Bud Brigham – Chairman, President and CEO Gene Shepherd – EVP and CFO Lance Langford – EVP, Operations Jeff Larson – EVP, Exploration David Brigham – EVP, Land and Administration

John Freeman – Raymond James Brian Lively – Tudor, Pickering, Holt Joe Allman – J.P. Morgan Ron Mills – Johnson Rice Scott Hanold – RBC Steve Berman – Pritchard Capital Partners Michael Bodino – Global Hunters David Snow – Energy Equity, Inc. Richard Bresler – Gulfsands Petrol Subash Chandra – Jefferies Eugene Lipovetsky [ph] Ed Campbell [ph]

Good day, ladies and gentlemen, and welcome to the second quarter 2010 Brigham Exploration Company earnings conference call. My name is Erica, 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 your host for today’s call Mr. Bud Brigham, Chairman, President and CEO. Please proceed, sir.

Thank you, Erica. Thanks to each of you for participating in Brigham Exploration Company’s second 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; David Brigham, Executive Vice President Land, Legal and Administration; 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 web site at www.bexp3d.com. It includes very helpful information regarding our second 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. It will help you to be prepared with this as we’ll flip through some of the slides pretty quickly. During the call, we're going to make some forward-looking statement 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 Web site under the section entitled Investor Relations at www.bexp3d.com. So let's get started. First if you'll go to slide four, you can see our items for discussion during the call today. I am going to start by covering the headline items. I’ll then briefly discuss our near-term catalysts. Following that, Gene Shepherd will provide you with the financial update, and Lance Langford will finish with an update on our operational activity on the field. After that, we’ll be happy to answer any questions. Regarding the headline items, we’re very excited about the 52,800 net acres we've acquired both organically by leasing and in four recent transactions. These are quality acquisitions at a very attractive cost, particularly relative to recent M&A transactions and, of course, the state lease sales. These transactions illustrate that our track record in the area makes us the purchaser of our choice for consolidating acreage, particularly in the Rough Rider area. Our core acreage has grown by roughly 34,000 net acres or 21% to approximately 198,000 net acres. This core acreage is generally proximal to the 21 consecutive high rate wells we've drilled in the Rough Rider area today, as well as that of key wells drilled by other operators. I will first show you these acquisitions in map view. Following that, I’ll discuss our first Montana discovery, the Rogney; then discuss other catalysts including our currently drilling Rough Rider Three Forks well and our Increased Density well, and briefly discuss our production, which continues to ramp up and is currently at record levels. If you’ll to go slide six, you can see our acreage position in the basin prior to our 2010 acreage acquisition transactions. If you then flip forward to slide seven, you can see the acreage we’ve added during 2010 in orange. Now, let’s zoom in and look in more detail at Rough Rider on slide eight. Well, you can see our position prior to the 2010 edition. Flipping to slide nine, illustrates our 2010 editions again in orange. This includes the acreage additions we previously announced in April. Moving forward one more time to slide 10 and you’ll see the 52,800 net acres we've just added. Some of this acreage is in sections in which we already had acreage, and in most cases, we color those sections orange. Importantly, these acreage additions were driven by the same geologic attributes that had been validated by our drilling of the 21 consecutive successful high rate Bakken wells that we've drilled in this area. In addition to the geologic attributes and the wells we’ve drilled, there are also some key third party operated wells that help us delineate these opportunities. The combination of that production and geologic data makes the approximate 34,000 net acres in and proximal to our Rough Rider drilling core in our view, and therefore, more developmental in nature. For example, our recent Sedlacek well is located in the southwest portion of the Rough Rider area, just east of the state line separating Montana and North Dakota. The well recently commenced production at initial rate of approximately 2,695 barrels of oil equivalent per day. Roughly 12 miles to the northwest of the Sedlacek is the Zenergy Luke Sweetman, they commenced production at roughly 12,000 barrels of oil equivalent per day, which I will discuss further in a minute. Between the Sweetman and the Sedlacek wells, we've acquired a nice acreage block, including roughly 9,900 net acres right across the line from the Sedlacek in Richmond County, Montana. Based on those wells, which confirms our geologic attributes in the area, we believe that this acreage is significantly de-risked and is now core for us. We plan to spud a well in this area, almost half way between the Sweetman and our Sedlacek in October. There’s an additional 17,300 net acres that we acquired that lies a bit farther due west in Montana, northwest of the Elm Coulee Bakken field. It's shown in the lower left portion of the map roughly five miles or more from our Sedlacek well and southwest of the Sweetman. We think this area has very good potential, but the geology is a bit different and is not as proximal to these wells, so we don’t yet consider it to be core acreage. We currently plan to drill our first well in this area, which could potentially begin to move it into the core category during the first quarter of 2011. Now, before we leave this map of the Rough Rider area on slide 10, you can spot our currently drilling initial Three Forks test in the area. It’s at the upper right with the purple label. This is a significant potential near term catalyst for us and success here could begin to move up to 344 net Three Forks locations into the core category. We’re very positive about the Three Forks in the area given the geology and also given that other operators – excuse me, other operators had made encouraging Three Forks discoveries proximal to our acreage. Those Three Forks producers are shown with the purple stars. The state #2H Three Forks well is drilling in the curve and we currently expect to frac it in late October or early November. Moving to slide 11, to Roosevelt County in Eastern Montana, inclusive of our Rogney well, we now have three apparent Bakken discoveries proximal to our approximately 75,000 net acres in this area. In drilling and completing the Rogney well, our primary goal was to learn as much as possible on this first test to accelerate our learning curve which could – would benefit us on our all subsequent wells. We were particularly cautious that given that a third party well drilled about eight miles to the northwest, the FH muddy apparently produced with large water tests, and likely associated with that, lower oil rates. We designed the initial frac to stay more contained in the Bakken interval. Therefore, we fraced the initial nine stages in the lateral at lower frac rates. Although that reduced the productivity of that portion of the lateral, and ultimately, of the co-mingled well. It ensured that we could gain valuable data from this initial test. Given what we learned from the first nine stages, we treated the remaining 21 frac intervals at higher frac pump rates, and when co-mingled with the initial nine intervals, the well produced 909 barrels of oil equivalent in an early 24-hour peak period. The well seems to be leveling out at its recent rate of about 400 barrels of oil equivalent per day. In fact in the last 24 hours, it made roughly 455 barrels of oil equivalent per day. Immediately offsetting our acreage to the north, EOG apparently made a discovery with our Carat well. Based on publicly available data, the Carat produced an average of 246 barrels of oil equivalent per day during its first 26 days of production. It’s important to note that this was a short lateral well and we don’t know how many frac stages they utilized. However, they must be encouraged given that they've applied for spacing for 42 units in the area, approximately 11 of which include our acreage. Now, one of the most encouraging data points was provided by Zenergy when they successfully completed the Sweetman well which is located about 17 miles east, southeast of the Rogney. This well is about halfway between our Rogney and our Sedlacek discovery and is just north and west of the acreage we acquired proximal to our Sedlacek discovery. We participated with a very small working interest in the Luke Sweetman, which was completed with perf and plug and ceramic proppant, including 23 frac stages. However, it appears they did pop a lower amount of ceramic proppant per lateral foot than we do. They appeared to have pumped 150 pounds versus our 250 pounds per foot. The Luke Sweetman came on line in late April at initial rate of approximately 1,200 barrel of oil equivalent per day. After 100 days, it had produce roughly 30,000 barrels of oil and was recently producing about 320 barrels of oil equivalent per day. At this point, this well appears to be very economic and is therefore very encouraging for the area. There should be quite a bit of data flow in this area during the remainder of the year. Well spacing activity has increased with 78 units applied for by other operators at the June and August spacing hearings. The majority of these units are just east and north of our 75,000 net acre block in Roosevelt County. In some rigs, given the results for the Rogney, the EOG Carat and the Zenergy Luke Sweetman, we believe that we’re beginning to de-risk a portion of our 75,000 net acres in the area. Looking forward, we’ll continue to monitor the performance of the Rogney and other surrounding wells. And we’re very excited about starting our next Montana operated well, the Gobbs 17-8, approximately five miles east of the Rogney in October. We wanted to learn as much as we could on the Rogney, so there was quite a bit of R&D there. On the other hand, the Gobbs well provides us with the opportunity to optimize for performance. Our goal is to generate a highly economic well based on all that we’ve learned thus far as possible. Now, if you’ll view slide 12, and we’re going back to the Rough Rider area, we’ll see another potential catalyst. This slide illustrates our Brad Olson 2H increased density well, which is currently drilling in the lateral. In order to reduce our mobilization cost, we will sequentially follow the drilling of the Brad Olson #2H with the drilling of our third well in the unit, the Brad Olson #3H. We currently plan to stimulate the Brad Olson #2H in October. And during the stimulation, will record a FracStar microseismic array to monitor the propagation of our frac lanes. We plan to wait about 90 days to stimulate the third well in the unit, the Brad Olson number 3H. Given that we've successfully pioneered increase in number of frac stages without proportionally increasing the amount of proppant we're utilizing, we've effectively lowered our proppant intensity per stage. As evidenced by our strong well performance, we’re more effectively stimulating the near-well-bore area. At the same time, we've probably reduced the length of our frac wings. Obviously, it had a very positive impact on reserve recoveries and economics, but it may also provide us with the opportunity to drill more than the currently envisioned three wells per spacing unit. Hypothetically, if we could drill two more laterals between our currently envisioned three laterals per unit, that’s a potential 66% percent increase in net asset value here for us to recover. But we’re very excited about this project, though it will take some time to evaluate the results. If the microseismic and production evaluation indicates that we have the potential for more dense developmental drilling, then we could potentially test that with further density drilling in this unit in 2011. Moving briefly to the Ross area in Mountrail County on slide 13, as some of you recall, in this area we've completed two highest reported IP wells in the basin, the Sorenson and the Jack Cvancara, both of which had IPs of over 5,000 barrels of oil equipment per day. These wells continue to perform very strongly. We’re very excited about our upcoming completions here. We'll have 38 stages on these wells, a BEXP record. The first of these is the Wright 4-33 #1H, which is currently fracing. In early September, we plan to fracs 38 stages into Clifford Bakke, and in early October, the Domaskin, which directly offsets our two 5,000 barrels of oil equivalent per day IP wells. Those wells should contribute materially to a strong production exit rate this year. That completes our operational highlights discussion. Now I’d like to briefly discuss our operating environment, our well performance, economic and production growth. But first, if you will quickly view slide 14, you can see a picture recently taken of our currently drilling Brad Olson #2H, right next to it is the path to the Brad Olson #3H. In the foreground of the picture, you can also see the Brad Olson #1H and the first high frac stage, long lateral that we drilled in the basin, the Olson 10-15 #1H. Moving to slide 15, we can see that oil continues to trade at a meaningful premium for natural gas. Given the abundant supply of natural gas domestically, we believe that oil commodity advantage will continue for at least several more years. On slide 16, you can see how this advantage translates into improve margins for us relative to natural gas resource players. On a relative basis, investing incremental capital in our Bakken and Three Forks oil projects is much more accretive than incremental investment in natural gas projects today. We've got an amazing opportunity to grow, and contrary in many ways to the gas resource players, we're in an ideal window to do so. On slide 17 is our updated well list. Our (inaudible) is beginning its flow backs and we'll have results on it soon. Moving forward to slide 18, you can see the improvement in the performance our team has generated with recent wells as we've increased the number of frac stages which has elevated the entire production curve, and therefore, the ultimate recoveries. Slide 19, illustrates our type curves. Our average well falls somewhere in this range of 500,000 to 700,000 barrels of oil equivalent with strong rates of return in roughly 35-year reserve lives. You move to slide 20, you can see the cash return on investment over time for the midpoint EUR example of 600,000 barrels of oil equivalent, relative to various oil prices and assuming our current completed well costs. At $75 oil, a 600,000 barrel of oil equivalent well pays out in about a year and a half with a rate of return of roughly 59%. Gene will discuss our hedging in a minute, but we've been ensuring a minimum $65 oil price, stated in green here, on a good portion of our volume through collars and floors. Slide 21 is our updated drilling inventory table. We view our new acquisitions as extremely accretive relative to recent transactions in the area, but particularly relative to the value those estimated 81 net core locations we’ve added should provide for our shareholders. We believe that our core acres numbers should grow with further drilling in Montana. And as shown in slide 22, our currently drilling Three Forks well in our Rough Rider is also a major catalyst. With drilling success, we could add up to 344 net locations to our core inventory. Now moving forward to look at our production growth on slide 23, you can see our production through last year. And if you click forward to slide 24, you can see the acceleration in our growth, which has exceed our expectations. We've roughly doubled our Williston Basin oil daily production rate in a six-month period. Production addition should accelerate during the second half of the year as we bring on the additional frac crew. Slide 25 illustrates the impact our Williston production additions are having on our total company quarterly oil volume. Our second quarter oil production was up 57% sequentially and is more than three times that of the second quarter of 2009. Now that wraps up my portion of the presentation. I'm going to go ahead and hand over the call to Gene. Gene?

Thanks Bud. Before we get into the discussion of our first quarter results, several comments about what turned out to be a record quarter in terms of production and EBITDA for Brigham. First, we experienced strong operational performance during the quarter based on the continuing ramp up and success of our Williston Basin operated drilling program, we achieved record quarterly production volumes of 776 – 756 barrels of oil equivalent per day. Second, this strong operational performance translated into record financial results. Routine operating maintenance expense, production taxes in G&A expense all came in at or below the guidance that we issued for the second quarter, and when combined with our record total production volumes, result in the company achieving record EBITDA of $33 million for the quarter. Third, we continue to maintain a strong liquidity position. As depicted on slide number 27, we ended the second quarter with $330 million of cash, cash equivalent in investments on the balance sheet and an undrawn $110 million senior credit facility. Further, as of August 3rd, after July expenditures totaling $54 million for our Williston Basin acreage acquisition and $9 million dollars for construction of our Williston Basin field level infrastructure, as well as to fund our ongoing five-rig drilling program. We had $252 million of cash, cash equivalent in investments on the balance sheet. But combined with our expanded hedging program, which I'll outline, this level of liquidity ensures the company’s ability to continue to fund the ramp up in our operated Bakken and Three Forks drilling program. And then lastly, our expanded CapEx program is capturing additional acreage and additional NAV for our shareholders. Yesterday, we announced an expanded CapEx program that is largely funding incremental acreage in the Williston Basin at attractive prices in what is currently a very competitive environment. Our operational out-performance relative to our peers has helped us with our organic leasing efforts and the larger acreage acquisitions where the counter party has retained some participation in the leases. Since our last acreage update at the end of April, we have acquired an additional 58 – 52,800 net acres consisting of roughly 34,000 net acres in and proximal to our core acreage where we have drilled 21 recent long lateral, high rate Rough Rider completions and approximately 18,800 net acres in eastern Montana largely located between Rough Rider and Elm Coulee in Richland County. As a consequence, we believe we’ve added 81 potential core Bakken drilling locations primarily in and around our Rough Rider project area, significantly enhancing our net asset value for our shareholders. Given that we have significantly de-risked close to 200,000 net acres, the principal risk in front of us largely relates to our ability to get our horizontal wells drilled and completed at reasonable cost and the risk of a downturn in oil prices. Lance will discuss in a minute the steps that we are taking to continue to lock up the necessary services to get our wells drill completed and some of the other steps we are taking to ensure operational success. And now, I’m going to provide you with a quick update on some of the changes that we have made to our hedging program in order to mitigate oil price risk. In early 2010, we began to consider how to more significantly insulate the company from the possibility of lower oil prices and the resulting impact of having to lay down our drilling rigs during the next three critical years when we will be converting our acreage to help up production. At that time, it was clear to us that hedging even 90% of our current proved developed producing oil reserves over the next two-year period, as then allowed by our banks, provided very little price protection given the outlook for tremendous growth in our oil volumes. After devising a plan to provide greater price protection, we presented our ideas to our banks. Based on our current tenure inventory of horizontal development drilling locations, the predictability of our Williston Basin operated drilling results, our strong liquidity position and the fact that we have largely locked-up the services to execute our drilling program over the next two years, the banks agreed to an alternative approach to allow us to hedge up to 65% of our forecasted production volumes over the next two years. Further, our internal analysis based on evaluating numerous oil price and service costs in areas have led us to conclude that, to the extent we can predict a NYMEX price of $65 per barrel, that we would have sufficient liquidity if we chose to maintain a significant portion of the eight-rig program that we are currently building to. As a result, in May we amended our credit facility and have embarked on a program since then using primarily wide collar, and to a lesser degree purchasing puts, to build a floor at $65 per barrel. Our current goal that we are working towards is to hedge up to 50% of the growth in our oil volumes over a two-year forecasted period representing the production growth that we would expect to result from a four-rig program. As a consequence, over the last several months, we have hedged roughly an additional 3.2 million barrels of oil through midyear 2012 using primarily collars, and to a lesser degree purchasing puts. At the present time, our weighted average cap on our collars for our hedge portfolio is approximately $100 per barrel. Further, and as depicted on the slide number 28, we have 700,000 barrels hedged for the second of 2010 representing 58% of our forecasted oil volumes based on the midpoint of our updated production guidance, and 2.1 million barrels and 1.3 million barrels hedged for 2011 and 2012 respectively. Moving on to a brief discussion of our financial results, our second quarter total production volumes averaged 7,756 BOEs per day above the high-end of our updated Q2 production guidance and an increase of 43% sequentially and 71% from that in the second quarter of 2009. More importantly, given our focus on drilling our Bakken and Three Forks predominantly oil wells, our second quarter oil volumes averaged 5,584 barrels of oil per day, an increase of 57% sequentially and 206% from that in the second quarter of 2009. Our Q2 oil volumes represented 72% of our total production volumes. More importantly, because of 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 revenues represented 79% of our total second quarter pre-hedge revenues. Our second quarter total production volumes reflect an increase in our oil inventory of approximately 5,089 barrels held in our on-site tank batteries at June 30th, adjusting our Q2 production volumes for the growth in our oil inventory results in average daily sales volumes for the second quarter of 7,700 BOEs per day. Higher oil sales volumes and higher commodity prices more than offset the impact of lower gas sales volumes and lower hedge settlement gains during the second quarter, resulting in a 186% increase in revenues, including hedge settlements up to $41.4 million. Second quarter 2010 revenues were positively impacted by $15.5 million due to the increase in our sales volumes and $11.9 million due to an 81% more increase in our pre-hedge commodity prices. On a per unit basis, we saw operating expense, which includes operating and maintenance expense, expense work-overs, and ad valorem taxes decreased 28% to $6.30 per BOE in the second quarter 2010 from $8.76 per BOE in the second quarter 2009. Our per unit lease operating expense was favorably impacted by both the growth in our production volume and a $33,000 decrease in our base operating and maintenance expense. During the quarter, work-over expense increased $856,000 with roughly 56% of the increase related to work-overs of several of our conventional Gulf Coast and Anadarko Basin natural gas wells. On a per unit basis, production taxes increased to $5.63 per BOE in the second quarter 2010 from a $2.04 per BOE in the second quarter 2009. Due to the growth in our North Dakota oil volumes and the higher associated taxes, production taxes were 9.6% of pre-hedged revenues in the second quarter of 2010, compared to 6.3% of revenues in the second quarter 2009. In addition to the growth in our North Dakota oil volumes, higher commodity prices and the associated increase in revenues in the second quarter 2010 also contributed to the increase in production taxes over that for the comparable period last year. General and administrative expense for the second quarter increased to $2.7 million from $2.3 million in 2009. The increase in employee compensation expense accounted for the bulk of the increase in G&A expense. The growth in our oil volumes and the associated increase in our revenues contributed to a 57% sequential increase in EBITDA during the second quarter to $33.1 million. Further the growth in our oil volumes in the higher commodity prices contributed to a 295% increase in EBITDA during the second quarter of 2010 relative to that of the prior year's quarter. Moving on to the balance sheet, at the end of the second quarter, we had $333 million in cash, cash equivalents, and investment; $160 million of senior notes; and, nothing outstanding under the senior credit facility with a $110 million volume base. Reviewing capital expending activity for the second quarter, our exploration and development capital expenditures totaled $92.4 million, of which $71.3 million went to drilling expenditures and $21 million went to land expenditures. Yesterday, we announced a $110 million increase in our 2010 exploration and development CapEx budget. As depicted on slide number 29, this takes our currently forecasted E&D budget to $404 million, roughly $69 million or 62% of the CapEx increase will fund the aforementioned acquisition of addition Williston base and acreage, primarily in our Rough Rider project area. In our earnings release yesterday, we provided production guidance for the second half of 2010. In terms of our expectations for the third quarter, we are forecasting our total production volumes to average between 7,900 and 8,500 barrels of oil equivalent per day, with 72% of this volume, forecasted to the oil. In terms of our expectations for the fourth quarter, we are forecasting for our total production volumes to average between 9,500 and 10,500 barrels oil equivalent per day, with 74% of this volume, forecasted to the oil. Using the net point of our guidance for third and fourth quarters would result in 2010 full year production growth of 56% over that for 2009 for our total production volumes and 143% for our oil volumes. This forecast reflects the continuation in production growth that is being driven by our highly successful horizontal Bakken and Three Forks drilling program that has taken us to record total production volumes in the second quarter with the expectation that we will continue to generate record volumes in the second half 2010 and beyond. That concludes my remarks. I'll turn the call over to Lance for some operational comments.

Thanks, Gene. If you move to slide 31, as most of you know, our operations team pioneered the use of long laterals with a high number of frac stages in the Williston Basin. We believe this has resulted in a step change in the economics and has significantly expanded the core economic area within the Williston Basin. To date, we've drilled 30 long lateral wells with a high number of frac stages that have averaged an early 24-hour peak rate of 2,600 barrels of oil equivalent. These wells have continued to perform strongly. Our wells have averaged over 1,000 barrels of oil equivalent per day over the first 30 days of production. Now, many of our peers are replicating our formula. In fact, a year ago in the Rough Rider area, we were the only operator drilling wells. Now, there are approximately 32 rigs running, which is largely the result of our success in transforming Rough Rider into a highly economic core area. The key components that contributed to the greatly improved economics within the tighter Bakken areas include the use of geo-steering, swell packers, perf and plug, and ceramic proppants. We identified these components in early 2009. And subsequently began actively planning a ramp-up to eight rigs. Since that time, we've been able to put in place contracts or firm commitments with multiple service and product providers. This has enhanced our execution of our plan and helped control our costs such as we anticipate being able to deliver predictable and repeatable organic growth for our shareholders. In terms of drilling services, we currently have five rigs under long term contracts. And we have a firm commitment to go to eight rigs by May of next year. Our six rigs will commence operations at the beginning of October, with our seventh rig at year-end, and the eighth rig in May of 2011. In terms of completion services, we have contracted with Halliburton to increase from our current one dedicated frac crew to two dedicated frac crews at year-end. Our one dedicated frac crew can currently complete four wells per month. In this contract, we will increase from on frac crew to 1.5 frac crews in the next 30 days, and further increase to two dedicated frac crews at year-end. With two dedicated frac crews, Brigham will be able to frac eight wells per month, which matches our output from our eight rigs. We have also have contracts and commitments for ceramic proppants to mirror our frac crew capacity as I just outlined. There are other services that we rely on to drill and complete our wells, but the rigs, pressure pumping services, and ceramics generally represent approximately 50% of our drilling completion costs and currently represent the biggest constraints to getting wells drill and completed in a timely and cost effective manner. Early this year, we also identified that it would be important to enhance control and minimize the cost related to transportation of our crude oil, gas, produced water, and fresh water. Currently, the liquids are transported to and from the well locations via truck; additionally, produced waters disposed of via third party disposal wells. To accomplish our goals of enhancing control and minimizing costs, we dedicated our portion of our proceeds from our April equity offering to efficiently move our volumes via pipeline and dispose of produced water in our disposal sites. Our infrastructure development plan also includes building a regional office in Williston, North Dakota to oversee our 358,000 net acres and multibillion dollar asset. Through the end of July, we have spent a total of $18.2 million on infrastructure of the $32.8 million budgeted for 2010. In terms of our production-related pipeline infrastructure, we currently have two gathering systems that are under construction. The first system, our Ross gathering system is located east of the Nesson Anticline in Mountrail County; the second, our Williams gathering system is located west of the Nesson Anticline in Williams County. If you move to slide 32, our Ross gathering system consists of a gas gathering line and a produced water gathering line, each of which extend over 28 miles. Currently, our gas gathering line is actively moving our Ross area gas to Whiting's processing plant. In terms of our produced water collection and disposal, our produced water gathering lines construction is complete. And the associated disposal well has been drilled and completed. The disposal facility itself is currently being constructed with a start-off in the next 60 days. We currently do not have any oil gathering capabilities in the Ross area, but we are considering construction of such facilities. If you move to slide 33, our Williams gathering system consists of three separate gathering lines, each of which extend over 70 miles. The oil gathering line will collect and transport produced oil to our collection facility, and then, have the option to go to a major pipeline or rail loading facility. The produced water line will gather water and transport it to our disposal well, which will be located adjacent to our Williston regional office. We will add additional disposal wells along our gathering system as our water disposal needs expand with our drilling program. We also have installed fresh water lines, which will take fresh water from several sources for delivery to our wells. This fresh water will be utilized for frac fluids and for the treatment fluids after the wells have gone online to production. The entire system should be fully operational in the second quarter of 2011. To ensure that we're able to move our produced oil for the best price, we are working on multiple oil contracts, and are currently focused on capturing adequate take-away capacity for our 2011 production volumes. Further, we are also working on a rail option to ensure we can move additional barrels if necessary. But most importantly, to ensure that we effectively manage our $358,000 acres, we have promoted Russel Rankin to regional manager and he's family will move to Williston this summer. Russell is uniquely qualified to run our field operations as he's designed and overseen the critical completion side of our operations in the Williston Basin since its inception. Our Williston regional office is currently under construction and is expected to open in the first quarter of 2011. This office will provide 8,000 square feet of office space and 6,500 square feet of heater warehouse. Associated with the office will be a 750,000 square foot pipe yard for storage of our pre-purchased tubulars and equipment. Overall, there's a tremendous amount of activity in the field that is intended to create sufficient capacity to match the significant growth in our drilling activity and our oil production. That completes my operational view. I'll now turn the call over to Bud.

Thank you, Lance. That's concludes our prepared portion of the call. We'd certainly be happy to answer any questions.

(Operator Instructions) And our first question comes from the line of John Freeman with Raymond James. Please proceed. John Freeman – Raymond James: Good morning, guys.

Good morning, John. John Freeman – Raymond James: First question I had, on the last call, so the ASC on the wells was around $6.5 million. I think it even had a few – I think Lance said that we're coming maybe a little bit below that. If you could just walk through what's been the major impact increasing it from $6.5 million now to $7.5 million?

Yes. I think that the cost that you're referring is what our actual wells were coming in previous to that call. I think we had listed on our – in that call that our current cost at that time was $7.2 million. And our current cost today is $7.5 million. And I think in our last call, we talked about cost creep coming. We've seen additional costs creep. We're not seeing quite as much now, but we're still seeing cost creep. And the cost that have increased the most, of course, are frac services are probably number one, followed by rig cost. And then overall, you're seeing creep on most of the services. John Freeman – Raymond James: Okay. And then, regards to – on the frac side, what's the current spud to sales? And then, what will it be once you've got both frac crews in place?

Well historically, we've been running about 60 days from spud to first sell. Now, we've got five rigs running with a capability of only completing four wells per month. So that's getting extended out to 90 days. But soon in October, on October 1, we'll pick up our seventh rig, and then we'll start catching up again.

Second frac rig.

I'm sorry. The second frac rig will pick it up. We'll pick up the second frac rig this month. And we'll start catching up. And that will handle six rigs running. And then when we pick up seven, we'll fall behind, and then we'll pick up to full crew and we'll – we'll pick up two full crews.

Yes, John, we'll have 50% of the frac – additional frac crew, which gives us such a capacity for six rigs running. And so, that'll give us a cutoff on our backlog that we're building up with five rigs. And then as Lance said, then we have a full frac crew coming on. And that'll give us a lot of further capacity for the eight rigs running. John Freeman – Raymond James: So your guidance for 2011, let's say when you got everything in place, is based on just a reversion to the historical 60 days or spud to sales?

Yes.

Yes, because we'll add the optimum number of frac rigs relative to the rigs working. John Freeman – Raymond James: Okay. And then last question for me, and then I'll turn it over to somebody else. Lance, can you quantify, just ballpark, the savings you're expecting when all of this is done, with your guidance systems, or disposing – taking care of your own water disposal for the third parties.

Well, it's going to be a profit center. But what we're going to do is be able to guarantee that we're going to have our barrels move in both oil, gas, fresh water, and salt water. They'll be moving via those pipelines. We'll reduce the need for trucks, which is a problem out there and it even becomes more problematic in the winter, of course. So we'll be able to move our barrels. We'll be able to reduce our costs some to the well, and then we'll have a profit center that we think is going to create a really good rate of return for the company.

A profit center that attracts third party volumes into the system. John Freeman – Raymond James: Excellent. Thanks, guys, good quarter.

Thank you, John.

Our next question comes from the line of Brian Lively with Tudor, Pickering, Holt, please proceed. Brian Lively – Tudor, Pickering, Holt: Good morning. Follow-up to last question, next year, as you get your frac crude in place and move out to high rate count, how faster are you going to be actually turning on the wells though? It seems like you have a backlog of wells that aren't completed, so you'll actually be turning wells on faster than every 60 days.

Okay. So it'll be caught up. So basically, what happens to that is (inaudible) answering that. Right now, we've got five drilling rigs running. And we've got one dedicated frac crew, so we are falling behind. And we're pushing more into the 90-day from the spud to first sales. But we're getting ready to pick up the second half crew. So we'll have one-and-a-half crew. We'll be able to do – complete six wells per month. And we'll have five rigs running. So we'll catch up. Then, we'll pick up another rig. And we'll start falling back again. And then ultimately, at year-end, we'll have two dedicated frac crews' capability of doing eight wells per month. Okay? And we'll only have seven frac – I mean seven rigs running, until eight. We'll have eight rigs and the capability of doing eight frac jobs per month. So in May, it should equalize – and we should go to that historical zero – 60-days from spud to first sales. Brian Lively – Tudor, Pickering, Holt: Okay. And just staying on the CapEx side, on the $40 million of increased CapEx for non-leasing, how much of that was related to just inflation and service costs versus doing more frac stages?

Gene, the question was relative that $40 million increased CapEx. It was not on the papers (inaudible), $10 million was low, especially since–

It was $36 million. So you're talking about the $46 million increase. Of the $110 million, $36 million was associated with incremental wells, both at our increase and Williston Basin wells, and there was an incremental Wolfberry as well, and then $10 million was due to the higher rates AFE costs, essentially the difference between $7.2 million and $7.5 million, which is what we're currently using. And then on top of those two numbers, we've got a 5% over that's built into our models. So we're forecasting nominally higher CapEx, then the $7.2 million and $7.5 million in place.

Slide 29 shows the $6.7 million in incremental in Williston Basin wells, plus $3.1 million in incremental primarily Wolfberry wells in West Texas. Brian Lively – Tudor, Pickering, Holt: Okay. And just thinking conceptually, as inflation is bringing cost out, but you're also adding more stages and adding some pretty big production up west. What are your thoughts today on just that optimum inflection point in terms of greater return through the number of frac stages?

Yes, just about – I'll start, and Lance will probably want to add more details. But we think it's going to be a little different recipe in the different areas. And in some of that, we've probably found a pretty optimal number of frac stage – probably maybe most areas. But in the Ross area, we've seen a significant recent record wells up there as we increase the number of stages in that really rich area. So we're completing the next three wells in that area with 38 stages. And we're really excited about seeing that. So I think to answer the question, we're just going to vary it by area. And in some areas, we're not going to be able to come back in and reduce our costs on top to the margin returns. Lance, you want to add anything to that?

Right, basically we've got 30 wells that we varied the number of stages. And you just got to remember, that's 30 wells. And it sounds like it's enough. But you got to remember that's about 200,000 net acres and what is that on a gross – it's just a gross area. I bet it's 0.5 million acres plus. So it's just going to – like Bud says, it's going to vary by area. We're going to continue to alter them until we get a good handle on each area and what the optimum numbers of stages are.

We'll know that and we'll announce it in the future.

And we'll also – when we talk about the fact that we have the opportunity – we've been primarily varying the number of stages. But now, we're also varying – we're fixing the number of stages in certain areas and varying other elements. So that does give us opportunity to further optimize the performance relative to the cost by varying those other elements. We're going to continue to learn about that. Brian Lively – Tudor, Pickering, Holt: Right, and as you've locked up long term drilling contracts and frac crews, what are you able to lock-in in terms of cost or pricing for those services?

Well, I'm not going to talk specifically about the cost. But typically, the contracts are locked up. And they have adjustments for their cost increases or market reasons depending on the contract. So I'd say that we have very favorable contracts. And we are fortunate to have them. And we've got the volume in those contracts that a lot of people are looking for today. It's the increase in volume. So we've already – we've been working on that for some time, so they've been in place. So people are trying to do it now or probably much further out in trying to increase their capacity or they can't.

We mentioned some constraints or cost crew, maybe relative to our peers. It obviously does not –100% of it. But there are constraints.

Right. There are some of the costs – some of the contracts are based on just a fixed price. Some of them are based – as their costs increase, then they can pass it on. Some of them are structured where we're below the market. And we do a quarterly adjustment based on the markets. But even when we're adjusting, we're adjusting below the markets. It'll adjust down if the markets that we're building–

They can only adjust some. They can't per quarter. Brian Lively – Tudor, Pickering, Holt: And is there a typical timeframe on these contracts?

Most of it's – through this year, some of them are through – all the way through next year. But they're all different periods. But the problem with the contracts is that after they terminate, they go away to process, to change. That's the downside. I don't expect them to. I expect just to evergreen this contract. And what you have in equipment and services and everything that's going on, I don't see them ever taking the services away. So I think it's all (inaudible). Brian Lively – Tudor, Pickering, Holt: The last question on the geology side, as you move from Rough Rider west into the Rogney well, what are you seeing in terms of geology changes from the net pay, porosity, permeability standpoint?

Yes, this is Jeff. I mean, when you look just on the overall thicknesses, Middle Bakken, we're about five feet thinner in the overall Middle Bakken interval when you go to Eastern Montana versus our Rough Rider area. Porosity is pretty comfortable. We'll probably lose about 1% porosity. You're going from an average of 8% porosity in Rough Rider to about 6.5% to 7% in Eastern Montana. Brian Lively – Tudor, Pickering, Holt: Okay. Thanks for the call there.

Thank you.

Our next question comes from the line of Joe Allman with J.P. Morgan, please proceed. Joe Allman – J.P. Morgan: Thank you. Good morning, everybody.

Good morning, Joe. Joe Allman – J.P. Morgan: So in terms of the constraints – I guess this is probably for Lance. So it sounds as if the spring the next year you'll have that – the water handling system and the gathering systems in place. By then, you will have eight rigs, and then the two full frac crews. So at that point, what constraints would you see having at that point in, say, next spring?

There could be some smaller things that constrain us, but those things are so easily resolved. So I don't think – I think we've done a good job of taking care of the constraints. You got to also add in the contracts we're doing in creating the capacity for our barrels of oil to move out of the basin. So I think 2011 at eight rigs, I think we're looking at execution risks versus – but not being able to execute. Joe Allman – J.P. Morgan: Got you. Okay. I understand this. And now you've got – you've fallen behind in terms of being able to complete the wells because you got more rigs than the frac crews – than the one frac crew can handle. So what's held back right now? So how much gas production is being basically shut in? And how much oil production is actually being shut in at this point? And what other constraints do you have right now that's holding you back?

Joe, just by the (inaudible), I'll give you more specifics. But it's really – it's not a – no production is being shut in. But it's just an increase in the number of wells that are waiting to be fraced. And so, we've got – previously, it was four.

Seven last time.

Seven last time, now it's nine.

Yes.

So it's just the transition as you recognized, Joe, going from four with one frac – dedicated frac crew who handles four rigs working and going up to five. You're starting to accumulate some – a little more backlog. And then, we'd get that half crew. We'll get caught up for a while. And then we add the other rig, and then we get behind a little bit more. And then we have the full dedicated crew, we'll get – we'll queue all that up and be ahead until we have the eighth rig in May of 2011. Joe Allman – J.P. Morgan: Okay. Are you producing all the gas that you can or not?

Well, on the gas–

On the gas side itself, we're not selling all of our gas. We do have over in the Rough Rider. As you know, Bear Paw has a huge expansion of their system. They basically got the approval because we've been telling them about two years about what we're going to do out here and the success we're having. And that's under construction. We do have some high pressures out there. And so, we're selling or flaring a part of it. As far as having wells hooked up, almost all the wells are hooked up right from the beginning. There're a couple of exemptions. There's one down by the river that requires a core permit to take in a while in the Williston well. And then there's one in Northern Montreal that doesn't have a gas line to it right now. And we expect to hopefully be able to have that hooked up to the gas line in 2011. But for the most part, our volumes are going into the gathering systems. Joe Allman – J.P. Morgan: I get it.

From the initial test. Joe Allman – J.P. Morgan: I get it. That's helpful. And then, are there plans at this point to go beyond the eight rigs?

We don't have any plans right now to beyond eight rigs. But certainly, we feel like we've capitalized and we're – our sales such that we have a critical mass sense of – we have that potential down the road, particularly with potential divestitures of some of our conventional assets. Joe Allman – J.P. Morgan: Got you. And then just a question on financing, so I know in one of the slides – I think it was one of your slides, Gene. There's a line about a future leveraging event. So it sounds as if – just to cover any gap between spending and cash flow that you might reduce some debt.

Well, we have the credit facility that's untapped. So we're going to have a substantial cash position on the balance sheet as the end of the year, so early part of next year – majority of next year's funding will come from cash flow and that cash position. Obviously, at some point down the road, we'll have the ability to draw down the credit facility to plug that funding gap. So beyond that, no. Certainly, it makes sense down the road to think about using some incremental leverage. I mean we're doing – we're funding development drilling. And certainly given where our balance sheet is today, you would – equity investors I wouldn't how they would – think would want to see us use additional debt. But that's probably the two big buckets of liquidity beyond cash and cash flow are the proceeds from any further assets sales and leveraging event, which certainly includes the usage of the credit facility. Joe Allman – J.P. Morgan: Okay, got you. And then, just on the overall – maybe this is for Lance again. In terms of your – it sounds like you're settled on – it varies by area, but you're settled on roughly 30 stages for these completions. And what about doing fewer say stages, but more intense fracs? Why not give that a shot for a longer period of time?

That is one of the plans. And I think we talked about it at the last conference call where we've broken it up in our quarterly in I think four or five different areas. And we're changing different variables. But one of the areas we're going to try and keep the number of stages consistent, I think it's 30 stages. And we're just going to increase the amount of profited pump to increase the frac links. And so, that is one of the things that we're doing in smaller areas so that it's actually spread out over our 200,000 net acres. Joe Allman – J.P. Morgan: Okay. That's helpful. And then just lastly, on the Rogney well, could you describe that completion? You basically had nine stages initially. Those nine stages were spread out across the length of that lateral?

You have to start out at the very toe and work your way back to the hill, so it's the furthest out, third of the well bore. We started out there. We did nine stages. Basically, we just reduced our frac rate. And that reduced our frac pressure. And it kept – what it keeps you from happening is your frac height from being this much. So it reduces your frac height. And what it did for is that it just didn't give us the profit concentrations that we needed and ended up really hurting instead of helping in. I'll take the blame for that, I wanted to split this well up and try and learn as much as we could. And the only way we could do it is to test the one end, use one technique, and then produce it for a while, and then do the other 21 stages, make adjustments, do the other 21 stages, and test it. So that's what happened. It ended up it didn't help us. It hurt us.

But we learned.

But we learned. We learned–

We learned (inaudible). We look forward to the Gobbs as opposed to the little R&D that we did on the log, including the core. With the Gobbs, we have to take what we've learned and try to generate a positive economics as possible. Joe Allman – J.P. Morgan: Okay. All right, very helpful. Thank you.

Thank you.

The next question comes from the line of Ron Mills with Johnson Rice. Please proceed. Ron Mills – Johnson Rice: Good morning, guys. A couple of questions, just as you – I guess a follow-up on Byan's question earlier, as you continue to move east – I'm sorry, west in Montana, I'm assuming – we're talking about the FH Petroleum well that had a higher water cut. Does the bottom thin as you continue to go from east to west? Or just geologically, how does – how does the play look in that portion, and especially given that you've acquired all that acreage now between your Sedlacek well and your Ghost Rider area.

Hi, Ron, Jeff here. When you look at the – basically, Rough Rider going east towards Eastern Montana, again as a reminder, middle Bakken goes from about 35 feet to about 30 feet thick. And we do see thinning of the upper shale. The upper shale goes from about 15 feet thick to 12 feet thick. However, it's still highly resistive and hydrocarbon generating. The Three Forks also thins. We see the Three Forks in our Rough Rider roughly about 25 feet thick. When you get to east – get into Eastern Montana, specifically on the western side of the Eastern Montana block, it thins to about 15 feet. It still has processing. It still has saturations. It has experienced some thinning. It gets back to Bud and Lance's point, the red flag we originally saw when we looked at the muddy well is about 200 feet below the base of the lower Bakken shale as they are limestone, then they are called the (inaudible). And it's got a water-bearing interval in it. And that was the thing we were looking real hard at and trying to understand. Since then, we've showed that we could put our big frac jobs on and not have to worry about that, so it's definitely a good thing to learn. When you go towards the – Elm Coulee piece of business, you could see a significant chunk of our acreage, that 17,000 plus acres for Elm Coulee. When you get over there, we look at that as more of a step out area. Obviously, the stuff next to Sedlacek we believe is core, and the existing historical data points confirm that. As you go a little bit more westward, we're stepping out a little bit and the geology does get a little bit more variable over there as Bud spoke to. What you see over there is the middle Bakken fracs is more variable. We like to look at the acreage that the folks selected that we've acquired their acreage, but we'll continue to hydrate that and continue to distill that down. Our plan there, Joe, is to test a well over there in the first quarter of 2011. We are going to pick our best geological location, high probability it's going to be a Bakken well, and see if we can do some good over there also. Ron Mills – Johnson Rice: Okay. And from just a take-away capacity in the area, the current production for the region is – you hear varying numbers, 310,000, 330,000 barrels a day. Current capacity is just under 400,000 barrels a day. I know you have planned expansions over the course of the next 2 to 2.5 years that, depending on which projects come to fruition, go from 500,000 to 600,000 plus barrels a day. Based on your view of your own and industry activity, from a timing standpoint, do you foresee any problems in terms of – similar to what we saw in late 2008, production starting to bump up against that capacity until some of the projects are completed?

Ron, this is Lance. I think that that could happen but only for short periods. And I think the difference between 2008 and where we are today, the rail unit train's – EOG's got it working. It pretty much puts a cap $9.5, $10 of differential in the basin. You got Hess building a bigger unit train. You've got a bunch of other people building partial loading stations for crude oil and trains, on rail. And then you got other ones looking at doing additional unit trains. So you got a lot of capacity that kind of caps what that differential should be. And at $9.5, $10, we should never see that $18, $19, $20, I guess some people saw over $20 in late December in '08. I don't suspect that that's going to happen again to that magnitude. So we might have short periods of time where we could spike up but I still think the spikes are going to be taken care of by the rail options. On top of rail, you got all the pipeline capacity expansions going on. From Enbridge's continued expansions, but on top of that you have XL pipeline and connecting to that and there're probably three or four more pipeline deals that are in the works. And in December of '08, none of those were there. So I think it's different world and if we do have a high spike I think it's going to be limited to the rail differentials and cost $10. And I don't expect that differential to stay around for long. Ron Mills – Johnson Rice: Okay. And then y'all drilled some additional wells in the Wolfberry, obviously in West Texas. Do you have many additional plans there? And I know you still have legacy mid-continent assets, all of which between Vicksburg and West Texas in the mid-continent probably eventually did get sold over a couple-year period. But where are those properties located relative to some of the recent Cleveland and/or Granite Wash plays?

Ron, Jeff again. The Wolfberry Project is in Howard County West Texas. We are a in a joint venture there and we are the minority non-operating partner who got about 12.5% interest. The operation currently has two rigs running and looks like they all have two rigs running throughout year end and we like it. It's a very economically attractive play. And their plans are to potentially have at least two rigs running through 2011 also. We're also – when you go up in the Anadarko (inaudible).

Hey, Jeff. One comment before you leave but also, Ron, just a point about how we can kind of view that. It is non-operative but it is obviously a – can't say a lot of operators are doing a lot of good there in Wolfberry. And so it's accreting a lot of value as they drill these wells to delineate more of the value, so I think at some point it is an option for us – potentially, an attractive one a little bit further down the road as they drill more wells, potentially develop that. But it's certainly not – it's attractive but it's not really competitive with the Bakken in terms of the rates of return. Ron Mills – Johnson Rice: Right.

And so the Anadarko, we have – go ahead, Jeff.

On the Anadarko, there's a pretty significant Granite Wash horizontal play going on and we are non-operating partners in a number of wells. There is currently one well completing and also another well has just spud, so you'll see a little bit of non-operated activity in the Big Wash play. One of the opposite wells IP'd about 27 million a day so we're definitely excited to be able to participate in those wells.

And then of course you're familiar with the Vicksburg line, and we've got our second Vicksburg well and we drilled one successful well this year and we got the second one waiting to be fraced. Once we get that fraced, there is the potential to get out there and potentially divest that. We've got 50 un-drilled locations there. The majority of the value there is liquids so it's a very attractive project for somebody who got the potential to develop this. Ron Mills – Johnson Rice: Right. And then just from a – I think you currently have, of your five rigs, four at Rough Rider area, or at least west of the Anticline, and one is at Ross. When you – as you march up to six, seven, and eight rigs, do you forecast having one rig in Montana, one to two rigs in Ross, and staying at getting up to five or six rigs at Rough Rider? Is that kind of the right way to look at distribution? Or how would you suggest we do that?

Frankly, Ron, now, we envision two rigs working in the Ross area. And then Montana, in – west of the Nesson, and I think we are optimistic now that we'll want to –- I think it's highly probable that we are going to have one rig working up in Montana and the rest in Rough Rider. It will be determined by how economic we can make the Montana area relative to Rough Rider. You know, the relative waiting there. Go ahead, Jeff.

And Ron, Jeff. Just to quickly add onto that, we are being very proactive with spacing here in Eastern Montana. We're going back in October and get nine more 1280 space. Montana is a little different than North Dakota. They have hearings every two months versus every month. You have to plan your business. Ron Mills – Johnson Rice: How is Montana versus North Dakota from a permitting and regulatory standpoint in terms just of planning?

I think they're trying to catch up. I think this October is going to be a watershed event. As Bud spoke about, there're 78-some odd spacing units in front of the commission. And our hope is that they may ultimately go into a monthly meeting. Ron Mills – Johnson Rice: Okay. Great. Thank you.

Thanks to you.

Next question comes from the line of Scott Hanold with RBC. Please proceed. Scott Hanold – RBC: Yes, thanks to you guys.

Hey, Scott. Scott Hanold – RBC: Yes, thanks you guys.

Hi, Scott. Scott Hanold – RBC: Just one question, you guys touched pretty much on everything else. But when you take a look at the activity levels relative to HPP requirements, it sounds like you're going to have, at the peak, it looks probably eight rigs next year, five in the Rough Rider area. In terms of your lease expiration, how long are some of the leases that you have in as far as time?

Well with that, Scott, Lance I think may have some of the specifics on that.

Yes, I think when we raised the money in 2009, we had scheduled to have them look at expiring leases, at least in our core acreage, that it only required three rigs to protect all of our core acreage. That being said, we've been running 4%, about 5%. So every month, we're getting further and further ahead of our expiring acreage issue. As we move into Montana and continue to have more success, there'll be more issues there. But I think that we're going to have way more rigs than required to hold our expiring acreage.

Our core acreage has grown. But a number of – several months ago, when we looked at it, we would have all of our core acreage (inaudible) in three years, I think it was, but the part is well. Now, we've added more core acreage, but we're also drilling with more rigs. Scott Hanold – RBC: Okay. When you say core, is that basically Rough Rider and Ross?

Yes, that's 34,000 net acres that we have with these new acquisitions. Scott Hanold – RBC: Okay. And so Montana, typically, how long are those leases?

It's David. Some of the extensional acres that we acquired does have some limited term, there's – that we're going to be working to extend. And some of it may expire. But most of the acreage has, even in the extensional area, we have until 2011 on the primary terms, and still beyond that. But the extensional area has more term issues that, again, I will be working on. Scott Hanold – RBC: So is it logical to assume that should you have some success on Montana, we could see another rig, whether it's either moving from Ross or Rough Rider in the Montana some time in 2011?

Yes, this is Jeff again. We've already know – currently we have our Gobb, which is going to be eastward of the Rogney scheduled for an October spud. And we've already got another well spud. And it's the Oelkers, you can see that in one your slides, scheduled for January spud. So we're already gearing up in scheduling the plan to begin to develop the eastern Montana property. Scott Hanold – RBC: Okay, okay. That's good. And one last question, you all picked up about 6,000 acres here recently. And it looks like that wrote, on average, $1,000 per acre. How much more capacity there to add some acreage in some of your core areas? Are you going to lease sales? Are you picking it up from organically on the ground? How are you picking up acreage, and how much more acreage do you want to pick up going forward here over the next year or two?

This is David again. We are still looking at opportunities. And there are still some opportunities out there. We'll continue in our effort. We are getting – there are fewer and fewer blocks to acquire, and obviously, within these areas that – where we've had success has become more and more competitive. The ground for organic leasing is really starting to drive, the trucks – available trucks are fewer and fewer. But we do still see some opportunities down here that we're pursuing. Scott Hanold – RBC: Is there a limit to what you would be willing to spend? I mean, if you – if we look at the lease sales from yesterday, I think the high bid came in near $10,000 an acre, in the millions, if I'm not mistaken.

Yes, Scott, this is Bud. That was clearly it. I mean you've seen – we hadn't been – we don't reach up there to those levels. And it's really high threshold for us. And it's also very geographically selective. As you see, what the acres over that is based on a lot of knowledge and data. We're only buying in areas that are either core or that we think we can make the big turn into core. And we're not reaching up there in those $4,000, $5,000 an acre level.

And you need to know that we already – our operators (inaudible) that we can become an operator by picking up more acreage jobs that you can take precedent also. Scott Hanold – RBC Capital: I appreciate it, guys. Thanks.

Thank you.

Our next question comes from the line of Steve Berman with Pritchard Capital Partners. Please proceed. Steve Berman – Pritchard Capital Partners: Hi, guys. A couple of questions, I guess for Gene, can you clarify the $252 million in cash? Is that a July number after the acquisitions or is that a number as we sit here today?

Well, no. That's August the 3rd, I think, is what I said. That includes all the acres acquisitions that we've announced. It also includes an additional – I think in the second quarter, we had roughly $9 million of CapEx associated with our field level infrastructure. And so, in the updated number, in the $252 million, there's – in the month of July, there's an additional $9 million. So in total, we've spent a little over $18 million today in terms of implementing the – what Lance outlined in his operational discussion. Steve Berman – Pritchard Capital Partners: Okay. Then the next question, can you bring us up to speed on where you stand – what the US energy wells – where that – how far along you are and when you anticipate starting to get those working interests back up on those wells?

First of all, just as a reminder, 15 wells, that's the (inaudible) team we have to – and we spud actually to 15 by year-end. And so, we're moving forward with that effort. And maybe David can talk about the–

Right. I'm not certain where we are in some of the earlier wells and the fail calculations. And the thing on the grouping of wells, there is – we do back it in for additional interest upon recurrence of about – and I don't have the details. In fact, I'm not sure – I don't have the details on where we are and how close we are on those bailout and currencies. I don't have it on right now.

The state is – by that, we got a couple more – two more wells in the 15-well program that – as you know, as you're referring to those were diluted. But we get the odd – we finished the initial 15 wells here at year-end. Steve Berman – Pritchard Capital Partners: Okay. Great. That's fine. Thanks, guys. That's it for me.

Okay. Thank you, Steve.

Our next question comes from the line of Michael Bodino of Global Hunters, please proceed. Michael Bodino – Global Hunters: Good morning, guys, great quarter.

Thanks, Michael. Michael Bodino – Global Hunters: Hey, just a couple of follow-ups, a little clarification on, on the acreage add, can you give us some more data in terms of how much of it – what's your average working interest – what your average revenue interest is across that acreage?

You bet. In most of the acreage, we acquired 100% of the lease hold. In a couple of the transactions, there are – there were some retained working interest in the lease hold. The transactions are pretty clean in that there are no work programs required or no well carries. And what's good about these transactions is that we're able to acquire lots of acreage that gives us the ability to operate in one of the – operate in a lot of the acreage. We don't give a whole lot of the details of transactions. But we're obviously very pleased with them. We think we got it at a really good price. And it was in a good position, especially with respect to the acreage acquired in our core areas. Michael Bodino – Global Hunters: Can you give us a sense of what the average royalties are on the acreage?

In the vast majority of the acreage, we've got greater than 80% of net revenue interests. We're down to – the lowest were down to 38%. And that's on maybe 6,000 net acres, that's all. So other than that 6,000 net acres, were about 80% average in interest on the acreage acquired. Michael Bodino – Global Hunters: Is the 80% a good average or 81%? What do you think is a good average?

It's actually higher than that. It's probably somewhere – it's definitely not 80%, 82% probably is close to the average on the total acreage. Michael Bodino – Global Hunters: Okay. And relative to the stepped-up capital budget, can you give us a little sense on how much of that is on operated wells and how much of that's non-operated wells on the drilling portion of that?

The vast majority of that – it's certainly – with respect to the Williston Basin, we have a nominal increase in the non-operated activity. But the bulk of the roughly seven wells is operated activity. Michael Bodino – Global Hunters: Okay. I'm just trying to – dot a couple of Is and cross a couple of Ts here. Any idea of what your Wolfberry inventory looks like on a net basis?

We currently dig in – I apologize, I don't have the Wolfberry math in from of me. But we've got, from here to year-end, it's going to be – it looks about 14 wells drilled of that. We're going to end up having about a net 12 – particularly by year-end, we're using our $12.4 million interest. And it looks like they're going to schedule – next year, it looks like it's going to continue to March forward. So we'll probably end up having an incremental 2.5 net wells in 2011.

Jeff, you don't remember how many gross acreage of this. So if you could check please, thanks. We might be looking for a list that – that's the total net exposure we might have there potentially.

If I can get that – can you follow-up in the call. We can get– Michael Bodino – Global Hunters: Sure. That's fine. I was just curious more than anything else. My last question and I'll jump out. But in Montana, I know it's early days there, any further thoughts on EURs as you move out to the west and what your thoughts are on that?

This is Bud. Lance, you may want to add to what I have to say. I think it's really just too early. And we're really encouraged. All these areas, the early wells, we tend to innovate and do better. And if something's not right here, we were doing a lot of R&D. So it's just too early. The Sweetman is really encouraging. Lance, maybe you could go about (inaudible) short laterals. And we don't know how many stages are EUR, et cetera. But we didn't to have stay EUR space in a lot of long laterals. So it's just so hard to say. My thought's a big error bar right now. I think that next level we got is going to really, really help us to really provide a little more definition on that. Michael Bodino – Global Hunters: Very nice, good quarter, guys.

Great. Thank you, Michael.

Our next question comes from the line of David Snow with Energy Equity, Inc. Please proceed. David Snow – Energy Equity, Inc.: Yes, hi. I'm wondering, the 358 – 200 net acres, does that take into account the work down, and then back end of US Energy?

This is Bud. It does. US Energy, we're going to finish up the initial 15-well program by the end of December. And none of the – say, let me think about that.

Yes, the net impact of US Energy over the 350 acres is minimal.

Yes. There is an impact as I – now that I think about it. There is an impact, but it's very, very small. When you think about – we can do the math on–

I think we've done the calculations in the past. And assuming they participate to the maximum of their interest and we do as well, they are up to 5,000 acres. So you could take–

Yes, the 358 acres down to 353 acres.

Three, fifty-three acres. So obviously, that would be the most conservative, probably, outcome. David Snow – Energy Equity, Inc.: And then if you back in, it's less than 5,000?

That's right because we backed in for – after payout on those wells for some of that equity. David Snow – Energy Equity, Inc.: Okay. Terrific. Great job.

Okay. Thank you. Yes, Jeff has – Mike, if you're still on, the reflection on the Wolfberry at the end–

We've got some quick numbers. Again, that's a joint venture. We've got about – just about 10,300 gross acres. Of that, we've got about 1,300 net acres. The plan is for 40-acre spacing. That comes out to about 291 gross wells, 32 net wells to the company.

Thank you, Jeff.

Our next question comes from the line of Richard Bresler with Gulfsands Petrol. Please proceed. Richard Bresler – Gulfsands Petrol: Hi, gentlemen. Kudos for a great first – second quarter, and it looks like a great 2010 and a really exciting 2011. You guys have got the tiger by the tail.

Well, thank you. We're very fortunate, very excited about what's – what we're doing. Richard Bresler – Gulfsands Petrol: Quick question, this may be in the SEC filings, but what is Brigham's working interest, 1P, 2P, and 3P reserves?

We just don't really provide – and all we provide is just the further preserve volumes. So that was between 7.7 million barrels at the end of last year. Richard Bresler – Gulfsands Petrol: Okay. All right, that was it. All the other guys have pretty much covered all the other bases. So that's it, gentleman, and looking forward to more outstanding results.

Great. Thank you. Thank you for participating in this call. Richard Bresler – Gulfsands Petrol: You bet, sure.

Okay. Take care.

Our next question comes from the line of Subash Chandra with Jefferies. Please proceed. Subash Chandra – Jefferies: Yes, just one quick one, and if you addressed this, I apologize. But how does geo-pressure compare in Eastern Montana and – throughout Eastern Montana, compared to Rough Rider?

Hi, Subash. This is Lance. Rough Rider, our Ross area Rough Rider and Eastern Montana have all the same pressure gradients. They're all normal pressure. Subash Chandra – Jefferies: Okay. Perfect. That's all. Thank you.

Sure. Thank you.

Our next question comes from the line of Eugene Lipovetsky [ph]. Please proceed.

Hi, guys. How are you?

We're doing great. How are you?

Doing well. Thanks for taking my call. First question is, you guys have an inventory of over 300 or so net wells just in your core alone. And I'm wondering whether or not the eight rigs – that eight-rig program that you're talking about starting next year is really the max that you could attack this acreage in these locations with. Can you please comment on further ability to accelerate that value? And I understand the complexities that go along with managing and growing as fast as you guys have. But it just seems to me that, potentially, there's further upside to that eight-rig number. Am I correct?

It's really just a financing issue. I mean, you look at Continental, what do they run in, 20 rigs right now. But on a – the safest thing that we've tried to do is to manage the ramp-up and bring it on a rig every four months. And Lance and the team has done a great job of planning ahead in working with the contractors on communicating what the plan is, and working with them and to have a plan that works so that the service is all lined up. So clearly, there is the opportunity to continue to ramp-up beyond eight rigs, and ramp – potentially double it over time. So it's a matter of financing that growth over time. But it's out there.

Got you. So do you think that once you become self-funding with the cash flow you're generating, you will then consider increasing beyond eight? And obviously, there's also another source of funds that you've referred to earlier, being the non-core assets. But can you just comment on when you expect to let the street know your ultimate ambitions?

I guess the – where we are today is we're focused on the eight rigs. Certainly, when we become self-funding, yes, I mean that is an easy – that's not a huge issue to ramp-up from that level of activity. And it's not only the financing issue. Lance has got to go out and procure the services, which he's done a great job of. And I think we're so focused now today around execution risks and not having any operational issue, which would raise questions about the quality of our acreage, so ramped up our activity in a way that we don't feel like we're taking on incremental operational risk by virtue of picking up an additional rig. So certainly, you would look at the inventory at the locations that we have, it's only grown as a result of the acreage acquisitions that we've just made. And you would argue that that would remain at the higher level of activity beyond the eighth rig. Clearly, that's out there in front of us. And I think as we get more visibility around funding sources and as we've talked about those, we'll be principally, in the near term, debt financing and the proceeds from asset sales. And that would give us – certainly, those would serve as a catalyst to maybe potentially talk about some higher level activity beyond the eight rigs.

Yes, this is Bud. And if you set aside how we finance it, we just assume for this moment that we figure out the optimal way to fund it. So we actually now think early 2011, when we see we're getting the eight rigs in May, is when we could be thinking about – from a practical standpoint, with the eight rigs coming online in May, four months later, September potentially, a ninth rig. We could be, from a practical standpoint, thinking about execution of that assuming that we've figured out how to optimally fund it.

That's awesome. Thanks a lot, guys. And one quick numbers question, the 37.5 or so net wells that you intend to drill this year in the Williston Basin, can you please give me a breakup by region and interval, so Montana, Rough Rider, Ross, and then maybe Bakken, and maybe Three Forks?

Well, I think we've got two Montana wells. And then, really, I think generally speaking, we've got a third of the activity in Ross and two-thirds of the activity in Rough Rider. And then, you've got – I guess we've got two Three Forks well over in Rough Rider.

And then, we have – we're currently drilling, as a reminder, that is going to be a three points just to the Rough Rider. Currently in Ross, the remaining wells this year are scheduled as Bakken wells.

Hopefully that helps frame that for you.

It does.

And Jeff, if you could later follow-up with volume.

I will.

All right.

Thank you so much.

All right. Well, thank you.

Our next question comes from the line of Ed Campbell [ph]. Please proceed.

Yes. Could you comment on the extent of the acreage that you have that's been de-risked in the Williston Basin?

Yes, this is Bud. We view core, right now, is about 198,400 net acres. And that's inclusive of the 34,000 net acres that we believe to be core that we just added with this transaction. So that's just – that's it in summary.

Thank you. One further question, could you comment on the book value or the net asset value of Brigham at the present time?

You just have to look at the balance sheet. Is there a specific part of the – of value that you're focusing on? We've got all our gas property is – the proved piece, as of June 30th, $355 million. And the unproved piece is $82 million, so a total of $447 million of total gas proved and unproved properties.

Thank you. One final question, is it possible to comment on any potential or probable reserves other than proving reserves?

We just don't really comment on non-proved reserves.

Thank you. Great job, guys. Keep it up. Thank you.

Well, thank you.

That's all the time we have for the Q&A portion of today's call. I would now like to turn the call back over to Bud Brigham for any closing remarks.

Well, thanks again to everybody for participating in what's been a very exciting quarter. And we look forward to reporting our results on the third quarter. Thanks again.

Thank you for your participation in today's conference. This concludes the presentation. Everyone may now disconnect.