 6,800 barrels of oil equivalent per day with 68% of these volumes forecasted to be oil. The mid point of our Q2 guidance would represent an approximate 20% sequential increase in total production volumes relative to that for Q1 and a 44% increase relative to that for Q2 last year. This forecast reflects the continuation in production growth that is being driven by horizontal Bakken and in Three Forks drilling program that will take us to record total production volumes in the second half of 2010 and beyond. That concludes my remarks. I will now turn the call back over to Bud.

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. Ron Mills - 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. Ron Mills - Johnson Rice: 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? Ron Mills - Johnson Rice: 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. Ron Mills - Johnson Rice: 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. Ron Mills - Johnson Rice: 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. Ron Mills - Johnson Rice: 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. John Freeman - 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. John Freeman - Raymond James: 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. John Freeman - Raymond James: 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. John Freeman - Raymond James: 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. John Freeman - Raymond James: 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. Subhash Chandra - Jefferies: 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]? Subhash Chandra - Jefferies: Well that was, so that another Panther well?

Its actually operated by [Dynergy]. Subhash Chandra - Jefferies: Okay, got it

One section to the west of Bakken Subhash Chandra - Jefferies: 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? Subhash Chandra - Jefferies: Arnson, yes. Did I misspeak?

Well, we thought we are heard Anderson, but we just couldn’t hear you well. Subhash Chandra - Jefferies: 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. Subhash Chandra - Jefferies: Yes, that’s make sense.

Does that answer your question? Subhash Chandra - Jefferies: 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. Subhash Chandra - Jefferies: 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. Subhash Chandra - Jefferies: 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… Subhash Chandra - Jefferies: 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. Scott Hanold - 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. Scott Hanold - RBC Capital: 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. Scott Hanold - RBC Capital: 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. Michael Scialla - Thomas Weisel: 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. Michael Scialla - Thomas Weisel: 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) Michael Scialla - Thomas Weisel: 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? Michael Scialla - Thomas Weisel: 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. Michael Scialla - Thomas Weisel: 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. Michael Scialla - Thomas Weisel: 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. Derrick Whitfield - 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 Derrick Whitfield - Canaccord Adams: 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. Derrick Whitfield - Canaccord Adams: 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.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.